0000930413-01-501307.txt : 20011019 0000930413-01-501307.hdr.sgml : 20011019 ACCESSION NUMBER: 0000930413-01-501307 CONFORMED SUBMISSION TYPE: U-1/A PUBLIC DOCUMENT COUNT: 7 FILED AS OF DATE: 20011012 FILER: COMPANY DATA: COMPANY CONFORMED NAME: AMERICAN ELECTRIC POWER COMPANY INC CENTRAL INDEX KEY: 0000004904 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 134922640 STATE OF INCORPORATION: NY FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: U-1/A SEC ACT: 1935 Act SEC FILE NUMBER: 070-09785 FILM NUMBER: 1757658 BUSINESS ADDRESS: STREET 1: 1 RIVERSIDE PLZ CITY: COLUMBUS STATE: OH ZIP: 43215 BUSINESS PHONE: 6142231000 FORMER COMPANY: FORMER CONFORMED NAME: KINGSPORT UTILITIES INC DATE OF NAME CHANGE: 19660906 U-1/A 1 c22015_u1-.txt AMENDMENT NO. 2 File No. 70-9785 SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 --------------------------------- AMENDMENT NO. 2 TO FORM U-1 ---------------------------------- APPLICATION OR DECLARATION under the PUBLIC UTILITY HOLDING COMPANY ACT OF 1935 * * * AMERICAN ELECTRIC POWER COMPANY, INC. 1 Riverside Plaza, Columbus, Ohio 43215 --------------------------------------- AMERICAN ELECTRIC POWER SERVICE CORPORATION 1 Riverside Plaza, Columbus, Ohio 43215 --------------------------------------- CENTRAL AND SOUTH WEST CORPORATION 1 Riverside Plaza, Columbus, Ohio 43215 --------------------------------------- CENTRAL POWER AND LIGHT COMPANY 539 North Carancahua Street, Corpus Christi, Texas 78401-2802 ------------------------------------------------------------- COLUMBUS SOUTHERN POWER COMPANY 1 Riverside Plaza, Columbus, Ohio 43215 --------------------------------------- OHIO POWER COMPANY 301 Cleveland Avenue, S.W., Canton, Ohio 44702 ---------------------------------------------- SOUTHWESTERN ELECTRIC POWER COMPANY 428 Travis Street, Shreveport, Louisiana 71156-0001 --------------------------------------------------- WEST TEXAS UTILITIES COMPANY 301 Cypress Street, Abilene, Texas 78601-5820 --------------------------------------------- (Name of company or companies filing this statement and addresses of principal executive offices) * * * AMERICAN ELECTRIC POWER COMPANY, INC. 1 Riverside Plaza, Columbus, Ohio 43215 --------------------------------------- (Name of top registered holding company parent of each applicant or declarant) * * * Susan Tomasky, General Counsel AMERICAN ELECTRIC POWER SERVICE CORPORATION 1 Riverside Plaza, Columbus, Ohio 43215 --------------------------------------- (Name and address of agent for service) TABLE OF CONTENTS PAGE NUMBER Glossary of Terms ............................................................ I Item 1. Description of the Proposed Transaction ........................... 1 A. Introduction .................................................. 1 B. Description of the Applicants ................................. 3 C. Overview of the Proposed Restructuring ........................ 5 1. Reorganization of the Texas Operating Companies ........... 7 2. Reorganization of the Ohio Operating Companies ............ 9 D. Overview of Requested Authorizations .......................... 9 1. The Transaction ............................................ 9 a. Formation and Capitalization of Enterprises, Wholesale Holdco and Domestic Holdco ................... 10 b. Formation of Texas PGCs and Tax Beneficial Entities .... 10 c. Formation of EDC Subsidiaries .......................... 11 d. Capitalization of Subsidiaries ......................... 11 e. Transfers .............................................. 12 2. Agreements ................................................. 15 3. Services, Goods and Assets Involving the Utility Operating Companies ................................ 16 E. Financing Plan ................................................. 17 1. Overview of the Financing Request .......................... 17 2. Parameters for Financing and Hedging Transaction Authorization .................................. 18 a. Effective Cost of Money ................................ 18 b. Maturity of Debt and Final Redemption on Preferred Securities ................................ 19 c. Insurance Expenses ..................................... 19 d. Use of Proceeds ........................................ 19 e. Financial Condition .................................... 20 f. Hedging Transactions ................................... 22 3. AEP Guarantees, Intra-system Advances and EWG Investment ............................................. 23 a. Guarantees ............................................. 23 b. Intra-system Advances .................................. 25 c. EWG Investment ......................................... 25 4. Unregulated Holding Companies Authority .................... 26 a. Financing Authority .................................... 26 b. Guarantee Authority .................................... 27 c. Hedging Transaction Authority .......................... 27 d. Intra-system Advances .................................. 27 5. Unregulated Subsidiaries Authority ......................... 27 a. Financing Authority .................................... 27 b. Guarantee Authority .................................... 28 c. Hedging Transaction Authority .......................... 28 PAGE NUMBER 6. Reg Holdco Authority ....................................... 28 a. Financing Authority .................................... 28 b. Guarantee Authority .................................... 29 c. Hedging Transaction Authority .......................... 29 d. Intra-system Advances .................................. 29 7. Regulated Subsidiaries Authority ........................... 29 a. Financing Authority .................................... 29 b. Guarantee Authority .................................... 30 c. Money Pool Authority ................................... 30 d. Hedging Transaction Authority .......................... 30 8. Finance Subsidiary Authority ............................... 30 F. AEP's Non-utility Holdings ..................................... 31 G. Request for Authority to Pay Dividends Out of Capital or Unearned Surplus by the Utility Subsidiaries ................... 31 H. Other Regulatory Approvals ..................................... 32 Item 2. Fees, Commissions and Expenses ..................................... 33 Item 3. Applicable Statutory Provisions .................................... 33 A. Sections 9 and 10 .............................................. 34 1. The Transaction Complies With State Law .................... 35 2. The Capital Structure is not Unduly Complicated ............ 35 3. The Consideration is Fair and Reasonable ................... 37 B. Section 12 and Rule 46 ......................................... 37 C. Section 13(b) Compliance ....................................... 38 D. Rule 54 Compliance ............................................. 39 Item 4. Regulatory Approval ................................................ 40 Item 5. Procedure .......................................................... 40 Item 6. Exhibits and Financial Statements .................................. 41 a. Exhibits .............................................. 41 b. Financial Statements .................................. 41 Item 7. Information as to Environmental Effects ............................ 42 Signature ................................................................... 42 GLOSSARY OF TERMS When the following terms and abbreviations appear in the text of this Application, they have the meanings indicated below: TERM MEANING 1935 Act............................. Public Utility Holding Company Act of 1935 AEP.................................. American Electric Power Company, Inc. AEPSC................................ American Electric Power Service Corporation Applicants........................... AEP, AEPSC, CPL, CSP, CSW, OPCo, SWEPCO and WTU Commission........................... Securities and Exchange Commission CPL.................................. Central Power and Light Company CPL EDC.............................. CPL following the transfer of its generating assets and related liabilities CPL PGC.............................. A to-be-formed PGC organized to hold the generating assets and related liabilities of CPL CPL PGC LLC.......................... A to-be-formed limited liability company organized by CPL PGC to act as the general partner of CPL PGC LP CPL PGC LP........................... a to-be-formed limited partnership organized by CPL PGC to hold its generation assets and related liabilities CSP.................................. Columbus Southern Power Company CSP EDC.............................. a to-be-formed EDC organized to hold the transmission and distribution assets and related liabilities of CSP CSP PGC.............................. CSP following the transfer of its transmission and distribution assets and related liabilities CSW.................................. Central and South West Corporation Domestic Holdco...................... Domestic Generating Holding Company, a to-be-formed wholly owned subsidiary corporation or limited liability company of Wholesale Holdco EDC.................................. Energy Delivery Company Enterprises.......................... AEP Enterprises, a to-be-formed wholly owned subsidiary corporation or limited liability company of AEP TERM MEANING ETCs................................. exempt telecommunications companies within the meaning of Section 34 of the 1935 Act and related rules thereunder EWGs................................. exempt wholesale generators within the meaning of Section 32 of the 1935 Act and related rules thereunder FERC................................. Federal Energy Regulatory Commission Finance Applicants................... CPL EDC, CPL PGC, CPL PGC LLC, CPL PGC LP, CSP EDC, CSP PGC, Domestic Holdco, Enterprises, OPCo EDC, OPCo PGC, Reg Holdco, SWEPCO EDC, Wholesale Holdco, WTU EDC, WTU PGC, WTU PGC LLC and WTU PGC LP FUCOs................................ Foreign Utility Companies within the meaning of Section 33 of the 1935 Act and related rules thereunder Holding Companies.................... collectively, Enterprises, Wholesale Holdco, Domestic Holdco and Reg Holdco LPSC................................. Louisiana Public Service Commission OPCo ................................ Ohio Power Company OPCo EDC............................. a to-be-formed EDC organized to hold the transmission and distribution assets and related liabilities of OPCo OPCo PGC............................. OPCo following the transfer of its transmission and distribution assets and related liabilities Operating Companies.................. collectively, CPL, CSP, OPCo, SWEPCO and WTU PGC.................................. Power Generating Company PUCO................................. Public Utilities Commission of Ohio PUCT................................. Public Utility Commission of Texas Reg Holdco........................... Central and South West Corporation Regulated Subsidiaries............... CPL EDC, CSP EDC, OPCo EDC, SWEPCO EDC and WTU EDC REP.................................. Retail Electric Provider Restructured Generation Assets ...... The generation assets of CPL, CSP, OPC and WTU immediately prior to the Transaction Rule 58 Subsidiaries................. energy related companies within the meaning of Rule 58 TERM MEANING STP.................................. South Texas Project 2,630 MW nuclear generating station Subsidiaries......................... the to-be-formed wholly-owned direct and indirect subsidiaries of each Operating Company SWEPCO............................... Southwestern Electric Power Company SWEPCO EDC........................... a to-be-formed EDC organized to hold the transmission and distribution assets and related liabilities of SWEPCO situated in Texas Unregulated Holding Companies........ Enterprises, Wholesale Holdco and Domestic Holdco Unregulated Subsidiaries............. CPL PGC, CPL PGC LLC, CPL PGC LP, CSP, OPCo, WTU PGC, WTU PGC LLC and WTU PGC LP Unregulated Unit..................... the direct and indirect subsidiaries of Enterprises Utility Subsidiaries................. CPL EDC, CPL PGC, CPL PGC LLC, CPL PGC LP, CSP EDC, CSP PGC, OPCo EDC, OPCo PGC, SWEPCO, SWEPCO EDC, WTU EDC, WTU PGC, WTU PGC LLC and WTU PGC LP Vertically-Integrated Companies ..... AEP Generating Company, Appalachian Power Company, Indiana Michigan Power Company, Kentucky Power Company, Kingsport Power Company and Wheeling Power Company (each of which is currently directly owned by AEP and (except for AEP Generating Company) remains subject to regulation by at least one state utility commission) Wholesale Holdco..................... Wholesale Holding Company, a to-be-formed wholly owned subsidiary corporation or limited liability company of Enterprises WTU.................................. West Texas Utilities Company WTU EDC.............................. WTU following the transfer of its generation assets and related liabilities WTU PGC.............................. a to-be-formed PGC organized to hold the generation assets and related liabilities of WTU WTU PGC LLC.......................... a to-be-formed limited liability company organized by WTU PGC to act as the general partner of WTU PGC LP WTU PGC LP .......................... a to-be-formed limited partnership organized by WTU PGC to hold its generation assets and related liabilities This amendment restates in its entirety Amendment No. 1 to the Application-Declaration filed on August 22, 2001. ITEM 1. DESCRIPTION OF THE PROPOSED TRANSACTIONS A. INTRODUCTION AEP and CSW, holding companies registered under the 1935 Act, CPL, CSP, OPCo, SWEPCO, WTU, each a direct or indirect wholly owned public utility electric subsidiary of AEP, and AEPSC, hereby file this Application-Declaration with the Commission under Sections 6(a), 7, 9(a), 10, 12 and 13(b) of the 1935 Act, and Rules 43(a), 44, 45, 46, 54, 90 and 91 thereunder, for authority to engage in certain transactions in connection with state mandated restructuring in Ohio and Texas. AEP holds vertically-integrated electric utility companies with retail utility operations in eleven states - Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia. These states have reached different decisions as to whether, when and how to restructure their electric industries. Texas and Ohio have opted to deregulate generation, require separation of the generation and energy delivery functions, and eliminate the concept of native load retail service, all in favor of free and open competition at retail and have approved restructuring plans that are to be implemented by January 1, 2002. Under these approved plans, the Operating Companies will legally separate their assets between: o PGC affiliates that will sell power and energy at wholesale, and o EDC affiliates that will own transmission and local distribution facilities and transport the energy and perform metering functions. In connection with this restructuring, AEP proposes to realign certain of its utility and non-utility businesses under three first-tier subsidiaries in a manner similar to that approved in Exelon Corporation, HCAR No. 27259 (Oct. 20, 2000). Of interest here: o CSW, as the Reg Holdco(1), will serve as an intermediate holding company for the EDC affiliates and certain other AEP public-utility subsidiary companies that are not required to restructure, including, subject to any necessary state approval, the Vertically-Integrated Companies. o Enterprises will serve as an intermediate holding company for AEP's non-utility businesses and, through Wholesale Holdco and Domestic Holdco, for the PGC affiliates and the system's other "unregulated" generation. o AEPSC will continue to provide services to the AEP system companies. Among other things, AEPSC will provide centralized and regionalized management and support for both regulated and unregulated generation. Charts setting forth the AEP system and the Operating Companies post-restructuring are attached hereto as Exhibit B-1. The mechanics of the proposed restructuring are described more fully herein. AEP respectfully requests authority to form and capitalize Enterprises, Wholesale Holdco, Domestic Holdco and Subsidiaries to be formed for the purpose of acquiring and holding certain utility and other assets of each Operating Company and for each Operating Company to transfer to the applicable Subsidiary certain utility and other assets (the "Transfers") and for certain of the Operating Companies and Subsidiaries to be dividended to AEP and for AEP to contribute certain of the Operating Companies and Subsidiaries to Enterprises, Wholesale Holdco, Domestic Holdco and/or Reg Holdco to implement their respective plans to separate their generation and power marketing businesses from their transmission and distribution businesses in the states of Texas and Ohio as more fully described herein (the "Transaction"). Certain financing authority will be required in connection with the restructuring. These financing requests, which are ---------- (1) Throughout this Application-Declaration names are used for affiliates of the Applicants that are intended to be descriptive of the functions such affiliates will serve after the reorganization of the AEP system to comply with the state restructuring laws of Ohio and Texas is completed. Such names are fictitious and used as a matter of descriptive convenience. The actual legal names of such affiliates will be determined as part of the implementation of such reorganization. 2 described more fully herein at Item 1.E., are consistent with the ongoing needs of the restructured entities and similar to the "housekeeping" authority that the Commission has granted to other companies. B. DESCRIPTION OF THE APPLICANTS AEP is a corporation organized and existing under the laws of New York, with its principal offices in Columbus, Ohio. AEP is one of the largest investor owned electric public utility holding companies in the United States serving over 4.8 million retail customers in eleven states and selling bulk power at wholesale both within and beyond its domestic retail service area. AEP and CSW completed their merger on June 15, 2000 and as a result AEP now has 38,000 megawatts of generation, over 38,000 miles of transmission lines and 186,000 miles of distribution lines in the United States. Subsidiaries own 544 megawatts as independent power producers in Colorado, Florida and Texas. In recent years AEP has expanded its domestic operations to include gas marketing, processing, storage and transportation operations, electric, gas and coal trading operations and telecommunication services. Subsidiaries also provide power engineering, generation and transmission plant maintenance and construction, and energy management services worldwide. AEP is one of the largest traders of electricity and gas in the United States. AEP intends to continue to expand its competitive energy business by growing the trading and marketing business through expanding operations to be a leading trader in all energy commodities; optimizing the operations of its assets to yield maximum value in competitive markets; and acquiring generation and natural gas assets that complement this strategy. As of July 24, 2001, Standard & Poor's rating of AEP's senior unsecured indebtedness was BBB+ while Moody's was Baa1. CPL is a corporation organized and existing under the laws of the state of Texas, and has its principal office in Corpus Christi, Texas. CPL is a wholly owned subsidiary of CSW, and an indirect subsidiary of AEP and is a public utility under the 1935 Act. CPL is engaged in generating, transmitting and distributing electric energy to the public in south Texas. CPL also owns an undivided 25.2% interest in STP Nuclear Operating Company, which operates and maintains the STP, of which CPL owns an 25.2% undivided interest. CPL serves approximately 661,000 retail customers. In addition to its undivided interest in STP, 3 CPL owns 3,861 MW of coal- and gas-fired generating capacity. As of July 24, 2001, Standard & Poor's rating of CPL's senior unsecured indebtedness was BBB+ while Moody's was Baa1. CSP is a corporation organized and existing under the laws of the state of Ohio, and has its principal office in Columbus, Ohio. CSP is a wholly owned subsidiary of AEP and is a public utility under the 1935 Act. CSP is engaged in generating, transmitting and distributing electric energy to the public in central and southern Ohio. CSP owns 2,595 MW of coal-fired generating capacity which includes 1,330 MW in generating facilities jointly owned with two unaffiliated utilities. CSP serves approximately 658,000 retail customers in Ohio. CSP also sells electricity to wholesale customers. As of July 24, 2001, Standard & Poor's rating of CSP's senior unsecured indebtedness was BBB+ while Moody's was A3. OPCo is a corporation organized and existing under the laws of the state of Ohio, and has its principal office in Canton, Ohio. OPCo is a wholly owned subsidiary of AEP and is a public utility under the 1935 Act. OPCo is engaged in generating, transmitting and distributing electric energy to the public in northwestern, east central, eastern and southern Ohio. OPCo owns 8,464 MW of coal-fired generating capacity and 48 MW of hydroelectric generating capacity. OPCo serves approximately 679,000 retail customers in Ohio. OPCo also sells electricity to wholesale customers. As of July 24, 2001, Standard & Poor's rating of OPCo's senior unsecured indebtedness was BBB+ while Moody's was A3. SWEPCO is a corporation organized and existing under the laws of the state of Delaware, and has its principal office in Shreveport, Louisiana. SWEPCO is a wholly owned subsidiary of CSW, and an indirect subsidiary of AEP and is a public utility under the 1935 Act. SWEPCO is engaged in generating, transmitting and distributing electric energy to the public in east Texas, northwestern Louisiana and southwestern Arkansas. SWEPCO owns 4,487 MW of coal- and gas-fired generating capacity. SWEPCO serves approximately 422,000 retail customers. SWEPCO also sells electricity to wholesale customers. As of July 24, 2001, Standard & Poor's rating of SWEPCO's senior unsecured indebtedness was BBB+ while Moody's was A2. WTU is a corporation organized and existing under the laws of the state of Texas, and has its principal office in Abilene, Texas. WTU is a wholly owned subsidiary of CSW, and an indirect subsidiary of AEP and is a public utility under the 1935 Act. 4 WTU is engaged in generating, transmitting and distributing electric energy to the public in western and northern parts of Texas. WTU owns 1,376 MW of coal and gas-fired generating capacity. WTU serves approximately 189,000 retail customers. WTU also sells electricity to wholesale customers. As of July 24, 2001, Standard & Poor's rating of WTU's senior unsecured indebtedness was BBB+ with no corresponding Moody's rating of senior unsecured indebtedness. ENTERPRISES, WHOLESALE HOLDCO AND DOMESTIC HOLDCO. For a variety of tax, regulatory and business reasons, AEP has determined that the best way to organize its non-utility subsidiaries is through the creation of Enterprises. Enterprises will be a first tier subsidiary of AEP. It will own all of Wholesale Holdco. Wholesale Holdco, in turn, will own Domestic Holdco, which will hold, directly or indirectly, the PGCs. Enterprises, Wholesale Holdco and Domestic Holdco will be formed to hold utility and non-utility subsidiaries of AEP whose revenues derive from competitive, usually market-based, activity. This structure allows AEP to align its non-utility enterprises and its non-State regulated electric generating business in an efficient and simple manner. AEP is seeking EWG status for CPL PGC, WTU PGC, their respective subsidiaries, CSP PGC and OPCo PGC. If EWG status is not obtained within twelve months of the date of the anticipated order in this file, Enterprises, Wholesale Holdco and Domestic Holdco will register as holding companies under the 1935 Act. REG HOLDCO. Likewise, for a variety of tax, regulatory and business reasons, AEP has determined that it wishes to retain another intermediate holding company - Reg Holdco - in its corporate organization. This company would hold the EDCs and, in some instances subject to any necessary state approval, other operating utility subsidiaries that are not required to restructure, including the Vertically-Integrated Companies. Reg Holdco is a holding company and will remain a registered company following the Transaction. C. OVERVIEW OF THE PROPOSED RESTRUCTURING The assets involved in the Transfers are generating facilities, the step-up transformers, circuit breakers, interconnection facilities, related facilities and other assets associated with generating units and their operations that CPL and WTU will transfer to CPL PGC and WTU PGC, respectively, and transmission lines and other transmission facilities and distribution lines and other distribution facilities and other 5 assets that CSP, OPCo and SWEPCO will transfer to CSP EDC, OPCo EDC and SWEPCO EDC, respectively, that will be chartered to own, maintain and operate transmission and distribution facilities located in the states of Ohio and Texas, respectively. Exhibit B-1 to this Application contains diagrams of the pre-Transfer and post-Transfer organizations of Applicants and their relevant affiliates. Exhibit D-7 to this Application contains a list of the generating stations that CPL and WTU will transfer to CPL PGC and WTU PGC, respectively, and a description of the transmission and distribution facilities that CSP, OPCo and SWEPCO will transfer to CSP EDC, OPCo EDC and SWEPCO EDC, respectively. CPL, SWEPCO and WTU will make their Transfers to comply with the provisions of a Texas statute commonly referred to as S.B. 7.(2) S.B. 7 requires vertically integrated electric utilities to separate ownership of their generating and other power supply assets from ownership of their transmission and distribution assets no later than January 1, 2002. Under S.B. 7, vertically integrated utilities are generally obligated to disaggregate into at least three separate corporate units: (1) a PGC that will sell power and energy at wholesale; (2) an EDC that will own transmission and local distribution facilities and perform metering functions, but is prohibited from owning power supply facilities or selling electricity; and (3) a REP that will sell electricity to retail customers. By order issued July 7, 2000, the PUCT approved corporate separation plans CPL, WTU and SWEPCO filed to explain how they will comply with S.B. 7 (see Exhibit D-2 to this Application). Per PUCT Substantive Rule 25.342(d)(4), all transfers made in compliance with S.B. 7 must be recorded at book value. CSP and OPCo will make their Transfers to comply with the provisions of an Ohio statute that provides for Competitive Retail Electric Service, commonly referred to as S.B. 3.3 The statute directs vertically integrated electric utilities that offer retail electric service in Ohio to separate their generating and other competitive operations (such as aggregation, marketing, and brokering) and related assets from their transmission and distribution operations and assets. On September 28, 2000, the PUCO approved corporate separation plans CSP and OPCo filed to explain how they will comply with S.B.(3) ---------- (2) Tex. Util. Code Ann.ss.39.001-909 (Vernon Supp. 2000). (3) Ohio Rev. Code Ann.ss.ss.4928.01-67 (Anderson 2000). 6 (see Exhibit D-4 to this Application). Under their approved corporate separation plans (which plans assume that all transfers will be made at book value), CSP and OPCo proposed, subject to receipt of federal regulatory approvals, to transfer their transmission and distribution assets and operations to EDC affiliates. 1. REORGANIZATION OF THE TEXAS OPERATING COMPANIES To comply with S.B. 7, each of CPL and WTU will contribute their generating assets to newly formed PGC affiliates, WTU PGC and CPL PGC.(4) Subsequently, CPL EDC and WTU EDC will dividend the common stock of, or limited liability interest in, CPL PGC and WTU PGC to Reg Holdco, which, in turn, will dividend the stock or limited liability interest to AEP.(5) In turn, AEP will contribute such common stock or limited liability interest to Enterprises, which will contribute such common stock or limited liability interest to Wholesale Holdco, which will contribute such common stock or limited liability interest to Domestic Holdco. AEP is seeking state consent for EWG status for CPL PGC and WTU PGC including their respective subsidiaries as more fully described below.(6) ---------- (4) CPL has committed to divest by June 2002 its Lon Hill Units 1-4, which have an aggregate generating capability of 546 MW, its Nueces Bay plant, which has a generating capability of 559 MW, and its Joslin Unit 1, which has a generating capability of 249 MW, subject to certain recall rights with respect to CPL's obligation to serve retail customers in ERCOT. CPL made this commitment in connection with the PUCT proceedings brought to consider the merger of CSW and AEP. AEP is seeking EWG status for the entity owning these units. In the event EWG status is not obtained in time, divestiture of such generating capability to third parties is sought from the Commission pursuant to Section 12(d) of the 1935 Act. (5) CPL and WTU may delay the transfer of their stock in CPL PGC and WTU PGC until sometime after June 15, 2002, in order to avoid adverse tax consequences relating to intra-corporate transfers after a merger. (6) In addition to the foregoing affiliate transfers, CPL, SWEPCO and WTU seek authority to sell certain utility assets to non-affiliates as required by Section 39.051 of S.B. 7 which states "On or before September 1, 2000, each electric utility shall separate from its regulated utility activities its customer energy services business activities that are otherwise also already widely available in the competitive market". In accordance with this Section, PUCT developed and adopted PUCT Substantive Rule 25.341(6) which prohibits regulated utilities from providing certain facilities and/or services that the PUCT believes to be generally available in the open market. The prohibited facilities and/or services identified in the Rule are classified as "competitive energy services" and consist of nonroadway lights, distribution facilities including distribution transformers, conductors, and associated distribution equipment beyond the customer's primary metering point and substation facilities dedicated to serving individual customers. 7 SWEPCO will retain title to its generating assets because it provides bundled retail electric service in Louisiana, which to date has not adopted retail competition legislation, and in Arkansas, where SWEPCO is not obligated to separate ownership of its generating assets from its transmission and distribution assets.(7) In order to comply with S.B. 7, however, on or before January 1, 2002 (or such later date as determined by the PUCT), SWEPCO will contribute its transmission and distribution assets located in Texas and related business operations to a wholly owned EDC subsidiary, SWEPCO EDC. CPL EDC and WTU EDC will retain their respective transmission and distribution assets and after transfer of their generating assets to CPL PGC and WTU PGC, CPL EDC and WTU EDC will operate as EDCs. On September 25, 2001, AEP announced that it had filed a request with the PUCT to delay implementation of competition from January 1, 2002 until March 31, 2003 in those portions of the state that lie in the Southwest Power Pool. The request was made to allow adequate time for infrastructure, processes and procedures to be in place for fair competition. If granted, the delay would effect all of SWEPCO's service territory in Texas and a small portion of WTU's service territory. As illustrated by the post-Transfer organization chart in Exhibit B-1, Reg Holdco will also hold the common stock of certain other regulated utility subsidiaries of AEP, subject to any required state approval. ---------- CPL, SWEPCO and WTU have offered their customers the option to (i) purchase such facilities from the utility; (ii) provide their own facilities; or (iii) convert their service to secondary metering. Should the customer elect to purchase the affected facilities, CPL, SWEPCO and WTU request authority to sell the affected assets, the proceeds of which could total up to $30 million. By order of the PUCT, the price for purchased facilities agreed to prior to October 1, 2001 will be based on the original market cost at the time the facility was placed in service adjusted for depreciation and undepreciated contributions in aid to construction ("CIAC") multiplied times 1.10; provided that the total cost of the facility will not exceed original market cost adjusted for depreciation and undepreciated CIAC plus $15,000. After October 1, the price for purchased facilities will be based on reproduction cost less depreciation. The actual purchase does not have to be completed until January 1, 2004. The purchase price for nonroadway lighting facilities must be 50% of their replacement cost as mandated by the PUCT. (7) The Arkansas legislature recently postponed the start of retail electric competition in Arkansas to a date no earlier than October 1, 2003 and no later than October 1, 2005. 8 As a part of the Texas retail access program, the Texas retail rates of CPL, WTU and SWEPCO are frozen until December 31, 2001. On and after January 1, 2002, bundled Texas retail residential and small commercial customers formerly served by CPL, WTU and SWEPCO will be served by REPs at the "price to beat" established for their respective Texas service areas. 2. REORGANIZATION OF THE OHIO OPERATING COMPANIES To comply with S.B. 3, CSP and OPCo will contribute their transmission and distribution assets to CSP EDC and OPCo EDC, respectively. The common stock of, or limited liability interest in, OPCo EDC and CSP EDC will be dividended to AEP. AEP, in turn, will contribute such common stock or limited liability interest to Reg Holdco. Surviving CSP PGC and OPCo PGC will be PGCs whose common stock AEP will contribute to Enterprises, which will contribute such common stock to Wholesale Holdco, which will contribute such common stock to Domestic Holdco. AEP is seeking state consent for EWG status for CSP PGC and OPCo PGC. Under S.B. 3, CSP EDC and OPCo EDC must serve as default suppliers to residential customers that do not choose an alternative power supplier. The retail rates for power supply that OPCo EDC and CSP EDC will charge Ohio retail residential customers that do not choose an alternative supplier will be frozen for the first five years of retail competition, unless the PUCO finds that effective competition with respect to particular customer classes is occurring before the end of a five-year market development period. D. OVERVIEW OF REQUESTED AUTHORIZATIONS 1. THE TRANSACTION AEP's corporate separation is designed to align the company's legal structure and business activities with the realities of a restructuring electric industry. Corporate separation responds to the changing laws, regulations and business requirements of the electric industry. AEP's realigned corporate legal structure complies with restructuring statutory and regulatory requirements and provides greater flexibility to conduct business. This realignment consists of actual legal corporate separation of certain subsidiaries and companies of AEP and is not a functional reorganization of those entities. See Exhibit B-1 (the post-Transfer corporate structure chart) 9 for a complete diagram of the final corporate structure sought by Applicants. (a) Formation and Capitalization of Enterprises, Wholesale Holdco and Domestic Holdco AEP seeks authorization to form and capitalize Enterprises, a first tier wholly owned corporation or limited liability company, Wholesale Holdco (a wholly-owned subsidiary corporation or limited liability company of Enterprises) and Domestic Holdco (a wholly-owned subsidiary corporation or limited liability company of Wholesale Holdco). AEP, Enterprises and Wholesale Holdco, respectively, propose to make an initial capital contribution to Enterprises, Wholesale Holdco and Domestic Holdco, respectively, in an amount to be determined, in exchange for all of the common stock of, or limited liability interest in, Enterprises, Wholesale Holdco and Domestic Holdco, respectively. AEP, Enterprises and Wholesale Holdco, respectively, seek authorization for Enterprises, Wholesale Holdco and Domestic Holdco to issue, and for AEP, Enterprises and Wholesale Holdco, respectively, to acquire, all of the common stock of, or limited liability interest in, Enterprises, Wholesale Holdco and Domestic Holdco, respectively. (b) Formation of Texas PGCs and Tax Beneficial Entities AEP seeks approval for: (1) CPL to form and capitalize CPL PGC for the purpose of holding the generation assets and related liabilities of CPL; (2) WTU to form and capitalize WTU PGC for the purpose of holding the generation assets and related liabilities of WTU; (3) CPL PGC to form and capitalize CPL PGC LLC, which would serve as the general partner of CPL PGC LP; (4) CPL PGC and CPL PGC LLC to form and capitalize CPL PGC LP for the purpose of holding the generation assets and related liabilities of CPL PGC; (5) WTU PGC to form and capitalize WTU PGC LLC, which would serve as the general partner of WTU PGC LP; and (6) WTU PGC and WTU PGC LLC to form and capitalize WTU PGC LP for the purpose of holding the generation assets and related liabilities of WTU PGC. 10 (c) Formation of EDC Subsidiaries AEP seeks approval for: (1) OPCo to form and capitalize OPCo EDC for the purpose of holding the transmission and distribution assets and related liabilities of OPCo; (2) CSP to form and capitalize CSP EDC for the purpose of holding the transmission and distribution assets and related liabilities of CSP; and (3) SWEPCO to form and capitalize SWEPCO EDC for the purpose of holding the Texas-based transmission and distribution assets and related liabilities of SWEPCO. (d) Capitalization of Subsidiaries (i) AEP seeks approval for CPL to acquire all of the common stock of, or limited liability interest in, CPL PGC in exchange for transferring its generation assets (including its interest in STP) and related liabilities to CPL PGC and for CPL PGC to issue, and for CPL to acquire, all of the common stock of, or limited liability interest in, CPL PGC. (ii) AEP seeks approval for CPL PGC to acquire all of the membership interests of CPL PGC LLC in exchange for sufficient capitalization for CPL PGC LLC to act as general partner of CPL PGC LP and for CPL PGC LLC to issue, and for CPL PGC to acquire, all of the membership interests of CPL PGC LLC. (iii) AEP seeks approval for CPL PGC to acquire all of the limited partnership interest of CPL PGC LP in exchange for transferring its generation assets and related liabilities to CPL PGC LP, for CPL PGC LLC to acquire the general partnership interest of CPL PGC LP, for CPL PGC LP to issue, and for CPL PGC to acquire, all of the limited partnership interest of CPL PGC LP and for CPL PGC LP to issue, and for CPL PGC LLC to acquire, the general partnership interest of CPL PGC LP. (iv) AEP seeks approval for WTU to acquire all of the common stock of, or limited liability interest in, WTU PGC in exchange for transferring its generation assets and related liabilities to WTU PGC and for WTU PGC to issue, and for WTU to acquire, all 11 of the common stock of, or limited liability interest in, WTU PGC. (v) AEP seeks approval for WTU PGC to acquire all of the membership interests of WTU PGC LLC in exchange for sufficient capitalization for WTU PGC LLC to act as general partner of WTU PGC LP and for WTU PGC LLC to issue, and for WTU PGC to acquire, all of the membership interests of WTU PGC LLC. (vi) AEP seeks approval for WTU PGC to acquire all of the limited partnership interest of WTU PGC LP in exchange for transferring its generation assets and related liabilities to WTU PGC LP, for WTU PGC LLC to acquire the general partnership interest of WTU PGC LP, for WTU PGC LP to issue, and for WTU PGC to acquire, all of the limited partnership interest of WTU PGC LP and for WTU PGC LP to issue, and for WTU PGC LLC to acquire, the general partnership interest of WTU PGC LP. (vii) AEP seeks approval for OPCo to acquire all of the common stock of, or limited liability interest in, OPCo EDC in exchange for transferring its transmission and distribution assets and related liabilities to OPCo EDC and for OPCo EDC to issue, and for OPCo to acquire, all of the common stock of, or limited liability interest in, OPCo EDC. (viii) AEP seeks approval for CSP to acquire all of the common stock of, or limited liability interest in, CSP EDC in exchange for transferring its transmission and distribution assets and related liabilities to CSP EDC and for CSP EDC to issue, and for CSP to acquire, all of the common stock of, or limited liability interest in, CSP EDC. (e) Transfers (i) AEP seeks approval for CPL to transfer or contribute a total of 100% of its ownership interests in its generation assets (estimated net book value at December 31, 2000, $2,366.3 million) and related liabilities (estimated book value at December 31, 2000, $1,980.1 million) to CPL PGC at their net book value at the transfer date and for CPL PGC to transfer or contribute a total of 100% of its 12 ownership interests in such generation assets and related liabilities to CPL PGC LP at the same book value. (ii) AEP seeks approval for WTU to transfer or contribute a total of 100% of its ownership interests in its generation assets (estimated net book value at December 31, 2000, $484.1 million) and related liabilities (estimated book value at December 31, 2000, $333.4 million) to WTU PGC at their net book value at the transfer date and for WTU PGC to transfer or contribute a total of 100% of its ownership interests in such generation assets and related liabilities to WTU PGC LP at the same book value. (iii) AEP seeks approval for OPCo to transfer or contribute a total of 100% of its ownership interests in its transmission and distribution assets (estimated net book value at December 31, 2000, $2,231.5 million) and related liabilities (estimated book value at December 31, 2000, $536.6 million) to OPCo EDC at their book value at the transfer date. (iv) AEP seeks approval for CSP to transfer or contribute a total of 100% of its ownership interests in its transmission and distribution assets (estimated net book value at December 31, 2000, $1,440.4 million) and related liabilities (estimated book value at December 31, 2000, $424.8 million) to CSP EDC at their book value at the transfer date. (v) AEP seeks approval for SWEPCO to transfer or contribute a total of 100% of its ownership interests in its Texas transmission and distribution assets (estimated net book value as of December 31, 2000, $631.6 million) and related liabilities (estimated book value at December 31, 2000, $174.0 million) to SWEPCO EDC at their book value at the transfer date. (vi) After the transfers are executed, AEP seeks approval for: o CPL EDC to dividend CPL PGC's common stock or limited liability interest to CSW, which will dividend the stock to AEP, which will 13 contribute the stock to Enterprises, which will contribute the stock or limited liability interest to Wholesale Holdco, which will contribute the stock or limited liability interest to Domestic Holdco. o WTU EDC to dividend WTU PGC's common stock or limited liability interest to CSW, which will dividend the stock to AEP, which will contribute the stock or limited liability interest to Enterprises, which will contribute the stock or limited liability interest to Wholesale Holdco, which will contribute the stock to Domestic Holdco. o OPCo PGC to dividend OPCo EDC's common stock or limited liability interest to AEP, which will contribute the stock or limited liability interest to Reg Holdco. o CSP PGC to dividend CSP EDC's common stock or limited liability interest to AEP, which will contribute the stock or limited liability interest to Reg Holdco. o SWEPCO to dividend the common stock or limited liability interest of SWEPCO EDC to CSW. (vii) Upon completion of the Transaction, Reg Holdco will hold CPL EDC, WTU EDC, SWEPCO, SWEPCO EDC, OPCo EDC and CSP EDC, each of which will own transmission and distribution assets and related liabilities (other than SWEPCO which will continue to be a vertically integrated utility with respect to its assets located outside of Texas.) Domestic Holdco will hold, among other things, CPL PGC, WTU PGC, OPCo PGC and CSP PGC, each of which will own, directly or indirectly, generation assets and related liabilities and, upon all necessary state and federal regulatory approval, will be EWGs. (viii) Subject to any required state approval, AEP seeks authorization to contribute the stock of the Vertically-Integrated Companies to Reg Holdco and for Reg Holdco to acquire the stock of the Vertically-Integrated Companies. 14 AEP proposes to restructure its non-utility holdings (including utility holdings that are no longer subject to state regulation) from time to time as may be necessary or appropriate in the furtherance of its authorized non-utility activities. The restructuring could involve the acquisition of one or more new special-purpose subsidiaries to acquire and hold direct or indirect interests in any or all of AEP's existing or future authorized non-utility businesses. The restructuring could also involve the creation, capitalization and acquisition of a subsidiary to hold the non-utility interests, the transfer of existing subsidiaries, or portions of existing businesses, among AEP associates and/or the reincorporation of existing subsidiaries in a different state. This authority would enable AEP to consolidate similar businesses and to participate effectively in authorized non-utility activities, without the need to apply for or receive additional Commission approval.(8) 2. AGREEMENTS (a) Authorization is requested for AEPSC to render services to any direct or indirect subsidiary of any Applicant to be formed as permitted in this file, pursuant to the existing AEP Service Agreement. All services will be performed in adherence with the 'at cost' provisions of Rules 90 and 91 under the 1935 Act. (b) AEP may establish a specialized service company for dispatch, wholesale trading, and fuel procurement of the generation assets not subject to state regulation and/or other energy-related services ("GenServCo"). The GenServCo will pay the salaries of its employees and be responsible for the administration of all employee benefit plans. Affiliate companies will reimburse GenServCo for its expenses on a full cost basis in accordance with the requirements imposed by Section 13 of the 1935 Act and the Rules promulgated thereunder. AEP will provide information regarding such a service company by pre- or post-effective amendment hereto which will include a services agreement. (c) In order to comply with S.B. 7, a division of AEPSC may be established to meet Texas code of conduct concerns which in general prohibit PGCs and EDCs in that state from sharing the services of a single service ---------- (8) Similar authority was granted to Columbia and other registered holding companies. SEE Columbia Energy Group, HCAR No. 27099 (Nov. 5, 1999). 15 provider with respect to engineering, purchasing of electric transmission, transmission and distribution system operations and marketing services. If created, this division would perform some but not all of the services contemplated in the existing AEP Service Agreement and would function pursuant to a service agreement substantially the same as the existing AEP Service Agreement and pursuant to the allocation methods approved for AEPSC. (d) Authorization is requested for the time period following receipt of respective state regulatory approval of relevant portions of the Transaction but prior to the Transaction for the Operating Companies to enter into Operating Agreements with the respective Subsidiaries for the purpose of allowing the Operating Companies to operate the respective utility and related assets of the Subsidiaries. These agreements may be necessary to transfer control of such assets before assets can be transferred because of mortgage or financial restrictions or delays in obtaining assignments of environmental permits or other regulatory approvals. 3. SERVICES, GOODS AND ASSETS INVOLVING THE UTILITY OPERATING COMPANIES The Utility Subsidiaries and Vertically-Integrated Companies may provide to one another and other associate companies services incidental to their utility businesses, including but not limited to, infrastructure services, maintenance, storm outage emergency repairs, and services of personnel with specialized expertise related to the operation of the utility. These services will be provided in accordance with Rules 87, 90, and 91. Moreover, in accordance with Rules 87, 90, and 91, certain goods may be provided through a leasing arrangement or otherwise by one Utility Subsidiary to one or more associate companies, and certain assets may be used by one Utility Subsidiary for the benefit of one or more other associate companies. Because these services will be provided and goods transferred in accordance with applicable rules, no relief is sought from the Commission regarding these services. Although CPL PGC, CPL PGC LP, WTU PGC, WTU PGC LP, CSP PGC and OPCo PGC each will be a "public-utility company" until AEP obtains EWG status for such companies, none is subject to State rate regulation or will have "captive" customers. 16 E. FINANCING PLAN 1. OVERVIEW OF THE FINANCING REQUEST The Applicants hereby request authorization to engage in the financing transactions set forth herein through June 30, 2005 (the "Authorization Period"). The approval by the Commission of this Application will give the Applicants the flexibility that will allow them to respond quickly and efficiently to their financing needs and to changes in market conditions, allowing them to efficiently and effectively carry on competitive business activities designed to provide benefits to customers and shareholders. The financing authorizations requested herein relate to: (a) issuances by AEP of guarantees of obligations of affiliated or unaffiliated persons in favor of other unaffiliated persons and the acquisition of the securities of the Holding Companies; (b) issuances of securities and guarantees, the entering into of transactions to manage interest rate risk ("hedging transactions")(9) and the acquisition of the securities of the Unregulated Subsidiaries by the Unregulated Holding Companies; (c) issuances of securities and guarantees and the entering into of hedging transactions by the Unregulated Subsidiaries to the extent not exempt pursuant to Rule 52 (although each Unregulated Subsidiary will be an "electric utility company" under the 1935 Act, none will be subject to the jurisdiction of any State commission in connection with the issuance of securities - therefore, all securities issuances for the Unregulated Subsidiaries will require approval of the Commission until EWG status is obtained); ---------- (9) "Hedging Transactions" include only those transactions related to financing activities. Engaging in futures and other commodity related risk management by AEP and its subsidiaries constitute part of their normal business activities and as such do not require Commission approval. SEE Southern Energy, Inc., HCAR No. 27020 (May 13, 1999); Entergy Corp., HCAR No. 26812 (Jan. 6, 1998); New Century Energies, HCAR No. 26748 (Aug. 1, 1997); National Fuel Gas Co., HCAR No. 26667 (Feb. 12, 1997). 17 (d) issuances of securities and guarantees, the entering into of hedging transactions and the acquisition of the securities of the Regulated Subsidiaries by Reg Holdco to the extent not exempt pursuant to Rules 52 and 45; (e) issuances of securities and guarantees and the participation in the AEP Money Pool and the entering into of hedging transactions by the Regulated Subsidiaries to the extent not exempt pursuant to Rule 52; (f) the ability of AEP and its subsidiaries to pay dividends out of capital or unearned surplus; (g) the formation of financing entities and the issuance by such entities of securities otherwise authorized to be issued and sold pursuant to this Application or pursuant to applicable exemptions under the 1935 Act, including intra-system guarantees of such securities; and (h) To the extent the conversion of the PGC affiliates from "public-utility companies" to EWGs counts as "aggregate investment" in EWGs for purposes of Rule 53, obtaining authorization to 'invest' (pursuant to the transactions described herein, including the financings and guarantees) in the PGC affiliate EWGs up to the aggregate estimated net book value of the Restructured Generation Assets (approximately $9,425 million as of December 31, 2000). 2. PARAMETERS FOR FINANCING AND HEDGING TRANSACTION AUTHORIZATION Authorization is requested herein to engage in certain financing transactions during the Authorization Period for which the specific terms and conditions are not at this time known, and which may not be covered by Rule 52, without further prior approval by the Commission. The following general terms will be applicable where appropriate to the financing transactions requested to be authorized hereby: (a) Effective Cost of Money The effective cost of money on long-term debt borrowings occurring pursuant to the authorizations granted under this Application will not exceed the greater of (i) 18 500 basis points over the comparable term U.S. Treasury securities or (ii) a gross spread over U.S. Treasuries that is consistent with similar securities of comparable credit quality and maturities issued by other companies.(10) The effective cost of money on short-term debt borrowings pursuant to authorizations granted under this Application will not exceed the greater of (i) 350 basis points over the comparable term London Interbank Offered Rate ("LIBOR") or (ii) a gross spread over LIBOR that is consistent with similar securities of comparable credit quality and maturities issued by other companies. The dividend rate on any series of preferred securities will not exceed the greater of (a) 700 basis points over the yield to maturity of a U.S. Treasury security having a remaining term equal to the term of such series of preferred securities or (b) a rate that is consistent with similar securities of comparable credit quality and maturities issued by other companies. (b) Maturity of Debt and Final Redemption on Preferred Securities The maturity of indebtedness will not exceed 50 years. All preferred securities will be redeemed no later than 50 years after the issuance thereof. (c) Issuance Expenses The underwriting fees, commissions or other similar remuneration paid in connection with the non-competitive issue, sale or distribution of a security pursuant to this Application (not including any original issue discount) will not exceed 5% of the principal or total amount of the security being issued. (d) Use of Proceeds The proceeds from the sale of securities in external financing transactions will be used for general corporate purposes including: o the financing, in part, of the capital expenditures of the AEP System; ---------- (10) SEE The Southern Company, HCAR No. 27134 (Feb. 9, 2000). 19 o the financing of working capital requirements of the AEP System; o the acquisition, retirement or redemption pursuant to Rule 42 of securities previously issued by AEP subsidiaries without the need for prior Commission approval; and o other lawful purposes, and, for the Unregulated Holding Companies, the direct or indirect investment in companies authorized by prior Order of this Commission, Rule 58 companies, other subsidiaries approved by the Commission, EWGs, FUCOs and ETCs.(11) The Applicants represent that no such financing proceeds will be used to acquire or form a new subsidiary unless such financing is consummated in accordance with an order of the Commission or an available exemption under the 1935 Act. Direct or indirect investments by AEP in Rule 58 Subsidiaries would be subject to the limitations of Rule 58. (e) Financial Condition The Operating Companies are financially sound and each have investment grade ratings from major national rating agencies as indicated in Item 1.B. The business of the Unregulated Unit will be conducted by companies that will also be financially sound.(12) Furthermore, AEP has an investment grade rating (a senior unsecured debt rating of BBB+ from Standard & Poor's and Baa1 from Moody's). The consolidated common equity of AEP was 33.5% of total Consolidated Capitalization (common equity, preferred stock ---------- (11) AEP will make additional investments in EWGs and FUCOs during the Authorization Period. Accordingly, Rules 53 and 54 apply to this Application. Compliance with these rules is addressed below. (12) As a newly formed group, companies in the Unregulated Unit may not have a rating from nationally recognized rating agencies immediately when it commences operations. As noted herein, the absence of an investment grade rating will likely increase the necessity for the Unregulated Unit to receive financial support from AEP. 20 and long-term and short-term debt, including current maturities of long-term debt) as of June 30, 2001.(13) AEP commits that (a) its common equity (as reflected on the balance sheets contained in its most recent 10-K or 10-Q filed with the Commission pursuant to the 1934 Act) will be at least 30% of its Consolidated Capitalization and (b) it will maintain at least an investment grade corporate or senior unsecured debt rating by at least one nationally recognized rating agency. Further, the Utility Subsidiaries commit that each will maintain common equity of at least 30% of its capitalization (calculated in the same manner provided, however, that CPL may exclude securitization debt from the calculation of indebtedness and total capitalization)(14) and at least an investment grade rating by one nationally recognized rating agency. The consequences of failing to maintain an investment grade rating or common equity of at least 30% of Consolidated Capitalization when required is that such company would require additional Commission approval to issue securities except for securities which would result in an increase in such common equity percentage or restoration of such rating. ---------- (13) See footnote 14 below for the reasons it is appropriate to consider the special status of securitization debt for purposes of consideration of the financial condition of AEP and its Utility Subsidiaries. (14) The Commission has recognized that it is appropriate to consider securitization debt in the calculation of capitalization to determine compliance with its traditional test of a minimum equity component of capitalization of 30%. SEE West Penn Power Co., HCAR No. 27091 (Oct. 19, 1999) (exemption from 30% equity standard granted where utility's equity ratio was 15% because of transition bonds and other factors; excluding transition bonds, utility would satisfy 30% test). This approach is consistent with the rating agencies analysis of the impact of securitization on a utility's capital structure. AEP anticipates that the outstanding securitization bonds of any subsidiary will be rated "AAA." The structure of these financings, the orders of the respective State commissions and the statutory provisions of each State ensure that there will be sufficient cash flow from a dedicated portion of payments made by utility customers to at all times provide for principal and interest on the securitization bonds. The rates paid by customers are subject to adjustment in accordance with procedures of the respective states to ensure that amounts collected are sufficient to meet debt service and other requirements under the securitization financings. SEE Utility Stranded Costs: Rating the Securitization of Transition Tariffs, Special Report, FitchIBCA (September 24, 1998) (available at www.FitchIBCA.com). 21 (f) Hedging Transactions Interest rate hedging transactions with respect to existing indebtedness ("Interest Rate Hedges"), subject to certain limitations and restrictions, would be entered into in order to reduce or manage interest rate cost or risk. Interest Rate Hedges would only be entered into with counterparties ("Approved Counterparties") whose senior debt ratings, or whose parent companies' senior debt ratings, as published by Standard and Poor's Ratings Group, are equal to or greater than BBB, or an equivalent rating from Moody's Investors' Service or Fitch Investor Service. Interest Rate Hedges will involve the use of financial instruments and derivatives commonly used in today's capital markets, such as interest rate swaps, options, caps, collars, floors, and structured notes (i.e., a debt instrument in which the principal and/or interest payments are indirectly linked to the value of an underlying asset or index), or transactions involving the purchase or sale, including short sales, of U.S. Treasury obligations. The transactions would be for fixed periods and stated notional amounts. In no case will the notional principal amount of any interest rate swap exceed that of the underlying debt instrument and related interest rate exposure. Applicants will not engage in speculative transactions. Fees, commissions and other amounts payable to the counterparty or exchange (excluding, however, the swap or option payments) in connection with an Interest Rate Hedge will not exceed those generally obtainable in competitive markets for parties of comparable credit quality. In addition, interest rate hedging transactions with respect to anticipated debt offerings (the "Anticipatory Hedges"), subject to certain limitations and restrictions would only be entered into with Approved Counterparties, and would be utilized to fix and/or limit the interest rate risk associated with any new issuance through (i) a forward sale of exchange-traded U.S. Treasury futures contracts, U.S. Treasury obligations and/or a forward swap (each a "Forward Sale"); (ii) the purchase of put options on U.S. Treasury obligations (a "Put Options Purchase"); (iii) a Put Options Purchase in combination with the sale of call options on U.S. Treasury obligations (a "Zero Cost Collar"); (iv) transactions involving the purchase or sale, including short sales, of U.S. Treasury obligations; or (v) some combination of a Forward Sale, Put 22 Options Purchase, Zero Cost Collar and/or other derivative or cash transactions, including, but not limited to structured notes, options, caps and collars, appropriate for the Anticipatory Hedges. Anticipatory Hedges may be executed on-exchange ("On-Exchange Trades") with brokers through the opening of futures and/or options positions traded on the Chicago Board of Trade or the Chicago Mercantile Exchange, the opening of over-the-counter positions with one or more counterparties ("Off-Exchange Trades"), or a combination of On-Exchange Trades and Off-Exchange Trades. Each Applicant will determine the optimal structure of each Anticipatory Hedge transaction at the time of execution. Applicants may decide to lock in interest rates and/or limit its exposure to interest rate increases. Applicants represent that each Interest Rate Hedge and Anticipatory Hedge will be treated for accounting purposes under generally accepted accounting principles. Applicants will comply with the then existing financial disclosure requirements of the Financial Accounting Standards Board associated with hedging transactions.(15) 3. AEP GUARANTEES, INTRA-SYSTEM ADVANCES AND EWG INVESTMENT (a) Guarantees AEP requests authorization to enter into guarantees, obtain letters of credit, enter into support or expense agreements or otherwise provide credit support with respect to the obligations of the Finance Applicants as may be appropriate or necessary to enable such Finance Applicant to carry on in the ordinary course of its respective business in an aggregate principal amount, and to enter into guarantees of non-affiliated third parties obligations in the ordinary course of AEP's business ("AEP Guarantees") in an amount not to exceed $15.0 billion outstanding at any one time (not taking into account obligations exempt pursuant to Rule 45). Any such guarantees shall also be subject to the limitations of Rule 58(a)(1) or the Rule 53 limitation then in effect for AEP, as applicable. Each guarantor proposes to charge each ---------- (15) The proposed terms and conditions of the Interest Rate Hedges and Anticipatory Hedges are substantially the same as the Commission has approved in other cases. SEE Entergy Corporation, HCAR No. 27371 (April 3, 2001); New Century Energies, Inc., et al., HCAR No. 27000 (April 7, 1999); and Ameren Corp., et al., HCAR No. 27053 (July 23, 1999). 23 subsidiary a fee for each guarantee provided on its behalf that is comparable to those obtainable by the beneficiary of the guarantee from third parties. A substantial amount of the guarantees proposed to be issued by AEP will be in connection with the Unregulated Unit. As a result of the Transaction, the Unregulated Unit will be a newly formed business consisting of the generating assets of CPL, WTU, CSP and OPCo. The Unregulated Unit will also conduct the power marketing and trading operations previously conducted by CPL, WTU, CSP and OPCo. For various business reasons, AEP may wish to provide credit support in connection with the Unregulated Unit's obligations to independent power producers to purchase the output of generating units, in connection with the trading positions of the Unregulated Unit entered into in the ordinary course of the Unregulated Unit's energy marketing and trading business and for other purposes. AEP may wish to provide guarantees to the Unregulated Unit for reasons that are not unusual in today's increasingly competitive electricity markets. The second reason for the requested level of guarantee authority is that many of the counterparties with whom the Unregulated Unit will buy and sell power may demand that the Unregulated Unit provide credit support, as its credit rating may not be as strong as the present credit ratings of CPL, CSP, OPCo and WTU. The provision of parent guarantees by holding companies to affiliates in the generation and power marketing business is a standard industry practice. Given the substantial volume of the Unregulated Unit's business, AEP's $15.0 billion request for authority to issue guarantees, including the guarantees relating to the Unregulated Unit, is reasonable and appropriate under current industry practice. AEP expects the Unregulated Unit to grow quickly and obtain its own investment grade rating soon after the Restructuring. To the extent the Unregulated Unit has such a rating, the need for support from AEP will likely be reduced. However, in that situation, the Unregulated Unit will likely be required to offer its guarantee in connection with the business activities of its subsidiaries through which AEP's generation business will be developed. 24 Certain of the guarantees referred to above may be in support of the obligations of subsidiaries which are not capable of exact quantification. In such cases, AEP will determine the exposure under such guarantee for purposes of measuring compliance with the $15.0 billion limitation by appropriate means including estimation of exposure based on loss experience or projected potential payment amounts. If appropriate, such estimates will be made in accordance with generally accepted accounting principles. Such estimation will be reevaluated periodically. AEP requests that this guarantee authority include the ability to guarantee debt. The debt guaranteed will comply with the parameters set forth in this Section E. Any guarantees or other credit support arrangements outstanding at the end of the Authorization Period will continue until expiration or termination in accordance with their terms. The aggregate amount of the guarantees issued by AEP for the purpose of funding any direct or indirect investment in an EWG or FUCO would not, when added to AEP's "aggregate investment" (as defined in Rule 53(a)(1)) in all such companies, exceed the Rule 53 limitation then in effect for AEP. Direct or indirect investments by AEP in Rule 58 Subsidiaries would be subject to the limitations of Rule 58. (b) Intra-system Advances Authority is sought for AEP to acquire the debt or other securities of the Holding Companies for the purpose of lending to them. All such intra-company conduit financing transactions shall comply with the "at cost" requirements of Rules 45 and 52. (c) EWG Investment As noted above, AEP is seeking EWG status for the PGC affiliates that will own the Restructured Generation Assets. Immediately following the Transaction, the PGC affiliates will be "public-utility companies" under the 1935 Act. Once EWG status is obtained, each PGC affiliate will be an EWG and the Restructured Generation Assets owned 25 by each will be "eligible facilities" under the 1935 Act. To the extent the conversion of the PGC affiliates from "public-utility companies" to EWGs counts as "aggregate investment" in EWGs for purposes of Rule 53, AEP seeks authorization to 'invest' (pursuant to the transactions described herein, including the financings and guarantees) in the PGC affiliate EWGs up to the aggregate estimated net book value of the Restructured Generation Assets (approximately $9,425 million as of December 31, 2000). No new financing is associated with the obtaining of EWG status for the PGC affiliates. AEP respectfully submits that the obtaining of EWG status by the PGC affiliates, when it occurs, is a purely legal distinction under the 1935 Act and is without economic effect on the capitalization or retained earnings of the AEP system or its financial condition. In point of fact, AEP respectfully suggests that the application of Rule 53 to an internal reorganization/restructuring transaction in which generation assets are simply being moved from one subsidiary to another was not the kind of transaction at which Rule 53 was targeted. To the extent, however, that staff deems the conversion of the PGC affiliates from "public-utility companies" to EWGs counts as "aggregate investment" in EWGs for purposes of Rule 53, AEP will require the authority to 'invest' (pursuant to the transactions described herein, including the financings and guarantees) in the PGC affiliate EWGs up to the aggregate estimated net book value of the Restructured Generation Assets. The authority requested herein is essential if AEP is to successfully adapt to the state-law mandated restructuring described in this file and which materially impacts significant portions of its regulated utility operations. AEP must obtain sufficient investment flexibility under the 1935 Act to obtain EWG status for the PGCs owning the Restructured Generation Assets. For the foregoing reasons, AEP hereby requests the authorization to 'invest' in EWGs as described above. 4. UNREGULATED HOLDING COMPANIES AUTHORITY (a) Financing Authority Authority is sought for each Unregulated Holding Company to engage in financings and to issue securities to 26 non-affiliated and affiliated entities subject to and in accordance with the parameters set forth in Item E.2, above, in an aggregate principal amount not to exceed $5.0 billion, other than the refunding of outstanding securities, which would not be limited. (b) Guarantee Authority Authority is sought for each Unregulated Holding Company to issue guarantees and extend credit support to any Unregulated Subsidiary, Finance Subsidiary, as defined below, owned by it or any other Unregulated Holding Company subject to and in accordance with the parameters set forth in Item E.3.(a), above, in an aggregate amount not to exceed $10.0 billion, exclusive of any guarantees and other forms of credit support that are exempt pursuant to Rule 45 and Rule 52, provided however, that the amount of guarantees in respect of obligations of any Rule 58 Subsidiaries shall remain subject to the limitations of Rule 58(a)(1). (c) Hedging Transaction Authority Authority is sought for each Unregulated Holding Company to enter into any hedging transaction subject to and in accordance with the parameters set forth in Item E.2, above. (d) Intra-system Advances Authority is sought for each Unregulated Holding Company to acquire the debt or other securities of any Unregulated Subsidiary or other Unregulated Holding Company for the purpose of lending to such Unregulated Subsidiary or other Unregulated Holding Company. All such intra-company conduit financing transactions shall comply with the "at cost" requirements of Rules 45 and 52. 5. UNREGULATED SUBSIDIARIES AUTHORITY (a) Financing Authority Authority is sought for each Unregulated Subsidiary, to the extent not exempt under Rule 52, to engage in financings(16) and to issue securities to non- ---------- (16) CPL PGC is expected to assume the obligations on certain pollution control loan obligations of CPL issued in connection with facilities located at the 27 affiliated and affiliated entities subject to and in accordance with the parameters set forth in Item E.2, above, up to the following principal amounts, other than the refunding of outstanding securities, which would not be limited: CPL PGC, CPL PGC LP, CPL PGC LLC............ 1,000,000,000 CSP PGC..................................... 500,000,000 OPCo PGC.................................... 1,000,000,000 WTU PGC, WTU PGC LP, WTU PGC LLC............ 250,000,000 (b) Guarantee Authority Authority is sought for each Unregulated Subsidiary to issue guarantees and extend credit support to any subsidiary owned by it (including any Finance Subsidiary, as defined below) or to any other Unregulated Subsidiary subject to and in accordance with the parameters set forth in Item E.3.(a), above, in amounts not to exceed the amounts set forth in Item E.5.(a), above, exclusive of any guarantees and other forms of credit support that are exempt pursuant to Rule 45 and Rule 52, provided however, that the amount of guarantees in respect of obligations of any Rule 58 Subsidiaries shall remain subject to the limitations of Rule 58(a)(1). (c) Hedging Transaction Authority Authority is sought for each Unregulated Subsidiary to enter into any hedging transaction subject to and in accordance with the parameters set forth in Item E.2, above. 6. REG HOLDCO AUTHORITY (a) Financing Authority Authority is sought for Reg Holdco to engage in financings and to issue securities to non-affiliated and affiliated entities subject to and in accordance with the parameters set forth in Item E.2, above, in an aggregate principal amount not to exceed $10.0 billion, other than ---------- generating stations to be transferred to CPL PGC from CPL. WTU PGC is expected to assume the obligations on certain pollution control loan obligations of WTU issued in connection with facilities located at the generating stations to be transferred to WTU PGC from WTU. 28 the refunding of outstanding securities, which would not be limited. (b) Guarantee Authority Authority is sought for Reg Holdco to issue guarantees and extend credit support to any Regulated Subsidiary and any Finance Subsidiary, as defined below owned by it subject to and in accordance with the parameters set forth in Item E.3.(a), above, in an aggregate amount not to exceed $10.0 billion. (c) Hedging Transaction Authority Authority is sought for Reg Holdco to enter into any hedging transaction subject to and in accordance with the parameters set forth in Item E.2, above. (d) Intra-system Advances Authority is sought for Reg Holdco to acquire the debt or other securities of any affiliated public utility company (other than the Unregulated Subsidiaries) for the purpose of lending to such affiliate. All such intra-company conduit financing transactions shall comply with the "at cost" requirements of Rules 45 and 52. 7. REGULATED SUBSIDIARIES AUTHORITY (a) Financing Authority Authority is sought for each Regulated Subsidiary, to the extent not exempt under Rule 52, to engage in financings and to issue securities to non-affiliated and affiliated entities subject to and in accordance with the parameters set forth in Item E.2, above, up to the following principal amounts, other than the refunding of outstanding securities, which would not be limited: CPL EDC..................................... 1,000,000,000 CSP EDC..................................... 1,000,000,000 OPCo EDC.................................... 1,250,000,000 SWEPCO EDC.................................. 500,000,000 WTU EDC..................................... 500,000,000 29 (b) Guarantee Authority Authority is sought for each Regulated Subsidiary to issue guarantees and extend credit support to any subsidiary owned by it (including any Finance Subsidiary, as defined below) subject to and in accordance with the parameters set forth in Item E.3.(a), above, in amounts not to exceed the amounts set forth in Item E.7.(a), above. (c) Money Pool Authority AEP currently administers the AEP Money Pool as authorized by AMERICAN ELECTRIC POWER COMPANY, INC. ET AL., HCAR No. 27186 (June 14, 2000) subject to the general authority set forth therein and CENTRAL AND SOUTH WEST CORP., HCAR No. 26697 (March 28, 1997) and CENTRAL AND SOUTH WEST CORP., HCAR No. 26854 (April 3, 1998) and any subsequent orders which may be issued relating to the AEP Money Pool (collectively, the "Money Pool Orders"). Authority is sought for each Regulated Subsidiary to participate in the AEP Money Pool subject to and as set forth in the Money Pool Orders and to be permitted to issue, to the extent not exempt under Rule 52, short-term debt up to the amounts set forth below (which amounts shall be included in the limits set forth in Item E.7.(a), above): CPL EDC..................................... 200,000,000 CSP EDC..................................... 175,000,000 OPCo EDC.................................... 250,000,000 SWEPCO EDC.................................. 100,000,000 WTU EDC..................................... 75,000,000 (d) Hedging Transaction Authority Authority is sought for each Regulated Subsidiary to enter into any hedging transaction subject to and in accordance with the parameters set forth in Item E.2, above. 8. FINANCE SUBSIDIARY AUTHORITY Authority is sought for any Finance Applicant to organize and acquire all of the common stock or other equity interests of one or more subsidiaries (collectively, the "Financing Subsidiary") for the purpose of effecting any financing as described herein. Authority is further sought for 30 any Financing Subsidiary to effect any such transaction for which any Finance Applicant has received authority herein to effect per this Section E. F. AEP'S NON-UTILITY HOLDINGS Applicants propose to restructure AEP's non-utility holdings from time to time as may be necessary or appropriate in the furtherance of its authorized non-utility activities. The restructuring could involve the acquisition of one or more new special-purpose subsidiaries to acquire and hold direct or indirect interests in any or all of the AEP system's existing or future authorized non-utility businesses. The restructuring could also involve the transfer of existing subsidiaries, or portions of existing businesses, among AEP associates and/or the reincorporation of existing subsidiaries in a different state. This would enable the AEP system to consolidate similar businesses and to participate effectively in authorized non-utility activities, without the need to apply for or receive additional Commission approval.(17) These direct or indirect subsidiaries might be corporations, partnerships, limited liability companies or other entities in which AEP, directly or indirectly, might have a 100% interest, a majority equity or debt position, or a minority debt or equity position. These subsidiaries would engage only in businesses to the extent the AEP system is authorized, whether by statute, rule, regulation or order, to engage in those businesses. AEP does not seek authorization to acquire an interest in any non-associate Company as part of the authority requested in this Application and states that the reorganization will not result in the entry by the AEP system into a new, unauthorized line of business. G. REQUEST FOR AUTHORITY TO PAY DIVIDENDS OUT OF CAPITAL OR UNEARNED SURPLUS BY THE UTILITY SUBSIDIARIES Section 12 of the 1935 Act, and Rule 46 thereunder, generally prohibit the payment of dividends out of "capital or unearned surplus" except pursuant to an order of the Commission. The legislative history explains that this provision was intended to "prevent the milking of operating companies in the interest of the controlling holding company groups." S. Rep. No. ---------- (17) PowerGen plc, HCAR No. 27291 (Dec. 6, 2000); Columbia Energy Group, HCAR No. 27099 (Nov. 5, 1999). 31 621, 74th Cong., 1st Sess. 34 (1935).(18) In determining whether to permit a registered holding company to pay dividends out of capital surplus, as discussed in the 1991 case involving Eastern Utilities Associates, the Commission considers various factors, including: (i) the asset value of the company in relation to its capitalization; (ii) the company's prior earnings; (iii) the company's current earnings in relation to the proposed dividend; and (iv) the company's projected cash position after payment of a dividend. In recent cases, the Commission has determined that holding company systems may continue to pay dividends although retained earnings have been reduced or eliminated because of write-offs associated with State utility regulation restructuring legislation or because of application of generally accepted accounting principles to a merger involving two previously unaffiliated companies. For extraordinary reasons related to the adoption of utility restructuring legislation in Texas and Ohio, CPL, CSP, OPCo, SWEPCO and WTU will each have on a pro forma basis, unusual reductions in their respective retained earnings which may make it difficult in some cases to continue to pay dividends at historical levels without such dividends being paid from paid-in-capital. Generally accepted accounting principles may result in an elimination of retained earnings at CPL, CSP, OPCo, SWEPCO and WTU. Further, such elimination may have the effect of limiting the amount available for dividends. Accordingly, authority is requested for AEP and the Holding Companies to pay dividends out of capital or unearned surplus. H. OTHER REGULATORY APPROVALS The goals of the proposed restructuring are to comply with the requirements of Texas and Ohio while maintaining the benefits of integrated operations for system consumers and, in particular, continuing to provide customers with a reliable power supply. To that end, all of AEP's energy regulators will be involved in some aspect of the restructuring. The proposed transactions will require approvals from the Federal Energy Regulatory Commission ("FERC") under Sections 203 and 205 of the Federal Power Act in connection with the transfer of assets and the restructuring of FERC-approved Operating and Interconnection agreements (to remove companies in deregulated states). Applications were filed with the FERC on July 24, 2001 and copies are attached hereto as Exhibit D-7. ---------- (18) Compare Section 305(a) of the Federal Power Act. 32 In addition, AEP is seeking orders from each of its state regulators, pursuant to Section 32(c) of the 1935 Act, to establish EWG status for all Ohio and Texas generation. EWG status is needed to enable AEP to divest certain generation by July, 2002, in fulfillment of its merger commitments. AEP will seek FERC certification once the state orders have been received. ITEM 2. FEES, COMMISSIONS AND EXPENSES Estimated fees and expenses expected to be incurred by Applicants in connection with the Transaction will be filed by amendment. ITEM 3. APPLICABLE STATUTORY PROVISIONS SECTIONS OF THE 1935 ACT TRANSACTIONS TO WHICH SECTION OR RULE MAY BE APPLICABLE: 9, 10 and 11 and rules thereunder Creation of Enterprises, Wholesale Holdco and Domestic Holdco 11(b)(2) and rules thereunder Declaration that Enterprises, Wholesale Holdco, Domestic Holdco and Reg Holdco are not subsidiary companies or holding companies solely with respect to the "great-grandfather" provisions of Section 11(b)(2) 9, 10 and 12 and rules thereunder Transfers of utility assets and securities of public utility subsidiaries 13 and rules thereunder Approval of services to be provided by AEPSC to the direct and indirect subsidiaries formed herein; approval of the performance of certain services between AEP system companies 6, 7, 9, 10 and 12 and rules Transfers of utility assets and securities thereunder of public utility subsidiaries 6 and 7 and rules thereunder Issuance of securities 12 and rules thereunder Dividends out of paid-in capital The relevant standards for Commission review of this Application under Sections 6, 7, 9, 10, 11, 12 and 13 of the 1935 Act, and Rules 43(a), 44, 45, 46, 54, 90 and 91 thereunder. 33 A. SECTIONS 9 & 10 Section 9(a)(1) provides that unless the Commission under Section 10 has approved the acquisition, it shall be unlawful for any registered holding company or any subsidiary company thereof "to acquire, directly or indirectly, any securities or utility assets or any other interest in any business." Section 10(f) provides that: The Commission shall not approve any acquisition as to which an application is made under this section unless it appears to the satisfaction of the Commission that such State laws as may apply in respect of such acquisition have been complied with, except where the Commission finds that compliance with such State laws would be detrimental to the carrying out of the provisions of Section 11. If the requirements of subsection (f) of this section are satisfied, the Commission shall approve the acquisition unless the Commission finds that: (1) such acquisition will tend towards interlocking relations or the concentration of control of public-utility companies, of a kind or to an extent detrimental to the public interest or the interest of investors or consumers; (2) in case of the acquisition of securities or utility assets, the consideration, including all fees, commissions, and other remuneration, to whomsoever paid, to be given, directly or indirectly, in connection with such acquisition is not reasonable or does not bear fair relation to the sums invested in or the earning capacity of the utility assets to be acquired or the utility assets underlying the securities to be acquired; or (3) such acquisition will unduly complicate the capital structure of the holding-company system of the applicant or will be detrimental to the public interest or the interest of investors or consumers or the proper functioning of such holding-company system. The Transaction, for the reasons set forth below, satisfy the standards of Section 10 of the 1935 Act. 34 1. THE TRANSACTION COMPLIES WITH STATE LAW The Transaction complies with, or upon completion of the record shall comply with, applicable state laws on the matter of restructuring and the transfer of utility assets. Specifically, each Operating Company has structured the Transaction in response to state law and legislative mandate. The Transaction puts into effect the state regulatory and legislative determination that restructuring is in the public interest. The Transaction is reasonably incidental, economically necessary and appropriate to the operations of each Operating Company and the AEP system. Specifically, the Transaction will (a) allow AEP to continue to serve the needs of its regulated customers while positioning the AEP system for competition in the deregulated generation market; (b) segregate the transmission and distribution assets into rate-regulated subsidiaries; (c) allow each deregulated Operating Company to manage and operate its respective generating assets with due regard to market considerations; and, (d) increase the flexibility for financing activities on cost-effective terms that reflect the costs of capital for each area of business activity. 2. THE CAPITAL STRUCTURE IS NOT UNDULY COMPLICATED AEP seeks approval to form one first tier holding company, Enterprises, to hold the interests in Wholesale Holdco; a second tier holding company, Wholesale Holdco, to hold the interests in Domestic Holdco and a third tier holding company, Domestic Holdco, to hold the PGCs. Each holding company is necessary to achieve a simple corporate structure while minimizing the Federal and State income tax impact of combining the unregulated businesses of AEP. Alternative structures were considered but each had serious disadvantages including potential tax liabilities. Alternative structures which would minimize tax liability were much less desirable from a business organization viewpoint and involved much more complicated corporate structures. With respect to Reg Holdco, AEP wishes to emphasize the separation of its "wires" business - the transmission and distribution functions of the EDCs - from its non-State regulated utilities - the PGCs - and non-utility - Enterprises - businesses. Providing a corporate organization that clearly and 35 fully separates the distribution business from other businesses will better insulate the distribution business, which will continue to be regulated, from unregulated business. Further, providing a separate management structure for the distribution business will provide for management focus on that business enabling better integration and efficient development of that business. The Commission has recognized in recent cases that there are organizational, regulatory and tax benefits to the creation of intermediate holding companies that should be considered. The harms that the 1935 Act envisioned would be prevented by the reduction or elimination of intermediate holding companies are unlikely to occur given modern financial reporting and affiliate transaction requirements. AEP's proposal will not result in harmful pyramiding of holding company groups. There is no risk of unfair or inequitable distribution of voting power from the proposal. No proposed holding company will issue any voting securities to anyone other than AEP or a directly or indirectly wholly owned subsidiary of AEP. Consequently, the Commission should approve the formation of such entities, "look through" the intermediate holding companies or treat them as a single company for purposes of analysis under Section 11(b)(2) of the 1935 Act.(19) Enterprises and Reg Holdco will be wholly-owned, directly by AEP. Other than to enhance the full integration of the regulated utilities, Reg Holdco will not affect the operation of CPL EDC, WTU EDC, SWEPCO, SWEPCO EDC, CSP EDC or OPCo EDC. Likewise, Enterprises will not affect the operation of CPL PGC, WTU PGC, CSP PGC and OPCo PGC. Thus, there is no possibility that implementation and continuance of the proposed transaction structure could result in an undue or unnecessarily complex capital structure or inequitable distribution of voting power to the detriment of the public interest or the interest of consumers. This is not the type of situation that concerned the drafters of the 1935 Act and AEP urges the Commission to exercise its discretion to find that any apparent complexity of the proposed transaction structure is neither undue nor unnecessary. ---------- (19) Exelon Corporation, HCAR No. 27256 (Oct. 19, 2000) (approving intermediate holding company structure resulting from merger); National Grid Group plc, HCAR No. 27154 (Mar. 15, 2000) (intermediate holding companies necessary for cross-border tax considerations); Dominion Resources, HCAR No. 27113 (Dec. 15, 1999) (intermediate holding company "CNG Acquisitions" to hold CNG's utility subsidiaries under alternative form of merger). 36 The Transaction does not unduly complicate the capital structure of the AEP system. The capital structure of the AEP system on a consolidated basis will be essentially unchanged. The Transaction will tend toward the proper functioning of the AEP system in a partly deregulated, partly regulated operating environment. The Transaction results in a more economical and efficient system. The resulting increased efficiency of operations significantly offsets any perceived added complexity caused by the Transaction.(20) Being done in part because of state mandate and for all of the foregoing reasons, the Transaction satisfies the requirements of, and is entirely consistent with the 1935 Act. 3. THE CONSIDERATION IS FAIR AND REASONABLE The consideration to be paid in connection with the Transaction is fair and reasonable. Indeed, each state public utility commission has approved or will approve the corporate separation plan as it relates to its particular jurisdiction. B. SECTION 12 & RULE 46 Section 12(c) governs the proposed dividends for which authorization has been sought. Section 12(c) provides that: It shall be unlawful for any registered holding company or any subsidiary company thereof, by use of the mails or any means or instrumentality of interstate commerce, or otherwise, to declare or pay any dividend on any security of such company or to acquire, retire, or redeem any security of such company, in contravention of such rules and regulations or orders as the Commission deems necessary or appropriate to protect the financial integrity of companies in holding-company systems, to safeguard the working capital of public-utility companies, to prevent the payment of dividends out of capital or unearned surplus, or to prevent the circumvention of the provisions of this chapter or the rules, regulations, or orders thereunder. ---------- (20) SEE Wisconsin's Environmental Decade, Inc. v SEC, 882 F.2d 523, 527 (D.C. Cir. 1989); Northeast Utilities, HCAR No. 25221 (Dec. 21, 1990); Entergy Corp., HCAR No. 25136 (Aug. 27, 1990). 37 AEP expects that the distribution of entities owning utility assets of this magnitude, in each instance could be a dividend out of "capital or unearned surplus" within the meaning of Rule 46 under the 1935 Act. Applicants believe that, in the overall context of the Transaction, neither shareholders, ratepayers nor the public will be adversely affected.21 The distributions will be structured as such in order to minimize the tax burden on the Applicants. The distributions are fundamentally necessary to effect the transfer of their respective generation or transmission and distribution assets to an affiliate in the AEP system in accordance with the relevant order of each respective state utility commission. The distributions will be the final step in the reorganization of the AEP system, in accordance with, and fulfillment of, the regulations and legislative policies and objectives that culminated in deregulation of and competition in electrical generation in each state, as described herein. The distributions are not intended to harm the interests of any Operating Company, successor or, ultimately, AEP. The AEP system will continue to own the assets transferred by such distributions. Subject to any necessary state approvals, the regulated parts of the AEP system that are not subject to deregulation and competition will be owned directly by Reg Holdco. For these reasons, the proposed distributions are entirely consistent with the policies and principles behind Section 12 of the 1935 Act. C. SECTION 13(B) COMPLIANCE Section 13(b) of the 1935 Act provides that: It shall be unlawful for any subsidiary company of any registered holding company or for any mutual service company, by use of the mails or any means or instrumentality of interstate commerce, or otherwise, to enter into or take any step in the performance of any service, sales, or construction contract by which such company undertakes to perform services or construction work for, or sell goods to, any associate company thereof except in accordance with such terms and conditions and subject to such limitations and prohibitions as the Commission by rules and regulations or order shall prescribe as necessary or appropriate in the public interest or for the ---------- (21) IBID. The Commission, among other things, authorized the dividending of interests to Genco. 38 protection of investors or consumers and to insure that such contracts are performed economically and efficiently for the benefit of such associate companies at cost, fairly and equitably allocated between such companies. Any transaction between AEPSC and any newly formed affiliates and any related service agreements shall be in compliance with section 13(b) of the 1935 Act and Rules 87, 90 and 91 under the 1935 Act. D. RULE 54 COMPLIANCE Rule 54 provides that, in determining whether to approve an application which does not relate to any EWG or FUCO, the Commission shall not consider the effect of the capitalization or earnings of any such EWG or FUCO which is a subsidiary of a registered holding company if the requirements of Rule 53(a), (b) and (c) are satisfied. AEP consummated the merger with Central and South West Corporation on June 15, 2000 pursuant to an order issued June 14, 2000 (HCAR No. 27186), which further authorized AEP to invest up to 100% of its consolidated retained earnings, with consolidated retained earnings to be calculated on the basis of the combined consolidated retained earnings of AEP and CSW (as extended pursuant to HCAR No. 27316, December 26, 2000, the "Rule 53(c) Order"). AEP currently meets all of the conditions of Rule 53(a) and none of the conditions set forth in Rule 53(b) exist or will exist as a result of the transactions proposed herein. RULE 53(a)(1) At June 30, 2001, AEP's "aggregate investment", as defined in Rule 53(a)(1), in EWGs and FUCOs was approximately $1.315 billion, or about 40.6% of AEP's "consolidated retained earnings", also as defined in Rule 53(a)(1), for the four quarters ended June 30, 2001 ($3.242 billion). RULE 53(a)(2) Each FUCO in which AEP invests will maintain books and records and make available the books and records required by Rule 53(a)(2). RULE 53(a)(3) No more than 2% of the employees of the electric utility subsidiaries of AEP will, at any one time, directly or indirectly, render services to any FUCO. 39 RULE 53(a)(4) AEP has submitted and will submit a copy of Item 9 and Exhibits G and H of AEP's Form U5S to each of the public service commissions having jurisdiction over the retail rates of AEP's electric utility subsidiaries. RULE 53(b) (i) Neither AEP nor any subsidiary of AEP is the subject of any pending bankruptcy or similar proceeding; (ii) AEP's average consolidated retained earnings for the four quarters ended June 30, 2001 ($3,242,159,000) represented a decrease of approximately $302,490,000 (or 8.5%) in the average consolidated retained earnings from the four quarters ended June 30, 2000 ($3,544,649,000); and (iii) for the fiscal year ended December 31, 2000, AEP did not report operating losses attributable to its direct or indirect investments in EWGs and FUCOs. AEP's interests in EWGs and FUCOs have made a positive contribution to earnings over the four calendar years ending after the Rule 53(c) Order. Accordingly, since the date of the Rule 53(c) Order, the capitalization and earnings attributable to AEP's investments in EWGs and FUCOs has not had an adverse impact on AEP's financial integrity. ITEM 4. REGULATORY APPROVAL The FERC must approve the sale of utility assets and other action contemplated in this Application. The LPSC must approve the business unbundling plan of SWEPCO. On July 7, 2000, the PUCT issued an order approving the corporate separation plan of CPL, SWEPCO and WTU (Exhibit D-2.) On September 28, 2000, the PUCO issued an order on each of OPCo and CSP's request to separate its generation assets from its transmission and generation assets. In that order, the PUCO approved the Stipulation Agreement requiring the separation of each of OPCo and CSP's generation assets from its transmission and distribution assets as determined in accordance with accepted PUCO procedures (Exhibit D-4). On September 1, 2000, SWEPCO filed an application before the LPSC seeking approval to transfer its Texas transmission and distribution assets to SWEPCO EDC (Exhibit D-5). ITEM 5. PROCEDURE It is requested that the Commission's order granting this Application or Declaration be issued on or before October 1, 40 2001. There should be no recommended decision by a hearing or other responsible officer of the Commission and no 30-day waiting period between the issuance of the Commission's order and its effective date. Applicants consent to the Division of Corporate Regulation assisting in the preparation of the Commission's decision and order in this matter, unless the Division opposes the Transaction covered by this Application or Declaration. ITEM 6. EXHIBITS AND FINANCIAL STATEMENTS (a) Exhibits: B-1 Form of Proposed AEP Structure (previously filed on Form SE) D-1 PUCT Application D-2 PUCT Order D-3 PUCO Application D-4 PUCO Order D-5 LPSC Application D-6 LPSC Order (to be filed by amendment) D-7 FERC Application D-8 FERC Order (to be filed by amendment) F Opinion of Counsel (to be filed by amendment) (b) Financial statements: Consolidated balance sheets as of June 30, 2001 and consolidated statements of income for the period ended June 30, 2001 of AEP, CPL, CSP, OPCo, SWEPCO and WTU. (Incorporated by reference from AEP's Form 10-Q for the period ended June 30, 2001, File No. 1-3525.) 41 ITEM 7. INFORMATION AS TO ENVIRONMENTAL EFFECTS As described in Item 1, the proposed transactions are of a routine and strictly financial nature in the ordinary course of AEP's business and the Commission's action in this matter will not constitute any major federal action significantly affecting the quality of the human environment. No other federal agency has prepared or is preparing an environmental impact statement with regard to the proposed transactions. SIGNATURE Pursuant to the requirements of the Public Utility Holding Company Act of 1935, the undersigned companies have duly caused this statement to be signed on their behalf by the undersigned thereunto duly authorized. AMERICAN ELECTRIC POWER COMPANY, INC. AMERICAN ELECTRIC POWER SERVICE CORPORATION CENTRAL AND SOUTH WEST CORPORATION CENTRAL POWER AND LIGHT COMPANY COLUMBUS SOUTHERN POWER COMPANY OHIO POWER COMPANY SOUTHWESTERN ELECTRIC POWER COMPANY WEST TEXAS UTILITIES COMPANY /s/ A.A. Pena ----------------------------- Treasurer Dated: October 12, 2001 42 EX-99.D1 3 c22015_ex99-d1.txt PETITION FOR TIMELY ENTRY OF PRELIMINARY ORDER DOCKET NO.______________ APPLICATION OF CENTRAL POWER ss. BEFORE THE AND LIGHT COMPANY, WEST TEXAS ss. UTILITIES COMPANY, AND ss. PUBLIC UTILITY COMMISSION SOUTHWESTERN ELECTRIC POWER ss. COMPANY FOR APPROVAL OF ss. PROPOSED BUSINESS SEPARATION PLAN ss. OF TEXAS PETITION OF CENTRAL POWER AND LIGHT COMPANY, WEST TEXAS UTILITIES COMPANY, AND SOUTHWESTERN ELECTRIC POWER COMPANY AND REQUEST FOR THE TIMELY ENTRY OF A PRELIMINARY ORDER Central Power and Light Company, West Texas Utilities Company, and Southwestern Electric Power Company (the Companies) jointly file the attached Business Separation Plan-Filing Package pursuant to Section 39.051 of the Public Utility Regulatory Act (PURA) and P.U.C. SUBST. R. 25.342. The Companies seek approval of the plan by the Public Utility Commission of Texas (Commission) as well as the more specific relief requested below. I. THE APPLICANTS -------------- Each of the Companies is a wholly owned subsidiary of Central and South West Corporation (CSW), a public utility holding company registered under the Public Utility Holding Company Act of 1935 with utility subsidiaries that provide electric service to approximately 1.7 million customers in four states. Central Power and Light Company is headquartered in Corpus Christi, Texas, and provides electric service in south Texas. West Texas Utilities Company is headquartered in Abilene, Texas, and provides electric service in west Texas. Southwestern Electric Power Company is headquartered in Shreveport, Louisiana, and provides electric service in east Texas and in portions of Louisiana and Arkansas. II. DESIGNATED REPRESENTATIVES -------------------------- Philip F. Ricketts Joe N. Pratt Bracewell & Patterson, L.L.P. Pratt and Grant, P.C. Suite 2300 Suite 250, One Northpoint Centre 111 Congress Avenue 6836 Austin Center Boulevard Austin, Texas 78701 Austin, Texas 78731 (512) 472-7800 (512) 794-2100 (512) 472-9123 (FAX) (512) 794-2111 (FAX) III. SERVICE ------- Pursuant to P.U.C. PROC. R. 22.74(b), the Companies designate their authorized representative for purpose of service of pleadings as follows: Ron Ford CSW Services, Inc. Norwest Bank Building 400 West 15th Street, Suite No. 650 Austin, Texas 78701 (512) 481 4564 (512) 481-4588 (FAX) IV. PERSONS AFFECTED ---------------- All customers and classes of customers of the Companies will be affected by this filing. V. JURISDICTION ------------ The Commission has jurisdiction over this filing pursuant to Section 39.051 of PURA. VI. THE PROPOSED BUSINESS SEPARATION PLAN ------------------------------------- The proposed business separation plan is set forth in detail in the attached Business Separation Plan-Filing Package, which includes supporting testimony. The plan proposes that full legal entity or structural separation of the Companies occur in two stages in order to minimize refinancing costs that must be incurred to address existing contractual requirements related to existing securities issued by the Companies. The first stage would occur on January 1, 2002, and would last up to six years. By January 1, 2002, separate legal entities with separate management would be established to conduct energy delivery, power generation, and retail electric provider businesses. During the first-stage period, the electric delivery and generation assets, as well as certain operating employees, will remain with the Companies, although those assets and -2- employees will be managed and controlled by the electric delivery and power generation businesses. The primary purpose of the Companies after January 1, 2002, will be to hold legal ownership of the electric delivery and generation assets. All employees and assets needed by the retail electric provider will be transferred to it by January 1, 2002. No later than January 1, 2008, all assets and employees of the Companies will have been transferred to the energy delivery company and power generation company as the existing contractual requirements that affect the transfer of legal ownership of assets are eliminated through refinancing in a cost efficient manner. Further details of the Companies' plan are contained in the testimony of Mark D. Roberson and Wendy D. Hargus that is a part of this filing. The plan also requests certain approvals, to the extent the Commission deems them necessary, for the Companies to continue offering certain services from September 1, 2000, to January 1, 2002. VII. REQUEST FOR A PRELIMINARY ORDER ------------------------------- The Companies believe that the above-described two-stage process complies with the letter and intent of the industry restructuring provisions of PURA. However, in the event that the Commission decides to require transfers of employees and the legal ownership of all assets by January 1, 2002, it will be necessary for the Companies to immediately begin implementing a number of federal and other state filings to accomplish such a transfer. If the Companies first learn of this request in late 2000 or early 2001, when a final order is issued in this proceeding, it will be very difficult, if not impossible, to obtain the necessary federal and state approvals for the asset transfers by January 1, 2002. Accordingly, the Companies respectfully request that the Commission timely issue a preliminary order in this case which addresses the issue of whether the Companies' proposed two-step plan complies with PURA. VIII. PROTECTIVE ORDER ---------------- While no confidential information is being filed in the Business Separation Plan-Filing Package, the Companies anticipate that during the course of this proceeding they may be asked to furnish confidential information, the disclosure of which to third parties would place the Companies at a severe competitive disadvantage or cause the Companies to violate contractual confidentiality obligations. Therefore, the Companies may later request that a protective order be entered in this case. -3- IX. NOTICE ------ The Companies propose that notice of this case consist of published newspaper notice in the service areas of each of the Companies once a week for two consecutive weeks. The companies further propose that individual notice be provided to each participant in Project No. 20970; to each intervenor in Docket No. 19265, the proceeding involving the merger of CSW and American Electric Power Company; and to each municipality served by the Companies. A copy of a proposed public notice for newspaper publication is attached as Exhibit 1. The Companies propose that the individual notice to the above persons and entities consist of a copy of the proposed public notice sent by electronic mail or first class mail. X. REQUESTED COMMISSION ACTIONS ---------------------------- 1. The Companies request that the proposed business separation plan be approved, including any necessary waivers to continue to provide certain competitive energy services until January 1, 2002. 2. The Companies request that the Commission timely issue a preliminary order declaring that the Companies' proposed two-stage restructuring plan complies with PURA and the Commission's rules. 3. The Companies further request that the Commission approve the proposed form of notice. -4- Respectfully submitted, BRACEWELL & PATTERSON, L.L.P. PRATT AND GRANT, P.C. Suite 2300 Suite 250, One Northpoint Centre 111 Congress Avenue 6836 Austin Center Boulevard Austin, Texas 78701 Austin, Texas 78731 (512) 472-7800 (512) 794-2100 (512) 472-9123 (fax) (512) 794-2111 (fax) By: /s/ Philip F. Ricketts By: /s/ Joe N. Pratt ----------------------------------- ------------------------------ Philip F. Ricketts Joe N. Pratt State Bar No. 16882500 State Bar No. 16240100 ATTORNEYS FOR APPLICANTS -5- EXHIBIT 1 Page 1 of 2 PUBLIC NOTICE On January 10, 2000, Central Power and Light Company, West Texas Utilities Company, and Southwestern Electric Power Company (the Companies) filed with the Public Utility Commission of Texas (the Commission) a business separation plan as required by Section 39.051 of the Public Utility Regulatory Act (PURA) and Section 25.342 of the Commission's substantive rules. As required by Section 39.051 of PURA, the plan proposes that each of the companies, subject to certain actions by other federal and state regulatory authorities, be separated into three new businesses, one of which will provide transmission and distribution or electric delivery services to competitive retail electric providers, one of which will be a competitive retail electric provider, and one of which will provide competitive wholesale generation services. The plan further provides that each newly created business will operate independently of each other pursuant to a code of conduct which will govern transactions between the businesses and their affiliates, after the introduction of electric competition, to recognize federal and state code of conduct requirements and appropriate business practices. The three new businesses will be managed by three new separate legal entities which will be created by January 1, 2002, at which time all functions now provided by the Companies will be separated into the new businesses. All assets and employees of the Companies will be transferred to the new legal entities by January 1, 2008. The plan also contains a proposal for physical separation of the new businesses, for sharing of information and technology systems, and for maintenance of separate books and records for the new businesses. It also provides details regarding the separation of functions and operations among the new businesses, financial and legal aspects of the proposed business separation, asset and liability transfers to the new businesses, and the provision of corporate support services through a separate organization. It also contains a proposed plan for interim separation of certain services designated by the Commission as "competitive energy services" on or before September 1, 2000, as required by Section 39.051(a) of PURA and Section 25.343 of the Commission's substantive rules. EXHIBIT I Page 2 of 2 The plan does not propose any change in the existing rates of the Companies. On April 1, 2000, the Companies will file an application with the Commission requesting that rates be set for the new transmission and distribution utility business which begins operation on January 1, 2002. This filing has been assigned Docket No. __________________. Persons who wish to intervene or comment upon these proceedings should notify the Commission. A request to intervene or for further information should be mailed directly to the Public Utility Commission of Texas, P. O. Box 13326, Austin, Texas 78711-3326. Further information may also be obtained by calling the Commission's Office of Consumer Affairs at (512) 396-7120. Hearing and speech impaired individuals with text telephones may contact the Commission at (512) 936-7136. -2- EX-99.D2 4 c22015_ex99-d2.txt PRATT AND GRANT LETTER [PRATT & GRANT LETTERHEAD] June 8, 2000 Administrative Law Judge Melene R. Dodson Office of Policy Development Public Utility Commission of Texas 1701 N. Congress Avenue Austin, Texas 78701 RE: Docket No, 21953, SOAH Docket No. 473-00-0498 - APPLICATION OF CENTRAL POWER AND LIGHT COMPANY, SOUTHWESTERN ELECTRIC POWER COMPANY AND WEST TEXAS UTILITIES COMPANY FOR APPROVAL OF PROPOSED BUSINESS SEPARATION PLAN PURSUANT TO 25.342 Dear Judge Dodson: Attached is the stipulation that resolves the structural business separation issues in this docket. The stipulation lists the positions of the parties to this case with the exception of the Louisiana Public Service Commission (LPSC). The LPSC is no longer actively participating in this docket because it has opened its own docket to monitor the restructuring efforts in Texas and other states and take any necessary steps to ensure protection of Louisiana customers. Very truly yours, /s/ Joe N. Pratt ---------------- Joe N. Pratt cc: All Parties of Record Attachment 1 SOAH DOCKET NO. 473-00-0498 PUC DOCKET NO. 21953 APPLICATION OF CENTRAL POWER ss. AND LIGHT COMPANY, ss. STATE OFFICE OF SOUTHWESTERN ELECTRIC POWER ss. COMPANY AND WEST TEXAS ss. UTILITIES COMPANY FOR ss. ADMINISTRATIVE HEARINGS APPROVAL OF PROPOSED BUSINESS ss. SEPARATION PLAN PURSUANT TO ss. 25.342 ss. STIPULATION ----------- This stipulation is entered between Central Power and Light Company (CPL), West Texas Utilities Company (WTU) and Southwestern Electric Power Company (SWEPCO), together referred to as the CSW Companies; the Office of Regulatory Affairs for the Public Utility Commission of Texas; Office of Public Utility Counsel and South Texas Electric Cooperative. Parties that have stated they do not oppose this stipulation are as follows: o Cities Served by CPL and WTU o State of Texas o Texas Industrial Energy Consumers o Rayburn County Electric Cooperative, Inc. and Magic Valley Electric Cooperative, Inc. o Shell Energy Services Co., L.L.C. o Consumers Union o Commercial Ratepayer Coalition o Power Choice, Inc.; Corpus Christi Power & Light, L.C.C.; Hino Electric Power Company o Texas Legal Services Center o Texas Ratepayers' Organization to Save Energy o New Energy Texas, L.L.C. Parties whose position on the stipulation is not known are as follows: o Public Citizen o Competitive Power Advocates; PG&E Corporation The signatories to this docket stipulate that the proposed structural separation plan of Central and South West Corporation (CSW), described below for the CSW Companies is 1 consistent with the requirements of PURA ss. 39.051 and resolves all disputes concerning the structural business separation of the CSW Companies. The CSW Companies will separate their business activities, personnel and assets no later than January 1, 2002, in accordance with the following plan: CSW will establish three new first-tier subsidiaries as separate legal entities: an Energy Delivery Company (EDC), a Power Generation Company (PGC) and a Retail Electric Provider (REP). Attachment 1 hereto is a diagram reflecting the restructured entities. CPL, WTU and SWEPCO will take necessary steps regarding their existing debt to accomplish the transfer of assets. The EDC, PGC, and REP companies will each issue new debt securities to finance assets transferred to the new entities. After separation, there will be no cross-collateralization between entities. As a result, the EDC and its subsidiaries will only be responsible for debt related to authorized transmission and distribution (T&D) utility operations, functions and assets. All issues related to the appropriate capital structures for the EDC and its subsidiaries will be resolved in the proceedings under PURA ss. 39.201 to establish rates for T&D services. REP The REP will be a separate legal entity with its own assets and employees, and debt, if any, that will provide retail electric services in Texas in compliance with all requirements of PURA. PGC The PGC will employ generation management employees that will manage, direct and control generation operations and the wholesale sale of electricity. Existing wholesale power sales contracts will be performed by the PGC for CPL and WTU. The PGC will own two separate legal entity subsidiaries. One will own CPL's generating assets and will employ the generation employees that are currently employed by CPL. A separate legal entity will own WTU's generating assets and will employ the generation employees currently employed by WTU. SWEPCO will continue to own its generation located in Texas and other states, and will continue to employ generation operating and maintenance personnel but those employees will be managed by the PGC. SWEPCO will register as a power generation company in Texas. Nothing in this plan will affect SWEPCO's obligations under PURA relating to capacity auctions. 2 EDC The EDC will employ the management employees that will direct, manage and control the provision of regulated transmission and distribution (T&D) utility services in Texas. The EDC will own three separate legal entities: one each to own the T&D assets currently owned by CPL, WTU and SWEPCO in Texas and employ the T&D employees currently employed by CPL, WTU and SWEPCO in Texas. The EDC subsidiaries for the CPL, WTU and SWEPCO Texas subsidiaries will be the providers of tariffed T&D utility services and the CCNs currently issued to CPL, WTU and SWEPCO will be transferred to these subsidiaries. CSW maintains that implementation of this plan will require CPL, WTU and SWEPCO to obtain other regulatory approvals, including approvals from the Securities and Exchange Commission, the Federal Energy Regulatory Commission, the Nuclear Regulatory Commission and the Arkansas and Louisiana Public Service Commission. A listing of the filings known to CSW at this time is attached as Attachment 2. The CSW Companies intend to initiate the filings within 180 days after receipt of a Texas PUC order approving the form of separation. The signatories agree to not challenge the form of separation in filings in other jurisdictions seeking regulatory approval of separation. CPL, WTU and SWEPCO commit to make a filing with this Commission of any orders issued by any of the other jurisdictions that modify the plan approved by this Commission and notify the Commission of any delay in obtaining any approval if that delay will affect the ability of the Companies to implement the plan effective January 1, 2002. Parties to this case will have ten days from the filing of any order modifying the plan to file a response as to whether they believe the modification is material. This stipulation addresses and resolves only the issue of whether the structural business separation of CPL, WTU and SWEPCO complies with PURA. By agreeing to this stipulation, no party to this case waives, prejudices or otherwise affects their ability or right to contest other issues or portions in other dockets, including ratemaking issues and the recovery of restructuring costs in the PURA ss. 39.201 proceedings. 3 CENTRAL POWER AND LIGHT COMPANY TEXAS RATEPAYERS' SOUTHWESTERN ELECTRIC POWER COMPANY ORGANIZATION TO SAVE ENERGY WEST TEXAS UTILITIES COMPANY By: By: /s/ Joe N. Pratt ------------------------------- ------------------------------- Title: Title: Attorney ---------------------------- ---------------------------- Date: Date: June 8, 2000 ----------------------------- ----------------------------- SHELL ENERGY SERVICES CO., L.L.C. OFFICE OF REGULATORY AFFAIRS PUBLIC UTILITY COMMISSION OF TEXAS By: ------------------------------- By: Illegible Title: ------------------------------- ---------------------------- Title: Attorney-Legal Date: ---------------------------- ----------------------------- Date: 5/8/00 ----------------------------- STEERING COMMITTEE OF CITIES SERVED BY CPL OFFICE OF PUBLIC UTILITY COUNSEL By: By: Illegible ------------------------------- ------------------------------- Title: Title: Assistant Public Counsel ---------------------------- ---------------------------- Date: Date: June 8, 2000 ----------------------------- ----------------------------- COMPETITIVE POWER ADVOCATES TEXAS LEGAL SERVICES CENTER PG&E CORPORATION By: By: ------------------------------- ------------------------------- Title: Title: ---------------------------- ---------------------------- Date: Date: ----------------------------- ----------------------------- STATE OF TEXAS By: ------------------------------- Title: ---------------------------- Date: ----------------------------- 4 NEW ENERGY TEXAS, L.L.C. By: TEXAS INDUSTRIAL ENERGY CONSUMERS ------------------------------- Title: By: ---------------------------- ------------------------------- Date: Title: ----------------------------- ---------------------------- Date: ----------------------------- LOUISIANA PUBLIC SERVICE COMMISSION By: COMMERCIAL RATEPAYER COALITION ------------------------------- Title: By: ---------------------------- ------------------------------- Date: Title: ----------------------------- ---------------------------- Date: ----------------------------- POWER CHOICE, INC. CORPUS CHRISTI POWER & LIGHT, L.C.C. HIND ELECTRIC POWER COMPANY PUBLIC CITIZEN TEXAS By: By: ------------------------------- ------------------------------- Title: Title: ---------------------------- ---------------------------- Date: Date: ----------------------------- ----------------------------- RAYBURN COUNTRY ELECTRIC COOPERATIVE, INC. CONSUMERS UNION MID-TEX ELECTRIC COOPERATIVE, INC. MAGIC VALLEY ELECTRIC COOPERATIVE, INC. By: ------------------------------- By: Title: ------------------------------- ---------------------------- Title: Date: ---------------------------- ----------------------------- Date: ----------------------------- SOUTH TEXAS ELECTRIC COOPERATIVE By: ------------------------------- Title: ---------------------------- Date: ----------------------------- 5 CITY OF BROWNSVILLE By: ------------------------------- Title: ---------------------------- Date: ----------------------------- TEX-LA ELECTRIC COOPERATIVE OF TEXAS, INC. NORTHEAST TEXAS ELECTRIC COOPERATIVE, INC. By: ------------------------------- Title: ---------------------------- Date: ----------------------------- FOWLER ENERGY COMPANY By: ------------------------------- Title: ---------------------------- Date: ----------------------------- 6 COMMERCIAL RATEPAYER COALITION By: CITY OF BROWNSVILLE ------------------------------- Title: By: ---------------------------- ------------------------------- Date: Title: ----------------------------- ---------------------------- Date: ----------------------------- PUBLIC CITIZEN TEXAS By: TEX-LA ELECTRIC COOPERATIVE OF TEXAS, INC. ------------------------------- NORTHEAST TEXAS ELECTRIC COOPERATIVE, INC. Title: ---------------------------- By: Date: ------------------------------- ----------------------------- Title: ---------------------------- Date: CONSUMERS UNION ----------------------------- By: ------------------------------- FOWLER ENERGY COMPANY Title: ---------------------------- By: Date: ------------------------------- ----------------------------- Title: ---------------------------- Date: SOUTH TEXAS ELECTRIC COOPERATIVE ----------------------------- By: /s/ Joe Campbell ------------------------------- Title: Attorney for STEC ---------------------------- Date: 6/1/00 ----------------------------- 5 Attachment 1 EXHIBIT WGH-2A Legal Entity Structure (January 1, 2001) ------------------- CSW ------------------- | ---------------------------------------------------------------------------------------------------------------- | | | | | | --------------------- -------------------- -------------------- -------------------- -------------------- | ------------------- ENERGY DELIVERY RETAIL ELECTRIC POWER GENERATION CSWS OTHER EXISTING | SWEPCO COMPANY PROVIDER COMPANY UNREGULATED +-- (EDC) (REP) (PGC) COMPANIES | ------------------- --------------------- -------------------- -------------------- -------------------- -------------------- | PSO - | | +-- | --------------------- | -------------------- ------------------- | CPL-EDC | CPL-PGC +-- +-- (holding company) | --------------------- | -------------------- | | | | | | --------------------- | | -------------------- | | CPL-ERCOT | | CPL-PGC | +-- Transco | +-- (assets) | | --------------------- | -------------------- | | | | | --------------------- | -------------------- | | SPE | WTU-PGC | +-- +-- | --------------------- -------------------- | | --------------------- | WTU-EDC +-- | --------------------- | | | | --------------------- | | WTU/ERCOT | +-- Transco | | --------------------- | | --------------------- | SWEPCO-EDC +-- --------------------- | | --------------------- | SWEPCO/SPP +-- Transco ---------------------
Attachment 2 OTHER REQUIRED FILINGS TO IMPLEMENT SEPARATION PLAN Other filings required to implement the separation plan include at least the following: * SEC Filing Under PUHCA - Creation of new subsidiaries - Approval of necessary financings * FERC Filings: - Transfer of ownership and control of CPL, WTU AND SWEPCO assets - OATT tariff revisions - to make CPL, WTU AND SWEPCO EDC subsidiaries entities charging for transmission service - Interconnection agreements - new CPL/WTU PGC subsidiaries and SWEPCO with the new CPL, SWEPCO AND WTU EDC subsidiaries - Network transmission agreements and network operating agreements for PGC, CPL/WTU PGC subsidiaries and SWEPCO with CPL, WTU and SWEPCO EDC subsidiaries - Service agreements between REP AND CPL/WTU/SWEPCO EDC subsidiaries - Revisions to CSW operating agreement - creation of agency relationship for PGC to manage generation assets - Management agreement for EDC - creation of relationship for EDC to manage T&D assets - Revisions to CSW transmission coordination agreement - to reflect new management and asset relationships * Nuclear Regulatory Commission - transfer of STP license to CPL sub of PGC * APSC or LPSC - Approval of separation of Texas T&D Assets SOAH DOCKET NO. 473-00-0498 P.U.C. DOCKET NO. 21953 APPLICATION OF CENTRAL POWER ss. PUBLIC UTILITY COMMISSION AND LIGHT COMPANY, ss. SOUTHWESTERN ELECTRIC POWER ss. OF TEXAS COMPANY AND WEST TEXAS ss. UTILITIES COMPANY FOR ss. APPROVAL OF PROPOSED BUSINESS ss. SEPARATION PLAN PURSUANT TO ss. 25.342 ss. INTERIM ORDER APPROVING STIPULATION AND SETTLEMENT REGARDING APPROVAL OF BUSINESS SEPARATION PLAN On June 8, 2000, Central Power and Light Company (CPL), Southwestern Electric Power Company (SWEPCO), and West Texas Utilities Company (WTU), (collectively referred to as CSW), the Office of Regulatory Affairs (ORA) of the Public Utility Commission of Texas, the Office of Public Utility Counsel (OPC), and South Texas Electric Cooperative filed with the Public Utility Commission of Texas (Commission) a request for approval of a stipulation and settlement regarding the application for approval of CSW's business separation plan pursuant to P.U.C. SUBST. R. 25.342. All of the parties to the proceeding either support the stipulation, have not expressed a position on the matter, or, in the case of the Louisiana Public Service Commission, have withdrawn ftom the case. The principal issue in this proceeding is whether the business separation plan establishes separate legal entities to carry out various functions in the restructured electric market. The Commission concludes that CSW's proposed plan would create legally distinct entities and is consistent with PURA ss. 39.051. I. BACKGROUND On January 10, 2000, CSW filed its application for approval of its business separation plan pursuant to P.U.C. SUBST. R. 25.342. In its initial application, CSW proposed a two-stage separation of the companies in order to minimize refinancing costs. During the first-stage period, beginning January 1, 2002, the electric delivery and generation assets, as well as certain PUC DOCKET NO. 21953 Interim Order Page 2 of 3 operating employees, would remain with the existing utility companies, although those assets and employees would be managed and controlled by an energy delivery company (EDC) and power generation company (PGC). CSW proposed to transfer all assets and employees of the existing utility companies to the EDC and PGC no later than January 1, 2008. As established in the Order Memorializing Pre-hearing Conference and Clarifying Nature of Referral to SOAH, issued on February 16, 2000, the scope of the expedited hearing before the Commission in this docket is "whether the proposed plan creates a functional separation, as opposed to creating legally distinct entities, and if such functional separation fulfills the requirements of PURA." At the hearing conducted in this docket on March 16, 2000, the Commission determined that the proposed corporate structure was not appropriate, but deferred a final decision to allow CSW to amend its business separation plan. The parties agreed to file an agreed proposed interim order on the business separation plan on June 1, 2000. On June 5, an order was issued granting CSW's motion for a one-week delay until June 8, 2000. CSW filed a revised plan to create separate legal entities for the power generation, energy delivery, and retail sales functions. II. ORDERING PARAGRAPHS Consistent with the stipulation and settlement, the Commission: 1) Admits into evidence the Supplemental Testimonies of Mark D. Roberson and Wendy G. Hargus, filed May 15, 2000, and the Stipulation, filed June 8, 2000 for the limited purpose of establishing pertinent facts justifying the interim relief granted in this Order; 2) Finds that CSW's proposed plan does not create a "functional separation as opposed to creating legally distinct entities;" 3) Finds that CSW's proposed plan is consistent with PURA ss. 39.051; 4) Finds that the settlement in this docket is in the public interest; PUC DOCKET NO. 21953 Interim Order Page 3 of 3 5) Finds that there is no need for further hearings before the Commission in this docket on the question of whether CSW's proposed plan creates a functional separation, as opposed to creating legally distinct entities; and 6) Finds that issues related to CSW's business separation plan that are not addressed by the settlement, including, but not limited to issues relating to CSW's code of conduct, ratemaking issues, and/or the recovery of restructuring costs, may be considered in the proceeding to review CSW's proposed tariffs for its transmission and distribution utility filed on March 31, 2000 as Dockets No. 22352 (CPL), 22353 (SWEPCO), and 22354 (WTU). SIGNED AT AUSTIN, TEXAS the 7th day of July, 2000. PUBLIC UTILITY COMMISSION OF TEXAS /s/ Pat Wood, III ---------------------------------- PAT WOOD, III, CHAIRMAN /s/ Judy Walsh ---------------------------------- JUDY WALSH, COMMISSIONER /s/ Brett A. Perlman ---------------------------------- BRETT A. PERLMAN, COMMISSIONER EX-99.D3 5 c22015_ex99-d3.txt APPLICATIONS FOR APPROVAL BEFORE THE PUBLIC UTILITIES COMMISSION OF OHIO IN THE MATTER OF THE APPLICATION OF ) COLUMBUS SOUTHERN POWER COMPANY FOR ) APPROVAL OF ELECTRIC TRANSITION PLAN AND ) CASE NO. 99- ___-EL-ETP APPLICATION FOR RECEIPT OF TRANSITION ) REVENUES ) IN THE MATTER OF THE APPLICATION OF ) OHIO POWER COMPANY FOR ) APPROVAL OF ELECTRIC TRANSITION PLAN ) AND APPLICATION FOR RECEIPT OF ) CASE NO. 99- ___-EL-ETP TRANSITION REVENUES ) -------------------------------------------------------------------------------- APPLICATIONS OF COLUMBUS SOUTHERN POWER COMPANY AND OHIO POWER COMPANY FOR APPROVAL OF ELECTRIC TRANSITION PLANS AND APPLICATIONS FOR RECEIPT OF TRANSITION REVENUES -------------------------------------------------------------------------------- Edward J. Brady, Esq. Kevin F. Duffy, Esq. Marvin I. Resnik, Esq. Trial Attorney American Electric Power Service Corporation 1 Riverside Plaza Columbus, Ohio 43215 (614) 223-1606 Fax: (614) 223-1687 Email: miresnik@aep.com Daniel R. Conway, Esq. Porter, Wright, Morris & Arthur 41 South High Street Columbus, Ohio 43215 (614) 227-2270 Fax: (614) 227-2100 Email: dconway@porterwright.com Attorneys for Columbus Southern Power Company and Ohio Power Company BEFORE THE PUBLIC UTILITIES COMMISSION OF OHIO IN THE MATTER OF THE APPLICATION OF ) COLUMBUS SOUTHERN POWER COMPANY FOR ) APPROVAL OF ELECTRIC TRANSITION PLAN AND ) CASE NO. 99- ___-EL-ETP APPLICATION FOR RECEIPT OF TRANSITION ) REVENUES IN THE MATTER OF THE APPLICATION OF ) OHIO POWER COMPANY FOR ) APPROVAL OF ELECTRIC TRANSITION PLAN ) AND APPLICATION FOR RECEIPT OF ) CASE NO. 99- ___-EL-ETP TRANSITION REVENUES ) -------------------------------------------------------------------------------- APPLICATIONS OF COLUMBUS SOUTHERN POWER COMPANY AND OHIO POWER COMPANY FOR APPROVAL OF ELECTRIC TRANSITION PLANS AND APPLICATIONS FOR RECEIPT OF TRANSITION REVENUES -------------------------------------------------------------------------------- I. INTRODUCTION Ohio Power Company ("OPCO") and Columbus Southern Power Company ("CSP") (collectively referred to herein as the "Companies") are "electric utilities" as defined by ss. 4928.01(A)(11), Ohio Rev. Code, supplying "retail electric service," as defined in ss. 4928.01(A)(27). Section 4928.31(A) requires each electric utility to file with the Commission a plan for the utility's provision of retail electric service during the transition to a competitive market, i.e., during "the market development period." Section 4928.31(A) describes the various elements that such a "Transition Plan" must include and others that it may include. Pursuant to ss. 4928.06(A), the Commission promulgated rules for Transition Plans and Consumer Education Plans on November 30, 1999, in Case No. 99-1141-EL-ORD.(1) II. TRANSITION PLAN Accordingly, CSP and OPCO hereby submit their Transition Plan filings under ss. 4928.31(A). As further explained below, the Companies' Transition Plans address all of the five elements that ss. 4928.31(A) requires: (1) a rate unbundling plan; (2) a corporate separation plan; (3) plans to address operational support systems and other technical implementation issues; (4) an employee assistance plan; and (5) a consumer education plan. In addition to those required elements, the Transition Plans address other elements that ss. 4928.31(A) permits, but does not require: (1) tariff terms and conditions to address matters necessary to accommodate electric restructuring; (2) an application for the opportunity to receive transition revenues; and (3) a plan for the independent operation of the Companies' transmission facilities. Finally, the Transition Plans include a shopping incentive plan, pursuant to Rule 4901:1-20-03(C)(3). For purposes of providing a clear understanding of their filings, the Companies have addressed all of the requirements contained in the Commission's rules. A. ELEMENTS OF THE TRANSITION PLAN 1. RATE UNBUNDLING PLAN (PART A) CSP and OPCO will conduct their rate unbundling consistent with ss. 4928.31(A)(1), ss. 4928.34(A)(1) to (7), and Rule 4901:1-20-03, Ohio Administrative Code, Appendix A. Beginning on the starting date of competitive retail electric service, there will be two tariff offerings: the Standard Tariff and the Open Access Distribution Tariff. The first tariff applies to ---------- (1) On December 29, 1999, CSP and OPCO jointly filed an Application for Rehearing and sought clarification of several rules included in the Commission's November 30, 1999 Order. 2 those customers who do not choose an alternative electric supplier and continue to take energy-related services from either of the distribution companies. The second tariff applies to those customers who choose an alternative electric supplier. The rate schedules for the Standard Tariff detail the generation, transmission and distribution components of existing rates and include the following riders: Universal Service Fund, Energy Efficiency Fund, KWH Tax, Gross Receipts Tax Credit, Property Tax Credit, Municipal Income Tax, Franchise Tax and Regulatory Asset Charge. The riders included in the Open Access Distribution Tariff are the same except that there is an additional Transition Charge, but no Property Tax Credit. The tariffs and charges are described in detail in the testimony of Witnesses Thomas, Roush, and Forrester. 2. CORPORATE SEPARATION PLAN (PART B) CSP and OPCO will implement and operate under a Corporate Separation Plan consistent with ss. 4928.31(A)(2) and ss. 4928.17. Since the Code of Conduct, adopted by the Commission under Rule 4901:1-20-16(G)(4), governs relationships between the corporate entities established pursuant to the Corporate Separation Plan, the Code of Conduct will become effective upon implementation of the Corporate Separation Plan. In addition, the Companies will comply with ss. 4928.17(A)(3) as of January 1, 2000. As part of the Corporate Separation Plan, included as Part B, each Company plans to establish a new transmission subsidiary and a new distribution subsidiary, the details of which are set forth in Part B to this Application, and explained in the testimony of Witnesses Forrester, Knorr and Pena. These new distribution subsidiaries will own and operate all of the distribution assets currently owned by CSP and OPCO, respectively. While the new transmission subsidiaries will own the transmission assets, currently owned by CSP and OPCO, respectively, those assets will be operated in a manner described in Witness Baker's testimony. The generation assets will remain with CSP and OPCO. The new distribution and transmission 3 subsidiaries will be public utilities, as defined in ss.ss. 4905.02 and 03. The plan will be implemented with appropriate recognition of the substantial overlapping financial arrangements that currently exist. The goal is to separate each operating company in an orderly and economically efficient manner, and to minimize additional transition costs that result from prematurely unwinding the existing financial arrangements. Because CSP's and OPCO's customers will continue to receive the same level of service, the transaction will be transparent to them. CSP and OPCO request that the Commission approve their Corporate Separation Plan at the same time the Commission approves their Transition Plans. While the Companies believe that Am. Sub. S.B. No. 3 provides the Commission with ample statutory authority by which to approve the proposed Corporate Separation Plan as filed, the Commission may have statutory authority under ss. 4905.48 (B) and (C) and ss. 4905.63(2), to approve the transfer of assets from CSP and OPCO to their transmission and distribution subsidiaries.(3) To the extent the Commission determines to assert jurisdiction over the proposed transactions based on ss. 4905.48 or ss. 4905.63, the Companies urge the Commission to 1) determine that they have met the necessary filing requirements under such statutory provisions ---------- (2) While the two subsidiaries of each Company are not yet public utilities, they will be upon completion of the transaction. Thus, to the extent that the Commission determines that ss. 4905.63, provides jurisdiction to review the transfer of assets that the Companies' Corporate Separations Plans contemplate, the Companies also request the appropriate approvals which that statutory provision contemplates. (3) No abandonment of service will occur as a result of the proposed transactions. Therefore, Commission review of the proposed transfer of assets under ss. 4905.20 and ss. 4905.21 (known as the "Miller Act"), is not necessary and would be inconsistent with the Commission's treatment of similar applications. SEE, WESTERN UNION CORP, Case No. 89-649-TP-ABN (Aug. 6, 1998), COLUMBIA Gas, Case No. 90-754-GA-ATR (Oct. 25, 1990), COLUMBIA GAS, Case No. 90-1561-GA-ATR (Dec. 13, 1980), and NETWORK ONE, Case No. 97-1534-CT-ATR (Aug. 6, 1998). In the event the Commission determines, nevertheless, to assert Miller Act jurisdiction over the proposed transactions, the Companies urge the Commission to conduct its review within the context of the Transition Plan proceedings and to notify the Companies promptly if the Commission requires any additional information to complete its review. In addition, the Companies request that, if the Miller Act is applied, the Commission find that the notice of these Applications is sufficient to satisfy the notice requirements under the Miller Act. 4 through their pending request for approval of their Transition Plans filed in these proceedings, 2) utilize the information provided through testimony and exhibits in the Transition Plan filings as support for approval, and 3) conduct any further review, including a public hearing if necessary, and grant approval within the context of these proceedings. The testimony submitted in support of the Companies' Transition Plans includes extensive information regarding the proposed transactions. If jurisdiction exists under ss. 4905.48 (B) and (C), the information included in the Transition Plan filings fully supports an approval of the transfer of assets under that section. However, should the Commission require any additional information, CSP and OPCO recommend that the Commission seek such information during the course of its review of the Transition Plan filings. Therefore, to the extent the Commission exercises jurisdiction under ss. 4905.48(B) and (C), it should proceed with review and grant approval of the transactions in tandem with its review and approval of the Transition Plans. 3. PLAN(S) TO ADDRESS OPERATIONAL SUPPORT SYSTEMS AND OTHER TECHNICAL IMPLEMENTATION ISSUES (PART C) CSP and OPCO will implement a plan or plans to address operational support systems and other technical implementation issues pertaining to competitive retail electric service. The plan(s) will be consistent with ss. 4928.31(A)(3) and Rule 4901:1-20-03, Appendix B. Those plans are presented in Part C to the Transition Plan filings. Included in that Part is a project timeline which demonstrates that the Companies have already completed a number of activities in an effort to implement operational support systems. The plans are further described in Witness Laine's testimony. 4. EMPLOYEE ASSISTANCE PLAN (PART D) CSP and OPCO have plans for providing severance, retraining, early retirement, retention, outplacement, and other assistance for their employees. The Companies, however, at 5 this time, have not identified any employee who will be affected by electric utility restructuring under Chapter 4928. Therefore, the Companies are not requesting recovery, at this time, of any Employee Assistance Plan costs as part of their Application to Receive Transition Revenue. The Companies' Employee Assistance Plans, which are consistent with ss. 4928.31(A)(4), and Rule 4901:1-20-03, Appendix C, are described in Witness Ackerman's testimony. 5. CONSUMER EDUCATION PLAN (PART E) CSP and OPCO, working with the state's other electric utilities through the Ohio Electric Utility Institute, will implement a statewide and coordinated local-territory campaign plan by which they will provide consumer education on electric restructuring under Chapter 4928. Consistent with ss. 4928.31(A)(5) and ss. 4928.42, and the Commission-ordered consumer education plan set forth in Attachment II of the Commission's November 30, 1999, Order, CSP's and OPCO's Consumer Education Plans will be supervised by the Commission's Staff. The Consumer Education Plans are included in Part E. Additional information regarding the plans is included in Witness Forrester's testimony. B. COMPONENTS OF A TRANSITION PLAN THAT SECTION 4928.31(A) PERMITS 1. TARIFF TERMS AND CONDITIONS TO ADDRESS MATTERS NECESSARY TO ACCOMMODATE ELECTRIC RESTRUCTURING Section 4928.31(A) permits an electric utility to include in its Transition Plan tariff terms and conditions to address matters necessary to accommodate electric restructuring, including reasonable requirements for changing suppliers and the length of commitment by a customer for service. As set forth in Part A, CSP's and OPCO's plans include a tariff for customers who continue to take energy-related services from the Companies and a distribution-only tariff that will apply to any customer who switches to an alternative provider. The tariffs are explained in Witness Thomas's testimony. 6 2. APPLICATION FOR OPPORTUNITY TO RECEIVE TRANSITION REVENUES (PART F) CSP and OPCO hereby apply for an opportunity to receive transition revenues as authorized under ss.ss. 4928.31 to 4928.40. They request recovery of stranded generation costs for the difference between the lower estimated market price of electric energy and the unbundled generation rate of each current applicable rate schedule. The charge for such recovery for each Company will be on a (cent)/KWH basis, as shown on Schedule UNB-2 of the Application. Such costs are to be recovered over the five-year transition period. Further, the Companies request recovery, over a 10-year period, of generation-related regulatory assets, including new regulatory assets resulting from compliance with electric industry restructuring obligations. The transition recovery mechanism is consistent with ss.ss. 4928.31 to 4928.40 and Rule 4901:1-20-03, Appendix D. CSP requests recovery of $363,199,000, attributed to existing and new regulatory assets. OPCO requests recovery of $610,786,000 attributed to existing and new regulatory assets. The recovery amounts are reflected in Witness Roush's testimony. An overview of the transition revenue recovery mechanism is provided in Witness Forrester's testimony. 3. PLAN FOR THE INDEPENDENT OPERATION OF TRANSMISSION FACILITIES (PART G) The Companies will also implement a plan for the independent operation of their transmission facilities. This component of the Transition Plans will be consistent with ss. 4928.12 and ss. 4928.34(A)(13), and Rule 4901:1-20-17, to the extent that such sections and rule are not preempted by federal law, do not improperly interfere with interstate commerce, or are otherwise 7 not beyond the Commission's statutory authority.(4) CSP and OPCO intend to participate in the Alliance RTO, pending FERC approval. The Companies anticipate that the Alliance RTO will be operational during 2001. The plan is set forth in Part G and supported by Witness Baker. 4. SHOPPING INCENTIVE (PART H) The shopping incentives being proposed by each of the Companies are set forth in Part H, which is sponsored by Witness Forrester. The shopping incentives, or "the prices to compare," represent the lower of the market price or the unbundled generation rates of the current tariff for each Company. Company Witness Forrester explains in his testimony why the shopping incentive is not greater than the lower of the market price or the unbundled generation rate and why the Companies are not proposing that the incentive be increased in the second and third years. C. REQUEST FOR ACCOUNTING AUTHORITY TO ESTABLISH NEW REGULATORY ASSETS CSP and OPCO propose to establish new regulatory assets in these Transition Plan proceedings. The new regulatory assets for both Companies include: 1) the cost resulting from SFAS 106 (Post-Retirement Benefits) Transition Obligation; 2) the cost mandated by Am. Sub. S. B. No. 3 for consumer education on electric restructuring; 3) the cost of the development and operation of the operational support systems that the electric distribution service provider must have to allow electric consumers to choose their supplier of electric generation service; and 4) the cost of CSP and OPCO's Transition Plan filings including the public notice required and the necessary hearings on both Companies' transition filings. As set forth in Part F, these other ---------- (4) By submitting an Independent Transmission Plan, the Companies do not waive the arguments made in the Commission's Transition Plan rulemaking proceeding, in Case No. 99-1141-EL-ORD, and their Application for Rehearing filed on December 29, 1999, regarding the limitations of the Commission's jurisdiction to review and approve the Plan. 8 projected transition costs total $73,684,000 for CSP, and $90,260,000 for OPCO. These amounts are supported by Witnesses Forrester, McCoy, and Laine. The Companies request that the Commission grant the necessary financial accounting approvals to permit CSP and OPCO to treat these transition costs as Ohio retail jurisdictional regulatory assets and confirm that the costs will be recovered in regulated rates and reflected as such in their general purpose financial statements. Without such approval and confirmation, the Companies would be required, under financial accounting rules promulgated by the Financial Accounting Standards Board, to write-off those regulatory assets to expense, thereby reducing net income and retained earnings. Thus, the Companies request specific approval in a Commission Order of the amount of generation-related, Ohio retail jurisdictional regulatory assets and the timing of their recovery in accordance with the Transition Cost Recovery Plan included in the Companies' filing. D. CONFIDENTIAL INFORMATION On this same date, CSP and OPCO are filing a Motion for Protective Order to maintain the confidentiality of certain information, identified in that motion, that the Companies deem competitively sensitive and proprietary. The information has been redacted from the filings. In light of the pending public records request of Mr. Dave Rinebolt, on behalf of Ohio Partners for Affordable Energy, for copies of FirstEnergy Corp.'s documents filed under seal with its transition plan, the Companies will not be filing any of the confidential information with the Commission at this time. When the issues regarding the proprietary information that Mr. Rinebolt's public records request raises are finally resolved in a satisfactory manner, the Companies will submit their confidential information under seal. 9 CSP and OPCO intend to provide the confidential information to intervening parties. However, the information will only be provided to the parties subject to mutually agreeable protective arrangements, which address the difficult issues inherent in providing highly competitive confidential information to competitors. The basis for the Companies' entitlement to maintain the confidentiality of their information is more fully explained in the Motion for Protective Order. E. MISCELLANEOUS Attached to this Application is the Companies' witness list which briefly describes the subject matter addressed in each of the witnesses' testimony submitted in support of the Companies' Transition Plans and requests for transition revenues. Concurrent with this filing, the Companies have each provided notice of their Transition Plan filings to all parties to their most recent electric rate cases and conjunctive electric service cases. In addition, a combined public notice of these Applications will be made in accordance with Rule 4901:1-20-05. Copies of these notices are attached as part of this Application. F. CONCLUSION The exhibits filed with these Applications contain the support necessary for the Commission to make the findings required by ss. 4928.34. Therefore, the Companies respectfully request that the Commission approve the Transition Plans as filed and as described in the testimony in support of the Applications, authorize the Companies to collect transition revenues as requested, approve the tariffs filed with the Applications, authorize the accounting changes requested in the Applications, and make any other necessary determinations to meet its statutory obligations under Chapter 4928. Further, the Companies request that, if the Commission 10 determines that it cannot approve the Transition Plans as filed, the Commission hold a hearing on that portion of the Transition Plans subject to question. Respectfully submitted, ------------------------------------- Edward J. Brady, Esq. Kevin F. Duffy, Esq. Marvin I. Resnik, Esq. Trial Attorney American Electric Power Service Corporation 1 Riverside Plaza Columbus, Ohio 43215 (614) 223-1606 Fax: (614) 223-1687 Email: miresnik@aep.com Daniel R. Conway, Esq. Porter Wright Morris & Arthur 41 South High Street Columbus, Ohio 43215-6194 (614) 227-2270 Fax: (614) 227-2100 Email: dconway@porterwright.com Attorneys for Columbus Southern Power Company and Ohio Power Company 11 EX-99.D4 6 c22015_ex99-d4.txt SUMMARY Exhibit 99.D-4 SUMMARY OF THE COMMISSION'S OPINION AND ORDER OF SEPTEMBER 28, 2000 IN THE COLUMBUS SOUTHERN POWER COMPANY AND OHIO POWER COMPANY ELECTRIC TRANSITION PLAN CASES CASE NOS. 99-1729-EL-ETP AND 99-1730-EL-ETP On June 22, 1999, the Ohio General Assembly passed legislation requiring the restructuring of the electric utility industry and providing for retail competition with regard to the generation component of electric service (Amended Substitute Senate Bill No. 3 of the 123rd General Assembly). Governor Bob Taft signed this legislation (SB 3) on July 6, 1999, and most provisions of SB 3 became effective on October 5, 1999. Section 4928.31, Revised Code, requires each electric utility to file with the Commission a transition plan for the company's provision of retail electric service in the state of Ohio. On December 30, 1999, Columbus Southern Power Company and Ohio Power Company (hereinafter jointly referred to as "AEP") filed transition plans, as well as requests for receipt of transition revenues. On May 8, 2000, a stipulation and recommendation on AEP's transition plans, was filed on behalf of the following 23 parties: AEP, Appalachian People's Action Coalition, Association for Hospitals and Health Systems, also d/b/a the Ohio Hospital Association, Buckeye Power, Inc., Columbia Energy Services Corporation, Columbia Energy Power Marketing Corporation, Enron Energy Services, Inc., Industrial Energy Users-Ohio, The Kroger Company, Mid-Atlantic Power Supply Association, National Energy Marketers Association, NewEnergy Midwest, LLC, Ohio Consumers' Counsel, Ohio Council of Retail Merchants, Ohio Department of Development, Ohio Manufacturers' Association, Ohio Partners for Affordable Energy, Ohio Rural Electric Cooperatives, Inc. Peco Energy Company, d/b/a Exelon Energy, Public Utilities Commission staff, Strategic Energy L.L.P., WPS Energy Services, Inc., and WSOS Community Action Commission, Inc. Dynegy, Inc. and Ohio Environmental Council have stated that they do not oppose the May 8, 2000 stipulation. The evidentiary hearings were held on May 9, 31, and June 7, 8, and 12, 2000. Local public hearings were held on June 5, 2000, in East Liverpool, Ohio and on June 22, 2000, in Columbus, Ohio. On June 19, 2000, AEP and Ameritech New Media, Inc. filed a stipulation to resolve their differences. 99-1729-EL-ETP and 99-1730-EL-ETP -ii- In the opinion and order, the Commission is approving the agreements submitted by the various parties listed above with certain modifications regarding the load shaping service, the operational support plan, and the employee assistance plan. The Commission defers a ruling upon the independent transmission plan, as allowed by Section 4928.34(A)(13), Revised Code. The Commission found that the terms of the agreements, considered in their totality, advance the public interest and provides substantial benefits to all customer classes. The stipulations provide for extended rate freezes, flexibility for larger contract customers not otherwise available, and defined transition periods for AEP. The stipulations, among other things: (1) Provide a five-percent reduction of AEP's generation component for residential rate schedules; (2) Create shopping credits that facilitate the development of the retail marketplace; (3) Commit AEP to absorb certain costs associated with transitioning to a competitive marketplace; (4) Commit AEP to provide certain types of assistance to transmission users for a period of time; (5) Commit AEP to provide funds (up to $10 million) for reimbursement of certain transmission costs of suppliers and customers; (6) Commit AEP to develop and propose resolutions of reciprocity and interface/seams issues; (7) Provide a credit to suppliers for consolidated billing; and (8) Provide relief from certain charges for certain customers that switch suppliers between 2006 and 2007. The Commission also determined that AEP's transition plan filings, as amended by the settlement agreements and subject to the conclusions in the decision, are in compliance with the statutory requirements contained in SB 3. By approving the stipulations as set forth in this decision, the Commission also authorizes certain accounting treatments for AEP to create the necessary regulatory assets, defer costs, and recover those costs through a regulatory transition charge. THIS SUMMARY WAS PREPARED TO PROVIDE A BRIEF STATEMENT OF THE COMMISSION'S ACTION IN THESE CASES. IT IS NOT PART OF THE COMMISSION'S DECISION AND DOES NOT SUPERSEDE THE FULL TEXT OF THE COMMISSION'S OPINION AND ORDER. TABLE OF CONTENTS APPEARANCES:..................................................................1 OPINION: .....................................................................3 I. SUMMARY OF THESE PROCEEDINGS.............................................3 II. SUMMARY OF THE STIPULATIONS .............................................6 III. OPPOSITION TO THE TRANSITION PLANS AND STIPULATIONS AND REVIEW OF SECTION 4928.34, REVISED CODE........................................9 A. Unbundling Plan and Transition Costs...............................10 1. MDP Shopping Incentives....................................11 2. Post-MDP Incentive for OP Residential Customers .......... 14 3. Commission's Future Ability to Respond to the Market ..... 15 4. Generation Transition Charges and Stranded Generation Benefits .............................................. 15 5. Frozen Generation Rates ...................................18 6. Distribution Rate Freeze...................................19 7. USF Rider and EERLF Rider..................................20 8. Load Shaping Service.......................................20 9. Remaining Concerns with the Unbundling Plan and Transition Costs .......................................21 B. Corporate Separation Plan .........................................23 C. OSP ...............................................................25 1. Supplier Consolidated Billing Credit ......................26 2. Residential Customer Switching/Minimum Stay Requirement ...28 3. Switching Fee and Alternative Metering Credit .............29 4. Supplier Registration Requirements.........................30 5. Overall OSP Conclusion ....................................31 D. Employee Assistance Plan (EAP) ....................................32 E. Consumer Education Plan ...........................................33 F. Independent Transmission Plan .....................................34 G. Section 4928.34(A)(14), Revised Code ..............................37 H. Accounting Authority .... .........................................37 IV. THREE-PART TEST FOR EVALUATING STIPULATIONS.............................38 V. GROSS RECEIPTS/EXCISE TAX ISSUE.........................................40 VI. FILED MOTIONS ..........................................................45 A. Motions to Reject Transition Plans as Inadequate ..................45 B. OCTA Motion to Intervene and Subsequent Conditional Withdrawal ....45 C. Motion for Protective Order .......................................45 D. Motion for Compliance Tariff Review Process .......................46 FINDINGS OF FACT AND CONCLUSIONS OF LAW: ....................................47 ORDER: ......................................................................48 BEFORE THE PUBLIC UTILITIES COMMISSION OF OHIO In the Matter of the Applications of ) Columbus Southern Power Company and ) Ohio Power Company for Approval of ) Case Nos. 99-1729-EL-ETP Their Electric Transition Plans and for ) 99-1730-EL-ETP Receipt of Transition Revenues ) OPINION AND ORDER The Commission, coming now to consider the stipulations, testimony, and other evidence presented in these proceedings, hereby issues its Opinion and Order. APPEARANCES: ------------ Marvin I. Resnick, Edward J. Brady, and Kevin F. Duffy, American Electric Power Service Corporation, One Riverside Plaza, Columbus, Ohio 43215, and Porter, Wright, Morris & Arthur, LLP, by Daniel R. Conway and Mary Kay Fenlon, 41 South High Street, Columbus, Ohio 43215-6194, on behalf of Columbus Southern Power Company and Ohio Power Company. Betty D. Montgomery, Attorney General of the State of Ohio, by Duane W. Luckey, Section Chief, and Thomas W. McNamee and Stephen A. Reilly, Assistant Attorneys General, Public Utilities Section, 180 East Broad Street, 9th Floor, Columbus, Ohio 43215-3793, on behalf of the staff of the Public Utilities Commission of Ohio. Betty D. Montgomery, Attorney General of the State of Ohio, by Jodi M. Elsass-Locker, Assistant Attorney General, 77 South High Street, 29th Floor, Columbus, Ohio 43215, and Maureen R. Grady, 369 South Roosevelt Avenue, Columbus, Ohio 43209, on Behalf of the Ohio Department of Development. Robert S. Tongren, Ohio Consumers' Counsel, and Colleen L. Mooney, Terry L. Etter, Ann M. Hotz, and Dirken D. Winkler, Assistant Consumers' Counsel, 10 West Broad Street, Suite 1800, Columbus, Ohio 43215-3485, on behalf of the residential customers of Columbus Southern Power Company and Ohio Power Company. McNees, Wallace & Nurick, by Samuel C. Randazzo, Gretchen J. Hummel, and Kimberly J. Wile, Fifth Third Center, 21 East State Street, Suite 1700, Columbus, Ohio 43215-4228, on behalf of Industrial Energy Users-Ohio. Boehm, Kurtz & Lowry, by Michael L. Kurtz, 2110 CBLD Center, 36 East Seventh Street, Cincinnati, Ohio 45202, on behalf of The Kroger Company. Chester, Willcox & Saxbe LLP, by John W. Bentine and Jeffrey L. Small, 17 South High Street, Suite 900, Columbus, Ohio 43215, and William T. Zigli and Ivan L. Henderson, 601 Lakeside Avenue, Room 106, Cleveland, Ohio 44144, and Climaco, Lefkowitz, Peca, Wilcox & Garfoli Co. LPA, by Anthony J. Garfoli, Joe Hegedus, and Scott Simpkins, on behalf of the city of Cleveland. 99-1729-EL-ETP and 99-1730-EL-ETP -2- Chester, Willcox & Saxbe LLP, by John W. Bentine and Jeffrey L. Small, 17 South High Street, Suite 900, Columbus, Ohio 43215, on behalf of the Ohio Council of Retail Merchants and American Municipal Power-Ohio, Inc. Craig G. Goodman, 3333 K Street, NW, Suite 425, Washington D.C. 20007, on behalf of The National Energy Marketers Association. Calfee, Halter & Griswold LLP, by Kevin M. Sullivan, Richard J. Mattera, and Peter A. Rosato, 1400 McDonald Investment Center, 800 Superior Avenue, Cleveland, Ohio 44114, on behalf of Ameritech New Media, Inc. William M. Ondrey Gruber, 2714 Leighton Road, Shaker Heights, Ohio 44120, and Vicki L. Deisner, 1207 Grandview Avenue, Room 201, Columbus, Ohio 43212-3449, on behalf of Ohio Environmental Council. David C. Rinebolt, 337 South Main Street, 4th Floor, Suite 5, Findlay, Ohio 45840, on behalf of Ohio Partners for Affordable Energy. Ohio State Legal Services Association, by Michael R. Smalz, 861 North High Street, Columbus, Ohio 43215, on behalf of the Appalachian People's Action Coalition. Ellis Jacobs, 333 West First Street, Suite 500, Dayton, Ohio 45402, on behalf of the WSOS Community Action Commission, Inc. Bricker & Eckler LLP, by Sally W. Bloomfield, Elizabeth H. Watts, and Amy Straker Bartemes, 100 South Third Street, Columbus, Ohio 43215-4291, on behalf of Mid-Atlantic Power Supply Association, Columbia Energy Services Corporation, Columbia Energy Power Marketing Corporation, and Ohio Manufacturers' Association. Bricker & Eckler LLP, by Sally W. Bloomfield, Elizabeth H. Watts, and Amy Straker Bartemes, 100 South Third Street, Columbus, Ohio 43215-4291, and David Dulick, 2600 Monroe Boulevard, Norristown, Pennsylvania 19403, on behalf of Peco Energy d/b/a Exelon Energy. Bricker & Eckler LLP, by Sally W. Bloomfield, Elizabeth H. Watts, and Amy Straker Bartemes, 100 South Third Street, Columbus, Ohio 43215-4291, and Wanda M. Schiller, Two Gateway Center, Pittsburgh, Pennsylvania 15222, on behalf of Strategic Energy L.L.C. Sutherland Asbill & Brennan LLP, by Paul F. Forshay, Keith McCrea, James M. Bushee, David A. Codevilla, and Daniel J. Oginsky, 1275 Pennsylvania, Avenue, NW, Washington D.C. 20004-2415; and Amy Gold, P.O. Box 4402, Houston, Texas 77210, on behalf of Shell Energy Services Co., LLC. Vorys, Sater, Seymour & Pease, by M. Howard Petricoff, 52 East Gay Street, P.O. Box 1008, Columbus, Ohio 43216-1008, on behalf of NewEnergy Midwest, LLC and WPS Energy Services, Inc. 99-1729-EL-ETP and 99-1730-EL-ETP -3- Vorys, Sater, Seymour & Pease, by M. Howard Petricoff, 52 East Gay Street, P.O. Box 1008, Columbus, Ohio 43216-1008, and Janine L. Migden, Enron Corp., 400 Metro Place North, Dublin, Ohio 43017-3375, on behalf of Enron Energy Services, Inc. Vorys, Sater, Seymour & Pease, by M. Howard Petricoff and Joseph C. Blasko, 52 East Gay Street, P.O. Box 1008, Columbus, Ohio 43216-1008, and David L. Cruthirds, 1000 Louisiana Street, Suite 5800, Houston, Texas 77002-5050, on behalf of Dynegy, Inc. Vorys, Sater, Seymour & Pease, by Philip F. Downey and Stephen M. Howard, 52 East Gay Street, P.O. Box 1008, Columbus, Ohio 43216-1008, on behalf of the Ohio Cable Telecommunications Association. Thompson Hine & Flory, LLP, by Robert P. Mone and Scott A. Campbell, 10 West Broad Street, Suite 700, Columbus, Ohio 43215, on behalf of Ohio Rural Electric Cooperatives, Inc. and Buckeye Power, Inc. Logothetis, Pence & Doll, by John R. Doll, 111 West First Street, Suite 1100, Dayton, Ohio 45402-1156, and Speigel & McDairmid, by Cynthia S. Bogorad, Scott H. Strauss, David B. Lieb, 1350 New York Avenue NW, Suite 1100, Washington D.C. 20005-4798, on behalf of United Workers Union of America, AFL-CIO, and the Utility Workers Union of America, Local Union Nos. 111, 116, 296, 468, 478, 492, and 544. Richard L. Sites, 155 East Broad Street, 15th Floor, Columbus, Ohio 43215, on behalf of the Association for Hospitals and Health Systems, also d/b/a Ohio Hospital Association. Taft, Stettinius & Hollister LLP, by James J. Mayer, 1800 Firstar Tower, 425 Walnut Street, Cincinnati, Ohio 45202-3957, and Thomas J. Russell, Unicom, Corporation, 125 Clark Street, Room 1535, Chicago, Illinois 60603, on behalf of Unicom Energy, Inc. and Unicom Energy Services, Inc. Thomas M. Myers, 56000 Dilles Bottom, Shadyside, Ohio 43947, on behalf of International United Mine Workers of America (UMWA), AFL-CIO, and UMWA District Six; Local Union Nos. 1604, 1857, 1886, and 6362. OPINION: I. HISTORY OF THESE PROCEEDINGS On June 22, 1999, the Ohio General Assembly passed legislation requiring the restructuring of the electric utility industry and providing for retail competition with regard to the generation component of electric service (Amended Substitute Senate Bill No. 3 of the 123rd General Assembly). Governor Bob Taft signed this legislation (hereinafter SB3) on July 6, 1999, and most provisions of SB 3 became effective on October 5, 1999. Section 4928.31, Revised Code, requires each electric utility to file with the Commission a transition plan for the company's provision of retail electric service in the state of Ohio. The plan must include a rate unbundling plan, a corporate separation plan, a plan to address operational support systems and any other technical implication issues 99-1729-EL-ETP and 99-1730-EL-ETP -4- related to competitive retail electric service, an employee assistance plan, and a consumer education plan. On November 30, 1999, as subsequently modified and/or clarified on January 4, 20, and 27, and February 17, 2000, the Commission adopted rules for the filing and processing of electric transition plans and adopted a consumer education framework. IN THE MATTER OF THE COMMISSION'S PROMULGATION OF RULES FOR ELECTRIC TRANSITION PLANS AND OF A CONSUMER EDUCATION PLAN, PURSUANT TO CHAPTER 4928, REVISED CODE, Case No. 99-1141-EL-ORD. On December 30, 1999, the Columbus Southern Power Company and Ohio Power Company(l) each filed transition applications with the Commission. Each company requested approval of its electric transition plan and for authorization to recover transition revenues. Thereafter, on January 14 and February 28, 200O, AEP filed amendments to the transition plan applications. A technical conference was conducted on January 10, 2000 at which AEP explained its filing and answered questions from participants. Preliminary objections to the applications were submitted on February 10, 11, 14, and 15, 2000. Pursuant to Section 4928.32(B), Revised Code, the Staff Report of Exceptions and Recommendations was filed on March 28, 2000. A procedural/settlement conference was conducted on March 3, 2000, and, on March 10, 2000, the attorney examiner issued an entry summarizing the rulings made during the conference and scheduling an additional prehearing conference. AEP filed additional supplemental testimony on April 18, 2000, in accordance with the attorney examiner's directive. Intervention was granted in this proceeding to the following parties: Appalachian People's Action Coalition (APAC); American Municipal Power-Ohio, Inc. (AMP-Ohio); Ameritech New Media, Inc. (ANM); Association for Hospitals and Health Systems, also d/b/a the Ohio Hospital Association (OHA); Buckeye Power, Inc.; City of Cleveland (Cleveland); Columbia Energy Services Corporation; Columbia Energy Power Marketing Corporation (Columbia Energy companies(2)); Dynegy, Inc. (Dynegy); Enron Energy Services, Inc. (Enron); Industrial Energy Users-Ohio (IEU-Ohio); The Kroger Company (Kroger); Mid-Atlantic Power Supply Association (MAPSA); National Energy Marketers Association (NEMA); --------- (1) The two utilities will be referred to individually as "CSP" and "OP" or collectively as "the companies" or "AEP", since the utilities are operating companies within the American Electric Power family. (2) Columbia Energy Services Corporation and Columbia Energy Power Marketing Corporation jointly filed a motion to intervene in these proceedings and shall be jointly referred to as "Columbia Energy companies". 99-1729-EL-ETP and 99-1730-EL-ETP -5- New Energy Midwest, LLC (New Energy); Ohio Consumers' Counsel (OCC); Ohio Council of Retail Merchants (OCRM); Ohio Department of Development (ODOD); Ohio Environmental Council (OEC); Ohio Manufacturers' Association (OMA); Ohio Partners for Affordable Energy (OPAE); Ohio Rural Electric Cooperatives, Inc. (OREC(3)); Peco Energy Company, d/b/a Exelon Energy (Exelon); PP&L EnergyPlus Co., LLC (EnergyPlus);(4) Shell Energy Services Company, L.L.C. (Shell); Strategic Energy L.L.P. (Strategic); Unicom Energy, Inc.; . Unicom Energy Services, Inc. (Unicom(5)); United Mine Workers of America, AFL-CIO; UMWA District Six, Local Union Nos. 1604, 1857, 1886, and 6362 (UMWA(6)); Utility Workers Union of America, AFL-CIO; Utility Workers Union of America, Local Union Nos. 111, 116, 296, 468, 478, 492, and 544 (UWUA(7)); WPS Energy Services, Inc. (WPS); and WSOS Community Action Commission, Inc. (WSOS). The joint motion to intervene by Ohio Edison Company, The Cleveland Electric Illuminating Company, and The Toledo Edison Company was denied on March 23, 2000. The Ohio Cable Telecommunications Association (OCTA) filed to intervene in these proceedings. However, OCTA filed two days later a notice of conditional withdrawal of its intervention request. The second prehearing conference was conducted as scheduled on April 28, 2000. On May 8, 2000, a stipulation and recommendation (Jt. Ex. 1) was filed. That stipulation was signed by AEP, the Commission staff, APAC, Columbia Energy companies, Enron, NewEnergy, WPS, Exelon, IEU-Ohio, Kroger, MAPSA, NEMA, OCC, OCRM, OHA, OPAE, OREC, Strategic, WSOS, ODOD, and OMA. The stipulation purports to resolve all issues in these proceedings, except for one issue related to AEP's proposed gross receipts/excise tax rider. Dynegy and OEC later stated that they do not oppose the stipulation. On May 8, 2000, Shell filed testimony opposing the transition plans in several respects. The hearing ----------- (3) Buckeye Power, Inc. and Ohio Rural Electric Cooperatives, Inc. jointly filed a motion to intervene in these proceedings and shall be jointly referred to as "OREC". (4) EnergyPlus was granted intervention in these proceedings, but filed a notice of withdrawal on March 13, 2000. (5) Unicom Energy, Inc. and Unicom Energy Services, Inc. jointly filed a motion to intervene in these proceedings and shall be jointly referred to as "Unicom". (6) United Mine Workers of America, AFL-CIO and UMWA District Six, Local Union Nos. 1604, 1857, 1886, and 6362 jointly filed a motion to intervene in these proceedings and shall be jointly referred to as "UMWA". (7) Utility Workers Union of America, AFL-CIO, and Utility Workers Union of America, Local Union Nos. 111, 116, 296, 468, 478, 492, and 544, jointly filed a motion to intervene in these proceedings and shall be jointly referred to as "UWUA". 99-1729-EL-ETP and 99-1730-EL-ETP -6- began on May 9, 2000, at which time it became clear that there was opposition to the proposed stipulation. At the request of the parties, the hearing was continued and, pursuant to oral rulings made by the attorney examiners, parties interested in the gross receipts/excise tax issue were given an opportunity to present evidence for the Commission's consideration. Additionally, parties were given the opportunity to present evidence in support of and in opposition to the stipulation. The hearing then continued on May 31, June 7, 8, and 12, 2000. Only AEP, OCC, Shell, the staff, and UWUA participated in the later stages of the hearing. On June 19, 2000, AEP and ANM file an agreement to remove from AEP's transition plan proceedings the substantive issues related to AEP's originally proposed pole attachment tariff provisions. Those two parties agreed that the pole attachment issues should instead be addressed in two cases already pending before the Commission. IN THE MATTER OF APPLICATIONS OF COLUMBUS SOUTHERN POWER COMPANY AND QHIO POWER COMPANY FOR APPROVAL OF POLE ATTACHMENT TARIFFS AND RELATED MATTERS, Case Nos. 97-1568-EL-ATA and 97-1569-EL-ATA. Local public hearings were conducted on June 5 and 22, 2000, in East Liverpool and Columbus, Ohio, respectively. On July 10, 25, and 26, 2000, AEP, OCC, Shell, the staff, IEU-OH, and UWUA filed briefs. II. SUMMARY OF THE STIPULATIONS The stipulation submitted on May 8, 2000 provides, among other things, that the companies' transition plans (as then-supplemented and revised) should be approved, except as specifically modified in that stipulation. Additionally, the stipulation states that: (1) Neither company will impose any lost revenue charges (generation transition charges) on any switching customer (Sec. IV). (2) All distribution electric rates in effect on December 31, 2005, will be frozen through December 31, 2007 for OP and through December 31, 2008 for CSP. Such frozen rates can, however, be adjusted to reflect the cost of complying with changes in environmental (distribution-related), tax and regulatory laws or regulations, relief from storm damage expenses, in the event of an emergency, or to reflect changes in the transmission/distribution facilities allocation (Sec. V). (3) CSP will absorb the first $20 million of consumer education, customer choice implementation, and transition plan filing costs and will be permitted to defer the remainder of those actual costs (estimated to be $40.6 million), plus a carrying charge and recover those costs by a rider as a cost of service in future distribution rates. OP will absorb the first $20 million of consumer education, customer choice implementation, and transition plan filing costs and will be permitted to defer the remainder of those actual costs (estimated to be $45.5 million), 99-1729-EL-ETP and 99-1730-EL-ETP -7- plus a carrying charge and recover those costs by a rider as a cost of service in future distribution rates. Determination of costs to be recovered (including the carrying charge) will be subject to Commission review (Sec. VI). (4) During the market development period (MDP), CSP will provide a shopping incentive of 2.5 mills/kilowatt-hour to the first 25 percent of the residential class load that switches to a competitor. Any unused portion of that shopping incentive will be credited to CSP's regulatory transition cost recovery. There will be no further shopping incentive for CSP and no shopping incentive at all for OP (Sec. VII). (5) AEP will transfer, by December 15, 2001, all operational control of transmission facilities to an operating regional transmission organization (RTO) that is approved by the Federal Energy Regulatory Commission (FERC). In the meantime, the companies will provide up to $10 million for certain costs imposed upon any supplier or customer associated with transmission charges imposed by the Pennsylvania-New Jersey-Maryland (PJM) Independent System Operator and/or Midwest Independent System Operator (MISO) for generation originating in those areas (Sec. VIII).(8) (6) The companies shall refile: (a) the unbundled residential tariffs so as to reflect a five percent reduction in the generation component, including the regulatory transition charge (RTC) component, and shall not seek to reduce that five percent during the MDP; and (b) the tariffs and UNB-8 schedules so as to achieve a revenue-neutral rate design and equalized bills within the commercial class (Sec. IX and X). (7) For issues being handled by the operational support plan (OSP) working group, the signatory parties accept any resolutions agreed upon by the working group. Further, the companies agree to abide by the determinations of the Commission as they relate to OSP issues (Sec. XI). (8) With respect to customer switching, the operating companies agree that, during the MDP, customers that can take generation service from the companies during any part of May 16 through September 15 must either remain a customer through April 15 of the following year or choose a market-based tariff which will not be lower than the generation cost ------------ (8) The stipulation specifically noted that, if any governmental agency invalidates or imposes conditions upon this aspect of the stipulation, the provision is deemed withdrawn and the parties agree to negotiate in good faith to restore the value of the provision. 99-1729-EL-ETP and 99-1730-EL-ETP -8- embedded in the standard offer. Nonaggregated residential customers will be permitted to shop three times during the MDP and to return two times to the default tariff before being required to choose from one of the above two options (Sec. XII). (9) The companies shall provide distribution services to each retail customer or supplier of electric energy in the same quality and price and subject to the same terms and conditions as provided by the companies to similarly situated retail customers, itself or any affiliate. Before participating in an approved RTO, the companies and/or their affiliates shall provide transmission services under their pro forma transmission tariff and in compliance with federal conduct requirements (Sec. XIII). (10) AEP will provide a $1.00 credit to suppliers for each consolidated bill issued by that provider during the first year of the MDP. The signatory parties agree to further negotiate a similar future credit. AEP shall reasonably attempt to implement supplier consolidated billing as soon as practicable (Sec. XIV). (11) Commercial and industrial customers need only provide 90 days notice to the companies of their intent to purchase electricity from another supplier, including providing such notice 90 days prior to January 1, 2001 (Sec. XV). (12) The companies' revenues from RTCs during the transition period and from existing frozen and unbundled rates recovered during the MDP are sufficient to recover regulatory assets as of the beginning of the MDP and for obligations required by the stipulation. The signatory parties agree that the Commission should direct the companies to amortize such regulatory assets during the MDP and thereafter, until fully amortized. Recorded regulatory assets as of the beginning of the MDP should be amortized on a per-kilowatt basis during the MDP and recovered through existing frozen and unbundled rates. Additionally, the signatory parties suggest that the Commission specifically address concerns of potential violations of the Internal Revenue Code's normalization rules regarding amortization of liabilities related to investment tax credits and excess deferred income taxes (Sec. XVII and Attach. I). (13) Between January 1, 2006 and December 31, 2007, the first 20 percent of OP residential customer load that switches from OP's standard offer as of December 31, 2005, to another provider will not be charged the RTC. Customers that remain 99-1729-EL-ETP and 99-1730-EL-ETP -9- on the standard offer under Section 4928.14(A) or (B), Revised Code, do not count as load that switches to a new provider (Sec. XVIII).(9) (14) AEP and the signatory marketers will further negotiate an AEP load shaping service. All such marketing intervenors shall be notified of dates, times, and locations for such meetings (Sec. XIX). (15) The operating companies will establish Universal Service Fund (USF) riders and Energy Efficiency Revolving Loan Fund (EERLF) riders at the rates determined by ODOD and approved by the Commission (Sec. XX). (16) The marketer intervenors' acceptance of the companies' corporate separation plan does not constitute acceptance of the companies' interpretation of Rule 4901:1-20-16(G)(4), Ohio Administrative Code (O.A.C.), relating to code of conduct (Sec. XXI). (17) The parties agree that the stipulation is conditioned upon acceptance in its entirety and without alteration. If the Commission rejects all or part of the agreement, or materially modifies its terms, any adversely affected party may file an application for rehearing or terminate and withdraw from the stipulation (Sec. XXII). As noted above, a second stipulation was filed in these dockets. On June 19, 2000, AEP and ANM filed a stipulation (hereinafter referred to as the ANM agreement, so as to distinguish it from the other stipulation) to remove from AEP's transition plan proceedings the substantive issues related to AEP's originally proposed pole attachment tariff provisions. Among other things, ANM does not object to AEP'S proposed withdrawal of the originally proposed pole attachment tariffs, while AEP agrees to not object to ANM's involvement (including discovery activities) in AEP's pending pole attachment tariff proceedings in Case Nos. 97-1568-EL-ATA and 97-1569-EL-ATA, SUPRA. AEP further agrees to not include the originally proposed pole attachment tariff provisions in any filing in the transition plan proceedings. III. OPPOSITION TO THE TRANSITION PLANS AND STIPULATIONS AND REVIEW OF SECTION 4928.34, REVISED CODE Although a large number of parties were granted intervention in this proceeding, only Shell and the UWUA continued to offer any opposition to AEP's transition plans, as modified by the settlement agreements entered into by the majority of parties. The UWUA addressed only one issue related to AEP's employee assistance plan. Shell, on the other hand, takes issue with several particular aspects of the transition plan stipulation on ---------- (9) The stipulation specifically noted that, if this provision is rejected by the Commission or determined unlawful by a court, the remainder of the stipulation will remain in effect. 99-1729-EL-ETP and 99-1730-EL-ETP -10- legal and conceptual grounds. Moreover, in Shell's view, it does not believe that the stipulation as a whole will establish the incentives for competitive suppliers to either enter AEP's service territory or remain there over time, all the while providing a financial windfall to AEP, (Shell Initial Br. at 3-4, 61-66, 68; Shell Reply Br. at 1-2, 7, 17). AEP OCC, IEU-Ohio, and the staff argue that the stipulation balances the diverse interests of nearly all parties to these proceedings and provides a number of varied benefits that are in the public interest, some of which are beyond what the Commission has authority to order (AEP Ex. 18, at 5-10; AEP Initial Br. at 10; OCC Initial Br. at 12-13; OCC Reply Br. at 11; IEU Br. at 3-4; Staff Initial Br. at 5, 6-8; Staff Reply Br. at 3-4). As noted earlier, Section 4928.31(A), Revised Code, provides that the company's transition plan must include a rate unbundling plan that specifies the unbundled components for electric generation, transmission, and distribution service components to be charged by the company on the start date of competitive retail electric service. The transition plan must also contain a corporate separation plan, a plan to address operational support systems, an employee assistance plan, and a consumer education plan (ID.). AEP's transition plans include those, as well as other proposals. Section 4928.34(A), Revised Code, requires the Commission to make determinations with respect to 15 separate "prerequisites" prior to approving a company's transition plan. Each of the opposing intervenors' comments and the 15 prerequisites is discussed below. A. UNBUNDLING PLAN AND TRANSITION COSTS Beginning on the start date of competitive electric service, AEP proposes two tariff offerings: the standard tariff for customers who do not choose an alternative electric supplier and the open access distribution tariff for customers who do choose an alternative electric supplier. AEP's transition plan proposed that the open access distribution tariff be similar to the standard tariff, except that a stranded, generation transition charge (GTC) applies and no property tax credit applies (AEP Ex. 2, Part A). The individual components were derived based upon cost-of-service studies from CSP's and OP's last rate cases and were then functionalized (AEP Ex. 24A at 13-14). Adjustments were made to reflect the overall revenue level resulting from the prior rate cases and to match individual customer class revenues (ID.). For CSP, special adjustments were made so that the adjusted distribution component equaled the sum of the unbundled distribution and transmission components, less the revenue generated by the Open Access Transmission Tariff (OATT) (AEP Ex. 8A at 4). AEP sought recovery of stranded generation costs during the MDP and regulatory assets over the full 10-year period allowed by Section 4928.40, Revised Code (AEP EX. 16, at 9-10; AEP Ex. 9A at 13). The companies also identified several transition costs that they requested be established as new regulatory assets (AEP EX. 2, Part F, Sec. (B)(1)(a); AEP Ex. 16, at 6; AEP Ex. 9A at 8-12; AEP Ex. 9C at 6). AEP included the five-percent reduction required by Section 4928.40 (C), Revised Code, in the proposed residential service rates (AEP Ex. 24A at 19). 99-1729-EL-ETP and 99-1730-EL-ETP -11- AEP proposed to recover the following under the transition plan as filed: Company Regulatory Assets Other Transition Costs Total ------- ----------------- ---------------------- ----- CSP $289,515,000 $73,684,000 $363,199,000 OP $520,526,000 $90,260,000 $610,786,000 (AEP Ex. 2, Part F). AEP contends that the stipulation provides additional benefits to the proposed unbundling plan and transition charges in several ways (AEP Initial Br. at 21-22, 59, 65-67). First, all distribution rates will be mostly frozen, effective December 15, 2005 through 2007 for OP and through 2008 for CSP (Jt. Ex. 1, at 3-4). Second, the frozen distribution rates can be adjusted to reflect changes in the functionalization of the transmission/distribution facilities under FERC's seven-factor test (ID. at 4). Third, the companies' tariffs and UNB-8 schedules will be revised consistent with Attachment 2 to the stipulation, in order to achieve revenue neutral rate designs and to equalize bill impacts for commercial customers (ID. at 7). Fourth, the companies will refile unbundled residential rate schedules that apply a five-percent reduction of the generation component, including the RTC component (ID. at 6). Fifth, the stipulation shortens the period during which the companies can recover stranded generation-related regulatory assets (from 10 years to seven years for OP and eight years for CSP) and limits the RTC levels for several years (ID. at 4 and Attach. 1). Next, the stipulation also specifies the levels of the RTCs for seven- and eight-year periods (ID. at Attach. 1). Under the stipulation, the companies can recover the following amounts as transition costs: Company In RTC During MDP In Distribution Rates in Later Years ------- ----------------- ------------------------------------ CSP $191,156,000 $40,526,000 OP $425,230,000 $45,533,000 (ID.; Tr. III, 50, 141). Additionally, AEP states that the companies have each foregone assessing its proposed GTCs on switching customers and $20 million in customer education, customer choice implementation and transition plan filing costs (Jt. Ex. 1, at 3 and 4). The remainder of customer education, customer choice implementation and transition plan filing costs (approximately $40.5 and $45.5 million) will be deferred. CSP has agreed to provide an additional shopping incentive of 2.5 mills/kilowatt-hour for the first 25 percent of CSP's residential load that switches during the MDP, with the unused portion at December 31, 2005, being credited to the RTC (ID. at 5). Lastly, OP agreed that, for 2006 and 2007, the first 20 percent of OP residential customers that switch will not be charged the RTC (ID. at 10). 1. MDP SHOPPING INCENTIVES AEP's transition plans proposed shopping incentives that were the lower of the estimated market cost of electric energy or the unbundled generation rate (AEP Ex. 9A at 28; AEP Ex. 2 at Part H; Tr. IV, 105). AEP did not propose to increase the incentives in the MDP (AEP Ex. 9A at 28-29). The stipulation includes an explicit additional shopping 99-1729-EL-ETP and 99-1730-EL-ETP -12- incentive of 2.5 mills/kWh for the first 25 percent of CSP's residential load that switches during the MDP, with the unused portion at December 31, 2005, being credited to the RTC (Jt. Ex. 1, at 5). In AEP's view, the transition plan stipulation would increase the proposed shopping incentive amounts by virtue of the companies agreeing to forego the amount of the GTCs and by the additional 2.5 mills/kilowatt-hour for the CSP residential class (AEP Initial Br. at 43).(10) AEP acknowledges that the stipulation states that "there will be no shopping incentive for [OP]", but contends that the language means there will be no explicit monetary incentive for OP customers during the MDP beyond that set forth in the plan (AEP Reply Br. at 22). Additionally, AEP argues that several other provisions in the stipulation constitute monetary and structural incentives to encourage shopping for CSP and OP customers (Tr. III, 148, 153, 157-160, 165, 167; AEP Reply Br. at 20-22). Shell has criticized the shopping incentive provisions of the stipulation for several reasons. In Shell's opinion, the key to engendering good alternatives to the standard offer during the MDP is an adequate shopping credit structure that reflects the costs of serving retail markets and that adjusts to reflect significant changes in underlying wholesale costs (Shell Initial Br. at 2).(11) First, Shell argues that the shopping credit scheme does not meet the requirements of SB 3 since the stipulation does not provide any shopping incentive for CSP commercial customers or for any OP customers during the entire MDP (ID. at 13; Shell Ex. 7, at 4, 8). In this respect, Shell states that neither the stipulation nor the transition plan provides a complete shopping incentive that will meet the statutory minimum switch rate or the Commission's requirements (Shell Initial Br. at 13-14; Shell Reply Br. at 9-12). Next, Shell states that the stipulation's terms discriminate against OP residential ratepayers since the CSP counterparts will have a shopping credit (Shell Ex. 7, at 4; Shell Initial Br. at 13-18). Also, Shell argues that the CSP shopping incentive is too small to produce the 20 percent load switching during the MDP (Shell Ex. 7, at 9-10; Shell Initial Br. at 12, 14, 18-19). Shell further states that there has been no evidence to support the CSP shopping credit level. Additionally, Shell states that, since there is no designated shopping credit for OP, the credit is simply the unbundled generation component in OP's tariff (Shell Ex. 6, at 49; Shell Ex. 7, at 8; Shell Initial Br. at 19). Shell provides an illustration as to why a marketer cannot effectively compete in AEP's territory under these circumstances (Shell Initial Br. at 19-23). Shell further states that the proposed fixed shopping incentives can become less economic over time, as other costs increase (Shell Initial Br. at 19-25, 32; Shell Ex. 7, at 7-10). Moreover, Shell points out that the declining block rate aspect of the shopping credits makes it increasingly difficult for the competitors and will frustrate achievement of SB 3's 20 percent load switching (Shell Ex. 7, at 10; Shell Initial Br. at 23). Shell recommends that the Commission either: (1) direct the parties to return to the bargaining table to devise an ----------------- (10) AEP states that this level of shopping incentive could not have been achieved without CSP's consent because the total amount exceeds the unbundled generation component for CSP's residential customers, which is the highest level the Commission could require. See, Section 4928.04(A), Revised Code. (11) Shell's witness Dr. Wilson distinguished between a shopping credit and a shopping incentive. He explained that a "shopping credit" is the "total amount by which the switching customer's bill would be reduced because the customer is taking service from an independent provider", while the "shopping incentive" is a "component of the shopping credit and is specifically designed to encourage 20 percent of the market to shift" during the MDP (Tr. V,74). 99-1729-EL-ETP and 99-1730-EL-ETP -13- agreement that makes blocks of generation capacity (at predetermined prices) available for competitive suppliers (modeled after Duquesne Light Company and FirstEnergy Corporation arrangements); or (2) increase the shopping credits to the levels recommended by its expert witness (Shell Ex. 6, at 56-60; Shell Ex. 7, at 10-11; Shell Initial Br. at 26-28). Shell contends that those changes are necessary, not to make it more economical for She11 to serve customers, but to induce the 20 percent customer switching mandated by SB 3 (Shell Reply Br. at 17). Finally, Shell states that the Commission should establish a tracking mechanism to adjust the shopping credits in response to wholesale price increases or annually review the adequacy of the shopping credits in each service territory (Shell Ex.7, at 10-11; Shell Initial Br. at 35; Shell Reply Br. at 15). With regard to Shell's discrimination argument, AEP states that SB 3 does not require all transition plans to be the same and, thus, the fact that the 2.5 mills only applies to CSP residential customers cannot be found improper (AEP Reply Br. at 27). AEP contends that nearly every other marketer in these proceedings supports the shopping incentives of the stipulation and that is telling of their significance (ID. at 22). AEP criticizes Shell's expert's suggested shopping incentives as not being based upon the companies' actual unbundled generation components and as violating Section 4928.40(A), Revised Code, because they exceed the unbundled generation component (AEP Initial Br. at 44-46; AEP Reply Br. at 24). Moreover, AEP states that the Commission has no authority to order the companies to make blocks of generation available to suppliers (AEP Reply Br. at 18,24). Therefore, the Commission should support the voluntary resolution that satisfied nearly every interested party (ID.). The staff contends that SB 3's 20 percent switching rate is not a mandate (Staff Reply Br. at 5-6). Rather, it is one basis upon which the Commission can end the MDP early (ID.). Also, the staff states that, since the companies' transition charges are so low, the large shopping incentives that Shell seeks are not possible because the effect of Shell's request would deny the companies the opportunity to collect any transition costs from customers who shop (ID. at 8-9). Shell argues first that the stipulation is discriminatory and violates SB 3 because it includes a shopping incentive during the MDP for CSP residential ratepayers, but not for OP residential ratepayers. Then, Shell also argues that there will be insufficient shopping incentives for both companies, which will be the generation shopping credit.(12) Thus, Shell has acknowledged that there would be an OP shopping incentive during the MDP under the stipulation and transition plan. At first blush, the stipulation would leave the impression that there will be no shopping incentive at all during the MDP for OP customers. However, AEP's plan included a shopping incentive for OP customers during the MDP and the stipulation did not modify that incentive. The fact that the proposed shopping incentives during the MDP vary between CSP and OP customers does not, in and of itself, lead us to conclude that the proposal before us should be rejected. In fact, we have already approved different shopping incentives between Ohio's utilities and the fact that both companies are within the AEP family does not convince us that the shopping incentives must be the same in order to be reasonable. ----------------- (12) We do not believe that Shell has presented consistent arguments on this point. 99-1729-EL-ETP and 99-1730-EL-ETP -14- The main thrust of Shell's argument against the proposed MDP shopping incentives is that they will be too small to engender competition. We do not agree with Shell's contention that the MDP shopping incentives are unlikely to affect the market in AEP's territory. We believe that the stipulation's 2.5 mills/kWh (for the first 25 percent of CSP residential customers, which is approximately 125,000 customers) will further help ensure that CSP's residential customers have an incentive to shop. The remaining customers will have an adequate incentive to shop inasmuch as the shopping incentives will equal either the estimated market cost of electric energy or 100 percent of the unbundled generation rate. As Shell's Dr. Wilson acknowledged, there is not going to be one number that gives every supplier the ability to make it in a competitive market (Tr. V, 80). We believe, however, the MDP shopping incentives proposed will effectively foster early competition by providing significant motivation to CSP and OP customers to switch retail generation suppliers. 2. POST-MDP INCENTIVE FOR OP RESIDENTIAL CUSTOMERS Section XVIII of the stipulation states that, for 2006 and 2007, the first 20 percent of OP residential customers that switch will not be charged the RTC (Jt. Ex.1, at 10-11). It is estimated that, in the first year (2006), approximately $5 million of RTC revenues will not be collected (Tr. III, 117). AEP will not amortize these RTC costs for future collection; it will expense the cost (ID. at 117-118). Shell contends that this provision of the stipulation violates SB 3 because the transition charge is "nonbypassable" and is not permitted to be discounted, per Sections 4928.37(A)(1)(b) and (3), Revised Code (Shell Initial Br. at 28-29). In response, AEP argues that the RTC cannot be "bypassable" during the MDP only and, since the MDP will not extend beyond December 31, 2005, this provision does not violate Section 4928.37(A)(1)(b), Revised Code (AEP Reply Br. at 28-29). As for the discount aspect of the provision, AEP states that, although the provision may "have the 'effect' of discounting the RTC, [it] is no different than providing an explicit monetary shopping incentive which offsets, i.e. discounts, the transition charge" (ID. at 29). Also, AEP believes that the statutory provision's goal is to prevent unjust discrimination among similarly situated customers and that will not occur under the stipulation because all residential customers will be eligible, but the discount ends when 20 percent switch (ID. at 29-30). AEP and the staff question the consistency of Shell's arguments thus far, stating that Shell should be welcoming this provision because its intent is to provide additional encouragement to OP residential customers to switch away from the standard offer after the MDP (ID. at 30; Staff Reply Br. at 11). AEP correctly points out that the "nonbypassable" restriction in Section 4928.37(A)(1)(b), Revised Code, is limited to the MDP. Thus, we do not find that the reduced RTC for OP customers in 2006 and 2007 would violate that aspect of SB 3. Additionally, Sections 4928.37(A)(1) and (3), Revised Code, specifically state that the transition charges that an electric utility can receive between the start of electric competition and the expiration of the MDP shall not be discounted by any party. The stipulation before us would not allow the discounting of the RTC to take place during the MDP. For that reason, we also conclude that Section XVIII is not contrary to SB 3. Moreover, we believe that the effect of this provision will provide OP residential customers another sizable incentive, after the MDP, to consider switching their 99-1729-EL-ETP and 99-1730-EL-ETP -15- generation supplier. For that reason, we find it to be consistent with the pro-competitive goals of SB 3. 3. COMMISSION'S FUTURE ABILITY TO RESPOND TO THE MARKET Shell contends that the stipulation (Sections VI and VII) unreasonably restricts the Commission's authority to modify the shopping incentive and the collection of RTCs or to carry out its market monitoring functions (Shell Ex. 7, at 7-8; Shell Initial Br. at 30, 33-34). Shell points to Sections 4928.06, 4928.40(B)(1), and 4928.39, Revised Code, for support. Shell states that the Commission's ability to respond to unanticipated market changes is very important (particularly where a fixed shopping incentive regime applies during the MDP) and the signatory parties cannot agree to rewrite that authority (Shell Initial Br. at 31-32,33). Shell believes market participants need the assurance that the Commission can and will take immediate action to safeguard the continuing viability of retail competition (ID. at 32-33). As in Shell's earlier recommendation, Shell suggests a tracking mechanism to adjust the shopping credits or annual consideration of whether the credits are adequate or require modification. AEP and the staff do not agree that Sections VI and VII of the stipulation violate SB 3. AEP states that the Commission may, but is not required to, make adjustments to transition charges (AEP Reply Br. at 32). In AEP's view, the Commission may exercise that discretion and should concur with the signatory parties' conclusion that no such further reviews are necessary (ID.). Further, AEP states that there is virtually nothing to which the Commission's discretionary authority could be applied for three reasons: (1) the companies have waived their claims for GTCs for the MDP; (2) RTCs can only be adjusted prospectively and only after December 31, 2004; and (3) CSP's additional shopping incentive more than eliminates those customers' RTCs for the MDP (ID. at. 32-33). Staff states that there are a number of statutory obligations imposed upon the Commission that are unaffected by the stipulation and the Commission will assuredly fulfill its obligations under SB 3 (Staff Reply Br. at 12). The Commission does not believe that Sections VI and VII of the stipulation conflict with Chapter 4928, Revised Code. Section 4928.40(B)(1), Revised Code, permits the Commission to conduct periodic reviews no more often than annually and, as it determines necessary, adjust the transition charges of the electric utility. It does not require such reviews or adjustments. We believe that the stipulation establishes reasonable transition charges, shopping credits, and incentives for customers to shop. We do not believe that Section VI or VII negate the Commission's broad authority to safeguard retail competition during the MDP. Various sections of SB 3 give the Commission continued oversight to monitor the progress of competitive retail electric services, to take action where necessary, and to promote the policies of the state of Ohio set forth in Section 4928.02, Revised Code. The Commission is charged with analyzing the efficacy of the market as it progresses over time and any evidence of the abuse of market power will be a signal for a change in the process. 4. GENERATION TRANSITION CHARGES AND STRANDED GENERATION BENEFITS As noted earlier, Section IV of the stipulation states that AEP will not impose lost revenue charges or GTCs on any switching customer (Jt. Ex. 1, at 3). AEP's original 99-1729-EL-ETP and 99-1730-EL-ETP -16- transition plan proposal included a proposed GTC of $291.43 million, representing above-market, stranded generation costs (AEP Ex. 9A at 12 and 9C at 5-6; Shell Ex. 6, at 39; Tr. III, 16). This calculation was based upon the difference between the generation components of the historic rates and the companies' projected market price of generation (Shell Ex. 6, at 38, 40-41; Tr. III, 19-21, 22). Shell states that AEP's GTC approach allows it the opportunity for a windfall because there should be no GTC so long as AEP's generating plants are valued at a market value equal or greater than their net book value (Shell Ex. 6, at 41,46-47; Tr. V, 114-115). For Shell, the correct generating plant valuations imply that there will be no GTC or stranded costs, only stranded benefits and, therefore, Section IV of the stipulation does not support a finding that the stipulation is reasonable (ID. at 43-44; Shell Reply Br. at 24-25). Shell argues that the stipulation and the proposed corporate separation plan will result in the transfer of generation assets to an unregulated affiliate at too low a value and harm ratepayers by denying them any share of the "market premiums" associated with the generation assets (Shell Ex. 6, at 43-44, 46, 83; Shell Initial Br. at 36; Shell Reply Br. at 28-29). Shell presented evidence that the more appropriate estimate of AEP's generating assets is a market value of nearly $7 billion, as opposed to the book value of approximately $2.2 billion (Shell Ex. 6, at 33-34; Tr. V, 114). Thus, in Shell's view, AEP's agreement in the stipulation to forego the GTC is meaningless because AEP had no such transition costs in the first place (Shell Initial Br. at 43). In particular, Shell's witness Dr. Wilson argues that AEP utilized overly optimistic, low market prices for power, citing to AEP's recent higher-priced purchases in the wholesale market and third-party forecasts of prices in the area (Shell Ex.6, at 15-18). Dr. Wilson noted that changing only the estimated market price of energy, as he suggested, raised the estimated value of the generation assets by more than $2 billion and resulted in an estimate of $1.5 billion of stranded benefits (ID. at 21). Next, Dr. Wilson noted that AEP improperly discounted by a full 12 months (rather than by six months) and deducted office building and other nongeneration plant construction costs from generation revenues (ID. at 22-23). Dr. Wilson then suggested that AEP should have assumed a 10.5 percent equity cost and a capital structure of 40 percent equity and 60 percent debt (ID. at 24-27). With all five of those inputs modified as suggested by Dr. Wilson, the value of AEP's generating plants would raise to nearly $5 billion and exceed book value by more than $2.5 billion (ID. at 27, 29, and JWW-5). Dr. Wilson noted that some other adjustments could be made, but he did not attempt them (ID. at 24, 31, 36-37). In addition, Shell contends that AEP will recover over $616 million in RTCs and all off-system generation sales (Shell Initial Br. at 43-44). Moreover, Shell takes issue with the fact that, under the stipulation, AEP ratepayers continue to pay for the transferred generation assets through unbundled, frozen generation rates, but not receive any benefit from the sales that the unregulated generation affiliate might make to third parties (Shell Initial Br. at 43; Shell Reply Br. at 20-21). Taken together, the book value transfer of generation assets would not serve the public interest. Shell suggests that the Commission provide AEP ratepayers a share by: (1) offsetting RTC recovery, and (2) funding more generous shopping credits for residential ratepayers with generation-related market premiums and third-party sales revenues (Shell Ex. 6, at 46; Shell Ex. 7, at 12; Tr. V, 40-41; Shell Initial Br. at 44-45; Shell Reply Br. at 29). 99-1729-EL-ETP and 99-1730-EL-ETP -17- AEP disagrees with Shell's argument on this issue. AEP points out that its corporate separation plan does not call for the transfer of its generation assets to an unregulated affiliate. Rather, the corporate separation plan involves the creation of new transmission and distribution subsidiaries; CSP and OP will continue to own and operate the generation assets. AEP disagrees with Shell's expert's estimate of AEP's generating assets and lists a number of reasons why the analysis is flawed (AEP Reply Br. at 35-37, 42-43). Specifically, AEP argues that the most accurate value of its generating assets is not necessarily measured by selling price (ID. at 35). AEP contends that Dr. Wilson's proposed substitute market price of electricity is too high and constitutes an improperly averaged price at times only when the companies were purchasing power, times of high demand and higher prices (ID. at 36-37). Next, AEP takes issue with Shell's reliance upon the valuation report and methodology of Research Data International (RDI) because it was a preliminary, working document for the FirstEnergy transition proceedings(13), which contained incorrect or non-comparable data (ID. at 42-42). Moreover, AEP states that Section 4928.35(A), Revised Code, does not entitle ratepayers to share in market premiums, even if there were any (AEP Reply Br. at 43-44). AEP further argues that Shell's suggestion that any market premiums fund larger shopping credits for switching customers is a violation of Section 4928.35(A), Revised Code, because that provision prohibits adjusting the utility's frozen unbundled rates during the MDP (AEP Reply Br. at 44). Likewise, AEP argues that Shell's suggestion to reduce the RTC violates Section 4928.39, Revised Code, because regulatory assets are a separate and distinct component of transition costs that can be adjusted only on a prospective basis (ID. at 44-47). Staff contends that Shell's GTC argument is inconsistent in saying that the unbundled generation charges are above market (based on old rate case data) and below market (based upon low market values) (Staff Reply Br. at 13-14). For this reason, staff says that Shell's position should be rejected (ID.). As noted earlier, if the stipulation is approved, AEP no longer seeks to recover a GTC. Therefore, the remainder of Shell's concern here is the netting of AEP's alleged stranded benefits/market premiums against transition costs. The Commission is not convinced that Dr. Wilson's analysis for determining the market value of the generating assets is fully correct. For instance, we believe Dr. Wilson's use of market price of electricity was overstated because it relied upon purchase data at times when electric prices were high and did not account for such abnormality. It also appears to improperly average the prices. We think AEP's criticisms, on these points, are valid. Changes to this one input in the valuation methodology, as Dr. Wilson noted, has a significant impact on the stranded benefits/market premiums. We also are unwilling to accept Dr. Wilson's reliance upon the RDI generation asset valuation methodology as grounds for rejecting AEP's valuation methodology. No RDI representative testified in this proceeding and the document was apparently a work in progress. Moreover, only parts of the working document are part of the record in these proceedings. Dr. Wilson's apparent use of the same methodology (with some substituted figures) does not convince us that we must ----------------- (13) IN THE MATTER OF THE APPLICATION OF FIRSTENERGY CORP. ON BEHALF OF OHIO EDISON COMPANY, THE CLEVELAND ELECTRIC ILLUMINATING COMPANY, AND THE TOLEDO EDISON COMPANY FOR APPROVAL OF THEIR TRANSITION PLANS AND FOR AUTHORIZATION TO COLLECT TRANSITION REVENUES, Case Nos. 99-1212-EL-ETP, 99-1213-EL-ATA, and 99-1214-EL-AAM (July 19, 2000). 99-1729-EL-ETP and 99-1730-EL-ETP -18- accept the methodology or the figures therein. In fact, AEP has raised doubt in our minds as to the accuracy of some comparison figures contained in the working document and relied upon by Dr. Wilson. For these reasons, we do not agree with Dr. Wilson's analysis or his conclusion that any stranded benefits exceed the amount of the GTC that AEP has agreed to forego as part of the stipulation. Furthermore, we believe that the stipulation provides a reasonable and equitable resolution on this issue. AEP has agreed to forego a claim of $291.43 million. The parties to the agreement have agreed, based on all of the terms and conditions of the agreement that there is no further netting or adjustments to the transition cost recovery during the MDP. Based upon the above findings, the Commission concludes that there are no stranded generation benefits that should either offset the RTCs or further fund the shopping incentives proposed by the stipulation. 5. FROZEN GENERATION RATES This next argument also relates to Section IV of the stipulation, wherein neither company will impose any lost revenue charges (GTC) on any switching customer (Jt.Ex.1, at 3). Shell argues that, for non-switching customers, the frozen, unbundled GENERATION rates only allow AEP another opportunity to collect excessive revenues since those rates will be uneconomic in a competitive market (Shell Initial Br. at 45; Shell Reply Br. at 24).(14) Shell further believes that the stipulation itself concedes an over-recovery of GENERATION revenues because the signatory parties agree that RTC revenues and frozen rate revenues are sufficient to recover regulatory assets (Shell Initial Br. at 47). Next, Shell contends that these frozen generation rates represent a "DE FACTO second RTC charge" because, under the stipulation, the companies will amortize and recover the value of the regulatory assets in excess of the stipulated regulatory asset rates (ID. at 48). Shell alleges that this is unlawful since some customers will pay it, but not others, and it will discourage customer switching (ID.) AEP states that SB 3's framework allows customers who do not switch to pay (as part of the unbundled generation component) generation costs that may be uneconomic (AEP Reply Br. at 48). In AEP's view, the legislature specifically chose to freeze rates at pre-SB 3 levels and did not allow, for instance, for adjustments in current costs or sales levels when unbundling generation rates (ID. at 49-50). Furthermore, AEP alleges that customers will pay the same frozen, unbundled generation rates, regardless of whether the companies amortize the regulatory assets over the MDP or expense them immediately (ID. at 51). Thus, AEP believes Shell's issue is with the requirements of SB 3 and the legislature has already disagreed with Shell's position (ID. at 52). Thus, there is no statutory basis to contend that the stipulation is improper (ID.). AEP further points out that it calculated the unbundled generation rates in accordance with Section 4928.34, Revised Code, and Shell has not taken issue with them. (ID. at 49). We cannot agree with Shell's arguments on this point. We find that the unbundling plan agreed to by stipulating parties to the transition plan stipulation is reasonable and consistent with Section 4928.34, Revised Code. The evidence of record shows that the ------------------ (14) Specifically, Shell contends that the frozen, unbundled generation rates are uneconomic because they are not reflective of current or competitive costs and demand (Shell Initial Br. at 46-47). 99-1729-EL-ETP and 99-1730-EL-ETP -19- unbundling plan proposed by AEP follows the intent of Section 4928.34, Revised Code. In unbundling the rates for each customer class, AEP had to follow the requirements of SB 3, which not only dictated the manner in which the generation component would be determined, but also necessitated the use of the AEP's earlier cost-of-service studies. We find that AEP has followed the statutory scheme in unblindling its rates. Further, one of the purposes of this proceeding is to establish unbundled rates based on the already adopted cost-of-service studies, not to alter those studies or to determine whether more appropriate rates should be used when unbundling services. To do so would clearly be inconsistent with the mandate of Section 4928.34(A)(6), Revised Code, which requires the unbundling of the rates in effect on the day before the effective date of SB 3. Therefore, we find the generation components to be reasonable. 6. DISTRIBUTION RATE FREEZE Section V of the stipulation states, that, except in the event of certain limited changes, all distribution rates in effect on December 31, 2005, will be frozen for three years for CSP and two years for OP (Jt. Ex. 1, at 3). Shell presents two very different arguments against this provision. First, Shell views this provision as an anti-competitive albatross because, after the MDP, those frozen rates will recover generation-related retail costs and subsidize the post-MDP, "market-based" standard offer. Essentially, Shell contends that the existence of the frozen distribution rates invites the creation of a below-market rate for the standard offer and provides AEP an unfair competitive advantage over other suppliers (Shell Initial Br. at 50). Second, Shell states that the frozen distribution rates allow AEP additional opportunity for cost over-recovery since the rates are based upon costs and sales levels from old base rate cases, rather than the lower costs of a competitive market (ID. at 50-51). Shell also states that the rate freeze would again tie the Commission's hands in achieving the pro-competitive policies of SB 3 (ID. at 51). AEP first states in response that Shell's criticism here is inconsistent with Shell's acceptance of a similar rate freeze provision in the FirstEnergy transition cases (AEP Reply Br. at 53). AEP acknowledges that the frozen distribution rates are unlikely to represent the items and levels of expense that the companies are incurring today or will be incurring at the end of 2005 (ID. at 54). However, AEP states that it is speculative to conclude that the companies will be over-recovering their distribution expenses in 2006, 2007 or 2008 (ID.). AEP notes that it and signatory consumer representatives have weighed the risks of the agreed-upon rate freeze and determined that it is a reasonable agreement as part of the overall stipulation, and the Commission should reject Shell's claims (ID.). We do not agree with Shell on this point either. We believe that the distribution rate freeze will provide some certainty to customers in AEP's service territory at a time when they are evaluating the competitive generation market. That is to say, OP customers may be assured that competitive, generation-related costs are not being shifted to non-competitive, distribution charges after the MDP. Furthermore, to accept Shell's argument on this point, we must assume that the 2005 distribution rates will include generation-related costs and will not be reflective of distribution costs in 2006 through 2008. We are not willing to accept those assumptions. 99-1729-EL-ETP and 99-1730-EL-ETP -20- 7. USF Rider and EERLF Rider ------------------------- On July 13, 2000, as amended on July 17, 2000, ODOD submitted a motion for approval of the USF and EERLF riders for AEP. ODOD states that the USF and EERLF riders were required to be effective on July l, 2000 and January 1, 2001, respectively. However, due to delays in the transfer of this program, ODOD requested that the Commission make the USF rider effective September 1, 2000. On August 4, 2000, IEU-Ohio filed a motion to disapprove those proposed riders. ODOD, OCC, OPAE, APAC, and OEC filed a memorandum in support of those riders. AEP recommended that the Commission adopt ODOD's calculations its reply brief (AEP Reply Br. at 64). By entry issued August 17, 2000, we agreed with the rates reflected in ODOD's motion. Accordingly, the USF rider rates proposed by ODOD ($0.0006240 for CSP and $0.0002998 for OP) became effective September 1, 2000. The approved rates for the EERLF rider will be $0.00010758 for both operating companies, effective January 1, 2001. A request for rehearing of our August 17, 2000 USF/EERLF ruling was then filed by IEU-Ohio, OMA, and OCRM. In a separate ruling issued this same day, we have granted rehearing in order for the ODOD and the Commission staff to provide additional data on various components of the USF riders. AEP's effective USF riders shall remain in effect pending the Commission's further review of this matter. 8. LOAD SHAPING SERVICE -------------------- Section XIX of the stipulation states that AEP and the signatory marketers will further negotiate an AEP load shaping service.(15) All such marketing intervenors shall be notified of dates, times, and locations for such meetings (Jt. Ex. 1, at 11). Shell argues that the stipulation's terms relating to load shaping service are discriminatory much in the same way as the consolidated billing terms, which is fully addressed later (Shell Ex. 7, at 15; Shell Initial Br. at 58, footnote 160). Shell worries that, because negotiations will only take place with signatory marketers, the resulting load shaping services could confer benefits to only signatory parties (Tr. V, 119-120). Moreover, Shell argues that, since the generation affiliate(s) providing the load shaping service will be outside of the Commission's jurisdiction, there will be no means for curbing discriminatory actions. Shell recommends that the Commission condition any approval of the proposed corporate separation plan on the resulting unregulated generation affiliate(s)' providing services like load shaping to all market participants in a nondiscriminatory manner (Shell Initial Br. at 58-59, footnote 160). We believe that Shell raises some valid points about the load shaping terms in the stipulation. Obviously, by agreeing to negotiate with stipulating marketers, AEP is not agreeing to negotiate with all marketers in its service territory. It is possible that any resulting load shaping service could then only confer benefits upon the negotiating marketers. However, we do not think that the entire stipulation or this part must be rejected because of this possibility. We believe that, as a condition of our approval of the stipulation and the transition plans, any resulting load shaping service must be provided in a nondiscriminatory manner. Furthermore, we direct AEP to open the negotiations to all ------------------ (15) Load shaping service allows a marketer to better tailor its power purchases to meet customer demands (Tr. III, 121-122). 99-1729-EL-ETP and 99-1730-EL-ETP -21- interested parties, not just signatory marketers, so that it is possible to develop a load shaping service that is based upon all interested persons' input. Not only do we think it is the smarter approach to take, we also think it can lead to a better end result. 9. REMAINING CONCERNS WITH THE UNBUNDLING PLAN AND TRANSITION COSTS Section 4928.34(A)(l), Revised Code, requires the Commission to determine whether the unbundled components for the electric transmission component of retail electric service equal the FERC tariff rates in effect on the date of approval of the transition plan. The unbundled transmission component must include a sliding scale of charges to ensure that refunds determined or approved by the FERC are flowed through to retail electric customers. After review of the filings and testimony submitted by AEP, we find that the companies' transition plans satisfy the requirements of Section 4928.34(A)(1), Revised Code. Section 4928.34(A)(2), Revised Code, requires that the unbundled components for retail electric distribution service in the rate unbundling plan equal the difference between the costs attributable to the company's transmission and distribution rates based on the company's most recent rate proceeding, and the tariff rates for electric transmission service determined by the FERC under division (A)(l) of that code section. We find that the companies' filings satisfy this prerequisite. AEP's adjusted unbundled distribution component is the sum of the transmission and distribution components of rates in effect on October 5, 1999, less the revenue generated by the applicable OATT (AEP Ex. 24A at 15). AEP stated that, in identifying the costs in the operating companies' last rate cases, costs were assigned to functions where possible (ID. at 13-14). We believe that the companies' allocations are reasonable and the companies' filings, as amended by the stipulation (and subject to review in the companies' compliance filings), satisfy prerequisite (A)(2) of Section 4928.34, Revised Code. Section 4928.34(A)(3), Revised Code, requires that all other unbundled components required by the Commission in the rate unbundling plan must equal the costs attributable to the particular service, as reflected in the company's schedule of rates and charges. In accordance with this provision, AEP's existing rates will be unbundled to separate out certain components that will be included in several riders in the operating companies' tariffs. We note that the stipulation provides for USF and EERLF riders for the companies (Jt. Ex. 1, at 11), which we fully discussed above. Based on the evidence presented in this proceeding, we find that the companies' filings, as amended by the stipulation (and subject to review of the companies' compliance filings), satisfy prerequisite (A)(3). Section 4928.34(A)(4), Revised Code, requires that the unbundled components for retail electric generation service in the rate unbundling plan equal the residual amount remaining after the determination of the transmission, distribution, and other unbundled components, and after any tax related adjustments as necessary to reflect the effects of the amendment of Section 5727.111, Revised Code. Upon review of AEP's transition filings, as amended by the stipulation, we find that the companies have satisfied this prerequisite. In Rule 4901:1-20-03, Appendix A, Part (C)(1), O.A.C., the Commission proposed a formula for determining the residual generation component that includes transition charges. However, the Commission left open the possibility that companies could propose alternative formulations. RULES FOR ELECTRIC TRANSITION PLANS, SUPRA, Opinion and Order at 16. 99-1729-EL-ETP and 99-1730-EL-ETP -22- AEP proposed such an alternative in its transition filing, but has agreed in the stipulation not to impose the GTC on any switching customer (AEP Exs. 2, at 15A and 15B; Jt. Ex.1, at 3). In addition, Section 4928.4O(C), Revised Code, requires a five-percent reduction in the unbundled generation component for residential customers. Under the stipulation, the five-percent reduction is to be applied to the generation component, including the RTC component (Jt. Ex. 1, at 6). In addition, as described above, the settlement requires AEP to forego its right to seek reduction of the discount for residential customers during the MDP (ID.). Section 4928.34(A)(5), Revised Code, requires that all unbundled components in the rate unbundling plan must be adjusted to reflect any rate base reductions on file with the Commission and as scheduled to be in effect by December 31, 2005, under rate settlements in effect on the effective date of this section. However, all earnings obligations, restrictions, or caps approved prior to the effective date of the statute are void. We find that the companies' filings, as amended by the stipulation, satisfy prerequisite(A)(5). Section 4928.34(A)(6), Revised Code, requires that the total of all unbundled components is capped and, during the MDP, will equal the total of rates in effect on the day before the effective date of SB 3. The cap will be adjusted for changes in taxes, the universal service rider, and the temporary rider under Section 4928.61, Revised Code. Under AEP's filings, the total of the companies' unbundled rates is capped, with limited exceptions, during the MDP. Further, under the stipulation, distribution rates are frozen for additional years beyond the MDP, through the end of 2007 for OP and through 2008 for CSP (Jt. Ex. 1, at 3). In addition, under the companies' filings, the total of all unbundled components of existing rates and contracts equals the rates and charges of the bundled components, except for adjustments to reflect taxation changes under SB 3 and for the USF fund and EERLF riders (AEP Ex. 9A at 14-15). AEP's transition filings, as amended by the stipulation and taking into consideration our conclusion for the gross receipts/excise tax issue (discussed below), satisfy prerequisite (A)(6). Section 4928.34(A)(7), Revised Code, requires the rate unbundling plan to comply with any rules adopted by the Commission under Section 4928.06(A), Revised Code.(16) The rules adopted by the Commission regarding unbundling of rates are set forth in Rule 4901:1-20-03, O.A.C., Appendix A. We find that the transition filings, through the various schedules and testimony submitted in this proceeding, satisfy Section 4928.34(A)(7), Revised Code. Section 4928.34(A)(12), Revised Code, requires that the transition revenues authorized under Sections 4928.31 to 4928.40, Revised Code, be the allowable transition costs of the company pursuant to Section 4928.39, Revised Code, and that the transition charges for customer classes and rate schedules are the charges under Section 4928.40, Revised Code. Based upon the discussion above and our consideration of the record, we find that AEP's filings, subject to the modifications contained in the stipulation, satisfy the prerequisite set forth in Section 4928.34(A)(12), Revised Code. ------------------ (16) Section 4928.06, Revised Code, directs the Commission to enact rules to effectuate commencement of competitive retail electric service. The Commission has enacted rules in compliance with this statute through various generic rule proceedings. 99-1729-EL-ETP and 99-1730-EL-ETP -23- Section 4928.34(A)(15), Revised Code, requires that all unbundled components be adjusted to reflect the elimination of the gross receipt tax imposed by Section 5727.30, Revised Code. The signatory parties agree that the revenues from the agreed-upon RTCs and from existing frozen and unbundled rates recovered during the MDP are sufficient to recover regulatory assets as of the beginning of the MDP and to provide for the stipulation's obligations (Jt. Ex. 1, at 10). We believe that this agreement is envisioned by and consistent with the requirements of Section 4928.34(A)(15), Revised Code, as well as Section 4928.34(A)(6), Revised Code. (17) Section 4928.39, Revised Code, requires the Commission to determine the total allowable amount of the company's transition costs to be received by the company as transition revenues. Such transition costs must meet the following criteria: (1) The costs were prudently incurred. (2) The costs are legitimate, net, verifiable, and directly assignable or allocable to retail electric generation service provided to electric consumers in this state. (3) The costs are unrecoverable in a competitive market. (4) The utility would otherwise be entitled an opportunity to recover the costs. We believe that, under the proposed transition plans as modified by the proposed stipulation, the amount of transition costs has been determined and that it meets the requirements for recovery through transition charges. B. CORPORATE SEPARATION PLAN Under AEP's corporate separation plan, the companies have proposed to move the regulated transmission and distribution functions into newly created affiliates (AEP Ex. 2, Part B). As a result, AEP acknowledges that the new entities will own and operate all transmission and distribution assets and be public utilities, as defined in Sections 4905.02 and 4905.03, Revised Code (AEP Ex. 9A at 19; AEP Initial Br. at 47). AEP plans to seek the necessary federal authorization for the transfer of assets in 2000 (AEP Ex. 9A at 21). The corporate separation plan will take into consideration the overlapping financial arrangements that currently exist and refinance substantially all of the obligations over a period of time (AEP Ex. 20, at 3-7). In particular, the plan involves: (1) assigning specific debt that can be identified to individual assets and leaving the remaining debt and preferred stock obligations with the generation company; (2) retire debt and preferred stock obligations; and (3) replace debt and preferred stock obligations in a manner that does not create or will eliminate future financial overlaps (ID. at 5-6). Nearly all service offerings will remain the same; AEP identified one service (storage water heater rental ------------------ (17) Section 4928.34(A)(6), Revised Code, provides that the effect on customer rates from the tax overlap between the existing gross receipts tax and the new franchise tax "shall be addressed by the Commission through accounting procedures, refunds, or an annual surcharge or credit to customers, or through other appropriate means, to avoid placing the financial responsibility for the difference upon the electric utility or its shareholders." 99-1729-EL-ETP and 99-1730-EL-ETP -24- program) that will be phased out as inappropriate in a competitive market for generation services (AEP Ex. 9A at 20). AEP's corporate separation plan and supporting testimony address safeguards, separate accounting, financial arrangements, complaint procedures, education and training, and a cost allocation manual (AEP Ex. 2, Part B; AEP Exs. 9A at 22-23, 9B at 3, 13, 20). AEP contends that the stipulation enhances the corporate separation plan in three respects (AEP Initial Br. at 50). First, the cost allocation manual (CAM) will definitively follow the uniform system of accounts, as well as the generally accepted accounting principles. (Jt. Ex. 1, at 11). Second, effective with the start of competition, the distribution affiliate will not provide competitive non-electric products or services to retail customers on a commercial basis, except under pre-existing contractual obligations or when incidental to the provision of customer services and not on a commercial basis (ID. at 11-12). Third, the stipulation requires that employees of the affiliates not have access to any information about the transmission or distribution systems that is not contemporaneously available in the same form and manner to nonaffiliated competitors of retail electric services (ID.). Shell raises two concerns with the corporate separation plan of AEP (Shell Ex. 6, at 83-84, 86-87; Shell Initial Br. at 66-67). First, Shell states that the corporate separation plan allows excessive sharing of accounting services and management with affiliates (ID.). Second, Shell contends that "declared emergencies" under the corporate separation plan will allow AEP to violate the affiliate code of conduct (ID.). Shell presented no evidence on either of these points. We are not convinced that Shell's concerns about the language or the corporate separation plan warrant its rejection. As for the sharing of accounting services and management, we have previously explained that the corporate separation rules were not intended to prohibit all sharing of employees between affiliated entities. RULES FOR ELECTRIC TRANSITION PLANS, SUPRA, Second Entry on Rehearing at 21. Moreover, we stated that certain centralized support functions may be permissable (ID.). Specifically, our corporate separation rules are "intended to require independent work/functions when the failure to maintain independent operations may have the effect of harming customers or unfairly disadvantaging unaffiliated suppliers of competitive retail electric service or non-electric products or services" (ID.). Without any evidence presented, we are not convinced that the AEP's plan could have the harmful effect we wish to avoid. Moreover, many interested parties have agreed to the contrary. Additionally, we are not convinced that AEP's corporate separation plan must contain a particular definition of "declared emergency". The corporate separation plan complies with Rule 4901:1-20-16(G)(4)(j), O.A.C., on this point and is acceptable. Unlike the corporate separation plans proposed by the FirstEnergy Corporation operating companies and Cincinnati Gas & Electric Company,(18) AEP has presented a corporate separation plan that provides for structural separation by January 1, 2001 (except for limited financial arrangements). Therefore, this Commission need not evaluate an interim plan under Section 4928.17(C), Revised Code. Section 4928.17(A)(2), Revised ------------------ (18) IN THE MATTER OF THE APPLICATION OF CINCINNATI GAS & ELECTRIC COMPANY FOR APPROVAL OF ITS ELECTRIC TRANSITION PLAN, APPROVAL OF TARIFF CHANGES AND NEW TARIFFS, AUTHORITY TO MODIFY CURRENT ACCOUNTING PROCEDURES, AND APPROVAL TO TRANSFER ITS GENERATING ASSETS TO ANY EXEMPT WHOLESALE GENERATOR, CASE NOS. 99-1658-EL-ETP, et al. (August 31, 2000). 99-1729-EL-ETP and 99-1730-EL-ETP -25- Code, requires that all plans satisfy the public interest in preventing unfair competitive advantage and abuse of market power. The plan must also be sufficient to ensure that no undue preference or advantage is extended to or received by the competitive retail affiliate from the utility affiliate. Section 4928(A)(3), Revised Code. We find that AEP has constructed its plan in a manner that achieves, to the extent reasonably practical, the structural separation contemplated by Section 4928.17(A)(1), Revised Code, and the corresponding Commission rules. However, the Commission reserves the right to invoke its authority to preserve fair competition, for both interim and permanent arrangements. Section 4928.34(A)(8), Revised Code, states that the corporate separation plan required under Section 4928.31(A), Revised Code, must comply with section 4928.17, Revised Code, and any rules adopted by the Commission pursuant to Section 4928.06(A), Revised Code. We find that the proposed corporate separation plan satisfies this prerequisite, for the reasons stated in the discussion above. We reserve the right to closely monitor the implementation of the plan to avoid competitive inequality, unfair competitive advantage or abuse of market power. We believe that through the periodic Commission review (i.e., through audits of the company's books and records, including the CAM) and the complaint process, this Commission may ensure that the corporate separation plan is implemented in accordance with the policy enunciated in SB 3. C. OSP Section 4928.34(A)(9), Revised Code, provides that the company's transition plan must comply with Commission requirements and rules regarding operational support systems and technical implementation issues pertaining to competitive retail electric service. The Commission's rules regarding operational support and technical implementation are set out in Appendix B of Rule 4901:1-20-03, O.A.C. Additionally, on November 30, 1999, the Commission issued an entry in Case No. 99-1141-EL-ORD, directing Ohio's investor-owned electric utilities and interested stakeholders to participate in a taskforce for the development of uniform business practices and electronic data interchange (EDI) standards. Pursuant to this directive, the Commission staff created the OSP taskforce (hereinafter referred to as OSPO). On May 15, 2000, numerous OSPO participants filed a pro forma certified supplier tariff (pro forma tariff) and a stipulation (hereinafter referred to as the OSPO stipulation) in each utility's transition plan case. The pro forma tariff contains a number of service regulations on which the parties were able to agree. These relate to: supplier registration and credit requirements, end-use customer enrollment process, supplier registration and credit requirements, end-use customer inquiries and requests for information, service request process, metering services and obligations, load profiling and scheduling, transmission scheduling agents, confidentiality of information, voluntary withdrawal by a competitive retail electric service provider, liability, and alternative dispute resolution. In the OSPO stipulation, the parties specifically requested the Commission to resolve issues in four general areas: (1) energy imbalance service, (2) minimum stay requirements for residential and small commercial customers returning to standard offer service, (3) consolidated billing and purchase of receivables, and (4) adoption of EDI standards. On May 18, 2000, the Commission issued and entry initiating a generic docket to establish procedures for parties desiring to file comments and reply comments regarding the OSPO stipulation and pro forma tariff. IN THE MATTER OF THE ESTABLISHMENT OF ELECTRONIC DATA EXCHANGE STANDARDS AND UNIFORM BUSINESS PRACTICES FOR THE 99-1729-EL-ETP and 99-1730-EL-ETP -26- ELECTRIC UTILITY INDUSTRY, Case No. 00-813-EL-EDI (hereinafter 00-813). On July 20, 2000, the Commission issued a finding and order approving the OSPO stipulation and resolving the four issues left unresolved. AEP's operational support and technical implementation plan is described in the testimony of Jeffrey Laine (AEP Ex. l4A and 14B). The OSP specifically addresses each requirement set forth in the Commission's rules (AEP Ex. 2, Part C). Specifically, as required by Rule 4901:1-20-03, Appendix B, Part (A), O.A.C., AEP's operational support plan addresses how the company intends to utilize its existing systems and what changes will be made to implement customer choice. Further, as required by Rule 4901:1-20-03, Appendix B, Part (B), O.A.C., the plan includes an electronic "clearinghouse" system that will provide functionality such as service provider registration, enrollment and switching, estimation and reconciliation, settlement, and bill data delivery (AEP Ex. 14B at 2). Under the transition plan stipulation in this case, AEP agrees to incorporate into its transition plan, the OSPO stipulation and pro forma tariff with the exception of certain terms that the stipulating parties have agreed will apply to AEP. According to the companies, the settlement modifies the companies' plans by providing minimum stay requirements and consolidated billing credits (AEP Initial Br. at 55). AEP contends that these modifications bring additional benefits to customers and, suppliers and, thus, encourage the development of the competitive retail market (ID.). Shell takes issue with four OSP-related items in the transition plans and stipulation: (1) supplier consolidated billing credit; (2) residential customer switching period (3) switching fee, and (4) additional certification requirements proposed by AEP. 1. SUPPLIER CONSOLIDATED BILLING CREDIT AEP did not propose a supplier consolidated billing credit in the transition plans. Section XIV of the stipulation states that AEP will provide a $1.00 credit to suppliers for each consolidated bill issued by that provider during the first year of the MDP (Jt. Ex. 1, at 9; Tr. III, 101). The signatory parties agree to conduct further negotiations related to a similar future credit (ID.). Finally, that provision states that AEP shall reasonably attempt to implement supplier consolidated billing as soon as practicable (ID.).(19) Shell believes that the stipulation's terms for a consolidated billing credit are inadequate to spur effective competition (Shell Ex. 7, at 16-17; Shell Initial Br. at 52). Shell, unlike most other marketers in these proceedings, provides consolidated billing for customers in Georgia and intends to do so in Ohio. First, Shell characterizes the stipulated credit amount as "anemic" and as requiring Shell's customers to pay twice for the billing service (once to Shell and a second time to AEP for costs not captured by the billing credit) (Tr. III, 115-116; Shell Initial Br. at 53; Shell Reply Br. at 27). Shell further states that the $1.00 is an arbitrary figure, while Shell's evidence supports a conclusion that CSP and OP residential accounting collections and services average $3.70 and $4.00 per customer per month, respectively (Shell Ex. 7, at 20; Shell Intitial Br. at 54-55). For that reason, Shell contends that the billing costs are virtually certain to be much higher than $1.00 (Shell Ex. 7, at 21). Shell also presented evidence of other utilities' billing costs, which were all quite a ----------------- (19) AEP has established its target date for implementing the supplier consolidated billing credit as January 1, 2001, the start of competition in Ohio (Jt. Ex. 1, at 7; Tr. III, 102, 156). 99-1729-EL-ETP and 99-1730-EL-ETP -27- bit higher than $1.00 (ID. at 23, JWW-1S, JWWW-2S). For these reasons, Shell contends that the Commission should reject Section XIV and take one of two actions. Those are: either adopt a higher figure, no lower than $2.00 per bill, pending completion of a separate proceeding to determine actual costs, or require AEP to establish a separate affiliate to perform billing functions (ID. at 23-24; Shell Initial Br. 57). Second, Shell also criticizes the stipulated process for modifying the credit because only signatory parties may participate in those future negotiations. Shell notes that even AEP acknowledged that, if none of the signatory parties seek such negotiations, they will not take place (Tr. III; 106; Shell Initial Br. at 58). Shell believes that none of the signatory marketers have an interest in performing consolidated billing and, therefore, there is a great risk that no future consolidated bill credit negotiations will take place. Shell also states that the stipulation's terms would have anti-competitive consequences, by excluding certain market participants from negotiations and by only allowing AEP to petition the Commission if negotiations fail (Shell Initial Br. at 59). Lastly, Shell points out that the stipulation also fails to provide a "fail-safe" credit in the event that future negotiations are not completed in the 12-month period (Shell Ex. 7, at 24). In Shell's view, not only does AEP not have an incentive to agree to a higher billing credit, but the stipulation provides AEP with further incentive to let the 12 months expire so that the stipulated credit expires (Shell Initial Br. at 59). AEP states that the Commission should view the stipulated consolidated billing credit as an extra bonus since AEP is not statutorily required to offer such a credit and since not other Ohio utility will be offering one as early as AEP (AEP Initial Br. at 54; AEP Reply BR. at 55). AEP also points out that the Commission did not require utilities to offer consolidated billing credits in consideration of the topic as part of the OSP issues (AEP Rely Br. at 55). Next, AEP contends that there is evidence to support the reasonableness of the stipulated credit amount. For instance, AEP's witness stated that the only avoided costs of providing billing services would be postage and the envelope, costs which are much less than $1.00 (Tr. III, 111-112, 149; AEP Reply Br. at 57). AEP also points out that Shell's witness acknowledged that other utilities have credits in the $1.00 range (TR. V. 94). Next, AEP contends that there is no basis in Ohio law for the Commission to adopt Shell's recommendation for a separate billing affiliate. AEP next noted that it has agreed to keep Shell involved and informed of the consolidated bill discussions (Tr. III, 106-108)(20), so that concern has already been addressed by the companies (AEP Reply Br. at 58-59). Staff contends that Shell's argument is premature because the stipulation is providing a credit only as a temporary measure during the first year (Staff Initial Br. at 9). Sine "fine-tuning" can and will be addressed in the future and there are many more pressing items to address during the first phase of the transition, Shell's concern should be not adopted according to the staff (ID.). Additionally, the staff states that the consolidated billing credit is a unique advantage of this stipulation since no other stipulation provide such a credit (ID). We established in 00-813 a target date for consolidated bill-ready billing of no later than June 1, 2002, and a target date for supplier consolidated billing of not later than July 1, ------------------ (20) AEP agreed to also allow participation by customer groups, such as the OCC, the staff, industrials (TR. III, 16-107). 99-1729-EL-ETP and 99-1730-EL-ETP -28- 2002. The stipulation before us, however, includes a target date for supplier consolidated billing that coincides with the start of competition. In this respect, AEP is planning to be the first utility to implement the necessary systematic changes for supplier consolidated billing. We find the stipulated target date by AEP to be reasonable.(21) Nevertheless, the crux of Shell's argument is not the start date, but the amount of the consolidated billing credit. Shell presented evidence from which it contends that the $1.00 credit is unreasonable. AEP presented evidence from which it contends that the $1.00 credit is reasonable. On balance, we conclude that, as part of an overall settlement of nearly all issues in these proceedings, the stipulated credit amount is acceptable. If this issue were fully litigated, we might very well reach a conclusion that differs from $1.00, but we cannot say that this provision (as part of a settlement reached with a broad range of interested parties and with a target of having the credit immediately available with the onset of competition) must be rejected. Additionally, AEP explained that, in the event that the system changes for supplier-consolidated billing are not in place at the start of competition on January 1, 2001, it would continue the consolidated billing credit on a day-for-day basis so that it was offered for a one-year period (Tr. 111, 156-157). Lastly, inasmuch as AEP has agreed to include Shell in the future negotiations (as well as customer groups), we believe that eliminates Shell's concern that those future negotiations might not take place (Shell itself can ensure that the negotiations take place). For these reasons, we do not accept either one of Shell's suggested approaches for this issue. 2. RESIDENTIAL CUSTOMER SWITCHING/MINIMUM STAY REQUIREMENT The transition plan filing provided that all customers returning to the company from an alternative supplier be required to stay on the standard service offer for 12 months or the MDP, whichever is longer (AEP Ex. 2, Part A, UNB-1, Sheet Nos. 3-18D for OP and 3-14D for CSP; AEP Ex. 24A at 5-6). AEP has agreed to mitigate this requirement in the settlement (Jt. Ex. 1, at 7-8). In Section XII of the stipulation, the operating companies agree that, during the MDP, customers who can take generation service from AEP between May 16 and September 15 must either remain a customer through April 15 of the following year or choose a market-based tariff which will not be lower than the generation cost embedded in the standard offer (ID. at 7). Under the stipulation, nonaggregated residential customers will be permitted to shop three times during the MDP and to return two times to the default tariff before being required to choose from one of the above two options (ID. at 8). Shell contends that AEP's proposed minimum stay requirement violates SB 3 because SB 3 contemplates no limitation on a residential customer's freedom of movement between service options even if those movements involve a return to standard offer service (Shell Ex. 6, at 64; Shell Initial Br. at 60). Shell also claims that AEP's minimum stay provision could remove large numbers of such consumers from the competitive market place for substantial periods of time and reduce competition (Shell Initial Br. at 60). AEP points out that Section 4928.31(A)(5), Revised Code, specifically allows transition plans to create reasonable minimum stay requirements (AEP Reply Br. at 60). Furthermore, AEP states that it is unrealistic for there to be no restrictions placed on ------------------------- (21) We note that, pursuant to Rule 4901:1-10-29(H)(1), O.A.C., the companies are still required to make rate-ready, electric distribution utility-consolidated billing available to suppliers on January 1, 2001. 99-1729-EL-ETP and 99-1730-EL-ETP -29- residential switching (ID.). Also, AEP states that the Commission has already rejected Shell's position in 00-813, there is no reason to alter that decision, and the Commission should adopt Section XII of the stipulation (ID. at 60-61). With respect to the issue of AEP's minimum stay requirements and Shell's criticisms thereof, we defer to our rulings in 00-813. In that first order (page 13), we approved the use of minimum stay requirements conditioned upon the development of a market-based "come and go" rate alternative service and only in the event the customer voluntarily chooses to return to the standard offer service. We prohibited the imposition of a mandatory stay when a customer defaults to the utility's standard offer service due to the default of the supplier of electricity. We also established a uniform penalty free return to standard offer service policy and a uniform period throughout Ohio in which companies can impose a summer/stay period of May 16th through September 15th. On August 31, 2000, we granted rehearing with regard to the minimum stay ruling and adopted the "first year exemption" proposal (as opposed to the two free returns proposal) as the uniform rule in Ohio for residential and small commercial customers. This uniform rule differs from what AEP agreed upon in its stipulation, but AEP also agrees in that same stipulation to abide by our OSP determinations. Having, addressed and considered Shell's arguments in 00-813, we conclude that no further conclusions need be expressed at this time. Accordingly, the Commission will modify the stipulation's treatment of minimum stay requirements so that AEP's minimum stay requirements are in full compliance with our orders in 00-813 and we reserve approval of any tariff provision relating thereto.(22) We also note that, as stated in our entry on rehearing in 00-813, our approval of the minimum stay requirements is conditioned upon the development of a uniform alternative, which will provide returning customers with a method of avoiding the minimum stay or which may eliminate the need for such requirement. 3. SWITCHING FEE AND ALTERNATIVE METERING CREDIT As part of its OSP, AEP originally proposed a $5.00 switching fee each time a customer authorized change in provider occurs, except under certain limited circumstances (AEP Ex. 2, Part A, UNB-1, Sheet Nos. 3-3D and 3-18D for OP and Sheet Nos. 3-3D and 3-14D for CSP). AEP later modified its switching fee proposal, increasing it to $10.00 (AEP Ex. 24B at 4-5). AEP states that it proposed the increased fee because of certain Commission rules(23) and the items being discussed in the OSPO (AEP Ex. 24B at 4- ------------------- (22) We note that the stipulation's minimum stay proposal was suggested to the Commission, UNLESS the OSPO agreed upon other, less restrictive minimum stay requirements. As noted above, the OSPO did not agree upon minimum stay requirements and requested a Commission ruling. That has occurred and, thus, Section XII's prefatory clause has not been triggered. We make this statement so that all interested parties fully understand that we expect that the conclusions we reached in 00-813 on the minimum stay issue will be followed. We also make this statement in light of Mr. Forrester's testimony, which would leave one to believe that the stipulation's minimum stay provision would be triggered (and not the Commission's 00-813 minimum stay conclusions) if the Commission's conclusion in 00-813 was more restrictive than the stipulation (Tr. IV, 134-135). We do not, accept the approach/interpretation set forth by Mr. Forrester and explicitly modify the stipulation on this issue and we reserve approval of any tariff provision relating thereto so that AEP's minimum stay requirements comply with our decisions in 00-813. (23) AEP specifically referred to the Commission's rules in IN THE MATTER OF THE COMMISSION'S PROMULGATION OF RULES FOR MINIMUM COMPETITIVE RETAIL ELECTRIC SERVICE STANDARDS PURSUANT TO CHAPTER 4928, REVISED CODE and IN THE MATTER OF THE COMMISSION'S PROMULGATION OF AMENDMENTS TO RULES FOR ELECTRIC SERVICE and 99-1729-EL-ETP and 99-1730-EL-ETP -30- 5). Shell argues that the switching fee proposed is excessive (Shell Ex. 6, at 66; Shell Initial Br. at 66-67).(24) AEP states that the Commission should deny Shell's objection, when it is weighed against the reasonableness of the stipulation as a package (AEP Reply Br. at 61-62). Also as part of its OSP, AEP proposed an $0.11 monthly alternative metering credit for CSP residential customers and a $0.12 monthly alternative metering credit for OP residential customers (AEP Ex. 2, Part A, UNB-1, Sheet No. 10-1D). Shell states that the proposed alternative metering credits are too low and effectively amount to barriers for suppliers to undertake alternative metering (Shell Ex. 6, at 78; Shell Initial Br. at 66-67). Shell wants the credits to reflect the utilities' fall cost, not only avoided cost (Shell Ex. 6, at 78). AEP states that the Commission should likewise deny Shell's objection, when it is weighed against the reasonableness of the stipulation as a package (AEP Reply Br. at 61-62). Similar to our finding for the consolidated billing credit amount, we conclude that the switching fee and alternative metering credit amounts are acceptable. Although we might conclude, based upon a fully litigated record, that other amounts are more appropriate, we have no evidence in the record to do so. Shell presented no such evidence as to what it contends are appropriate dollar amounts. Accordingly, we conclude that the modified switching fee and the alternative metering credit amounts proposed by AEP are acceptable, in the context of the overall settlement package presented to us. 4. SUPPLIER REGISTRATION REQUIREMENTS As part of the OSP, AEP proposed a two-step certification/registration process. AEP stated that, along with the Commission's certification process, it "proposes a registration process for its service territory" (AEP Ex. 2, Part A, UNB-1, Sheet No. 3-15D - 3-16D for CSP and Sheet No. 3-19D - 3-20D for OP). The registration process would require: (1) proof of certification, (2) $100 annual fee; (3) financial instrument to ensure against defaults and a description of the plan to meet requirements of firm service customers; (4) contact information; (5) dispute resolution process for supplier customer complaints; and (6) statement of adherence with tariffs and any agreements between AEP and the supplier (ID.). Shell contends that approval of the OSP will allow AEP to improperly impose additional certification requirements upon suppliers, beyond the Commission's certification requirements (Shell Ex. 6, at 68-72; Shell Initial Br. at 66-67). As noted earlier, on July 19, 2000, we approved of the OSPO's proposed pro forma tariff. That tariff contained (in Section V) the following language associated with supplier registration process, beyond the Commission's certification requirements: The Company shall approve or disapprove the supplier's registration within 30 calendar days of receipt of complete registration information from the supplier. The 30 day time period may be extended for up to 30 days for --------------------- SAFETY STANDARDS PURSUANT TO CHAPTER 4928, REVISED CODE, Case Nos. 99-1611-EL-ORD and 99-1613-EL-ORD, respectively. (24) Shell referred to the $5.00 switching fee proposal. We presume that Shell considers the current, higher fee proposal to be excessive as well and, therefore, shall address the argument. 99-1729-EL-ETP and 99-1730-EL-ETP -31- good cause shown, or until such other time as is mutually agreed to by the supplier and the Company. The approval process shall include, but is not limited to: successful completion of the credit requirements and receipt of the required collateral if any by the Company, executed EDI Trading Partner Agreement and Certified Supplier Service Agreement, payment and receipt of any supplier registration fee and completion of EDI testing for applicable transaction sets necessary to commence service. The Company will notify the supplier of incomplete registration information within ten (10) calendar days of receipt. The notice to the supplier shall include a description of the missing or incomplete information. Thus, we have agreed, not only that the electric utilities can have registration processes, but the registration processes can include some of the very items that were proposed by AEF in its transition plan. However, we believe that the stipulation before us resolves Shell's concerns over AEP's proposed registration requirements. In Section XI, the companies agree to accept resolution of issues by the OSP working group and to incorporate such in their transition plans (Jt. Ex. 1, at 7). Registration procedures were mutually resolved by the OSPO working group (as part of the pro forma tariff) after the plan was proposed and we have also approved that uniform tariff. It appears to us that AEP has accepted to modify supplier registration terms to comply with what was adopted by the OSPO working group, to which Shell was also a supporting party. We do not believe that there is any further disagreement on this issue. Accordingly, the Commission will approve the stipulation's treatment of supplier registration conditioned upon certain modifications so that AEP's supplier registration requirements are in full compliance with our orders in 00-813. 5. OVERALL OSP CONCLUSION While the settlement provides several express modifications to the operational support aspects of the transition plan filing, which the company argues benefit customers and suppliers alike, the settlement also states that AEP will abide by Commission determinations related to OSP issues when not resolved by the OSPO (Jt. Ex. 1, at 7). Thus, the settlement sets out not only its own provisions enhancing the development of a competitive retail market, but expressly encompasses such measures that the Commission has adopted to reach the same goal. We believe the companies' OSP set forth in the stipulation, subject to modifications to comply with 00-813, is reasonable and appropriately addresses operational support systems and technical implementation procedures. Accordingly, we find the transition plan meets the statutory requirements of Section 4928.34(A)(9), Revised Code. The Commission directs its staff to finalize a bill format that includes a "price to compare" (which is the price for an electric supplier to beat in order for the customer to save money) for residential and small commercial 99-1729-EL-ETP and 99-1730-EL-ETP -32- customers.(25) As part of our approval of AEP's transition plans, the companies must meet staff's requirements regarding billing format. D. EMPLOYEE ASSISTANCE PLAN (EAP) AEP's EAP was presented in the testimony of Melinda S. Ackerman, Vice President of Human Resources for American Electric Power Service Corporation (AEP Ex. 5). Ms. Ackerman stated that, in the event of job displacement due to organizational restructuring, AEP's EAP consists of programs to help individuals locate new positions, a relocation assistance program, an educational assistance program, professional outplacement services, and a re-employment workshop (AEP Ex. 5, at 2-3). Additionally, the EAP includes programs designed to help deal with the emotional and financial issues associated with displacement, such as, counseling, severance, extended medical and life benefits, and early retirement (ID. at 3). Ms. Ackerman noted that the programs being sponsored as the EAP are existing already and the companies have not identified any eligible employees (ID.). Finally, Ms. Ackerman noted that the companies are not seeking cost recovery in the transition charge of any costs associated with the EAP (ID.), UWUA points out that the EAP is lacking a disparate/adverse impact statement in accordance with Rule 4901:1-20-03, Appendix C, Part (C)(8), O.A.C. UWUA assert that, to the extent AEP seeks to "downsize" during the MDP, the Commission's regulations will require submission and approval of a disparate/adverse impact statement (UWUA Br. 2 and 4). Despite the fact that AEP has proposed no staffing changes and is not seeking any related transition cost, UWUA states that the filing of the statement is necessary before any staff downsizing takes place, not vice versa, so that the Commission can ensure the availability of reliable, safe, and efficient electric service (ID. at 4). Therefore, UWUA states that any approval of the transition plan (including the EAP) should include a condition requiring AEP to file and obtain approval of a disparate/adverse impact statement PRIOR to carrying out proposed staffing changes during the MDP (ID. at 6-7). Additionally, UWUA states that the Commission should clarify that "downsizing" during the MDP gives rise to the requirement of advance filing and approval of a disparate/adverse impact statement (ID. at 5-7). AEP responds by stating that, since it did not identify any positions affected by SB 3, no disparate/adverse impacts could be explained and, therefore, its EAP filing satisfies the Commission's filing requirements (AEP Reply Br. at 62). Next, AEP states that the UWUA would expand the requirement to apply to any downsizing, rather than just for employees that are adversely and directly affected by electric restructuring (ID. at 62-63). Lastly, AEP states that the UWUA's suggestion should be rejected because the Commission should not establish procedures for addressing speculative events; rather, the Commission can determine what procedures, if any, are appropriate when such a change occurs (ID.). Section 4928.31(A)(4), Revised Code, requires a utility to file, as part of its transition plan, an employee assistance plan "for providing severance, retraining, early retirement, ------------------- (25) We recognize that AEP already proposed a chart that reflects the companies' prices to compare, but by tariff service (AEP Ex. 9D at Attach. I). This information should be helpful for finalizing the bill format that includes the "price to compare" information. 99-1729-EL-ETP and 99-1730-EL-ETP -33- retention, outplacement, and other assistance for the utility's employees whose employment is affected by electric industry restructuring..." Rule 4901:1-20-03, O.A.C., Appendix C, Part (B)(3), defines "employee affected by restructuring" as an employee who is "directly and adversely affected by electric restructuring during the [MDP]...." Part (A) of the rule requires the utility to explain "how it would mitigate any necessary reductions in the electric utility workforce." Part (C) requires the EAP to provide the following components: notification of employees; outplacement assistance; relocation assistance; employee assistance, such as counseling; early retirement programs; severance packages; and "other assistance." To the extent UWUA argues that the EAP is deficient because no disparate/adverse impact statement was included, we disagree. Since the companies concluded that no employees would be directly and adversely affected by electric restructuring during the MDP, we do not believe a disparate/adverse impact statement was required in the filing. We find that AEP's EAP satisfies the filing requirements of Rule 4901:1-20-03, O.A.C. UWUA does also seek a further requirement for AEP. UWUA states that any approval of the transition plan (including the EAP) should include a condition requiring AEP to file and obtain Commission approval of a disparate/adverse impact statement prior to carrying out proposed staffing changes during the MDP. On this point, UWUA is seeking a Commission requirement upon AEP to file, during the MDP, statements regarding what effect planned staffing changes will have on service delivery. AEP is correct in noting that UWUA's request would apply to any staff changes, not just those directly and adversely affected by electric restructuring. For that reason, we agree that UWUA's request is somewhat over-broad. However, we do not believe such a condition upon approval of the EAP is unwarranted. Rather, we find it appropriate to require AEP to provide a disparate/adverse impact statement (in this docket) should the company subsequently determine that a reduction in the staffing level is necessary due to electric restructuring during the MDP. Moreover, we will require AEP to provide the Commission with all terms and conditions related to the sale of corporate assets (including the sale of affiliate coal mines) that could have an impact on employment levels. We will of course be monitoring the service delivery and will take all necessary steps to ensure that just, reasonable, reliable and safe electric service is provided. Pursuant to Section 4928.34(A)(10), Revised Code, the Commission finds that the companies' EAP, with the above-noted conditions, sufficiently provides severance, retraining, early retirement, retention, outplacement, and other assistance for the company's employees whose employment is affected by electric industry restructuring. E. CONSUMER EDUCATION PLAN Section 4928.31(A)(5), Revised Code, requires each utility's transition plan to include a consumer education plan consistent with Section 4928.42, Revised Code, and the applicable Commission rules. Section 4928.42, Revised Code, provides that, prior to the starting date of competitive retail electric service, the Commission shall prescribe and adopt a general plan by which each electric utility shall provide during its MDP consumer education on electric restructuring. Utilities are required to spend up to $16 million in the first year on consumer education within their certified service territories and an additional $17 million in decreasing amounts over the remaining years of the MDP. As part of its transition plan, AEP filed an education plan (AEP Ex. 2, Part E). AEP 's education plan targets residential customers, small and mid-sized commercial customers, elected officials, 99-1729-EL-ETP and 99-1730-EL-ETP -34- community leaders, civic organizations, trade associations, and consumer groups (AEP Ex. 9A, at 25). Industrial customers' needs will be addressed on an individual basis (ID.). A special effort will target low-income, special needs, and hard-to-reach customers (ID.). The plan also describes the methods, timelines, and spending that will be used for AEP's education campaign. Some opposition to AEP's education plan was raised by the Coalition for Choice in Electricity (CCE)(26) and OCC. As noted earlier, on November 30, 1999, the Commission issued rules for the electric transition plan proceedings. At that same time, the Commission adopted in Case No. 99-1141-EL-ORD a general plan for the electric utilities' consumer education. After the companies filed their transition plans, various intervenors filed preliminary objections. Separate staff reports were filed in each of the transition plan proceedings. In each staff report, the staff stated that the consumer education plans are consistent with the requirements issued by the Commission on November 30, 1999.(27) After reviewing all of the education plans filed in all of the transition cases and after considering the objections and comments submitted, we found in our July 19, 2000 Finding and Order in these proceedings that AEP's education plan is in compliance with Section 4928.42, Revised Code, and we approved AEP's education plan subject to a few contingencies. First, we noted that, with regard to provisions for the funding of local community-based organizations (CBO), although we did not require funding of the CBOs, we did encourage AEP to provide CBO funding. Second, we required AEP to include an unaffiliated energy marketer representative on the advisory board (we allowed AEP's operating companies to have a combined advisory group and a combined service territory-specific campaign). Third, we required that the plans for AEP include further details on how the territory-specific campaign will be managed and operated, how materials and information will be disseminated, and how funds will be allocated to activities, as well as other matters. Further, we conditioned our approval on the Commission staff's continuing supervision of the general and territory-specific plans as further details are developed for each of the consumer education programs. With the conditions to AEP's education plan set forth in our July 19, 2000 order, we find that AEP's transition plan complies with Section 4928.31(A)(5), Revised Code. Additionally, the Commission finds that the companies' consumer education plan sufficiently complies with Section 4928.34(A)(10), Revised Code, F. INDEPENDENT TRANSMISSION PLAN Section 4928.34(A)(13), Revised Code, requires that any transmission plan included in the transition plan must reasonably comply with Section 4928.12, Revised Code, and any rules adopted by the Commission unless the Commission, for good cause shown, authorizes the company to defer compliance until an order is issued under Section 4928.35(G), Revised Code.(28) Pursuant to Section 4928.12(A), Revised Code, no entity shall own or control transmission facilities (as defined by federal law) in Ohio as of the date of competitive retail electric service unless the entity is a member of, and transfers control of ---------------------- (26) The CCE group includes various marketers, low-income representatives, IEU, OCRM, OPAE, city of Cleveland, AMP-Ohio, and OMA. (27) The staff's only recommendation for the AEP consumer education plan was the inclusion of an energy marketer representative in the advisory group. (28) Section 4928.35(G), Revised Code, governs requirements for utilities that do not have an independent transmission plan with respect to transfer of control and operation of transmission facilities. 99-1729-EL-ETP and 99-1730-EL-ETP -35- those facilities to, one or more qualifying transmission entities. Section 4928.12(B), Revised Code, sets forth the specifications that such entities must meet. Both existing federal(29) and state requirements are designed to achieve the same key objectives for transmission service in the development of competitive wholesale and retail energy markets. These shared objectives include: corporate separation of generation and transmission, with decisions to provide service, pricing, and expansion of facilities made on an independent basis from the transmission provider's ownership of generation facilities; creation of RTOs with sufficient scope and configuration to increase economic supply options to customers; elimination of pancaked transmission charges within a single RTO; and improved reliability of transmission service. AEP's witness Craig Baker (AEP Exs. 6A, 6B, an d 6C) explained that the company will satisfy the requirements of the Ohio statute by transferring control and operation, and ultimately ownership, of its transmission facilities to the Alliance RTO. The Alliance RTO is currently composed of FirstEnergy Corporation, AEP, Consumers Energy Company, The Detroit Edison Company, and Virginia Electric and Power Company (AEP Ex. 6A at 4).(30) As presently configured, the Alliance RTO would serve a nine-state area with a population of approximately 26 million people and a connected load of 67,000 megawatts (AEP Ex. 2, Part G at 8). The Alliance transmission system has connected generation capacity of 72,000 megawatts and will be one of the largest RTOs in the nation (ID.). The FERC conditionally approved the Alliance RTO in December 1999, but required that the participants modify certain aspects of the entity's independence, governance configuration, and tariff design. 89 FERC paragraph 61,298 (1999). AEP claims that, upon final operational implementation, the Alliance RTO will minimize pancaked transmission rates within Ohio to the extent reasonably possible and be consistent with Section 4928.12(B)(3), Revised Code (AEP Ex. 6C at 8). Until the Alliance RTO is operational and the transfer has occurred, AEP proposes that retail customers or their suppliers use AEP's OATT to transmit power and energy from alternative suppliers to the customers' load (AEP Ex. 8B at 2). Thereafter, transmission service to retail customers will cease under AEP's OATT, but be offered by the Alliance RTO OATT (ID.). Additionally, in March 2000, the FERC conditionally approved the merger between American Electric Power Corporation and Central and South West Company. 90 FERC paragraph 61,242 (2000). That merger transaction will also impact the transferring of control, operation, and ultimately ownership of AEP's transmission facilities to the Alliance RTO. Although the Alliance RTO may not be operational before customer choice commences in Ohio (January 1. 2001), AEP asserts that the settlement will provide benefits to participants in the Ohio retail generation market (AEP Initial Br. at 69-71). The stipulation obligates AEP to transfer control and operation, and ultimately ownership, of AEP's transmission facilities to a FERC-approved RTO no later than December 15, 2001 (Jt. Ex 1, at 5). Additionally, AEP identified three transmission-related benefits of the stipulation that are specific to the period of time before that RTO becomes operational: ------------------ (29) Order No. 888, FERC Stats. & Regs. paragraph 31,089 (2000) and Order No. 2000, FERC Stats. & Regs., paragraph 31,036 (1996). (30) The Dayton Power & Light Company and Illinois Power Company have also announced their intention to join the Alliance RTO. 99-1729-EL-ETP and 99-1730-EL-ETP -36- (1) AEP will provide two full-time equivalent positions in the System Control Center to assist transmission uses with reservations, scheduling, and tagging; (2) AEP or its affiliates will provide transmission services for all power, including transmission of default service power and power for affiliated and nonaffiliated energy service providers only under the proposed PRO FORMA transmission tariff; and (3) AEP or its affiliates will comply with OASIS and conduct requirements promulgated by FERC. (ID. at 5, 8). Next, AEP listed four other transmission-related benefits of the stipulation. First, AEP will account for partial megawatt-hours when the load served by imports across AEP interfaces does not result in whole megawatts (Jt. Ex. 1, at 5). Second, AEP is required to make a unilateral filing at FERC to extend rollover rights to retail customers or their supplier, requesting an effective date of January 1, 2001 (ID.). Third, AEP will work with RTOs/ISOs and transmission-level customers to develop and implement resolutions for reciprocity and interface/seam issues and, if no other filing on this subject is made by September 1, 2000, AEP will file a proposal with the FERC (ID. at 5). Fourth, AEP will fund up to $10 million for costs imposed by PJM and/or the MISO on generation originating in the MISO or PJM (Id. at 5-6). In Shell's reply brief it argues that the $10 million fund will not promote competition because the commitment may not reach $10 million in the short time period and because the dollars are available for only certain transmission costs (Shell Reply Br. at 30). Shell estimates that the fund will only (at best) benefit 6 percent of the AEP load (Tr. III, 162-164; Shell Reply Br. at 31). Pursuant to Section 4928.34(A)(13), Revised Code, as an alternative to approving an independent transmission plan that complies with Section 4928.12, Revised Code, the Commission may, for good cause shown, authorize a company "to defer compliance until an order is issued under division (G) of section 4928.35 of the Revised Code." Because the Commission cannot determine, at this time, whether the Alliance ISO (or any other FERC-approved RTO as allowed by the stipulation) is compliant with the requirements of Section 4928.12, Revised Code, (due to changes that will occur as a result of the FERC's ongoing proceeding addressing the Alliance RTO, for instance), the Commission will defer approval of AEP's independent transmission plan until the opportunity is available to address the changes to the FERC-approved RTO. The Commission will exercise this later decision process through an order issued under Section 4928.35(G), Revised Code. We will authorize AEP to defer compliance with this provision until an order is issued pursuant to Section 4928.35(G), Revised Code. We will, however, address Shell's arguments against Section VIII of the stipulation ($10 million transmission fund). On balance, we find the $10 million fund to be a unique benefit offered by the stipulation. It is one of several beneficial aspects of the stipulation. While on its own, this term of the stipulation may not create effective competition, it can (in conjunction with all of the other terms of the plans and stipulation) collectively "jump 99-1729-EL-ETP and 99-1730-EL-ETP -37- start" competition and spur the development of effective competition in AEP's territory. For these reasons, we reject Shell's criticism of the $10 million transmission fund. G. SECTION 4928.34(A)(14), REVISED CODE Section 4928.34(A)(14), Revised Code, states that one of the findings the Commission must make in approving a utility's transition plan is that the utility is in compliance with Sections 4928.01 through 4928.11, Revised Code, and any rules or orders adopted or issued by the Commission under those sections. We wish to make clear that we have a continuing obligation to ensure that the transition plan and its implementation are in keeping with the policy of the state, as set forth in these provisions of the statute. For example, through the monitoring of markets and enforcement with fair standards of competition, we intend to make, as a top priority, enforcement of the overarching policies of SB 3 to ensure open markets. We believe that this prerequisite is thereby satisfied. H. ACCOUNTING AUTHORITIES The signatory parties also seek from the Commission the authority to implement various accounting entries on the regulatory books. These requested accounting approvals have been identified either in the companies' filings or in the transition plan settlement agreement and include: (1) Requested amortization of regulatory assets during the MDP and thereafter until such regulatory assets are fully amortized. (2) Requested amortization (on a per kilowatt-hour basis) of regulatory assets as of the beginning of the MDP that exceed the amounts on the attachment to the stipulation. Such amortization will occur during the MDP and recovered through existing frozen and unbundled rates. (3) Requested deferral of certain new regulatory assets actual costs, plus a carrying charge, as regulatory assets for future recovery in future distribution rates. (4) Addressing the issue of potential violations of Internal Revenue Code normalization rules with respect to amortization or regulatory liabilities of investment tax credits and deferred income taxes. The signatory parties ask that the Commission adopt certain specific language found in the settlement. (Jt. Ex. 1, at 4, 10). The requested accounting authority is reasonable and shall be granted. Additionally, we will approve the following language contained in the agreement: The base rates in the [MDP] embodied in this opinion and order include the amortization of regulatory liabilities related to [investment tax credits] no more rapidly than ratably, and the amortization of "excess 99-1729-EL-ETP and 99-1730-EL-ETP -38- deferred taxes" using the Average Rate Assumption Method in order to avoid any potential normalization violations. IV. THREE-PART TEST FOR EVALUATING STIPULATIONS Rule 4901-1-30, O.A.C., authorizes parties to Commission proceedings to enter into stipulations. Although not binding on the Commission, the terms of such agreements are accorded substantial weight. SEE, CONSUMERS COUNSEL V. PUB. UTIL. COMM. (1992), 64 Ohio St.3d 123, at 125, citing AKRON V. PUB. UTIL. COMM. (1978), 55 Ohio St.2d 155. This concept is particularly valid where the stipulation is supported or unopposed by the vast majority of parties in the proceeding in which it is offered. The standard of review for considering the reasonableness of a stipulation has been discussed in a number of prior Commission proceedings. SEE, E.G., OHIO-AMERICAN WATER CO., Case No. 99-1038-WW-AIR (June 29, 2000); CINCINNATI GAS & ELECTRIC CO., Case No. 91-410-EL-AIR (April 14, 1994); WESTERN RESERVE TELEPHONE CO., Case No. 93-230-TP-ALT (March 30, 1004); OHIO EDISON CO., Case No. 91-698-EL-FOR et al. (December 30, 1993); CLEVELAND ELECTRIC ILLUM. CO., Case No. 88-170-EL-AIR (January 30, 1989); RESTATEMENT OF ACCOUNTS AND RECORDS (ZIMMER PLANT), Case No. 84-1187-EL-UNC (November 26,1985). The ultimate issue for our consideration is whether the agreement, which embodies considerable time and effort by the signatory parties, is reasonable and should be adopted. In considering the reasonableness of a stipulation, the Commission has used the following criteria: (1) Is the settlement a product of serious bargaining among capable, knowledgeable parties? (2) Does the settlement, as a package, benefit ratepayers and the public interest? (3) Does the settlement package violate any important regulatory principle or practice? The Ohio Supreme Court has endorsed the Commission's analysis using these criteria to resolve issues in a manner economical to ratepayers and public utilities. INDUS. ENERGY CONSUMERS OF OHIO POWER CO. V. PUB. UTIL. COMM. (1994), 68 Ohio St.3d 547 (CITING CONSUMERS' COUNSEL, SUPRA, at 126). The court stated in that case that the Commission may place substantial weight on the terms of a stipulation, even though the stipulation does not bind the Commission. ID. AEP, OCC, the staff, and IEU-OH all state that the stipulations comport with this criteria (AEP Ex. 18, at 3; AEP Initial Br. at 9-14, AEP Reply Br. at 64; OCC Initial Br. at 12-13; Staff Initial Br. at 3-6; IEU-OH Br. at 3-4). Shell argues the stipulations are not in the public interest (Shell Initial Br. at 9-10). Based on our three-prong standard of review, we find that the first criterion, that the process involved serious bargaining by knowledgeable, capable parties, is met. Counsel for the applicant and the staff, as well as the numerous intervenors, have been involved in many cases before the Commission, including a number of prior cases 99-1729-EL-ETP and 99-1730-EL-ETP -39- involving rate issues. Further, there have been few settlements in major case before this Commission in which the overwhelming majority of intervenors either supported or did not oppose the resolution of issues presented by the stipulations. The stipulations also meet the second criterion. The stipulated resolution of these proceedings advances the public interest by resolving the extensive and complex issues raised in this proceeding without incurring the extensive time and expense of litigation that would otherwise have been required. In the case of the ANM stipulation, it will defer to an already pending proceeding the debate of pole attachments. We believe that such an agreement is in the interest of bringing the bigger restructuring issues to the forefront for resolution so that competitive choice can effectively begin on January 1, 2001. For that reason, we believe that the ANM stipulation advances the public interest. Adoption of the stipulations also reduce significantly the number of possible appeals, and provides additional lead time to put in place the mechanisms necessary to get the customer choice program up and running. Additional evidence that the public interest is served by the stipulations is found in the support offered by representatives of residential, commercial, and industrial customers, including OCC and the Commission's staff. As indicated above, the agreement provides that certain rates will be decreased and the prior rate plan freezes extended. Some of the stipulations' tangible benefits include: (1) Freezing, for the most part, base distribution rates for an additional 2 years beyond the MDP for OP and three additional years beyond the MDP for CSP; (2) Absorption by both companies of the first $40 million in consumer education, customer choice implementation, and transition plan filing costs; (3) Providing an additional shopping incentive of 2.5 mills/ kilowatt-hour to the first 25 percent of the CSP residential class load that switches during the MDP, with the unused portion being credited to the RTC; (4) Providing assistance to transmission users with reservations, scheduling, and tagging for the period of time before AEP transfers control and operation, and ultimately ownership, of AEP's transmission facilities to an RTO; (5) Accounting for partial megawatt-hours when load imports across AEP interfaces does not result in whole megawatt hours; (6) Providing a fund (up to $10 million) for reimbursement of certain transmission costs incurred by suppliers or customers; (7) Requiring the companies to reduce charges to residential customers during the MDP by 5 percent of transition costs; 99-1729-EL-ETP and 99-1730-EL-ETP -40- (8) Revising tariffs and schedules to equalize bill impacts within the commercial class; (9) Providing additional commitments to resolve interface, seam, and reciprocity issues impacting transmission; (10) Providing a credit to suppliers for consolidated bills during the first year of the MDP; (11) Providing commercial and industrial customers only a 90-day advance notice Of intent to switch suppliers; (12) For the first 20 percent of OP residential customers on its standard service offer, charging no RTC when they switch between 2006 and 2007; and (13) Negotiating with signatory marketers (as well as Shell) regarding a load shaping service. (Jt. Ex. 1). We believe that the terms of these agreements, considered in their totality, provide a sufficient basis for concluding that the settlement is in the public interest. Although it Will undoubtedly take some time for a fully competitive electric retail market to develop, the stipulations presented in this proceeding provide an opportunity to "jump start" the market by providing the resources necessary for retail customers to begin to shop for competitive generation services. For all these reasons, we find that the stipulations should be approved, subject to the modifications and clarifications described above. Finally, the stipulations meet the third criterion because they do not violate any important regulatory principle or practice. Indeed, the agreements balance the interests of a broad range of parties that represent a diverse spectrum of views. As indicated in the description of stipulations provided above, the stipulations provide substantial benefits to all customer classes and shareholders. Further, the policies of the state embodied in SB 3 will be implemented more quickly and efficiently than would otherwise be possible. V. GROSS RECEIPTS/EXCISE TAX ISSUE As part of their applications in these cases, the companies have included a public utilities excise tax credit rider. The companies intend that the credit rider become effective on April 30, 2002, the date on which the companies contend that ratepayer liability for the public utility excise tax ends. Prior to the effective date of the credit rider, the companies would collect through their respective rates an amount, which specifically represents the ratepayers' obligation for this tax. On the effective date of the public utilities excise tax credit rider, each of the companies will begin crediting back to their customers that amount included in their respective rates representing the public utilities excise tax. The parties opposing the companies with regard to this issue (staff, OCC, and IEU-Ohio) argue that the companies will have recovered this tax expenditure fully by April 30, 2001. Therefore, it is the position of these parties that the public utilities excise tax credit rider 99-1729-EL-ETP and 99-1730-EL-ETP -41 should become effective on April 30, 2001. As noted earlier, the parties signing the stipulation in this case have reserved this issue for Commission decision. The companies note that the public utilities excise tax is popularly referred to as the "gross receipts tax". The companies state that, contrary to this popular usage, the tax is not a "gross receipts" tax, but an "excise" tax. That is, the tax is not a tax on the gross receipts of utility companies but an assessment on the particular utility company for the privilege of doing business in a particular year, referred to as the privilege year. The amount of the tax is determined by the gross receipts of the particular utility for the year immediately prior to the privilege year, referred to as the measurement year. Because the amount of the gross revenues is not determined until the end of the measurement year, the companies argue that it is not possible for the companies' customers to have paid the tax for a particular privilege year until after the measurement year has expired. Earl Goldhammer, a witness for AEP, testified that SB 3 provides for the final year for which electric utilities will be liable for the public utility excise tax. Mr. Goldhammer further testified that, under SB 3, Ohio electric companies' final annual public utility excise tax reports will be filed on or before August 1, 2001. These reports are for the privilege year May 1, 2001 through April 30 2002. Mr. Goldhammer notes that the last public utility excise tax lien attaches on May 1, 2001. According to Mr. Goldhammer, the report each of the companies files will indicate that company's taxable gross receipts for the preceding twelve months-May 1, 2000 through April 30, 2001. The tax the Tax Commissioner assesses is 4.75 percent times the taxable gross receipts during the measurement period - May 1, 2000 through April 30, 2001. In accordance with statutory law, in December 2001, any tax deficiency or refund based on the assessment will be paid by or to the companies (Tr. 11, 8). Mr. Goldhammer argues that AEP does not become exempt from the public utility excise tax until the end of the privilege year ending April 30, 2002. Further. Mr. Goldhammer states the companies' tax liability for the last privilege year is not fixed as the companies receive rate payments from customers during the May 1, 2000 - April 30, 2001 measurement period. The intent of the General Assembly that the electric companies public utility excise tax obligation continues through April 30, 2002 is evidenced, Mr. Goldhammer concludes, by the manner in which the liability for the new corporate franchise tax was implemented. The companies contend that it is recognition of the fact that electric utilities will be paying the existing public utility excise tax for the privilege of doing business and owning property in Ohio through April 30, 2002, i.e. one third of the privilege year, that the payment the General Assembly requires for the 2002 franchise tax year equals only two-thirds of the tax liability for 2002. (ID. at 5). As a corollary to the above arguments, the companies cite Section 4928.34(A)(6), Revised Code, as follows: To the extent such total annual amount of the tax-related adjustment is greater than or less than the comparable amount of the total annual tax reduction experienced by the electric utility as a result of the provisions of Sub. S.B. No. 3 of the 123rd General Assembly, such difference shall be addressed by the Commission through accounting procedures, refunds, or an annual surcharge or credit to customers, or through other appropriate 99-1729-EL-ETP and 99-1730-EL-ETP -42- means TO AVOID PLACING THE FINANCIAL RESPONSIBILITY FOR THE DIFFERENCE UPON THE ELECTRIC UTILITY OR ITS SHAREHOLDERS (Emphasis added.) Because the companies are required to pay the public utility excise tax until April 30, 2002, they argue, it is clear that the Ohio General Assembly intended that their shareholders be held harmless for the amounts the companies owe after April 30, 2001. In their brief, the companies note that Sections 5727.33(A) and (B), Revised Code, provide that the tax is based on "the entire gross receipts actually received from all sources", excluding receipts derived wholly from interstate commerce, from business done for or with the federal government, from the sale of merchandise, and from sales to other public utilities. AEP argues that not only are rentals and other operating and non operating receipts includable gross receipts for purposes of calculating the public utility excise tax, but not all of the gross receipts from Ohio jurisdictional utility service derive from rates which are based, in part, on recovery of a test year level of that tax expense. William Forrester, a witness for the companies, testified that when the companies' electric fuel component (EFC) increases, that increase causes an increase in the companies' public utility excise tax expense, but there is no automatic change to base rates to compensate for this increased public utility excise tax expense (AEP Ex. 9D at 5). Consequently, the companies' note their EFC rates have fluctuated since a test year level of public utility excise tax was determined in their most recent base rate cases, there has been a breach in the relationship between gross receipts from jurisdictional service and any assumed amount that customers pay in their rates for this tax expense. The companies also argue that even the Staff recognized that the disconnect caused by EFC revenues has an impact on the companies' public utility excise tax obligation and is not built into base rates as part of the test year excise tax expense (Tr. II, 83, 114). Finally, the companies cite this Commission's decision in the FirstEnergy transition plan cases for the proposition that this Commission has already determined this issue in the companies' favor. In AEP's view, the Commission adopted in FIRSTENERGY, SUPRA, a stipulation pursuant to which the companies can recover from ratepayers amounts representing the public utilities excise tax through April 30, 2002. For the most part, the three parties opposing AEP with regard to this issue, staff, OCC, and IEU-Ohio, find no fault with the facts as set forth above. These parties agree that the tax is not in reality a "gross receipts tax", but an excise tax. The parties also agree with the companies' description of the method used to determine and assess the tax. The parties agree that the tax is an appropriate expense in the privilege year. The parties further agree that the companies' public utility excise tax obligation continues through April 30, 2002. The parties agree to the above, but consider these matters irrelevant to the issue at hand. According to staff, OCC, and IEU-Ohio, the issue to be resolved by the Commission in these proceedings is the liability of the companies' ratepayers for payment of the public utility excise tax through April 30, 2002. These parties contend that the ratepayer's liability ends on April 30, 2001. The issue as viewed by staff, OCC, And IEU-Ohio is primarily a question not of tax law, but of regulatory law. These parties, looking at the Commission's ratemaking process, argue that the ratepayers have paid through the rates charged by the companies in the "measurement year" amounts representing the companies' public utility excise tax 99-1729-EL-ETP and 99-1730-EL-ETP -43- obligation for the subsequent privilege year. That is to say, the companies' ratepayers have furnished the companies' monies in the year 2001 to reflect the companies' public utility excise tax obligation in the privilege year ending April 30, 2002. According to staff, if rates were intended merely to repay the companies for current expenditures for the public utility excise tax, all that would be required would be the inclusion of the current year's payments in the cost of service. The ratemaking treatment could have stopped at that point. It did not and so staff argues that the current payments for the tax were included in the cost of service calculation, but the revenue increase was also "grossed up" explicitly to reflect this tax. In fact, staff notes, the Commission, in arriving at the rate to be charged by a company seeking a rate increase, also calculates the "tax on tax" effect, i.e., the Commission recognizes that the revenues provided to a company to pay the gross receipts tax will themselves be subject to the tax (Staff Ex. 1, at 3). The Commission would not have made these calculations, staff argues, if the Commission's only concern was to recompense the company for the then-current (test year) tax expenditure since the test year tax expenditure was not affected by the increase. Nor, staff argues, did the Commission make these calculations to reflect the next year's tax expenditure since the increased revenues the companies enjoyed in first year after an increase did not have an impact on the companies' tax payments until the following year. Staff contends that because the rates are calculated to meet a company's cost of service and then grossed up to include the ultimate tax, the rates provide not the return of a fixed dollar value, but rather a percentage of whatever the revenues are. Each dollar, staff argues, includes the tax that will ultimately be owed. Staff concludes, therefore, that the ratepayers' tax obligation tracks the payments made dollar-for-dollar and in advance. Because the companies' revenues, grossed up to include the ultimate tax increase before the taxes increase, staff argues, it is clear, as a matter of fact that ratepayers prepay this tax expense. OCC's analysis and conclusions with regard to this coincide with those of staff in regard to the ultimate merits of the companies' proposed specific recovery of the public utility excise tax obligation through a tariff rider. IEU-Ohio states that, on balance, it believes staff and OCC have the better of the argument. Staff is not persuaded by the companies' arguments regarding the Commission's decision in the FirstEnergy transition plan cases. Staff notes that the FIRSTENERGY settlement is a so-called "blackbox" settlement. That is, FirstEnergy will obtain certain cash flows without agreement as to what those flows represent. In Staff's opinion, FirstEnergy could allocate more of these cash flows to excise taxes and lower its earnings or not. Staff is indifferent to FirstEnergy's choice because, as staff views the matter, there are no new monies extracted from the ratepayers and the "blackbox" settlement values are reasonable, in and of themselves, without any specific recovery of the public utilities" excise tax. However, staff notes, in the AEP situation, the companies seek additional cash, flows from the ratepayers specifically for this excise tax. Staff opposes the companies recovering additional cash flows representing a specific recovery of this excise tax as a double recovery of this expense item. OCC argues that the companies' position regarding base rates not fully recovering the gross receipts tax associated with fuel revenues or regarding base rates not always fully recovering gross receipts tax expenses are not relevant to the issue with regard to the date ratepayer funding of the Ohio gross receipts tax must cease. OCC notes there is no dispute that the tax expense embedded in base rates does not track changes in the companies' respective EFC-related revenues or that base rates do not always fully recover 99-1729-EL-ETP and 99-1730-EL-ETP -44- gross receipts tax expenses. However, if under-recoveries of the public utilities excise tax had been a serious problem over the years since the companies' last rate cases, OCC argues, they should have sought rate relief. The issue before us is purely one of fact, i.e., when does the liability of the companies' ratepayers for the public utility excise tax end. The companies' position is that the obligation of ratepayers to fund this tax ends on April 30, 2002. Staff's position with regard to this question is that ratepayers' obligation to fund the tax terminates on April 30, 2001. Of the two positions before us, the Commission finds staff's position to be the more reasonable. As staff argues the Commission's rate case process "grosses up" the revenues awarded in a rate proceeding to include the tax effect of the rate increase allowed by the Commission. Through the rate case process, the Commission even accounts for the increase in gross revenues caused by the tax itself, the so-called "tax on tax" effect. Thus, as argued by staff and OCC, the companies' customers pay in the measurement year amounts representing the companies public utilities tax obligation in the subsequent privilege year. For the purposes of illustration, assume that the measurement year for the public utilities excise tax is 2000 and the privilege year is 2001. If the Commission granted the companies a rate increase effective January 1, 2000, the ratepayers would be paying for the whole year of 2000, the measurement year, an amount that represents the companies' public utilities tax obligation for the privilege year of 2001. It is clear the ratepayers are not paying the companies' public utilities tax obligation for the privilege year of 2000 in 2000. The measurement year for privilege year 2000 is 1999. In 1999, the rate increase was not in effect. We do not find the companies' arguments related to our adoption of the stipulation in the FirstEnergy transition plan cases to be relevant to the resolution of any issue before us in these cases. Stipulations are filed in a myriad of cases before this Commission for a number of different reasons. Sometimes a party is unsure how a particular issue will be resolved by the Commission so it will reach agreement with the other parties in the case on that issue, often giving up something in return, through the vehicle of a stipulation. Sometimes, in so-called "black box" stipulations, dollar figures will be agreed to and each of the parties may claim victory as to the same issue. Sometimes various issues are compromised just to reach settlement on issues vital to one or more of the parties. In adopting stipulations, the Commission views the stipulation as a whole; we do not, for the most part, dissect the document approving some pieces and rejecting others. If we find that the stipulation on balance is reasonable, we will generally adopt the stipulation. In making our determination, we use the three-part test delineated earlier. In adopting the stipulation in the FirstEnergy transition plan cases, we were not passing favorably or negatively on the resolution of any particular issue contained in the stipulation. We found that the stipulation' as a whole met the three-part and was reasonable. The, case before us is the first case requiring a decision on the issue of ratepayer responsibility for a company's public utility excise tax obligation beyond April 30, 2001. Contrary, to the arguments of the companies, our decision with respect to this issue in the cases now before us is not influenced by our decision in the FirstEnergy transition plan cases. Based upon the above findings, we are directing the companies to implement the public utilities excise tax credit rider in their respective transition plans to be effective April 30, 2001. 99-1729-EL-ETP and 99-1730-EL-ETP -45- VI. FILED MOD A. MOTIONS TO REJECT TRANSITION PLANS AS INADEQUATE On January 14 and 18, 2000, OCC and CCE each filed motions to reject the transition plans of AEP. Both argued that the plans should be rejected, pursuant to Section 4928.31(A), Revised Code, because the plans contain a number of substantive deficiencies that needed to be corrected and/or require plan refiling. Section 4928.31(A), Revised Code, grants the Commission authority to reject a plan or to require refiling in whole or in part of any substantially inadequate transition plan. Rule 4901:1-20-14, O.A.C., states that the Commission shall conduct an adequacy review of transition plan filings within 30 days and notify the utility of any inadequacies or if refiling is deemed necessary. If no ruling is issued in that 30-day period, the transition plan application is deemed minimally adequate. In these proceedings, the Commission did not require AEP to refile or notify it of inadequacies in the first 30-day period. Thus, by virtue of the rule, the transition plan applications were deemed minimally adequate. We, therefore, find that the motions to reject the transition plans were, in effect, already ruled upon (and denied). B. OCTA MOTION TO INTERVENE AND SUBSEQUENT CONDITIONAL WITHDRAWAL As noted earlier, the OCTA filed a motion to intervene in these proceedings on the ground that AEP proposed pole attachment tariffs that were improper. However, OCTA filed two days later a notice of conditional withdrawal of its intervention request, stating that, if the Commission accepts AEP's subsequent request to withdraw its originally proposed pole attachment tariffs, OCTA will withdraw its motion to intervene in these proceedings. OCTA stated grounds for intervention in these proceedings. Inasmuch as we accept AEP's withdrawal of its originally proposed pole attachment tariffs (by virtue of our acceptance of the proposed stipulations and AEP's withdrawal of new pole attachment provisions), we conclude that the condition precedent to OCTA's withdrawal from these proceedings has taken place and, therefore, we grant OCTA's withdrawal from these proceedings. C. MOTION FOR PROTECTIVE ORDER On December 30, 1999, as supplemented on January 18, 2000, AEP filed a motion for a protective order with respect to 70 pages of its transition plan filing. AEP filed the information under seal with our docketing division. AEP argues that the information is highly proprietary, competitively sensitive, and confidential. Additionally, the companies state that the information is a trade secret, as defined in Section 1333.61(D), Revised Code. They request a protective order, pursuant to Rule 4901-1-24(D), O.A.C., for the following: (1) Three pages of the direct testimony of Edward Kahn (AEP Ex. 12, Attach. EPK-2). Those pages reveal: historic and forecasted operation and maintenance expenses by generating unit and a forecast of heat rates by generating unit. (2) Projected emission allowance balances for the years ending 1999 and 2000 (AEP Ex. 2, Part F). 99-1729-EL-ETP and 99-1730-EL-ETP -46- (3) Two attachments to the direct testimony of Oliver Sever (AEP Ex. 23, Attach. OJS-1 and QJS-2). Those pages address historic and forecasted fixed and variable operating and maintenance expenses by generating unit and projected fuel costs by generating unit. (4) Study regarding customer switching (AEP Ex. 2, Part H). At the hearing, the same information was placed into the record, as AEP Exhibit 4. We find AEP's motion for a protective order to be reasonable. In accordance with Rule 4901-1-24(F), O.A.C., our docketing Division shall maintain these items under seal for a period of 18 months from the date of this decision. Any party wishing to extend this confidential treatment should file an appropriate motion at least 45 days in advance of the expiration of the protective order. D. MOTION FOR COMPLIANCE TARIFF REVIEW PROCESS On June 27, 2000, CCE filed a motion for a "compliance tariff filing, service, review, and comment procedures" in these transition plan proceedings, as well as the other pending transition plan dockets. The motion states that, because of the broad-sweeping changes that will be subject to the provisions of the tariffs ultimately approved in these proceedings, it is necessary to allow interested parties adequate time to review and comment of the proposed tariffs prior to final approval. CCE requests that the Commission order each of the applicants in the transition plan cases to serve tariffs and associated workpapers simultaneous with their filing with the Commission. CCE asks that a two-week period be provided after the date of receipt of the tariffs and workpapers in order for intervenors to review the documents and submit comments to the Commission for its consideration prior to approval of the tariffs. CCE's motion shall be granted, subject to modification. We believe that, instead of receiving formal filings with respect to FirstEnergy's compliance tariffs, a more informal process will be beneficial to all interested parties. Accordingly, the companies and other interested parties should observe the following timelines for distributing, and reviewing AEP's proposed tariffs pursuant to this decision: (1) within 14 days following the issuance of this decision, AEP should distribute (via electronic mail, fax, or overnight delivery) to all intervenors a working draft of its proposed compliance tariffs, as well as associated workpapers and UNB schedules that reflect the rates embodied in the compliance tariffs; (2) within 14 days thereafter, interested parties should circulate (via electronic mail, fax, or overnight delivery) comments to AEP and the staff regarding the working draft(3l); and (3) within 14 days thereafter, AEP shall formally file its proposed tariffs in the form of an application for approval of compliance tariffs. Finally, to the extent any other motions or objections have been raised and they were not directly addressed above, they are denied. -------------------- (31) Neither the working draft nor the informal comments are to be filed formally in the dockets of these proceedings. 99-1729-EL-ETP and 99-1730-EL-ETP -47- FINDINGS OF FACT AND CONCLUSIONS OF LAW: (1) On December 30, 1999, CSP and OP filed transition plan applications, as well as applications for receipt of transition revenues. AEP supplemented those filings on January 14 and February 28, 2000. (2) A technical conference was conducted on January 10, 2000, and preliminary objections were filed on February 10, 11, 14 and 15, 2000. (3) A procedural/settlement conference was conducted on March 3, 2000. On March 28, 2000, the Staff Report of Exceptions and Recommendations was filed. AEP made a supplemental filing on April 18, 2000 in accordance with the attorney examiner's directive. A second prehearing conference was conducted on April 28, 2000. (4) Intervention was granted to a number of parties. On May 8, 2000, a Stipulation and Recommendation was filed by AEP, the Commission staff, APAC, Columbia Energy companies, Enron, NewEnergy, WPS, Exelon, IEU-Ohio, Kroger, MAPSA, NEMA, OCC, OCRM, OHA, OPAE, OREC, Strategic, WSOS, ODOD, and OMA. The stipulation purports to resolve all issues in these proceedings, except for one issue related to AEP's proposed gross receipts/excise tax rider. Dynegy and OEC later stated that they do not oppose the stipulation. (5) Evidentiary hearings were conducted on May 9 and 31 and June 7, 8, and 12, 2000. Local public hearings were held on June 5, 2000, in East Liverpool and on June 22, 2000, in Columbus, Ohio. AEP filed proof of the newspaper notices it provided for the filing of the transition plan applications and for the public hearings, in accordance with Commission directives. (6) On June 19, 2000, AEP and ANM filed a second settlement agreement in these dockets. (7) AEP's transition plans, as modified by the settlement agreement described above, satisfy the 15 prerequisites set forth in Section 4928.34(A), Revised Code, to the extent set forth herein. (8) Under the stipulations, CSP can recover $191,156,000 as transition costs during the MDP. OP can recover $425,230,000 as transition costs during the MDP. 99-1729-EL-ETP and 99-1730-EL-ETP -48- (9) The stipulations provide appropriate shopping incentives to achieve a 20 percent load switching as contemplated by Section 4928.40(A), Revised Code. (10) AEP's transition plans, as modified by the settlement agreements, satisfies the requirements of SB 3, and are approved for the reasons and to the extent set forth herein. (11) Our docketing division shall maintain the items filed under seal on January 18, 2000, and AEP Exhibit 4 for a period of 18 months from the date of this decision. Any party wishing to extend this confidential treatment should file an appropriate motion at least 45 days in advance of the expiration of the protective order. ORDER: It is, therefore, ORDERED, That AEP's transition plans and the settlement agreements filed on December 30, 1999 and May 8, 2000, respectively, are approved, to the exdent set forth herein, and subject to final approval of AEP's compliance tariffs. It is, further, ORDERED, That the tariff amendments and accounting authority requested by AEP are approved in accordance with the discussion set forth in this Opinion and Order. It is, further, ORDERED, That CCE's motion for a compliance tariff review process is granted in part. AEP and other interested intervenors shall follow the timelines for informal review and comments with respect to the companies' compliance tariffs, and AEP shall file an application for approval of compliance tariffs in accordance with the directives set forth in this Opinion and Order. It is, further, ORDERED, That AEP's request for a protective order is granted. It is, further, ORDERED, That our Docketing Division shall maintain the items filed under seal on January 18, 2000, and AEP Exhibit 4 for a period of 18 months from the date of this decision. Any party wishing to extend this confidential treatment should file an appropriate motion at least 45 days in advance of the expiration of the protective order. It is, further, ORDERED, That OCTA's request to intervene and subsequent request to withdraw from these proceedings are granted. It is, further, 99-1729-EL-ETP and 99-1730-EL-ETP -49- ORDERED, That a copy of this Opinion and Order be served, upon all parties of record. THE PUBLIC UTILITIES COMMISSION OF OHIO /s/ Alan R. Schriber --------------------------------- Alan R. Schriber, Chairman /s/ Ronda Hartman Fergus --------------------------------- --------------------------------- Ronda Hartman Fergus Craig A. Glazer Abstain - Not Voting /s/ Judith A. Jones /s/ Donald L. Mason --------------------------------- --------------------------------- Judith A. Jones Donald L. Mason GLP/SJD;geb Entered in the Journal SEP 28 2000 -------------------------- A True Copy /s/ Gary E. Vigorito -------------------------- Gary E. Vigorito Secretary BEFORE THE PUBLIC UTILITIES COMMISSION OF OHIO In the Matter of the Application of Columbus ) Southern Power Company for Approval of Electric ) Transition Plan and Application for Receipt of ) Case No. 99-1729-EL-ETP Transition Revenues ) ) In the Matter of the Application of Ohio Power ) Company for Approval of Electric Transition Plan ) Case No. 99-1730-EL-ETP and Application for Receipt of Transition Revenues ) STIPULATION AND RECOMMENDATION I. INTRODUCTION Rule 4901-1-30, Ohio Administrative Code ("OAC") provides that any two or more parties to a proceeding may enter into a written or oral stipulation covering the issues presented in such a proceeding. The purpose of this document is to set forth the understanding of the parties who have signed below (the "Signatory Parties") and to recommend that the Public Utilities Commission of Ohio (the "Commission") approve and adopt, as part of its Opinion and Order in these proceedings, this Stipulation and Recommendation (the "Stipulation") resolving all of the issues in the above-captioned proceedings except as specified in paragraph XVI herein. This Stipulation is supported by adequate data and information; represents a just and reasonable resolution of all issues in these proceedings; violates no regulatory principle or precedent; and is the product of lengthy, serious bargaining among knowledgeable and capable parties in a cooperative process, encouraged by this Commission and undertaken by the Signatory Parties to settle these cases. While this Stipulation is not binding on the Commission, it is entitled to careful consideration by the Commission, where, as here, it is sponsored by parties representing a wide range of interests, including the Commission's Staff. For purpose of resolving all issues raised by these proceedings, the Signatory Parties stipulate, agree and recommend as set forth below. II. PARTIES This Stipulation is entered into by and among Columbus Southern Power Company (CSP) and Ohio Power Company (OPCQ) (collectively, the "Companies") and such other parties as are signatory hereto. All Signatory Parties fully support this Stipulation and urge the Commission to accept and approve the terms hereof. To the extent that the implementation of the provisions herein reasonably require actions by the Companies' agents or affiliates, the Companies are responsible for the performance of such actions. III. RECITALS WHEREAS, the State of Ohio enacted Am. Sub. S.B. No.3, which provides for customer choice effective January I, 2001; WHEREAS, the Companies on December 30, 1999, filed transition plans as required by Am. Sub. S.B. No.3 and the Commission's rules adopted under the authority of Am. Sub. S.B. No.3, and supplemented such plans through the date hereof (the "Filing"); WHEREAS, the Signatory Parties have reviewed and discussed the transition plan and the Filing of the Companies in detail and are fully aware of its contents; WHEREAS, the agreements herein represent a comprehensive solution to the issues raised in these proceedings and more importantly create a unique and substantial opportunity to bring real customer choice to Ohio. The issues and concerns raised by the Signatory Parties have been addressed in the substantive provisions of this agreement, and reflect as a result of such discussions compromises by all parties to achieve an overall reasonable solution. This 2 Stipulation is the product of the discussions and negotiations of the Signatory Parties, and is not intended to reflect the views or proposals which any individual party may have advanced acting unilaterally. Accordingly, this agreement represents an accommodation of the diverse interests represented by the Signatory Parties, and is entitled to careful consideration by the Commission; WHEREAS, this Stipulation and Recommendation represents a serious compromise of complex issues and involves substantial benefits that would not otherwise have been achievable; and WHEREAS, the Signatory Parties believe that the agreements herein represent a solution to the issues raised in these proceedings that is designed to facilitate customer choice consistent with state policy as set forth in Section 4928.02 of the Revised Code and in compliance with Chapter 4928's determination of transition costs. NOW, THEREFORE, the Signatory Parties stipulate, agree and recommend that the Commission make the following findings and issue its Opinion and Order in these proceedings in accordance with the following: IV. GENERATION TRANSITION CHARGE Neither Company will impose any lost revenue charges (generation transition charges (GTC)) on any switching customer. V. DISTRIBUTION RATE FREEZE The Companies agree to freeze all distribution rates in effect on December 31, 2005 through December 31, 2007 for OPCO and through December 31, 2008 for CSP. The Companies can file an application, prior to the December 31, 2007 and December 31, 2008 dates to change their distribution rates. However, the new rates will not become effective prior to those dates. After December 31, 2005 such frozen rates can be adjusted to reflect the cost of complying with changes in environmental (distribution-related), tax and regulatory laws or 3 regulations, relief from storm damage expenses, or in the event of an emergency under ss. 4909.16, R.C. Further, the frozen distribution rate can be adjusted to reflect changes in allocation of the transmission/distribution facilities under FERC's seven-factor test. Such an adjustment will be made in a proceeding initiated by the Companies to address only this adjustment. As part of the freeze, the amortization of regulatory asset deferrals agreed upon in paragraph VI will begin when new distribution rates go into effect for each Company. VI. REGULATORY ASSET TRANSITION CHARGE AND DEFERRAL OF CERTAIN REGULATORY ASSETS The Companies will recover their regulatory assets in accordance with Attachment 1 hereto except as provided in paragraphs VII, XVII and XVIII. In accordance with the Staff Report and as reflected in the attached schedules: CSP will absorb the first $20 million of actual Consumer Education, Customer Choice Implementation and Transition Plan Filing Costs, and will be permitted to defer the remainder of its actual cost for such activities (currently estimated to be $40.6 million), plus a carrying charge, as regulatory assets for recovery as a cost of service, by a rider, in future distribution rates. OPCO will absorb the first $20 million of actual Consumer Education, Customer Choice Implementation and Transition Plan Filing Costs, and will be permitted to defer the remainder of its actual costs for such activities (currently estimated to be $45.5 million), plus a carrying charge, as regulatory assets for recovery as a cost of service, by a rider, in future distribution rates. Determination of the costs to be recovered, including the carrying charge, will be subject to review by the Commission. 4 VII. SHOPPING INCENTIVE During the Market Development Period CSP will make available to the first 25% of residential class load that switches to a Competitive Retail Electric Service (CRES) provider a shopping incentive of 2.5 mills/kWh. The unused portion of the shopping incentive as measured at December 31, 2005 will be credited by CSP to its regulatory transition cost (RTC) recovery for all customers. For the entire Market Development Period, there will be no additional shopping incentive for CSP and there will be no shopping incentive for OPCO. VIII. TRANSMISSION MATTERS From January 1,2001 through the time at which American Electric Power Service Corporation (AEP) as agent for the Companies transfers administration of its Open Access Transmission Tariff (OATT) to a regional transmission organization (RTO), AEP will provide two full-time equivalent positions in the AEP System Control Center to assist transmission users with the processes of reservations, scheduling and tagging. Further AEP will provide a mechanism to account for partial MWHs when the load served by imports across AEP interfaces does not result in whole MWHs. AEP will file with the Federal Energy Regulatory Commission (FERC) a proposed amendment to its OATT to extend rollover rights under Section 2.2 of the OATT to retail customers or their supplier. AEP will request an effective date of January 1, 2001 for the amendment. AEP shall actively work with the Alliance, the MISO, PJM and other RTO/ISOs and transmission-level customers in the area to develop and implement specific proposals to address reciprocity and interface/seam issues. In the event a filing is not made by the Alliance to deal with these issues by September 1, 2000, AEP shall cause a filing at the FERC to be made which will deal with these issues as to their respective areas and interfaces. AEP recognizes that 5 resolution of these issues is critical to a fully functioning retail market in Ohio and will endeavor to propose and resolve issues as promptly as possible. AEP shall (by no later than December 15, 2001) transfer operational control of their transmission facilities to an operating FERC-approved RTO. The Companies will make available a fund of up to $10 million for costs associated with transmission charges imposed by PJM and/or by the MISO, if the MISO is fully operating on a single tariff, on generation originating in the MISO or PJM as such cost may be incurred by: 1. Any supplier serving retail customers within their respective service areas; or, 2. A customer or group of customers where the customer or group of customers is securing and paying for the transmission service. The transmission charges to be reimbursed will not include losses, redispatch charges or other charges specifically impacting the transaction. Reimbursement of such costs shall apply only until the AEP transmission system is within the operational control of an operating FERC approved RTO. If any governmental agency invalidates or imposes conditions associated with this paragraph which would materially affect the obligation imposed by this paragraph, the paragraph will be deemed withdrawn from the Stipulation and Recommendation and the parties agree to negotiate in good faith to restore the value of this paragraph. IX. 5% RESIDENTIAL GENERATION REDUCTION Each Company will refile the unbundled residential tariffs contained in the Filing so as to reflect a 5% reduction in the generation component. including the RTC component, and will not seek to reduce such 5% generation component rate reduction for residential customers during the market development period. 6 X. COMMERCIAL CUSTOMER RATE DESIGN Each Company's tariffs and UNB-8 schedules should be revised, in the manner shown in Attachment 2 hereto, in order to achieve a revenue neutral rate design and to equalize the bill impacts within the Commercial class of customers. XI. TRANSITION PLANS The transition plans of the Companies as filed on December 30, 1999, and as supplemented and corrected through the date herein, will be approved, except as specifically modified herein or as is necessary to update tariff provisions to reflect the agreements made herein and the attachments hereto through a compliance filing. The Signatory Parties recognize that the OSP working group is engaged in discussions to resolve and/or address the issues arising in that area. The Signatory Parties agree to accept any resolution of such issues agreed to by the working group participants and to incorporate any such changes in the Companies' transition plans. The Companies agree to abide by the determinations of the Commission as they may relate to OSP issues that are not resolved by the working group participants. In doing so, the Companies are not waiving their rights to seek judicial review of such detenninations. XII. CUSTOMER SWITCHING Unless any agreed upon changes by the OSP working group are less restrictive for customers than the terms of this Stipulation, the Companies agree that during the market development period customers that take generation services from the company during any part of May 16 through September 15 must either: (1) remain a customer through April 15 of the following year before they switch to another supplier (minimum stay) or (2) choose a market price based tariff which has been filed with and approved by the Commission and which will not be lower than the generation cost embedded in the standard offer (come and go). Non- 7 aggregated residential customers will be permitted to shop three times during the market development period and to return two times to the default tariff, before being required to choose from the minimum stay or come and go tariff options described above. XIII. NONDISCRIMINATORY ACCESS TO TRANSMISSION AND DISTRIBUTION SYSTEM The Companies shall have the obligation to connect any retail customer located within their service territories to their distribution facilities that are used for delivery of retail electric energy, and to operate such facilities in a manner that will reasonably allow for such customer to receive power supply from the supplier of the customer's choice, subject to Commission Rules and approved tariff provisions relating to connection of service. Except as otherwise provided, the Companies shall provide distribution service within their service territories on a basis which is just, reasonable, and not unduly discriminatory to retail customers or suppliers of electric energy, including suppliers of distributed generation. The distribution services provided to each retail customer or supplier of electric energy shall be the same in quality and price and subject to the same terms and conditions to those services provided by the Companies to any similarly situated retail customer, itself or any affiliate. Prior to participation in a FERC-approved RTO: a) the Companies and/or their affiliates will provide transmission service for the delivery of all power, including transmission of default service power and transmission of power for both affiliated and nonaffiliated energy service providers, only under their proforma transmission tariff; b) the Companies and/or their affiliates will comply with the OASIS and Standards of Conduct requirements promulgated by the Federal Energy Regulatory Commission for the delivery of all power. Nothing in this paragraph XIII is intended to limit the Companies' right to contend that matters related to transmission in interstate commerce are subject to the exclusive jurisdiction of the Federal Energy Regulatory Commission. 8 The Companies will provide distribution service for the delivery of power, including default service and service provided by any affiliated or nonaffiliated supplier, only under the applicable distribution tariff. XIV. CONSOLIDATED BILLING CREDIT The Companies will provide a credit to CRES providers equal to $1.00 for each consolidated bill issued by the provider during the first year of the Market Development Period. The Companies and the marketing intervenors who are Signatory Parties agree that they will negotiate in good faith to determine a consolidated billing credit to be effective after the first year of the Market Development Period. The Companies reserve the right to petition the Commission at any time to set a consolidated billing credit which would supersede any credit then in effect. AEP will apply reasonable efforts to implement supplier consolidated billing as soon as practicable in keeping with the January 1, 2001 start date to competition. XV. COMMERCIAL AND INDUSTRIAL CUSTOMERS' NOTICE TO SHOP Notwithstanding any provision in the Companies' terms and conditions for service to Commercial and Industrial class customers, such customers need to provide only 90 days notice to the Companies of their intent to purchase electricity from a CRES provider. Such customers may provide the 90 days notice prior to January 1,2001, so as to enable them to receive generation from a CRES provider on or after the starting date for competitive retail electric service. XVI. GROSS RECEIPTS TAX The parties reserve for litigation the Companies' proposed gross receipts tax rider. A procedural schedule will be set by the Commission for the filing of testimony concerning this issue and for a hearing. 9 XVII. ACCOUNTING The Signatory Parties agree that the Companies' revenues from Regulatory Transition Charges during the transition period (see Attachment 1) and from existing frozen and unbundled rates recovered from customers of OPCO and CSP during the market development period are sufficient to recover regulatory assets as of the beginning of the market development period and to provide for obligations that are required by this Stipulation. The Signatory Parties agree that the Commission will direct OPCO and CSP to amortize such regulatory assets during the market development period and thereafter until such regulatory assets are fully amortized. In addition, recorded regulatory assets as of the beginning of the market development period, December 31, 2000, which exceed the amounts in Attachment 1 should be amortized on a per kWh basis during the market development period and recovered through existing frozen and unbundled rates. The Signatory Parties recommend that the Commission consider the concerns raised by the Companies with respect to potential violations of the normalization rules in the Internal Revenue Code relating to amortization of regulatory liabilities related to investment tax credits (ITC) and excess deferred income taxes. Accordingly, the Parties recommend that the Opinion and Order in this case reflect the following language: "The base rates in the market development period embodied in this Opinion and Order include the amortization of regulatory liabilities related to ITC no more rapidly than ratably, and the amortization of 'excess deferred taxes' using the Average Rate Assumption Method in order to avoid any potential nonnalization violations." XVIII. OPCO RESIDENTIAL CUSTOMERS' RTC For the period January 1,2006 through December 31, 2007, the first 20% of OPCO residential customer load that was on OPCO's standard service offer as of December 31, 2005 which switches to a certified retail electric generation service provider will not be charged the 10 Regulatory Transition Charge during that 2006-2007 two-year period. Customer load which remains on the Companies' standard service offer under ss.4928.14(A) or (B), Ohio Rev. Code, does not count as being load which switches to a certified retail electric generation service provider. Should the agreement embodied in the preceding paragraph be rejected by the Commission or determined to be unlawful by a court of competent jurisdiction, the remainder of this Stipulation and Recommendation will remain in effect. XIX. LOAD SHAPING The Companies and the marketing intervenors who are Signatory Parties agree to negotiate in good faith concerning a load shaping service which might be provided by the Companies. The Companies shall notify all such marketing intervenors of the place, dates and times of such meetings. XX. UNIVERSAL SERVICE FUND RIDERS AND ENERGY EFFICIENCY FUND RIDERS The Companies state that the rates for the Universal Service Fund Riders and the Energy Efficiency Fund Riders will be as determined by the Ohio Department of Development and approved by the Commission. XXI. CODE OF CONDUCT The Cost Allocation Manual (CAM) must follow the Uniform System of Accounts as well as GAAP. The Companies agree that effective January 1, 2001, their distribution affiliate companies will not provide competitive non-electric products or services to retail customers on a 11 commercial basis(1); provided, however, that the distribution affiliate companies are not precluded from a) fulfilling any contractual obligations existing prior to January 1, 2001; or b) providing to retail customers non-electric products or services which are incidental to the provision of customer service and not on a commercial basis. The distribution affiliate companies will not condition the provision of such incidental services on the basis of the customer's choice of retail electric supplier. Employees of the Companies' affiliates shall not have access to any information about their transmission or distribution systems (e.g., system operations, capability, price, curtailments, and ancillary services) that is not contemporaneously and in the same form and manner available to a nonaffiliated competitor of retail electric service. The Signatory Parties agree that by executing the Stipulation and Recommendation that accepts the Companies' corporate separation plan, the marketer intervenors(2) are not agreeing to the Companies' interpretation of the Commission's rules on Code of Conduct, ss.4901:1-20-16(G)(4), Ohio Admin. Code, and would recommend that the Commission recognize this in its Opinion and Order. Further, the Signatory Parties agree that by adopting the Companies' electric transition plans, the Companies' interpretation of the rules as set forth therein will not have any precedential effect. XXII. EFFECT OF STIPULATION Nothing in this Stipulation shall be used or construed for any purpose to imply, suggest or otherwise indicate that the results produced through the compromise reflected herein represent fully the objectives of any Signatory Party. --------------- (1) Examples of such products or services are customer-owned substation design and construction, customer-owned equipment maintenance, customer-owned distribution equipment service upgrades, power quality maintenance and improvement and power systems and safety training. (2) Designated on the signature page as a "marketer intervenor." 12 This Stipulation is submitted for purposes of this proceeding only, and is not deemed binding in any other proceeding, except as expressly provided herein, nor is it to be offered or relied upon in any other proceedings, except as necessary to enforce the terms of this Stipulation. In fact, none of the Signatory parties have submitted the entirety of the case they would have otherwise filed or will file if this Stipulation is rejected. The agreement of the Signatory Parties reflected in this document is expressly conditioned upon its acceptance in its entirety and without alteration by the Commission. The parties agree that if the Commission rejects all or any part of this Stipulation, or otherwise materially modifies its terms, any adversely affected party shall have the right, within thirty (30) business days of the Commission's order, either to file an application for rehearing or to terminate and withdraw from the Stipulation by filing a notice with the Commission. If an application for rehearing is filed, and if the Commission does not, on rehearing, accept the Stipulation without material modification, any party may terminate and withdraw from the Stipulation by filing a notice with the Commission within ten (10) business days of the Commission's order or entry on rehearing. In such an event, a hearing shall go forward, and the parties shall be afforded the opportunity to present evidence through witnesses, to cross-examine all witnesses, to present rebuttal testimony, and to file briefs on all issues. The Signatory Parties agree and intend to support the reasonableness of this Stipulation before the Commission, and to cause their counsel to do the same, and in any appeal from the Commission's adoption and/or enforcement of this Stipulation. 13 IN WITNESS WHEREOF, this Stipulation and Recommendation has been agreed to as of this 5th day of May, 2000. The undersigned parties respectfully request the Commission to issue its Opinion and Order approving and adopting this Stipulation. /s/ William J. Resnik * /s/ Samuel C. Randaggo/MR ------------------------------------- ------------------------------------ Ohio Power Company Industrial Energy Users-Ohio /s/ William J. Resnik * /s/ Eric B. Stephens/MR ------------------------------------- ------------------------------------ Columbus Southern Power Company Ohio Consumers' Counsel * /s/ Scott A. Campbell/MR * /s/ Sheldon A. Taft/MR ------------------------------------- ------------------------------------ Ohio Rural Electric Cooperative, Inc. Ohio Manufacturers' Association and Buckeye Power, Inc. * /s/ Craig G. Goodman/MR ------------------------------------- ------------------------------------ National Energy Marketers Association ------------------------------------- ------------------------------------ ------------------------------------- ------------------------------------ ------------------------------------- ------------------------------------ ------------------------------------- ------------------------------------ ------------------------------------- ------------------------------------ ------------------------------------- ------------------------------------ ------------------------------------- ------------------------------------ *Per Telephone Authorization 14 IN WITNESS WHEREOF, this Stipulation and Recommendation has been agreed to as of this 5th day of May, 2000. The undersigned parties respectfully request the Commission to issue its Opinion and Order approving and adopting this Stipulation. /s/ Sally M. Bloomfield -------------------------------- ------------------------------------------ Ohio Power Company Columbia Energy Power Marketing Corporation Columbia Energy Services Corporation /s/ Sally M. Bloomfield -------------------------------- ------------------------------------------ Columbus Southern Power Company Exelon Energy /s/ Sally M. Bloomfield -------------------------------- ------------------------------------------ Strategic Energy, LLC /s/ Sally M. Bloomfield -------------------------------- ------------------------------------------ Mid-Atlantic Power Supply Association -------------------------------- ------------------------------------------ -------------------------------- ------------------------------------------ -------------------------------- ------------------------------------------ -------------------------------- ------------------------------------------ 13 IN WITNESS WHEREOF, this Stipulation and Recommendation has been agreed to as of this 5th day of May, 2000. The undersigned parties respectfully request the Commission to issue its Opinion and Order approving and adopting this Stipulation. ------------------------------------- ------------------------------------ Ohio Power Company ------------------------------------- ------------------------------------ Columbus Southern Power Company /s/ Michael P. Kurtz ------------------------------------- ------------------------------------ Kroger Co. ------------------------------------- ------------------------------------ ------------------------------------- ------------------------------------ ------------------------------------- ------------------------------------ ------------------------------------- ------------------------------------ ------------------------------------- ------------------------------------ ------------------------------------- ------------------------------------ ------------------------------------- ------------------------------------ 13 IN WITNESS WHEREOF, this Stipulation and Recommendation has been agreed to as of this 5th day of May, 2000. The undersigned parties respectfully request the Commission to issue its Opinion and Order approving and adopting this Stipulation. ------------------------------------- ------------------------------------ Ohio Power Company ------------------------------------- ------------------------------------ Columbus Southern Power Company /s/ [Signature] ------------------------------------- ------------------------------------ Public Utilities Commission of Ohio Staff ------------------------------------- ------------------------------------ ------------------------------------- ------------------------------------ ------------------------------------- ------------------------------------ ------------------------------------- ------------------------------------ ------------------------------------- ------------------------------------ ------------------------------------- ------------------------------------ ------------------------------------- ------------------------------------ 14 Attachment 1 Page 1 of 2 COLUMBUS SOUTHERN POWER COMPANY REGULATORY ASSET RECOVERY Class First 5 years Second 3 years Total ----- ------------- -------------- ----- R-R, R-R-1, RLM, $ 20,941,102 65,901,798 86,842,900 RS-ES, RS- TOD kWh 33,197,686,834 22,093,197,011 55,290,883,845 --- --------------- -------------- --------------- Rate (c/kWh) 0.06308 0.29829 0.15707 GS-1 $ 926,570 2,911,661 3,838,231 kWh 1,675,837.432 1,113,615,927 2,789,453,359 --- --------------- -------------- --------------- Rate (c/kWh) 0.05529 0.26146 0.13760 GS-2, GS-2 TOD $ 4,931,811 15,497,601 20,429,412 kWh 8,685,825,300 5,771,918,172 14,457,743,472 --- --------------- -------------- --------------- Rate (c/kWh) 0.05678 0.26850 0.14130 GS-3 $ 15,798,814 49,312,920 65,111,734 kWh 34,631,330,709 22,858,629,291 57,489,960,000 --- --------------- -------------- --------------- Rate (c/kWh) 0.04562 0.21573 0.11326 GS-4, IRP, IRP-OS $ 3,582,607 10,915,250 14,497,857 IRP-CDB, IRP-CDA, kWh 9,049,274,943 5,830, 172,873 14,879,447,816 IRP-OR --- --------------- -------------- --------------- Rate (c/kWh) 0.03959 0.18722 0.09744 SL $ 40,443 117,902 158,345 kWh 153,712,091 94,761,175 248,473,266 --- --------------- -------------- --------------- Rate (c/kWh) 0.02631 0.12442 0.06373 AL $ 67,015 211,052 278,067 kWh 277,495,044 184,808,520 462,303,564 --- --------------- -------------- --------------- Rate (c/kWh) 0.02415 0.11420 0.06015 Total $ 46.288,362 144,868,184 191,156,546 kWh 871,671,162,353 57,947,102,969 145,618,265,322 --- --------------- -------------- --------------- Rate (c/kWh) 0.05280 0.25000 0.13127 Attachment 1 Page 2 of 2 OHIO POWER COMPANY REGULATORY ASSET RECOVERY Class First 5 years Second 2 years Total ----- ------------- -------------- ----- RS, RS-ES, $ 90,870,362 44,986,337 135,856,699 R5-TOD, ROMS kWh 35,863,273,049 15,117,392.577 50,980,665,626 --- --------------- -------------- --------------- Rate (c/kWh) 0.25338 0.29758 0.26649 GS-1 $ 4,522,232 2,220,837 6,743,069 kWh 2,023,369,948 846,032,994 2,869,402,942 --- --------------- -------------- --------------- Rate (c/kWh) 0.22350 0.26250 0.23500 GS-2, GS-TOD $ 38,152,488 18,667,832 56,820,320 kWh 16,944,612,231 7,059,650,084 24,004,282,315 --- --------------- -------------- --------------- Rate (c/kWh) 0.22516 0.26443 0.23671 GS-3 $ 67.272,273 32,741,340 100,013,613 kWh 33,897,144,370 14,047,253,781 47,944,398,151 --- --------------- -------------- --------------- Rate (c/kWh) 0.19846 0.23308 0.20860 GS-4, IRP-OS, $ 82,090,566 39,698,955 121,789,521 IRP-CDB, IRP-CDA, kWh 44,248,903,810 16,219,723,194 62,468,627,004 IRP-OR --- --------------- -------------- --------------- Rate (c/kWh) 0.18552 0.21789 0.19496 EHG $ 575,333 282,681 858,014 kWh 247,316,600 103,466,751 350,783,351 --- --------------- -------------- --------------- Rate (c/kWh) 0.23263 0.27321 0.24460 EHS $ 27,232 13,399 40,631 kWh 10,537,916 4,414,710 14,952,626 --- --------------- -------------- --------------- Rate (c/kWh) 0.25842 0.30351 0.27173 SS $ 1,193,923 587,463 1,781,386 kWh 504,851,145 211,500,194 716,351,339 --- --------------- -------------- --------------- Rate (c/kWh) 0.23649 0.27776 0.24867 OL $ 435,742 214,297 650,039 kWh 286,596,826 120,007,036 406,603,862 --- --------------- -------------- --------------- Rate (c/kWh) 0.15204 0.17857 0.15987 SL $ 459,850 217,443 677,293 kWh 304,394,105 122,558,679 426,952,784 --- --------------- -------------- --------------- Rate (c/kWh) 0.15107 0.17742 0.15863 Total $ 285,600,001 139,630,584 425,230,585 kWh 134,331,000,000 55,852,000,000 190,183,000,000 --- --------------- -------------- --------------- Rate (c/kWh) 0.21261 0.25000 0.22359 Attachment 2 Page 1 of 7 COLUMBUS SOUTHERN POWER Original Sheet No. 23-1 DISTRIBUTION COMPANY P.U.C.O. NO.5 SCHEDULE GS-3 (General Service - Medium Load Factor) MONTHLY RATE
--------------------------------------------------------------------------------------------------- Generation Transmission Distribution Total --------------------------------------------------------------------------------------------------- SECONDARY VOLTAGE: --------------------------------------------------------------------------------------------------- Customer Charge ($) -- -- 125.15 125.15 --------------------------------------------------------------------------------------------------- Demand Charge ($ per KW) 8.641 1.673 3.208 13.522 --------------------------------------------------------------------------------------------------- Off-Peak Excess Demand Charge ($ per KW) 1.125 -- -- 1.125 --------------------------------------------------------------------------------------------------- Excess KVA Charge ($ per KVA) -- -- 0.907 0.907 --------------------------------------------------------------------------------------------------- Energy Charge (cents per KWH) 2.34795 -- -- 2.34795 --------------------------------------------------------------------------------------------------- Maximum Energy Charge (cents per KWH) 4.56150 3.34600 6.41600 14.32350 --------------------------------------------------------------------------------------------------- PRIMARY VOLTAGE: --------------------------------------------------------------------------------------------------- Customer Charge ($) -- -- 278.90 278.90 --------------------------------------------------------------------------------------------------- Demand Charge ($ per KW) 8.357 1.618 2.382 12.357 --------------------------------------------------------------------------------------------------- Off-Peak Excess Demand Charge 1.088 ($ per KW) -- -- 1.088 --------------------------------------------------------------------------------------------------- Excess KVA Charge ($ per KVA) -- -- 0.878 0.878 --------------------------------------------------------------------------------------------------- Energy Charge (cents per KWH) 2.31606 -- -- 2.31606 --------------------------------------------------------------------------------------------------- Maximum Energy Charge (cents per KWH) 6.32350 3.23600 4.76400 14.32350 ---------------------------------------------------------------------------------------------------
Attachment 2 Page 2 of 7 OHIO POWER DISTRIBUTION COMPANY Original Sheet No. 23-1 P.U.C.O. NO.17 SCHEDULE GS-3 (General Service -Medium/High Load Factor) MONTHLY RATE
----------------------------------------------------------------------------------------------------------- Schedule Codes Generation Transmission Distribution Total ----------------------------------------------------------------------------------------------------------- 240, 242 SECONDARY VOLTAGE: ----------------------------------------------------------------------------------------------------------- Demand Charge ($ per KW) 6.76 1.64 4.08 12.48 ----------------------------------------------------------------------------------------------------------- Excess KVA Charge ($ per KVA) -- -- 4.00 4.00 ----------------------------------------------------------------------------------------------------------- Off-Peak Excess Demand Charge ($ per KW) 2.14 -- -- 2.14 ----------------------------------------------------------------------------------------------------------- Energy Charge (cents per KWH) 1.72947 -- -- 1.72947 ----------------------------------------------------------------------------------------------------------- Customer Charge ($) -- -- 24.00 24.00 ----------------------------------------------------------------------------------------------------------- Maximum Energy Charge (cents per KWH) 8.53733 1.64000 4.08000 14.25733 ----------------------------------------------------------------------------------------------------------- 244,246 PRIMARY VOLTAGE: ----------------------------------------------------------------------------------------------------------- Demand Charge ($ per KW) 6.53 1.56 3.25 11.34 ----------------------------------------------------------------------------------------------------------- Excess KVA Charge ($ per KVA) -- -- 4.00 4.00 ----------------------------------------------------------------------------------------------------------- Off-Peak Excess Demand Charge ($ per KW) 1.55 -- -- 1.55 ----------------------------------------------------------------------------------------------------------- Energy Charge (cents per KWH) 1.71595 -- -- 1.71595 ----------------------------------------------------------------------------------------------------------- Customer Charge ($) -- -- 100.00 100.00 ----------------------------------------------------------------------------------------------------------- Maximum Energy Charge (cents per KWH) 9.44737 1.56000 3.25000 14.25737 ----------------------------------------------------------------------------------------------------------- 248 SUBTRANSMISSION VOLTAGE: ----------------------------------------------------------------------------------------------------------- Demand Charge ($ per KW) 6.34 1.52 2.85 10.71 ----------------------------------------------------------------------------------------------------------- Excess KVA Charge ($ per KVA) -- -- 4.00 4.00 ----------------------------------------------------------------------------------------------------------- Off-Peak Excess Demand Charge ($ per KW) 1.20 -- -- 1.20 ----------------------------------------------------------------------------------------------------------- Energy Charge (cents per KWH) 1.70406 -- -- 1.70406 ----------------------------------------------------------------------------------------------------------- Customer Charge ($) -- -- 285.00 285.00 ----------------------------------------------------------------------------------------------------------- Maximum Energy Charge (cents per KWH) 9.88749 1.52000 2.85000 14.25749 ----------------------------------------------------------------------------------------------------------- 245 TRANSMISSION VOLTAGE: ----------------------------------------------------------------------------------------------------------- Demand Charge ($ per KW) 6.24 1.51 2.29 10.04 ----------------------------------------------------------------------------------------------------------- Excess KVA Demand Charge ($ per KVA) -- -- 4.00 4.00 ----------------------------------------------------------------------------------------------------------- Off-Peak Excess Demand Charge ($ per KW) 0.63 -- -- 0.63 ----------------------------------------------------------------------------------------------------------- Energy Charge (cents per KWH) 1.69795 -- -- 1.69795 ----------------------------------------------------------------------------------------------------------- Customer Charge ($) -- -- 560.00 560.00 ----------------------------------------------------------------------------------------------------------- Maximum Energy Charge (cents per KWH) 10.45738 1.51000 2.29000 14.24738 -----------------------------------------------------------------------------------------------------------
Attachment 2 Page 3 of 7 Columbus Southern Power Company Typical Bill Comparison
Level Level Current 10/04/99 Current Adjusted Line Rate of of Base Fuel Cost Bill Incl. Unbundled Dollar Percent No. Code Demand Usage Bill Revenue Fuel Costs Bill Increase Increase (A) (B) (C) (D) (E)=(C+D) (F) (G)=(F-E) (H)=(G/E) 0.0137261 1 GS-3-Sec 50 17,500 975.23 240.21 1,215.44 1,238.69 23.25 1.91 2 50 22,500 1,037.70 308.84 1,346.54 1,372.17 25.63 1.90 3 50 27,500 1,100.16 377.47 1,477.63 1,505.66 28.03 1.90 4 100 35,000 1,825.31 480.41 2,305.72 2,349.00 43.28 1.88 5 100 45,000 1,950.24 617.67 2,567.91 2,615.98 48.07 1.87 6 100 55,000 2,075.17 754.94 2,830.11 2,882.94 52.83 1.87 7 250 87,500 4,375.54 1,201.03 5,576.57 5,679.97 103.40 1.85 8 250 112,500 4,687.87 1,544.19 6,232.06 6,347.39 115.33 1.85 9 250 137,500 5,000.19 1,887.34 6,887.53 7,014.82 127.29 1.85 10 500 175,000 8,625.93 2,402.07 11,028.00 11,231.55 203.55 1.85 11 500 225,000 9,250.58 3,088.37 12,338.95 12,566.42 227.47 1.84 12 500 275,000 9,875.23 3,774.68 13,649.91 13,901.27 251.36 1.84 13 1,000 350,000 17,126.70 4,804.14 21,930.84 22,334.75 403.91 1.84 14 1,000 450,000 18,376.00 6,176.75 24,552.75 25,004.47 451.72 1.84 15 1,000 550,000 19,625.30 7,549.36 27,174.66 27,674.19 499.53 1.84 16 2,000 700,000 34,128.25 9,608.27 43,736.52 44,541.12 804.60 1.84 17 2,000 900,000 36,626.85 12,353.49 48,980.34 49,880.56 900.22 1.84 18 2,000 1,100,000 39,125.45 15,098.71 54,224.16 55,220.00 995.84 1.84 19 3,000 1,050,000 51,129.80 14,412.41 65,542.21 66,747.51 1,205.30 1.84 20 3,000 1,350,000 54,877.70 18,530.24 73,407.94 74,756.67 1,348.73 1.84 21 3,000 1,650,000 58,625.60 22,648.07 81,273.67 82,765.83 1,492.16 1.84 22 4,500 1,575,000 76,632.13 21,618.61 98,250.74 100,057.06 1,806.32 1.84 23 4,500 2,025,000 82,253.98 27,795.35 110,049.33 112,070.81 2,021.48 1.84 24 4,500 2,475,000 87,875.83 33,972.10 121,847.93 124,084.54 2,236.61 1.84
Attachment 2 Page 4 of 7 Columbus Southern Power Company Typical Bill Comparison
Level Level Current 10/04/99 Current Adjusted Line Rate of of Base Fuel Cost Bill Incl. Unbundled Dollar Percent No. Code Demand Usage Bill Revenue Fuel Costs Bill Increase Increase (A) (B) (C) (D) (E)=(C+D) (F) (G)=(F-E) (H)=(G/E) 0.0137261 1 GS-3-Pri 50 17,500 1,065.47 240.21 1,305.68 1,324.22 18.54 1.42 2 50 22,500 1,126.03 308.84 1,434.87 1,456.18 21.31 1.49 3 50 27,500 1,186.57 377.47 1,564.04 1,588.16 24.12 1.54 4 100 35,000 1,852.06 480.41 2,332.47 2,373.82 41.35 1.77 5 100 45,000 1,973.16 617.67 2,590.83 2,637.76 46.93 1.81 6 100 55,000 2,094.26 754.94 2,849.20 2,901.69 52.49 1.84 7 250 87,500 4,211.77 1,201.03 5,412.80 5,522.63 109.83 2.03 8 250 112,500 4,514.53 1,544.19 6,058.72 6,182.47 123.75 2.04 9 250 137,500 4,817.27 1,887.34 6,704.61 6,842.32 137.71 2.05 10 500 175,000 8,144.66 2,402.07 10,546.73 10,770.64 223.91 2.12 11 500 225,000 8,750.16 3,088.37 11,838.53 12,090.33 251.80 2.13 12 500 275,000 9,355.66 3,774.68 13,130.34 13,410.02 279.68 2.13 13 1,000 350,000 16,010.40 4,804.14 20,814.54 21,266.66 452.12 2.17 14 1,000 450,000 17,221.40 6,176.75 23,398.15 23,906.05 507.90 2.17 15 1,000 550,000 18,432.40 7,549.36 25,981.76 26,545.43 563.67 2.17 16 2,000 700,000 31,741.90 9,608.27 41,350.17 42,258.69 908.52 2.20 17 2,000 900,000 34,163.90 12,353.49 46,517.39 47,537.47 1,020.08 2.19 18 2,000 1,100,000 36,585.90 15,098.71 51,684.61 52,816.24 1,131.63 2.19 19 4,000 1,400,000 63,204.90 19,216.54 82,421.44 84,242.78 1,821.34 2.21 20 4,000 1,800,000 68,048.90 24,706.98 92,755.88 94,800.32 2,044.44 2.20 21 4,000 2,200,000 72,892.90 30,197.42 103,090.32 105,357.86 2,267.54 2.20 22 8,000 2,800,000 126,130.90 38,433.08 164,563.98 168,210.94 3,646.96 2.22 23 8,000 3,600,000 135,818.90 49,413.96 185,232.86 189,326.02 4,093.16 2.21 24 8,000 4,400,000 145,506.90 60,394.84 205,901.74 210,441.11 4,539.37 2.20 25 10,000 3,500,000 157,593.90 48,041.35 205,635.25 210,195.02 4,559.77 2.22 26 10,000 4,500,000 169,703.90 61,767.45 231,471.35 238,588.88 5,117.53 2.21 27 10,000 5,500,000 181.813.90 75,493.55 257,307.45 262,982.73 5,675.28 2.21
Attachment 2 Page 5 of 7 Ohio Power Company Typical Bill Comparison
Level Level Current 10/04/99 Current Adjusted Line Rate of of Base Fuel Cost Bill Incl. Unbundled Dollar Percent No. Code Demand Usage Bill Revenue Fuel Costs Bill Increase Increase (A) (B) (C) (D) (E)=(C+D) (F) (G)=(F-E) (H)=(G/E) 0.0145654 1 GS-3-Sec 10 3,500 164.85 50.98 215.83 222.55 6.72 3.11 2 10 4,500 171.89 65.54 237.43 245.28 7.85 3.31 3 10 5,500 178.93 80.11 259.04 268.01 8.97 3.46 4 25 8,750 376.11 127.45 503.56 520.60 17.04 3.38 5 25 11,250 393.72 163.86 557.58 577.45 19.87 3.56 6 25 13,750 411.32 200.27 611.59 634.26 22.67 3.71 7 50 17,500 728.24 254.89 983.13 1,015.99 32.86 3.34 8 50 22,500 763.45 327.72 1,091.17 1,126.84 35.67 3.27 9 50 27,500 798.65 400.55 1,199.20 1,237.70 38.50 3.21 10 75 26,250 1,080.35 382.34 1,462.69 1,507.86 45.17 3.09 11 75 33,750 1,133.16 491.58 1,624.74 1,674.14 49.40 3.04 12 75 41,250 1,185.98 600.82 1,786.80 1,840.44 53.64 3.00 13 100 35,000 1,432.46 509.79 1,942.25 1,999.72 57.47 2.96 14 100 45,000 1,502.88 655.44 2,158.32 2,221.44 63.12 2.92 15 100 55,000 1,573.30 801.10 2,374.40 2,443.16 68.76 2.90 16 200 70,000 2,840.93 1,019.58 3,860.51 3,967.22 106.71 2.76 17 200 90,000 2,981.76 1,310.89 4,292.65 4,410.65 118.00 2.75 18 200 110,000 3,122.60 1,602.19 4,724.79 4,854.10 129.31 2.74 19 500 175,000 7,066.32 2,548.95 9,615.27 9,869.67 254.40 2.65 20 500 225,000 7,418.41 3,277.22 10,695.63 10,978.28 282.65 2.64 21 500 275,000 7,770.50 4,005.49 11,775.99 12,086.88 310.89 2.64 22 1,000 350,000 14,108.63 5,097.89 19,206.52 19,707.13 500.61 2.61 23 1,000 450,000 14,812.81 6,554.43 21,367.24 21,924.33 557.09 2.61 24 1,000 550,000 15,516.99 8,010.97 23,527.96 24,141.54 613.58 2.61 25 3,000 1,050,000 42,277.89 15,293.67 57,571.56 59,056.90 1,485.34 2.58 26 3,000 1,350,000 44,390.43 19,663.29 64,053.72 65,708.52 1,654.80 2.58 27 3,000 1,650,000 46,502.97 24,032.91 70,535.88 72,360.14 1,824.26 2.59 28 7,000 2,450,000 98,616.41 35,685.23 134,301.64 137,756.46 3,454.82 2.57 29 7,000 3,150,000 103,545.67 45,881.01 149,426.68 153,276.90 3,850.22 2.58 30 7,000 3,850,000 108,474.93 56,076.79 164,551.72 168,797.35 4,245.63 2.58
Attachment 2 Page 6 of 7 Ohio Power Company Typical Bill Comparison
Level Level Current 10/04/99 Current Adjusted Line Rate of of Base Fuel Cost Bill Incl. Unbundled Dollar Percent No. Code Demand Usage Bill Revenue Fuel Costs Bill Increase Increase (A) (B) (C) (D) (E)=(C+D) (F) (G)=(F-E) (H)=(G/E) 0.0145654 1 GS-3-Pri 10 3,500 229.08 50.98 280.06 283.77 3.71 1.32 2 10 4,500 235.93 65.54 301.47 306.38 4.91 1.63 3 10 5.500 242.78 80.11 322.89 328.98 6.09 1.89 4 25 8,750 422.70 127.45 550.15 564.83 14.68 2.67 5 25 11,250 439.83 163.86 603.69 621.33 17.64 2.92 6 25 13,750 456.96 200.27 657.23 677.83 20.60 3.13 7 50 17,500 745.41 254.89 1,000.30 1,031.86 31.56 3.16 8 50 22,500 779.67 327.72 1,107.39 1,142.08 34.69 3.13 9 50 27,500 813.92 400.55 1,214.47 1,252.30 37.83 3.11 10 75 26,250 1,068.11 382.34 1,450.45 1,495.40 44.95 3.10 11 75 33,750 1,119.50 491.58 1,611.08 1,660.71 49.63 3.08 12 75 41,250 1,170.89 600.82 1,771.71 1,826.04 54.33 3.07 13 100 35,000 1,390.81 509.79 1,900.60 1,958.92 58.32 3.07 14 100 45,000 1,459.33 655.44 2,114.77 2,179.36 64.59 3.05 15 100 55,000 1,527.85 801.10 2,328.95 2,399.78 70.83 3.04 16 200 70,000 2,681.63 1,019.58 3,701.21 3,813.07 111.86 3.02 17 200 90,000 2,818.66 1,310.89 4,129.55 4,253.92 124.37 3.01 18 200 110,000 2,955.70 1,602.19 4,557.89 4,694.79 136.90 3.00 19 500 175,000 6,554.07 2,548.95 9,103.02 9,375.46 272.44 2.99 20 500 225,000 6,896.66 3,277.22 10,173.88 10,477.62 303.74 2.99 21 500 275,000 7,239.25 4,005.49 11,244.74 11,579.76 335.02 2.98 22 1000 350,000 13,008.13 5,097.89 18,106.02 18,646.15 540.13 2.98 23 1000 450,000 13,693.31 6,554.43 20,247.74 20,850.45 602.71 2.98 24 1000 550,000 14,378.49 8,010.97 22,389.46 23,054.75 665.29 2.97 25 3000 1,050,000 38,824.39 15,293.67 54,118.06 55,728.85 1,610.79 2.98 26 3000 1,350,000 40,879.93 19,663.29 60,543.22 62,341.75 1,798.53 2.97 27 3000 1,650,000 42,935.47 24,032.91 66,968.38 68,954.65 1,986.27 2.97 28 7000 2,450,000 90,458.91 35,685.23 126,142.14 129,894.27 3,752.13 2.97 29 7000 3,150,000 95,253.17 45,881.01 141,134.18 145,324.36 4,190.18 2.97 30 7000 3,850,000 100,049.43 56,076.79 156,126.22 160,754.45 4,628.23 2.96
Attachment 2 Page 7 of 7 Ohio Power Company Typical Bill Comparison
Level Level Current 10/04/99 Current Adjusted Line Rate of of Base Fuel Cost Bill Incl. Unbundled Dollar Percent No. Code Demand Usage Bill Revenue Fuel Costs Bill Increase Increase (A) (B) (C) (D) (E)=(C+D) (F) (G)=(F-E) (H)=(G/E) 0.0145654 1 GS-3-Sub 10 3,500 407.49 50.98 458.47 453.98 (4.49) (0.98) 2 10 4,500 414.20 65.54 479.74 476.46 (3.28) (0.68) 3 10 5,500 420.91 80.11 501.02 498.95 (2.07) (0.41) 4 25 8,750 591.23 127.45 718.68 725.42 6.74 0.94 5 25 11,250 608.01 163.86 771.87 781.65 9.78 1.27 6 25 13,750 624.79 200.27 825.06 837.86 12.80 1.55 7 50 17,500 897.46 254.89 1,152.35 1,176.42 24.07 2.09 8 50 22,500 931.02 327.72 1,258.74 1,286.06 27.32 2.17 9 50 27,500 964.57 400.55 1,365.12 1,395.72 30.60 2.24 10 75 26,250 1,203.69 382.34 1,586.03 1,623.93 37.90 2.39 11 75 33,750 1,254.03 491.58 1,745.61 1,788.39 42.78 2.45 12 75 41,250 1,304.37 600.82 1,905.19 1,952.86 47.67 2.50 13 100 35,000 1,509.91 509.79 2,019.70 2,071.43 51.73 2.56 14 100 45,000 1,577.03 655.44 2,232.47 2,290.73 58.26 2.61 15 100 55,000 1,644.15 801.10 2,445.25 2,510.01 64.76 2.65 16 200 70,000 2,734.83 1,019.58 3,754.41 3,861.44 107.03 2.85 17 200 90,000 2,869.06 1,310.89 4,179.95 4,300.03 120.08 2.87 18 200 110,000 3,003.30 1,602.19 4,605.49 4,738.63 133.14 2.89 19 500 175,000 6,409.57 2,548.95 8,958.52 9,231.50 272.98 3.05 20 500 225,000 6,745.16 3,277.22 10,022.38 10,327.97 305.59 3.05 21 500 275,000 7,080.75 4,005.49 11,086.24 11,424.44 338.20 3.05 22 1000 350,000 12,534.13 5,097.89 17,632.02 18,181.57 549.55 3.12 23 1000 450,000 13,205.31 6,554.43 19,759.74 20,374.52 614.78 3.11 24 1000 550,000 13,876.49 8,010.97 21,887.46 22,567.47 680.01 3.11 25 3000 1,050,000 37,032.39 15,293.67 52,326.06 53,981.89 1,655.83 3.16 26 3000 1,350,000 39,045.93 19,663.29 58,709.22 60,560.74 1,851.52 3.15 27 3000 1,650,000 41,059.47 24,032.91 65,092.38 67,139.58 2,047.20 3.15 28 7000 2,450,000 86,028.91 35,685.23 121,714.14 125,582.54 3,868.40 3.18 29 7000 3,150,000 90,727.17 45,881.01 136,608.18 140,933.17 4,324.99 3.17 30 7000 3,850,000 95,425.43 56,076.79 151,502.22 156,283.81 4,781.59 3.16
EX-99.D5 7 c22015_ex99-d5.txt TESTIMONY Exhibit 99.D5 BEFORE THE LOUISIANA PUBLIC SERVICE COMMISSION LPSC DOCKET NOS. U-21453, U-20925, U-22092 (SUBDOCKET C) SOUTHWESTERN ELECTRIC POWER COMPANY'S BUSINESS SEPARATION PLAN DIRECT TESTIMONY OF JOHN O. AARON FOR SOUTHWESTERN ELECTRIC POWER COMPANY SEPTEMBER 2001 DOCKET NOS. U-21453, U-20925, JOHN O. AARON U-22092 (SUBDOCKET C) DIRECT TESTIMONY 1 TESTIMONY INDEX SUBJECT PAGE I. INTRODUCTION........................................................3 II. PURPOSE OF TESTIMONY................................................5 III. OVERALL BUSINESS SEPARATION ACCOUNTING..............................5 A. Books, Records and Asset Transfers..............................6 B. Corporate Support Services.....................................11 IV. TRANSACTION AND TRANSITION COSTS INCLUDING THE PHYSICAL WORKFORCE SEPARATION COSTS.........................................12 V. CONCLUSION.........................................................13 DOCKET NOS. U-21453, U-20925, JOHN O. AARON U-22092 (SUBDOCKET C) DIRECT TESTIMONY 2 1 BEFORE THE 2 LOUISIANA PUBLIC SERVICE COMMISSION 3 LPSC DOCKET NOS. U-21453, 4 U-20925, U-22092 (SUBDOCKET C) 5 6 SOUTHWESTERN ELECTRIC POWER COMPANY'S 7 BUSINESS SEPARATION PLAN 8 9 DIRECT TESTIMONY OF 10 JOHN O. AARON 11 12 FOR 13 SOUTHWESTERN ELECTRIC POWER COMPANY 14 15 SEPTEMBER 2001 16 17 I. INTRODUCTION 18 Q. PLEASE STATE YOUR NAME, POSITION AND BUSINESS ADDRESS. 19 A. My name is John O. Aaron and I am employed as a Regulatory Accounting Consultant 20 by American Electric Power Service Corporation (AEPSC), a subsidiary of American 21 Electric Power Company, Inc. (AEP). My business address is Williams Tower II, 2 22 W. Second St., Tulsa, Oklahoma, 74103-3102.
DOCKET NOS. U-21453, U-20925, JOHN O. AARON U-22092 (SUBDOCKET C) DIRECT TESTIMONY 3 1 Q. WHAT ARE YOUR PRINCIPAL AREAS OF RESPONSIBILITY? 2 I am responsible for the preparation and coordination of accounting-related schedules 3 and other accounting information for regulatory filings made by the four domestic 4 electric operating companies of the western portion of AEP: Central Power and Light 5 Company (CPL), Southwestern Electric Power Company (SWEPCO), Public Service 6 Company of Oklahoma (PSO) and West Texas Utilities Company (WTU). 7 Q. PLEASE SUMMARIZE YOUR EDUCATIONAL BACKGROUND AND 8 PROFESSIONAL BACKGROUND. 9 A. I received a Bachelor of Science in Accounting from Louisiana State University in 10 Shreveport in May 1980. I am a Certified Public Accountant (CPA) in the State of 11 Oklahoma and a member of the American Institute of CPAs and the Oklahoma Society 12 of CPAs. Upon graduation from college, I was employed as an Internal Auditor for a 13 multi-state wholesale appliance and electrical supplier in Shreveport, Louisiana. In 14 May 1984, I accepted employment with SWEPCO as an accountant in the Property 15 Accounting Department. From 1985 through 1995, I held various positions in the 16 Accounting, Internal Auditing and Rate Departments, including Supervisor of 17 Regulatory Accounting Support and Supervisor of Wholesale Marketing Support. My 18 responsibilities at SWEPCO included preparing property accounting closing reports 19 and journal entries, conducting financial audits, and providing accounting support for 20 regulatory filings made in SWEPCO's retail jurisdictions and at the Federal Energy 21 Regulatory Commission (FERC). In April 1995, I assumed the position of Regulatory 22 Accounting Consultant at Central and South West Services, Inc. (CSWS) the service
DOCKET NOS. U-21453, U-20925, JOHN O. AARON U-22092 (SUBDOCKET C) DIRECT TESTIMONY 4 1 company for the former Central and South West Corporation (CSW). As of January 2 1, 2001, AEPSC became the successor to CSWS. 3 Q. HAVE YOU PREVIOUSLY SPONSORED TESTIMONY BEFORE THIS OR 4 OTHER COMMISSIONS? 5 A. Yes. I have sponsored written testimony on behalf of WTU and CPL before the 6 Public Utility Commission of Texas but not before the Louisiana Public Service 7 Commission (LPSC). 8 9 II. PURPOSE OF TESTIMONY 10 Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY IN THIS FILING? 11 A. The purpose of my testimony is to address accounting implications associated with 12 SWEPCO's business separation plan resulting from the restructuring of the electric 13 industry in SWEPCO's Texas service territory. 14 Q. IS THIS TESTIMONY TRUE AND CORRECT TO THE BEST OF YOUR 15 KNOWLEDGE AND BELIEF? 16 A. Yes. 17 18 III. OVERALL BUSINESS SEPARATION ACCOUNTING 19 Q. BRIEFLY DESCRIBE THE PROPOSED BUSINESS SEPARATION PLAN FOR 20 SWEPCO. 21 A. As discussed in the direct testimony of Mr. J. Craig Baker, SWEPCO's assets will be 22 split between SWEPCO and the SWEPCO Texas Energy Delivery Company
DOCKET NOS. U-21453, U-20925, JOHN O. AARON U-22092 (SUBDOCKET C) DIRECT TESTIMONY 5 1 (SWEPCO Texas EDC). The SWEPCO Texas EDC will be comprised of SWEPCO's 2 transmission and distribution assets physically located in Texas and any related general 3 plant. SWEPCO will continue to own all of SWEPCO's other assets, including all 4 generation assets, the transmission assets and distribution assets physically located in 5 Arkansas and Louisiana, and any related general plant assets. 6 7 A. BOOKS. RECORDS AND ASSET TRANSFERS 8 Q. HOW WILL THE TRANSFERS OF ASSETS AND LIABILITIES BETWEEN THE 9 LEGAL ENTITIES BE VALUED? 10 A. The transfers of assets and liabilities to accomplish the structural separation will be 11 valued at net book value. Net book value is defined as original cost less accumulated 12 depreciation. This is in compliance with the rules of the Securities and Exchange 13 Commission (SEC) as they pertain to holding companies registered under the Public 14 Utility Holding Company Act of 1935 (PUHCA), and is consistent with Texas 15 restructuring legislation and rules. 16 Q. HOW WILL THE ASSET SEPARATIONS OR TRANSFERS BE CONDUCTED? 17 A. Asset ownership will be detem1ined on the basis of the predominant use of the asset 18 and its physical location. FERC Account 101, Electric Plant in Service, contains most 19 of the assets to be separated. In general, generation assets recorded in FERC plant 20 accounts 310-346 will be functionally separated into generation and will stay on 21 SWEPCO's books.
DOCKET NOS. U-21453, U-20925, JOHN O. AARON U-22092 (SUBDOCKET C) DIRECT TESTIMONY 6 1 Transmission assets recorded in FERC plant accounts 350-359 and physically 2 located in Texas will be transferred to the SWEPCO Texas EDC. Transmission assets 3 recorded in FERC plant accounts 350-359 and physically located in Arkansas and 4 Louisiana will stay with SWEPCO. In addition, all generator step-up transformers and 5 related breaker equipment, regardless of physical location, will be transferred to the 6 generation function and remain on SWEPCO's books. 7 Distribution assets recorded in FERC plant accounts 360-373 and physically 8 located in Texas will be transferred to the SWEPCO Texas EDC. Distribution assets 9 recorded in FERC plant accounts 360-373 and physically located in Arkansas and 10 Louisiana will stay with SWEPCO. This follows the current treatment of distribution 11 costs that are maintained on a situs basis. 12 General plant assets recorded in FERC plant accounts 389-399 that can be 13 identified to a specific function (e.g., generation, transmission, distribution) will be 14 assigned to that function. The general plant assets that cannot be directly assigned will 15 be allocated based on functional gross plant balances. The SWEPCO Texas EDC 16 amount will be detern1ined based on the ratio of Texas transmission and distribution 17 situs plant balances to total transmission and distribution assets. 18 Q. HOW WILL SWEPCO IDENTIFY THE ASSETS TO BE TRANSFERRED? 19 A. For transmission and distribution assets, SWEPCO's books and records specify the 20 state in which the plant in service asset is located. Appropriate personnel are currently 21 reviewing the general plant assets to determine the assignment of the general plant 22 assets to be transferred to the SWEPCO Texas EDC.
DOCKET NOS. U-21453, U-20925, JOHN O. AARON U-22092 (SUBDOCKET C) DIRECT TESTIMONY 7 1 Q. HAS AN ESTIMATE OF THE SEPARATE SWEPCO AND SWEPCO TEXAS 2 EDC BALANCE SHEETS BEEN MADE? 3 A. Yes. Please refer to the July 24,2001 FERC filing in Docket No. ECO1-130-000 for a 4 balance sheet providing the estimated amounts for SWEPCO and the SWEPCO Texas 5 EDC at December 31, 2000. This balance sheet provides a reasonable estimate of the 6 expected assets, liabilities and capitalization for the separate SWEPCO entities. The 7 actual balances at the time of separation will be different and the methods used to 8 separate the assets more detailed and precise. 9 Q. WHEN WILL THE ASSETS AND LIABILITIES BE TRANSFERRED? 10 A. The asset and liability transfer will be effective January 1, 2002. 11 Q. ARE THERE ANY ASSETS WHICH WILL BE TRANSFERRED THAT HAVE A 12 ZERO BOOK VALUE BUT ARE STILL USEFUL? 13 A. No, for the most part. SWEPCO depreciates assets utilizing "mass asset" accounting. 14 In this type of accounting, assets with similar characteristics are grouped and 15 depreciation is recorded as a group instead of being recorded on an asset-by-asset 16 basis. In mass asset accounting, depreciation rates are adjusted to reflect the average 17 service life of the group as a whole. When an individual asset is no longer useful, that 18 asset is retired and removed from the group. Capitalized computer software is one 19 exception to the mass asset accounting method. For these types of assets, SWEPCO 20 identifies individual computer software systems and amortizes each software system 21 individually. Thus, at December 31, 2001, there is the possibility that a particular 22 system still in use will have a net book value of zero.
DOCKET NOS. U-21453, U-20925, JOHN O. AARON U-22092 (SUBDOCKET C) DIRECT TESTIMONY 8 1 Q. WILL SEPARATE BOOKS AND RECORDS BE MAINTAINED FOR SWEPCO AND 2 THE SWEPCO TEXAS EDC? 3 A. Yes. Separate books and records will be maintained. 4 Q. FOR RATE PROCEEDINGS BEFORE THE LPSC, WHERE WILL THE 5 FINANCIAL DATA UTILIZED TO DEVELOP TOTAL COSTS FOR SERVICES 6 PROVIDED TO SWEPCO'S REGULATED LOUISIANA CUSTOMERS RESIDE? 7 A. The financial data will reside both on SWEPCO's and the SWEPCO Texas EDC's 8 books and records. The SWEPCO Texas EDC's books and records will be used to 9 provide asset and cost data associated with assets that are used to provide electric 10 service to SWEPCO's regulated Louisiana customers. For example, the transmission 11 facilities physically located in Texas are utilized to transmit power from the SWEPCO 12 power plants physically located in Texas to SWEPCO's regulated Louisiana 13 customers. Because the financial data associated with the transmission facilities 14 physically located in Texas resides on SWEPCO Texas EDC's books and records, 15 SWEPCO Texas EDC's books and records must be used to develop total transmission 16 costs for SWEPCO's regulated Louisiana customers. For total SWEPCO 17 transmission cost determination, the appropriate financial data from these two 18 companies will be combined. Ms. Hargus provides an example of this concept as it 19 relates to cost of capital in her testimony. 20 Q. WILL THE CREATION OF THE SWEPCO TEXAS EDC RESULT IN 21 ADDITIONAL DATA BEING AVAILABLE TO DEVELOP PROPER 22 LOUISIANA RETAIL COSTS?
DOCKET NOS. U-21453, U-20925, JOHN O. AARON U-22092 (SUBDOCKET C) DIRECT TESTIMONY 9 1 A. Yes, it will. Previously, SWEPCO did not track separately Texas T&D cost data such 2 as operation and maintenance (O & M) expense. With the creation of the SWEPCO 3 Texas EDC, more accurate Texas T&D cost data will be available (e.g., Texas specific 4 distribution O & M and Texas specific transmission and distribution ad valorem taxes). 5 With this data, a more precise allocation of costs to SWEPCO's Louisiana retail 6 customers can be made. Because this more precise data was not available for 7 ratemaking purposes in the past, SWEPCO does not know if Louisiana retail costs will 8 increase or decrease. No matter which direction the costs go, the Louisiana retail 9 customer cost allocation will be more accurate. Mr. Chris Potter discusses the proper 10 allocation of the financial data to SWEPCO's Louisiana retail customers. 11 Q. DOES SWEPCO ANTICIPATE THERE WILL BE ANY MATERIAL EFFECT ON 12 LOUISIANA'S RETAIL CUSTOMERS AS A RESULT OF THE TRANSFER OF 13 ASSETS TO THE SWEPCO TEXAS EDC? 14 A. No, it does not. The assets to be transferred to the SWEPCO Texas EDC will be 15 accomplished at book value, which is consistent with the methodology used to set 16 rates. Therefore, no material effect is expected from the transfer. To the extent 17 additional more precise information, such as O & M, is available with the creation of 18 the SWEPCO Texas EDC, such information will be used, but is not expected to 19 significantly change Louisiana customers' costs. For information concerning the 20 implications of the cost of capital for these transfers, please see Ms. Hargus' 21 testimony. 22
DOCKET NOS. U-21453, U-20925, JOHN O. AARON U-22092 (SUBDOCKET C) DIRECT TESTIMONY 10 1 B. Corporate Support Services ----------------------------- 2 Q. PLEASE DISCUSS HOW THE CORPORATE SUPPORT SERVICES PROVIDED 3 BY THE AMERICAN ELECTRIC POWER SERVICE CORPORATION (AEPSC) 4 WILL BE SHARED AMONG THE BUSINESS UNITS. 5 A. AEP will continue to make use of corporate support services provided by AEPSC to 6 retain the efficiencies of central management that promote cost savings. Such services 7 will be provided by AEPSC to a larger number of AEP companies. 8 Q. HOW WILL COSTS RELATED TO SHARED SERVICES BE ACCOUNTED 9 FOR? 10 A. Costs related to services provided by corporate and shared services support will be 11 accounted for utilizing a work order type system as required by the SEC. 12 Expenditures for shared and support services will be accumulated in the work order 13 type system and ultimately billed to the AEP subsidiaries, including AEP's 14 non-regulated companies that benefit from the service. Accounting within each 15 activity or project will be in accordance with the FERC system of accounts. This 16 facilitates a clearer understanding of the specific service provided and simplifies the 17 recording of these charges on the benefiting companies' books. 18 Q. HOW ARE THESE EXPENDITURES ALLOCATED TO THE BENEFITING 19 COMPANIES? 20 A. Costs will be directly assigned to a specific company to the maximum extent possible. 21 When costs cannot be directly billed, appropriate SEC approved allocation factors will 22 be used. A volume-driven formula is used in cases where the cost driver is volume-
DOCKET NOS. U-21453, U-20925, JOHN O. AARON U-22092 (SUBDOCKET C) DIRECT TESTIMONY 11 1 based and the data is available. If a volume-based formula is not available, the most 2 representative factor will be used based on cost-causative criteria that are indicators of 3 the amount of activity within the companies that gives rise to the costs that are to be 4 allocated. Being based on the activity that gives rise to the costs, the factors assure 5 that costs are allocated on the basis of specific company cost-causative criteria, which 6 appropriately reflects the service recipients' activity level and use of equipment or 7 assets. 8 It is expected that the existing or similar allocation factors will be used to 9 allocate shared support services after the business separation. Although many of the 10 allocation factors will be the same as those used today, it is possible that additional 11 allocation factors may be required as a result of the business separations. AEPSC will 12 seek approval of any new allocation factors from the SEC. 13 14 IV. TRANSITION COSTS INCLUDING 15 THE PHYSICAL WORKFORCE SEPARATION COSTS 16 Q. WILL SWEPCO INCUR TRANSITION COSTS ASSOCIATED WITH THE 17 RESTRUCTURING OF THE ELECTRIC INDUSTRY IN TEXAS? 18 A. Yes. SWEPCO will place in service additional assets (such as load profiling system 19 and transmission metering at power plants) and will incur additional O & M related to 20 the restructuring of the electric industry in Texas. 21 Q. HOW DOES SWEPCO PROPOSE TO HANDLE THESE TRANSITION COSTS 22 WITH REGARD TO SWEPCO'S LOUISIANA RETAIL CUSTOMERS?
DOCKET NOS. U-21453, U-20925, JOHN O. AARON U-22092 (SUBDOCKET C) DIRECT TESTIMONY 12 1 A. SWEPCO proposes to identify transition costs in its accounting records and not 2 charge any of these costs to its Louisiana retail customers unless and until such time 3 such assets and costs are utilized in the provision of electric service to Louisiana retail 4 customers. New assets will be identified with a special code that will designate them 5 as restructuring assets. O & M costs will also be identified with a special code that 6 will also designate these costs as restructuring costs. The restructuring assets and 7 O & M data will thus be separated from the jurisdictional allocations so that these 8 costs will not be charged to Louisiana retail customers. At some time in the future, 9 should the Louisiana retail customers benefit from these assets, they will be assigned a 10 portion of the costs. Additional information about cost allocation can be found in the 11 direct testimony of Mr. Chris Potter. 12 13 V. CONCLUSION ------------- 14 Q. PLEASE BRIEFLY SUMMARIZE YOUR TESTIMONY. 15 A. SWEPCO's assets and liabilities required by the Texas restructuring initiative will be 16 transferred between entities at net book value. Separate books and records for the 17 separate legal entities will be maintained. For transmission rate making purposes, the 18 books and records of SWEPCO and the SWEPCO Texas EDC will be utilized to 19 develop total SWEPCO costs. Other costs such as distribution will be charged 20 separately to both entities. Corporate support service costs will be directly assigned to 21 the company benefiting from the service or allocated to the company benefiting from 22 the service on a cost-causative allocation basis. The transition costs associated with
DOCKET NOS. U-21453, U-20925, JOHN O. AARON U-22092 (SUBDOCKET C) DIRECT TESTIMONY 13 1 the restructuring in Texas will be identified and not charged to SWEPCO's Louisiana 2 retail customers until such time as those assets or costs are utilized 3 to provide service to SWEPCO's Louisiana retail customers. 4 Q. DOES THIS CONCLUDE YOUR DIRECT TESTIMONY? 5 A. Yes, it does.
DOCKET NOS. U-21453, U-20925, JOHN O. AARON U-22092 (SUBDOCKET C) DIRECT TESTIMONY 14 BEFORE THE LOUISIANA PUBLIC SERVICE COMMISSION LPSC DOCKET NOS. U-21453, U-20925, U-22092 (SUBDOCKET C) SOUTHWESTERN ELECTRIC POWER COMPANY'S BUSINESS SEPARATION PLAN DIRECT TESTIMONY OF J. CRAIG BAKER FOR SOUTHWESTERN ELECTRIC POWER COMPANY AUGUST 2001 DOCKET NOS. U-21453, U-20925, J. CRAIG BAKER U-22092 (SUBDOCKET C) DIRECT TESTIMONY 1 TESTIMONY INDEX SUBJECT PAGE ------- ---- I. INTRODUCTION .......................................................3 II. PURPOSE OF FILING AND TESTIMONY ....................................4 III. REQUEST FOR APPROVAL OF REQUIRED TRANSFERS AS PART OF THE, SEPARATION PLAN .............................................7 IV. PROPOSED BUSINESS SEPARATION PLAN ..................................8 V. STATUS OF STATE RESTRUCTURING IN SWEPCO'S SERVICE TERRITORY .......................................................13 VI. FERC RTO ISSUES IN RESTRUCTURING ..................................18 VII. SWEPCO BSP EFFECT ON COST STRUCTURE . .............................21 VIII. FERC FILINGS CONCERNING SWEPCO'S BSP ..............................24 IX. OTHER REGULATORY APPROVALS ........................................31 X. CONCLUSION ........................................................32 EXHIBITS -------- EXHIBIT JCB- I Organizational Charts EXHIBIT JCB-2 AEP WEST Comparison of 4 Company versus 2 Company Agreements DOCKET NOS. U-21453, U-20925, J. CRAIG BAKER U-22092 (SUBDOCKET C) DIRECT TESTIMONY 2 1 BEFORE THE 2 LOUISIANA PUBLIC SERVICE COMMISSION 3 LPSC DOCKET NOS. U-21453, 4 U-20925, U-22092 (SUBDOCKET C) 5 6 SOUTHWESTERN ELECTRIC POWER COMPANY'S 7 BUSINESS SEPARATION PLAN 8 9 DIRECT TESTIMONY OF 10 J. CRAIG BAKER 11 12 FOR 13 SOUTHWESTERN ELECTRIC POWER COMPANY 14 15 AUGUST 2001 16 17 1. INTRODUCTION --------------- 18 Q. PLEASE STATE YOUR NAME AND POSITION. 19 A. My name is J. Craig Baker, Senior Vice President-Regulation and Public Policy, 20 American Electric Power Service Corporation (AEPSC), 1 Riverside Plaza, 21 Columbus, Ohio 43215.
DOCKET NOS. U-21453, U-20925, J. CRAIG BAKER U-22092 (SUBDOCKET C) DIRECT TESTIMONY 3 1 Q. BRIEFLY DESCRIBE YOUR EDUCATIONAL AND PROFESSIONAL 2 QUALIFICATIONS AND YOUR BUSINESS EXPERIENCE. 3 A. I received a Bachelor's Degree in Business Administration from Walsh College in 4 1970 and a Masters Degree in Business Administration in Finance from Akron 5 University in 1980. I joined the American Electric Power (AEP) System in 1968 and 6 through 1979 held various positions in the Computer Applications Division. I 7 transferred to the System Operation Division in 1979 and held positions of 8 Administrative Assistant and Assistant Manager. In 1985, I took the position of Staff 9 Analyst in the Controller's Department and, in 1987, I became Manager-Power 10 Marketing the System Power Markets Department. In 1991, I became Director, 11 Interconnection Agreements and Marketing. I became Vice President-Power 12 Marketing for AEPSC and Senior Vice President of Energy Marketing for AEP 13 Energy Services, Inc. in November 1996 and August 1997, respectively. On July 1, 14 1998, I became Vice President of Transmission Policy for AEPSC. In June 2000, I 15 became Senior Vice President of Public Policy for AEPSC. 16 17 II. PURPOSE OF FILING AND TESTIMONY ----------------------------------- 18 Q. WHAT IS THE PURPOSE OF THIS FILING? 19 A. The purpose of this filing is to comply with the information request of the Louisiana 20 Public Service Commission (LPSC or Commission) in Docket Nos, U-21453, 21 U-20925, and U-22092 (Subdocket C) requiring Southwestern Electric Power 22 Company (SWEPCO or Company) to identify the changes in its corporate structure,
DOCKET NOS. U-21453, U-20925, J. CRAIG BAKER U-22092 (SUBDOCKET C) DIRECT TESTIMONY 4 1 and their potential impact on Louisiana retail ratepayers, resulting from SWEPCO's 2 restructuring activities in Texas and anticipated restructuring activities in Arkansas. 3 The filing requests LPSC approval of the of the transfer by SWEPCO of transmission 4 and distribution (T&D) and related general plant (GP) assets located in Texas to a 5 separate Energy Delivery Company (EDC), in order to comply with Texas 6 restructuring statutes. I believe that approval of the requested transfers consistent 7 with the SWEPCO Business Separation Plan (BSP) will constitute all LPSC actions 8 required as a prerequisite to the structural unbundling of SWEPCO as required by the 9 Public Utility Commission of Texas (PUCT) restructuring initiative. 10 Q. HAS SWEPCO PREVIOUSLY PRESENTED INFORMATION REGARDING ITS 11 PROPOSED CORPORATE RESTRUCTURING? 12 A. Yes. On May 25, 2001, SWEPCO made a preliminary filing with the LPSC 13 addressing the SWEPCO BSP. This filing was supplemented on June 29, 2001 14 with drafts of changes to existing AEP agreements and new AEP agreements necessary to 15 implement corporate restructuring. On July 26, 2001, the LPSC was also provided 16 copies of the Application of American Electric Power Service Corporation for 17 Authorization to Transfer Jurisdictional Assets (Docket No. EC0 1 - 130-000) and the 18 Application of American Electric Power Company, Inc. for Approval of Rate 19 Schedules Related to Corporate Restructuring (Docket No. ER01-2668-000) filed 20 before the Federal Energy Regulatory Commission (FERC) on July 24, 2001 21 (collectively, the "FERC filings"). The FERC filings contain the latest versions of 22 the agreements necessary to implement the SWEPCO BSP. On August 6, SWEPCO
DOCKET NOS. U-21453, U-20925, J. CRAIG BAKER U-22092 (SUBDOCKET C) DIRECT TESTIMONY 5 1 provided the LPSC "redlined" versions of the agreements comparing the agreements 2 filed at FERC with those previously filed at the LPSC. This filing (along with the 3 related agreements filed at FERC) replaces in their entirety the previous SWEPCO 4 BSP filings of May 25, 2001 and June 29, 2001. 5 Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY IN THIS PROCEEDING? 6 A. The purpose of my testimony is to provide an overview of the SWEPCO BSP and 7 discuss the following matters: 8 1. SWEPCO's plan for transferring its Texas T&D and related GP assets 9 to a new EDC and the associated ratemaking issues; 10 2. The restructuring requirements thus far adopted in Texas and the 11 impact those requirements will have on SWEPCO's BSP; 12 3. The status of the proceedings in Texas and Arkansas related to the 13 SWEPCO BSP; 14 4. A detailed summary of the transactions that are anticipated as a result 15 of the Texas business separation plan and a description of the Restated 16 and Amended AEP-West Operating Agreement (AEP West Operating 17 Agreement), Restated and Amended System Integration Agreement 18 (AEP SIA), Unit Power Sales Agreement between SWEPCO and 19 Power Marketing Affiliate (SWEPCO UPSA), and the Second Unit 20 Power Sales Agreement between Power Marketing Affiliate (PMA) 21 and SWEPCO (Second UPSA); and, 22 5. The cost implications of SWEPCO's restructuring activities in Texas 23 for SWEPCO and for Louisiana.
DOCKET NOS. U-21453, U-20925, J. CRAIG BAKER U-22092 (SUBDOCKET C) DIRECT TESTIMONY 6 1 III. REQUEST FOR APPROVAL OF REQUIRED ------------------------------------- 2 TRANSFERS AS PART OF THE SEPARATION PLAN ---------------------------------------- 3 Q. SHOULD THE LPSC APPROVE SWEPCO'S PROPOSED PLAN TO TRANSFER 4 ITS TRANSMISSION AND DISTRIBUTION ASSETS INTO A SEPARATE 5 COMPANY? 6 A. Yes. SWEPCO's BSP permits SWEPCO to comply with completely divergent state 7 laws and policies regarding restructuring in Texas, Arkansas, and Louisiana with no 8 disruption of and no material adverse effect on its ability to provide continuing 9 bundled retail utility service to Louisiana retail customers. The BSP will permit 10 compliance with the applicable statutes in each state with regulatory authority over 11 SWEPCO, thereby avoiding lengthy litigation which would result if state laws 12 required conflicting actions. The BSP, as structured, will not materially affect the 13 cost structure or rates of the SWEPCO Louisiana retail customers. By only 14 separating the Texas T&D and related GP assets of SWEPCO, the physical assets that 15 are utilized to serve Louisiana customers will be essentially unchanged. SWEPCO 16 remains committed to achieving the reliability and service quality standards which are 17 in effect in Louisiana with the same assets that are in place today. The BSP is in the 18 public interest of Louisiana customers, since it provides a path for resolution of 19 jurisdictional conflicts with a minimum of future litigation.
DOCKET NOS. U-21453, U-20925, J. CRAIG BAKER U-22092 (SUBDOCKET C) DIRECT TESTIMONY 7 1 IV. PROPOSED BUSINESS SEPARATION PLAN ------------------------------------- 2 Q. PLEASE DESCRIBE THE PROPOSED SWEPCO BSP. 3 A. In accordance with the legislative requirements discussed previously, the SWEPCO 4 T&D and related GP assets that are physically located in Texas will be transferred to 5 a separate wholly-owned subsidiary of AEP, the SWEPCO TEXAS EDC. In 6 addition, the SWEPCO generation assets and employees currently utilized to provide 7 generation services will remain the assets and employees of SWEPCO. The provision 8 of generation services and wholesale electricity sales currently supplied by SWEPCO 9 will be under the direction, management, and control of a separate wholly-owned 10 subsidiary of AEP, the Regulated Holdco, with the coordination, planning, operation 11 and maintenance responsibilities of its power supply resources delegated to AEPSC 12 pursuant to the AEP West Operating Agreement, continuing the practice currently in 13 effect. The T&D assets physically located in Arkansas and Louisiana and employees 14 currently utilized to provide service in Arkansas and Louisiana will remain assets and 15 employees of SWEPCO. However, SWEPCO and the SWEPCO TEXAS EDC 16 intend to turn over operational control of their FERC jurisdictional transmission 17 facilities to a regional transmission organization (RTO). AEP has also established a 18 retail energy provider (Mutual Energy SWEPCO, LP or "SWEPCO REP") under the 19 Texas REP Holdco discussed below that will provide retail electric services in Texas 20 as required by the restructuring rules of that state. 21 The proposed SWEPCO BSP is being carried out as part of AEP's overall corporate 22 restructuring to respond to the movement toward further competition in the
DOCKET NOS. U-21453, U-20925, J. CRAIG BAKER U-22092 (SUBDOCKET C) DIRECT TESTIMONY 8 1 electric power industry and to comply with the restructuring statutes in Texas and 2 Ohio. 3 Q. PLEASE DISCUSS THE OVERALL AEF RESTRUCTURING. 4 A. EXHIBIT JCB-1 provides the planned and current corporate structures for SWEPCO 5 and AEP resulting from the restructuring activities in Texas as described in the July 6 24 FERC filing. To accomplish its overall corporate restructuring (including 7 SWEPCO's BSP) AEP has established or will establish several intermediate holding 8 companies that will be used to reorganize its businesses in the following manner. 9 AEP will hold all of the common stock of three relevant first-tier subsidiaries: 10 (1) Regulated Holdco, which will be the holding company for AEP's regulated 11 businesses, including vertically integrated electric utilities in states the continue to 12 regulate electric utilities in the traditional manner (including SWEPCO) and 13 transmission and distribution (energy delivery) companies that result from the 14 corporate separation of Central Power and Light Company (CPL), West Texas 15 Utilities Company (WTU), SWEPCO, Ohio Power Company (OPCo) and Columbus 16 Southern Power Company (CSP); (2) AEP Texas REP Holdco, a first-tier AEP 17 subsidiary that will be the holding company for AEP's competitive retail energy 18 marketing businesses in Texas; and (3) AEP Enterprises, Inc., which, among other things, 19 will be the holding company for AEP's unregulated or lightly regulated 20 foreign and domestic power generation and marketing businesses, including the 21 power generation companies that will result from the corporate separation of CPL, 22 WTU, OPCo, and CSP to comply with Texas and Ohio electric utility restructuring
DOCKET NOS. U-21453, U -20925, J. CRAIG BAKER U-22092 (SUBDOCKET C) DIRECT TESTIMONY 9 1 laws. AEP Enterprises has established or will establish a second-tier holding 2 company, AEP Wholesale Holding Company, Inc. (Wholesale Holdco), that will 3 control the common stock of a third-tier holding company, AEP Domestic Generation 4 Holding Company, Inc. (Domestic Genco), that will hold the common stock of the 5 power generating companies that result from the corporate separation of CPL, WTU, 6 OPCo and CSP. AEP Texas REP Holdco, Inc., AEP Enterprises, Inc., AEP 7 Wholesale Holdco, Inc., AEP Domestic Generation Holding Company, Inc. and the 8 other corporate names used for affiliates of the existing AEP operating companies are 9 all placeholder names, which are being used for descriptive convenience pending 10 implementation of AEP's business reorganization plans. 11 Q. PLEASE DISCUSS THE FORMATION OF THE SWEPCO TEXAS EDC. 12 A. To comply with the Texas electric restructuring statute (Senate Bill 7), by January 1, 13 2002, SWEPCO will transfer title to its T&D and related GP assets, including 14 interconnection agreements with neighboring utility systems, located in Texas and 15 related business operations to a newly formed wholly owned subsidiary, SWEPCO 16 TEXAS EDC, in exchange for 100% of the capital stock of such subsidiary and then 17 contribute or dividend the shares of SWEPCO TEXAS EDC to SWEPCO's parent, 18 Regulated Holdco. Regulated Holdco will continue to hold all of the common stock 19 of SWEPCO. SWEPCO will retain title to its T&D assets located in Louisiana and 20 Arkansas and all of its generating plants. 21 Q. WHY WILL SWEPCO CONTINUE TO RETAIN TITLE TO ITS GENERATING 22 ASSETS?
DOCKET NOS. U-21453, U -20925, J. CRAIG BAKER U-22092 (SUBDOCKET C) DIRECT TESTIMONY 10 1 A. SWEPCO will continue to retain title to its generating assets because it provides 2 bundled retail electric service in Louisiana, which to date has not adopted a retail 3 Competition policy or legislation, and in Arkansas, where SWEPCO is not obliged 4 to separate ownership of its generating assets from its transmission and distribution 5 assets. SWEPCO also will retain its existing wholesale electric sales contracts, but 6 will sell to AEP's PMA proportionate rights to capacity in each SWEPCO generating 7 unit and certain capacity purchase agreements equal to the ratio of the sum of the 8 demands of the SWEPCO-Texas retail native load and the SWEPCO wholesale 9 contract native load at the time of the four Year 2000 coincident monthly summer 10 (June through September) SWEPCO peak demands to the sum of the same four 11 coincident peak demands of the total SWEPCO native load. As discussed later in this 12 testimony, such capacity and associated energy will be made available to PMA under 13 the SWEPCO UPSA. To enable SWEPCO to continue to supply its wholesale 14 requirements customers, PMA will sell back to SWEPCO under the Second UPSA 15 the capacity and associated energy needed for that purpose. 16 Q. PLEASE DISCUSS THE NEW SWEPCO REP ORGANIZATION, 17 A. As discussed earlier, AEP established the SWEPCO REP as a subsidiary with the 18 primary purpose of providing retail electric service to end-use customers in Texas, including 19 the procurement of generation services and competitive customer services 20 components. SWEPCO may also assign to the affiliated SWEPCO REP the 21 responsibility to provide the standard service package offering in Arkansas once retail 22 competition begins in that state. The SWEPCO REP will acquire wholesale energy supply and necessary transmission and distribution services to meet the needs of the
DOCKET NOS. U-21453, U -20925, J. CRAIG BAKER U-22092 (SUBDOCKET C) DIRECT TESTIMONY 11 1 remaining Texas retail customers. The SWEPCO REP anticipates acquiring energy 2 supplies from one or more of the following: its affiliate power generation company, 3 non-affiliate power generation companies, and power marketers. 4 Q. PLEASE DISCUSS THE TRANSFERS OF SWEPCO ASSETS AND LIABILITIES 5 ANTICIPATED UNDER THE SWEPCO BSP. 6 A. The only change in ownership of existing SWEPCO assets pertains to T&D assets 7 located in Texas and related general plant assets. The transfers of assets and 8 liabilities related to the transmission and distribution utility located in Texas will be 9 valued at net book value. Further, to functionally separate all of SWEPCO's assets 10 into generation, transmission, distribution, and customer services functions, assets 11 will be valued at net book value. Net book value is defined as original cost less 12 accumulated depreciation. This treatment complies with the rules of the Securities 13 and Exchange Commission (SEC) for holding companies registered under the Public 14 Utility Holding Company Act of 1935, such as AEP. Mr. John Aaron will be filing 15 testimony in this proceeding and will discuss the transfer of assets in more detail in 16 that testimony. 17 Q. WILL THERE BE A MATERIAL EFFECT ON LOUISIANA'S RETAIL 18 RATEPAYERS AS A RESULT OF THESE TRANSFERS? 19 A. No. As will be discussed in more detail by Ms. Wendy Hargus (who will also be 20 filing testimony in this proceeding), the SWEPCO Texas assets that are transferred to 21 the SWEPCO TEXAS EDC will be financed by the SWEPCO TEXAS EDC or 22 Regulated Holdco and will not be subject to any existing SWEPCO indentures or
DOCKET NOS. U-21453, U -20925, J. CRAIG BAKER U-22092 (SUBDOCKET C) DIRECT TESTIMONY 12 1 other form of lien or pledge. Because the transfer of the SWEPCO Texas assets can 2 be accomplished without violating the terms of SWEPCO's indentures or the terms of 3 other securities contracts, SWEPCO's capital costs are not expected to change 4 significantly. 5 6 V. STATUS OF STATE RESTRUCTURING 7 IN SWEPCO'S SERVICE TERRITORY 8 Q. WHAT IS THE STATE OF RETAIL COMPETITION POLICY IN LOUISIANA, 9 ARKANSAS, AND TEXAS? 10 A. The LPSC is currently evaluating the merits of a transition to retail competition. No 11 final decision has been reached regarding whether a transition to competition is 12 appropriate; therefore, SWEPCO remains obligated to provide bundled utility service, 13 at tariffed rates, to retail customers in Louisiana. 14 In Arkansas, legislation has been passed which requires SWEPCO to provide 15 retail customer choice no sooner than October 1, 2003, and no later than October 1, 16 2005. The statute requires SWEPCO to functionally separate its generation and 17 energy delivery functions, but does not require any structural separation of assets. 18 The requirements of this legislation could be met with organizational changes, and no 19 structural changes. 20 In Texas, the restructuring statute (Senate Bill 7 or SB7) requires SWEPCO to 21 offer retail customer choice on January 1, 2002 to Texas retail customers. The statute 22 also contains language that requires SWEPCO to undertake some form of structural
DOCKET NOS. U-21453, U -20925, J. CRAIG BAKER U-22092 (SUBDOCKET C) DIRECT TESTIMONY 13 1 separation of assets. As discussed later in this testimony, on August 3, 2001, the 2 PUCT Staff petitioned the PUCT to determine whether market institutions and 3 participants are ready for retail competition to begin within SWEPCO's Texas 4 jurisdiction, which is located in the Southwest Power Pool (SPP). 5 Because these policy directions are all different, considerable time and effort 6 was required to develop SWEPCO's BSP. Discussions with the affected state 7 regulatory commissions proved extremely valuable in developing a plan that best 8 meets the needs of each state, 9 Q. HAS THE SWEPCO BSP BEEN APPROVED BY EITHER Of THE 10 REGULATORY AGENCIES IN TEXAS AND ARKANSAS? 11 A. Yes. The proposed Texas business separation plan was subject to a settlement 12 agreement between AEP and the various intervenors in that case. The settlement was 13 approved by the PUCT on July 7, 2000. In Arkansas, SWEPCO filed a business 14 separation plan pursuant to the Arkansas Public Service Commission (APSC) 15 Affiliate Rules. That plan (APSC Docket No. 00-249-U) is pending before the APSC 16 at this time. 17 Q. PLEASE DISCUSS THE ARKANSAS RESTRUCTURING REQUIREMENTS 18 THAT IMPACT SWEPCO. 19 A. The State of Arkansas originally ordered retail customer choice to be implemented on 20 January 1, 2002. However, that date has been delayed at least until October 1, 2003, 21 with the possibility of further delays until October 1, 2005, based on APSC 22 determinations as to market readiness and quantifiable benefits to customers.
DOCKET NOS. U-21453, U -20925, J. CRAIG BAKER U-22092 (SUBDOCKET C) DIRECT TESTIMONY 14 1 Arkansas restructuring statutes require utilities to functionally separate the energy 2 delivery and generation businesses, but do not require separation of the energy 3 delivery, generation, and retail businesses into separate companies. In Arkansas, Ark. 4 Code Ann. ss. 23-19-205 (b) and (c) require that: 5 (b) Each electric utility shall functionally unbundle its business 6 activities from one another as follows: 7 (1) Generation facilities, operations, services, and rates; 8 (2) Transmission facilities, operations, services, and rates; 9 and 10 (3) Distribution and customer services facilities, operations, 11 services, and rates. 12 (c) An electric utility shall accomplish this functional separation 13 through creation of separate divisions or departments, 14 nonaffiliated companies, separate affiliated companies owned 15 by a common holding company, or through a sale of assets to a 16 third party. 17 In addition, APSC Affiliate Rule 3.01.A. provides that "[a]t a minimum, each electric 18 utility shall functionally unbundle its business activities as required by Ark. Code 19 Ann. ss. ss. 23-19-205 (b) and (c)." 20 Q. WHICH PROVISION OF THE TEXAS RESTRUCTURING STATUTE 21 REQUIRES SOME CHANGE IN THE STRUCTURE OF SWEPCO? 22 A. SB7 requires that any company that owns generation in the state may not own 23 transmission and distribution plant located in the state. Specifically, Section 24 39.051 (b) of the Texas Public Utility Regulatory Act (PURA) states: 25 (b) "Not later than January 1, 2002, each electric utility shall separate its business 26 activities from one another into the following units: 27 (1) a power generation company; 28 (2) a retail electric provider; and 29 (3) a transmission and distribution utility."
DOCKET NOS. U-21453, U -20925, J. CRAIG BAKER U-22092 (SUBDOCKET C) DIRECT TESTIMONY 15 14 Q. DO LOUISIANA RETAIL CUSTOMERS RECEIVE SERVICE FROM SWEPCO 15 GENERATORS THAT ARE LOCATED IN TEXAS? 16 A. Yes. SWEPCO Louisiana customers receive service from SWEPCO generation 17 assets that are located in Louisiana, Arkansas, and Texas. The generation assets are 18 dispatched in a least-cost manner, along with resources from affiliated companies and 19 the outside market, in order to achieve lowest reasonable cost for customers. 20 Q. DOES SWEPCO's PLAN MEET THE STRUCTURAL SEPARATION 21 REQUIREMENTS OF THE TEXAS STATUTE WITH MINIMAL STRUCTURAL 22 CHANGE TO THE ASSETS UTILIZED TO SERVE LOUISIANA CUSTOMERS? 23 A. Yes. Since only the Texas T&D and related GP assets of SWEPCO are to be 24 separated, the SWEPCO assigned capacity under the UPSA will come from the same 25 SWEPCO generation asset mix and will be available to meet the needs of Louisiana 26 customers. As discussed later in this testimony, the SWEPCO UPSA assigns rights to 27 the capacity in SWEPCO's generating units between SWEPCO's regulated operations
DOCKET NOS. U-21453, U -20925, J. CRAIG BAKER U-22092 (SUBDOCKET C) DIRECT TESTIMONY 16 1 and PMA unregulated operations. However, SWEPCO will continue to own, operate, 2 and maintain its power plants and its assigned capacity will continue to be dispatched 3 by AEPSC, which has performed this function since the merger of Central and South 4 West Corporation (CSW) with AEP. Further, although ownership of SWEPCO's 5 Texas transmission assets will change, use of those assets for Louisiana jurisdictional 6 customers will not change. 7 Currently, SWEPCO takes transmission service under the AEP Open Access 8 Transmission Tariff (AEP OATT) under a pricing zone which includes all AEP 9 transmission assets in the SPP and Electric Reliability Council of Texas (ERCOT). 10 Due to the changes required by Texas legislation and their effects on the AEP West 11 Operating Agreement, AEP anticipates filing changes to die AEP OATT that provide 12 for separate pricing zones for the SPP and ERCOT regions to be effective on January 13 1, 2002. Even though the SWEPCO transmission assets currently being utilized to 14 provide transmission service will not be changed, it is anticipated that SWEPCO's 15 future transmission costs will reflect the average cost of the AEP SPP transmission 16 system rather than the average costs of the AEP SPP and ERCOT transmission 17 systems. Louisiana customers will still be served by the same mix of SWEPCO 18 generation, transmission, and distribution assets that are utilized today. Most 19 importantly, the rate commitments currently in effect for SWEPCO limit the ability of 20 SWEPCO to request non-fuel rate changes for a significant period of time.
DOCKET NOS. U-21453, U -20925, J. CRAIG BAKER U-22092 (SUBDOCKET C) DIRECT TESTIMONY 17 1 VI. FERC RTO ISSUES IN RESTRUCTURING 2 Q. PLEASE DISCUSS THE FERC'S REJECTION OF THE SPP RTO. 3 A. On April 27, 2001, as supplemented on May 29, 2001, SWEPCO, WTU (for its 4 Northern Region, which is located in the SPP), and Public Service Company of 5 Oklahoma (PSO) (collectively, the AEP SPP Operating Companies) filed an 6 application with FERC to transfer operational control of their transmission facilities 7 located in the SPP to the SPP RTO. By order issued July 12, 2001 (Docket Nos. 8 RT01-34-000, et al.), FERC rejected the application as premature because it found 9 that the proposed SPP RTO did not meet the scope and configuration requirements of 10 Order No. 2000. The AEP SPP Operating Companies are currently participating in 11 the mediation (involving several entities for the purpose of forming a RTO in the 12 southeastern United States) being conducted under FERC auspices, and support the 13 participation of the SPP transmission owners in a large RTO that will meet the scope 14 requirements of Order No. 2000. 15 Q. HOW DOES THE FERC'S REJECTION Of THE SPP RTO AFFECT SWEPCO'S 16 PATH TO COMPETITION IN TEXAS? 17 A. On August 3, 2001, the PUCT Staff petitioned the PUCT to determine whether 18 market institutions and participants are ready for retail competition to begin within 19 SWEPCO's Texas jurisdiction, which is located in the SPP. There are two sets of 20 contingencies related to retail restructuring under the Texas PURA. 21 First, if the PUCT has not certified the "power region" in which SWEPCO is 22 located as a "qualifying power region" (QPR) at the time that retail customer choice
DOCKET NOS. U-21453, U -20925, J. CRAIG BAKER U-22092 (SUBDOCKET C) DIRECT TESTIMONY 18 1 begins, the SWEPCO REP will have a continuing Obligation to serve certain large 2 customers (1 MW or more) at rates that are no higher than the rates that, on a bundled 3 basis, were in effect on January 1, 1999, subject to certain adjustments provided for in 4 Section 39.202(m) of PURA. At this time, the PUCT has not yet certified 5 SWEPCO's power region as a "qualifying power region" under the Texas statute. 6 Second, if the PUCT determines that a power region is unable to offer fair 7 competition and reliable service to all retail customer classes on January 1, 2002, the 8 PUCT is to delay customer choice for the power region, in which case SWEPCO 9 would continue to have a public utility obligation to serve Texas retail customers at 10 cost-based rates. The PUCT Staff's August 3 petition also requests the PUCT to 11 suspend further activity on SWEPCO's required capacity auction until the PUCT 12 issues a final order in that proceeding. The Staff requests that the PUCT issue that 13 final order before November 1, 2001. 14 Q. WILL THIS DETERMINATION AFFECT SWEPCO's PROPOSED BUSINESS 15 SEPARATION? 16 A. No, it should not. On August 23, the PUCT voted not to delay SWEPCO's required 17 capacity auction in Texas at this time. Further, the PUCT directed its staff to develop 18 a list of required milestones necessary to achieve retail competition by January 1, 19 2002. The PUCT also stated that the absolute last resort should be a decision to delay 20 competition. As such, the LPSC's approval of the required T&D transfers should 21 proceed.
DOCKET NOS. U-21453, U -20925, J. CRAIG BAKER U-22092 (SUBDOCKET C) DIRECT TESTIMONY 19 1 Q. DOES THE REJECTION Of THE SPP RTO AFFECT THE STATUS OF THE 2 SWEPCO BSP FILING IN ARKANSAS? 3 A. No. On August 8, 2000, SWEPCO filed its business separation plan in Arkansas to 4 accomplish the required functional unbundling in APSC Docket No. 00-249-U. At 5 the present time, there have been no interventions and no APSC action. However, in 6 Arkansas Docket No. 00-010-U, the Show Cause Order relating to SWEPCO's 7 request to transfer operational control of certain SWEPCO transmission facilities to 8 the SPP RTO, due to FERC's rejection of the SPP RTO and the mandated mediation, 9 the APSC has suspended all activities in the docket, until such time as the direction of 10 a southeastern RTO is more clear. 11 Ark. Code Ann. ss. 23-19-107(a) requires the APSC to periodically report to the 12 Arkansas General Assembly on the progress of the development of competition in 13 electric markets and the impact, if any, of competition and industry restructuring on 14 retail customers in Arkansas. The APSC is to make the second such report before 15 January 15, 2002. The APSC, through Docket No. 00-190-U, will gather information 16 from electric utilities and the APSC General Staff to be used in its report to the 17 General Assembly. The issues pertaining to the FERC's SPP RTO order and its 18 effect on Arkansas' market readiness will be addressed in this docket. Initial filings 19 in this docket are due September 4, 2001.
DOCKET NOS. U-21453, U -20925, J. CRAIG BAKER U-22092 (SUBDOCKET C) DIRECT TESTIMONY 20 1 VII. SWEPCO BSP EFFECT ON COST STRUCTURE 2 Q. WHAT RATE COMMITMENTS HAS SWEPCO MADE THAT WILL PROTECT 3 LOUISIANA CUSTOMERS? 4 A. In the settlement related to the AEP-CSW merger, SWEPCO agreed to not seek an 5 increase in non-fuel rates prior to January 1, 2005, subject to certain force majeure 6 conditions and riders for the impact of purchased power costs. These restrictions will 7 significantly impact the ability of SWEPCO to request recovery of any additional cost 8 increases, and will provide customers a predictable path for SWEPCO future rates. 9 Q. WILL THE COST STRUCTURE OF SWEPCO LOUISIANA CUSTOMERS 10 CHANGE MATERIALLY AS A RESULT OF THE TEXAS T&D SEPARATION? 11 A. No. The cost structure for SWEPCO Louisiana retail customers is not expected to 12 change materially. In addition, SWEPCO witnesses Ms. Wendy Hargus, Mr. Chris 13 Potter and Mr. John Aaron will file testimony discussing the changes in more detail. 14 Q. WHAT CHANGES ARE EXPECTED IN THE COST STRUCTURE OF THE 15 PRODUCTION FUNCTION? 16 A. The changes in the costs of SWEPCO's production function should not be material, 17 because SWEPCO will continue to own the same production assets that it owns 18 today. The output of SWEPCO's generating capacity that is currently used to serve 19 existing wholesale and Texas retail customers will be sold to PMA pursuant to the 20 UPSA and sold back in part to SWEPCO under the SECOND UPSA. As will be 21 discussed by Mr. Potter in his testimony, the sale of the generation on this basis is 22 essentially equivalent to the jurisdictional allocation (4 Coincident Peak method) used
DOCKET NOS. U-21453, U -20925, J. CRAIG BAKER U-22092 (SUBDOCKET C) DIRECT TESTIMONY 21 1 in SWEPCO's last Louisiana retail rate case to allocate production costs among 2 SWEPCO's jurisdictions. Therefore, there should not be a material change in 3 production costs allocated to the Louisiana jurisdiction as a result of the UPSA. 4 As shown in the FERC filing, the changes related to the AEP West Operating 5 Agreement and the AEP SIA result in cost impacts that are DE MINIMIS for 6 SWEPCO's native load customers. An except from Attachment 12 from the July 24, 7 2001 FERC filing in Docket No. ER01-2668-000, which provides a comparison of 8 the AEP West Operating Companies moving from the existing four-company to a 9 two-company operating agreement, is included as EXHIBIT JCB-2. It should be 10 noted that the UPSA, SECOND UPSA, AEP SIA and AEP West Operating 11 Agreement replace the versions that were filed on June 29, 2001 with the LPSC. 12 Q. WHAT CHANGES ARE EXPECTED IN THE COST STRUCTURE OF THE 13 TRANSMISSION FUNCTION AS A RESULT OF THE TRANSFER OF THE 14 TEXAS TRANSMISSION ASSETS? 15 A. The changes in the costs of transmission service to SWEPCO Louisiana customers 16 should not be material, since they will be served from the same SWEPCO 17 transmission assets that serve those customers today. The Louisiana retail customers 18 will be charged rates based upon taking transmission service under a tariff that 19 reflects all transmission assets currently owned by SWEPCO, as well as the 20 transmission assets owned by other AEP subsidiaries in the SPP. The transmission 21 asset base of AEP in SPP will not change due to the transfer of SWEPCO's Texas 22 assets,
DOCKET NOS. U-21453, U -20925, J. CRAIG BAKER U-22092 (SUBDOCKET C) DIRECT TESTIMONY 22 1 After the transfer of Texas T&D assets from SWEPCO to the SWEPCO 2 TEXAS EDC, the SPP transmission system will still be operated as an integrated 3 system. In other words, even though the SWEPCO TEXAS EDC will own the 4 transmission assets physically located in Texas, SWEPCO will still require use of the 5 entire SPP transmission system (including those Texas assets) to serve customers in 6 Louisiana. 7 Q. WHAT CHANGES ARE EXPECTED IN THE COST STRUCTURE OF THE 8 DISTRIBUTION FUNCTION? 9 A. The changes in the costs of distribution service to SWEPCO Louisiana customers 10 should not be material, because the Louisiana distribution assets will continue to be 11 owned by SWEPCO, and will continue to be assigned to Louisiana customers. There 12 may be some minor allocation factor differences for O&M and common costs, which 13 will be addressed in the testimony of Mr. Potter. However, these differences are not 14 expected to produce any material cost changes. 15 Q. WHAT COST CHANGES ARE EXPECTED IN THE COST LEVELS FOR 16 ADMINISTRATIVE AND GENERAL MANAGEMENT EXPENSE? 17 A. The changes in the costs of administrative and general management expense for 18 SWEPCO Louisiana customers should not be material. SWEPCO is already managed 19 as part of a multi-state holding company system. The addition of more companies to 20 the eleven utilities already utilized for assignment of administrative costs should not 21 cause any material additional costs to be incurred. Mr. Aaron will address these 22 issues in more detail.
DOCKET NOS. U-21453, U -20925, J. CRAIG BAKER U-22092 (SUBDOCKET C) DIRECT TESTIMONY 23 1 Q. WHAT COST CHANCES ARE EXPECTED IN THE COST OF CAPITAL FOR 2 SWEPCO? 3 A. No material changes are expected to the capital costs of SWEPCO, because 4 SWEPCO's debt to be retired as a result of the removal of Texas T&D and related 5 GP assets is a relatively small part of SWEPCO's total outstanding debt. The capital 6 structure policy of SWEPCO is not expected to change materially as a result of the 7 separation of the Texas transmission and distribution assets. The effects of separation 8 on the cost of debt will be discussed in the testimony of Ms. Hargus. 9 Q. IN SUMMARY, DOES THIS PLAN CREATE ANY MATERIAL CHANGES IN 10 THE COST STRUCTURE OR ASSET MIX OF SWEPCO? 11 A. No. After separation of the Texas transmission and distribution assets, SWEPCO 12 Louisiana customers will still receive utility service from the same workforce using 13 the same physical assets and capital structure policy. Because the plan minimizes the 14 structural changes required to comply with Texas law, it produces a minimum of 15 possible cost changes for SWEPCO. Since compliance with Texas statutes will 16 minimize the potential for further litigation for SWEPCO, the plan is in the public 17 interest, and should be approved. 18 19 VIII. FERC FILINGS CONCERNING SWEPCO'S BSP 20 Q. PLEASE GENERALLY DESCRIBE AEP'S RECENT FERC FILINGS. 21 A. On July 24, 2001, AEP filed its Application of American Electric Power Service 22 Corporation for Authorization to Transfer Jurisdictional Assets (Docket: No. EC01-
DOCKET NOS. U-21453, U -20925, J. CRAIG BAKER U-22092 (SUBDOCKET C) DIRECT TESTIMONY 24 1 130-000) and Application of American Electric Power Company, Inc. for Approval of 2 Rate Schedules Related to Corporate Restucturing (Docket No. ER01-2668-000) at 3 the FERC. The applications request the approval of asset transfers and rate schedule 4 changes related to AEP's corporate restructuring that are required for AEP to comply 5 with the restructuring laws of Ohio and Texas and to foster the development of 6 competitive electric markets consistent with such state laws. In addition to 7 authorization to transfer SWEPCO's Texas T&D assets to the SWEPCO TEXAS 8 EDC, AEP seeks approval of the following agreements related to the SWEPCO BSP 9 AEP West Operating Agreement, AEP SIA, UPSA and the SECOND UPSA. 10 Q. PLEASE DESCRIBE THE CHANGES TO THE AEP WEST OPERATING 11 AGREEMENT. 12 A. The primary change in the Restated and Amended Operating Agreement for the AEP 13 West Operating Companies is the withdrawal of those companies that are undergoing 14 restructuring and corporate separation of their generation functions - WTU, CPL, and 15 the portion of SWEPCO's generation attributable to its Texas retail load. The Texas 16 companies will no longer have native load obligations. If they were to continue to 17 participate in the arrangement, the other participants would have first call on all of 18 their generation, defeating the purposes of deregulation in Texas and imposing 19 excessive burdens on Texas consumers. To The extent that the most economic 20 deregulated generation is burdened with obligations under the Operating Agreement, 21 the intent of the Texas restructuring legislation may be frustrated. Finally, the call on 22 Texas generation under the existing Operating Agreement would impede and distort
DOCKET NOS. U-21453, U -20925, J. CRAIG BAKER U-22092 (SUBDOCKET C) DIRECT TESTIMONY 25 1 the efforts of the deregulated companies to recover stranded costs, as permitted by the 2 Texas restructuring legislation. 3 The Restated and Amended Operating Agreement makes several other 4 substantive changes going forward. First, the provisions for joint planning of future 5 generation capacity and provisions for capacity sharing among the participating 6 companies are being modified so that the planning function recognizes and takes 7 account of possible restructuring in any of the three remaining jurisdictions 8 (Louisiana, Oklahoma and Arkansas). Oklahoma, served by PSO, has enacted 9 legislation to plan for deregulation but has so far not implemented any plan. 10 Arkansas has enacted deregulation but has deferred the effective date. Louisiana 11 continues to consider a transition to competition plan that would permit retail access 12 for certain large customers as soon as January 1, 2003. Planning of future capacity 13 additions must take account of the likelihood that deregulation will proceed - or 14 not - on a state-by-state basis, and not system-wide. 15 Second, energy purchases from other members continue to be priced at the 16 midpoint between the seller's incremental cost and the purchaser's decremental cost. 17 These provisions, which are in the existing AEP West Operating Agreement, 18 correctly reflect the economic costs of the options available to a member, while 19 permitting the use of the most economic energy by the member companies. 20 Third, the hourly net margins for off-system energy sales will continue to be 21 shared in proportion to each member's generation for sales, but that generation will
DOCKET NOS. U-21453, U -20925, J. CRAIG BAKER U-22092 (SUBDOCKET C) DIRECT TESTIMONY 26 1 now include economy sales. Economy purchases from other members will continue 2 to be subtracted from the allocation, with the result not less than zero. 3 AEP's cost studies show that PSO and SWEPCO can effectively operate a 4 "two-company system," incorporating the changes described above as well as the 5 changes in the SIA described below, without material adverse economic impact on 6 their native load customers. The overall effects on SWEPCO for years 2002-2004 are 7 DE MINIMIS. An except from Attachment 12 from the July 24, 2001 FERC filing in 8 Docket No. ER01-2668-000, which provides a comparison of the AEP West 9 Operating Companies moving from the existing four-company to a two-company 10 operating agreement, is included as EXHIBIT JCB-2. There are small cost reductions 11 for PSO; SWEPCO shows a small cost increase in the initial years, moving to a small 12 decrease by 2004. 13 Q. PLEASE DESCRIBE THE CHANGES TO THE AEP SIA. 14 A. The primary change in the Restated and Amended AEP SIA is the withdrawal of the 15 deregulated companies - OPCo, CSP, CPL, and WTU. For the same reasons 16 discussed previously, it no longer is appropriate in the inter-zone arrangements for the 17 deregulated companies to integrate and coordinate their power supply resources with 18 the regulated Operating Companies. The deregulated generation companies and the 19 remaining Operating Companies have disparate goals; having them continue to 20 coordinate and integrate their power supplies would cause inappropriate cost-shifting 21 and impede competition.
DOCKET NOS. U-21453, U -20925, J. CRAIG BAKER U-22092 (SUBDOCKET C) DIRECT TESTIMONY 27 1 The other principal change in the Restated and Amended AEP SIA is that non- 2 physical trading and marketing will not be part of the coordinated activities of the 3 parties. The AEP SIA, however, will continue to provide for centralization of off- 4 system purchases and off-system sales. This is consistent with AEP's overall 5 objective of charging the regulated merchant organization with minimizing the cost of 6 power through off-system sales and purchases. 7 In addition, the Restated and Amended AEP SIA provides that off-system 8 sales margins will be shared in proportion to owned generating capacity in the two 9 zones. This change will eliminate the historic threshold for the sharing of benefits 10 between the West and East Zones. In light of the departure of the Ohio and Texas 11 Operating Companies from the AEP SIA (as well as from their respective system 12 agreements), elimination of the previous threshold provides a better mechanism for 13 the sharing of benefits between the AEP East and West Zones. 14 Q. PLEASE DESCRIBE THE SWEPCO UPSA. 15 A. In order to comply with the Texas requirement to separate the generation function 16 from transmission and distribution functions, SWEPCO proposes to enter into a 17 SWEPCO UPSA with PMA and AEPSC. Effective January 1, 2002, SWEPCO will 18 separate its existing generation capacity into SWEPCO-assigned capacity 19 (representing that portion of SWEPCO's generation attributable to the continued 20 regulated requirements of Louisiana and Arkansas retail customers) and PMA- 21 assigned capacity (representing that portion of SWEPCO's generation attributable to 22 its current Texas retail native load and its wholesale requirements load). Under Texas
DOCKET NOS. U-21453, U -20925, J. CRAIG BAKER U-22092 (SUBDOCKET C) DIRECT TESTIMONY 28 1 law, the former capacity must be operated in the wholesale market on a deregulated 2 basis and may not be sold directly to Texas retail customers. The assignment of 3 capacity to PMA will be based on the ratio of the sum of the demands of the 4 SWEPCO-Texas retail native load and the SWEPCO wholesale contract native load 5 at the time of the four Year 2000 coincident monthly summer (June through 6 September) SWEPCO peak demands to the sum of the same four coincident peak 7 demands of the total SWEPCO native load. 8 This approach proportionally assigns rights to the capacity in SWEPCO's 9 generating units between SWEPCO's deregulated and regulated operations and 10 thereby facilitates the onset of competition in Texas and at the same time reasonably 11 maintains the status quo for the states that have not enacted restructuring statutes. 12 SWEPCO will continue to own, operate, and maintain its power plants and its 13 assigned capacity will continue to be dispatched by AEPSC, which has performed this 14 function since the merger of CSW with AEP. 15 Q. PLEASE DESCRIBE THE SECOND UPSA. 16 A. The SECOND UPSA (among PMA, SWEPCO, and AEPSC) provides SWEPCO 17 with access to a proportionate share of the assigned capacity received by PMA under 18 the SWEPCO UPSA so that SWEPCO can continue supplying its existing wholesale 19 contract customers for the remaining terms of their respective contracts. The 20 proportion of PMA's assigned capacity to be assigned to SWEPCO under the 21 SECOND UPSA will be based on the ratio of the sum of the four coincident peak 22 demands of native load for each wholesale contract to the sum of the same four
DOCKET NOS. U-21453, U -20925, J. CRAIG BAKER U-22092 (SUBDOCKET C) DIRECT TESTIMONY 29 1 coincident peaks demands of the total SWEPCO native load. Because SWEPCO's 2 wholesale contracts expire or may terminate at different times, the proportion of 3 PMA's assigned capacity that is assigned to SWEPCO under the SECOND UPSA 4 will change as each wholesale contract expires or is terminated. A portion of the 5 monthly costs that SWEPCO charges to PMA will be netted out based on the share of 6 capacity that is assigned to SWEPCO during that month and the energy dispatched 7 from SWEPCO out of the capacity assigned under the SECOND UPSA. 8 Q. PREVIOUSLY, YOU ADDRESSED TWO SETS OF REGULATORY 9 CONTINGENCIES RELATED TO RETAIL RESTRUCTURING IN SWEPCO'S 10 TEXAS SERVICE TERRITORY. DO THE UPSAS ADDRESS THOSE 11 CONTINGENCIES? 12 A. Yes. To address the contingencies discussed previously, the SECOND UPSA 13 provides that PMA will assign back to SWEPCO a proportionate share of the 14 assigned capacity it receives under the SWEPCO UPSA so that SWEPCO can furnish 15 part of the resources needed for the SWEPCO REP to fulfill the obligations imposed 16 under Section 39.202(m) of PURA, or if the PUCT delays retail customer choice in 17 SWEPCO's territory, that PMA will assign back to SWEPCO a proportionate share of 18 the assigned capacity it receives under the SWEPCO UPSA so that SWEPCO can 19 continue to furnish regulated electric service. As in the case of the wholesale 20 contracts, to the extent that the statutory obligations are reduced or eliminated, the 21 assignment back from PMA to SWEPCO will decrease by a corresponding 22 percentage.
DOCKET NOS. U-21453, U -20925, J. CRAIG BAKER U-22092 (SUBDOCKET C) DIRECT TESTIMONY 30 1 IX. OTHER REGULATORY APPROVALS 2 Q. IS THIS FILING THE ONLY FILING BEFORE ANY REGULATORY 3 AUTHORITY WHICH WOULD BE REQUIRED TO IMPLEMENT THE SWEPCO 4 BSP? 5 A. No. Implementation of the SWEPCO BSP requires a number of regulatory filings 6 before several other jurisdictions which have the authority to approve or disapprove 7 the necessary structural changes and/or transfers of assets. 8 At the SEC, an application for approval to create the new entities, retire 9 securities and issue new refinancing securities, transfer assets into the new entities, 10 and for certain affiliate transactions has been filed. The SEC has jurisdiction over 11 these transactions pursuant to the Public Utility Holding Company Act of 1935. 12 As discussed previously, applications were filed at FERC on July 24, 2001 for 13 approval of (1) the transfer of the T&D facilities to the energy delivery subsidiaries, 14 (2) transfer of generation assets to newly created legal entities owned by the Domestic 15 Genco, (4) UPSA and Second UPSA, and (5) modifications to the AEP West 16 Operating Agreement and AEP SIA to recognize the changing relationships between 17 deregulated generation business units and regulated generation divisions of utilities. 18 Approvals of the following will also be filed at the FERC: (1) revised open 19 access transmission tariff reflecting the new energy delivery subsidiaries and the 20 anticipated zonal pricing for the SPP and ERCOT transmission systems, (2) network 21 transmission agreements and network operating agreements for the Domestic Genco 22 and/or its generation subsidiaries to take transmission service from the transmission
DOCKET NOS. U-21453, U -20925, J. CRAIG BAKER U-22092 (SUBDOCKET C) DIRECT TESTIMONY 31 1 subsidiaries, (3) service agreements between the SWEPCO REP and the energy 2 delivery and/or generation subsidiaries, (4) interconnection agreements between the 3 generation entities and the energy delivery subsidiaries, and (5) modifications to the 4 CSW Transmission Coordination Agreement and AEP System Transmission 5 Integration Agreement to delegate to the energy delivery company the responsibility 6 and authority to act as the transmission provider as agent for and on behalf of the 7 transmission subsidiaries. 8 9 X. CONCLUSION 10 Q. WILL THE PROPOSED SWEPCO BSP ADVERSELY AFFECT THE CURRENT 11 PROVISION OF BUNDLED SERVICE FOR THE RETAIL RATEPAYERS OF 12 LOUISIANA? 13 A. No. Because SWEPCO's current operations in Louisiana will remain substantially 14 unchanged, retail ratepayers in Louisiana will continue to enjoy the same level of 15 service and low rates that SWEPCO has provided in the past. 16 Q. PLEASE SUMMARIZE THE RELIEF REQUESTED BY THE COMPANY IN 17 THIS FILING. 18 A. SWEPCO is requesting the Commission to approve the proposed asset transfers 19 necessary to fulfill the requirements of the industry restructuring in Texas as 20 described in the SWEPCO BSP. Because the SWEPCO Texas transmission assets are 21 utilized to provide utility service to Louisiana retail customers and are partially
DOCKET NOS. U-21453, U -20925, J. CRAIG BAKER U-22092 (SUBDOCKET C) DIRECT TESTIMONY 32 1 included in their rate base, approval from the LPSC will be required before the 2 requested assets can be transferred out of SWEPCO. 3 Q. PLEASE SUMMARIZE YOUR TESTIMONY. 4 A. The SWEPCO BSP separates the wires, generation, and retail businesses in order to 5 achieve compliance with the restructuring activities in Texas. It is anticipated that the 6 Louisiana retail rates will not be materially affected by the restructuring activities in 7 Texas. In addition, operations in Louisiana will not be affected by the restructuring 8 activities in Texas. 9 Q. DOES THIS CONCLUDE YOUR DIRECT TESTIMONY? 10 A. Yes, it does.
DOCKET NOS. U-21453, U -20925, J. CRAIG BAKER U-22092 (SUBDOCKET C) DIRECT TESTIMONY 33 SOUTHWESTERN ELECTRIC POWER COMPANY Exhibit WGH-1 WEIGHTED COST OF CAPITAL Page 1 of 5 December 31, 2000 BEFORE ASSET TRANSFER
--------------------------------------------------------------------------------------------------------------------------------- (A) (B) (C) (D) (E) (F) -------------------------------------------------------------------------------------------------------------------------- Percent of Cost of Weighted Page Amount Total Capital Average Line Description Reference Per Books Capitalization Rate Cost of Capital --------------------------------------------------------------------------------------------------------------------------------- 1 Long-Term Debt WGH-1, p. 4 $722,437,699 51.54% 7.93% 4.09% 2 Preferred Stock WGH-1, p. 2 $2,697,319 0.19% 12.83% 0.02% 3 Common Stock Equity na $676,655,920 48.27% 11.10% 5.36% -------------------- -------------------- -------------------- 4 $1,401,790,938 100.00% 9.47% ==================== ==================== ==================== ---------------------------------------------------------------------------------------------------------------------------------
SOUTHWESTERN ELECTRIC POWER COMPANY Exhibit WGH-1 WEIGHTED COST OF PREFERRED STOCK Page 2 of 5 December 31, 2000 -------------------------------------------------------------------------------- (A) (B) (C) (D) (E) (F) -------------------------------------------------------------------------------- Mandatory Premium Series Dividend Redemption Par Value or Date Rate (Y/N) at Issuance (Discount) -------------------------------------------------------------------------------- NOT SUBJECT TO MANDATORY REDEMPTION 5.00% 2/12/40 5.00% N $7,500,000 4.65% 6/19/49 4.65% N $2,500,000 8,250 4.28% 6/9/55 4.28% N $6,000,000 24,300 ---------------- Sub-Totals $16,000,000 SUBJECT TO MANDATORY REDEMPTION 6.95% 4/1/87 6.95% 4/1/18 $40,000,000 $0 ---------------- Sub-Totals $40,000,000 -------------------------------------------------------------------------------- TOTAL $56,000,000 -------------------------------------------------------------------------------- LOSS ON REDEEMED STOCK A. Annual Requirement = Preferred Stock Balance x Weighted Cost of Preferred Stock B. Adjusted Annual Requirement = Annual Requirement + Amortization of Loss on Redeemed Stock (S. Kerry monthly amortization schedule less gain on reacquired preferred stock (monthly a/c 1860.1213-.1220)) C. Adjusted Preferred Stock Balance = Preferred Stock Balance - Unamortized Loss on Redeemed Stock D. Adjusted Cost of Preferred Stock = Adjusted Annual Requirement / Adjusted Preferred Stock Balance -------------------------------------------------------------------------------- NOTES * Redeemed subsequent to the end of the test-year. See Adjustment 1. --------------------------------------------------------------------------------
---------------------------------------------------------------------------------------------------------------------------- (G) (H) (I) (J) (S, p.2) (K) (L) (M) ---------------------------------------------------------------------------------------------------------------------------- Under- Gain Net Book Value Issue Writing (Loss) on Net Proceeds Including as % Weighted Fees and Redeemed Proceeds as % Scheduled Total Cost of Average Issuance Exp. Stock at Issuance of Par Redemptions Book Value Money Cost ---------------------------------------------------------------------------------------------------------------------------- 7,500,000 100.00% $3,771,500 80.17% 5.000% 4.008% 2,508,250 100.33% $191,330 4.07% 4.635% 0.188% 6,024,300 100.41% $741,591 15.76% 4.263% 0.672% --------------- Sub-Totals $4,704,421 $342,315 $0 39,657,685 99.14% $0 0.00% 7.018% 0.000% --------------- Sub-Totals $0 ---------------------------------------------------------------------------------------------------------------------------- TOTAL $4,704,421 100.00% 4.869% ---------------------------------------------------------------------------------------------------------------------------- Preferred Stock Balance $4,704,421 x Weighted Cost of Preferred 4.87% --------------- = Annual Requirement $229,055 Annual Requirement $229,055 + Amortization of Loss/(Gain) on Redeemed Stock $117,132 --------------- = Adjusted Annual Requirement $346,187 Preferred Stock Balance $4,704,421 - Unamortized Loss/(Gain) on Redeemed Stock $2,007,102 --------------- = Adjusted Preferred Stock Balance $2,697,319 Adjusted Annual Requirement $346,187 / Adjusted Preferred Stock Balance $2,697,319 --------------- = Adjusted Cost of Preferred 12.830% --------------- -------------------------------------------------------------------------------- Note 1. Previously redeemed preferred. Series 6.95% Amortization schedule provided by S.Kerry $84,227 Series 8.16% " " " $685,376 Series 8.84% " " " $501,551 Series 9.72% " " " $1,593,507 Series 4.28% Gain on reacq'd Pref St - a/c1860.1214 ($1,189,073) Series 4.65% Gain on reacq'd Pref St - a/c1860.1216 ($433,769) Series 5.00% Gain on reacq'd Pref St - a/c 1860.1218 ($625,402) Series6.95% Gain(loss) on reacq'd Pref St - a/c 1860.1220 $1,390,685 --------------- $2,007,102 --------------------------------------------------------------------------------
Exhibit WGH-1 Page 3 of 5
-------------------------------------------------------------------------------------------------------------------------- (A,p.1) (N) (O) (P) (Q) (R) (S) -------------------------------------------------------------------------------------------------------------------------- Par Value Book Value Excluding Unamortized Unamortized Unamortized Including Par Value Scheduled Premium or Issuance Gain (Loss) on Scheduled Series Outstanding Redemptions (Discount) Expense Redeemed Stock Redemptions -------------------------------------------------------------------------------------------------------------------------- NOT SUBJECT TO MANDATORY REDEMPTION 5.00% $3,771,500 $3,771,500 $3,771,500 4.65% $190,700 $190,700 630 $191,330 4.28% $738,600 $738,600 $2,991 $0 $0 $741,591 ------------------------------ -------------------- Sub-Totals $4,700,800 $4,700,800 $4,704,421 SUBJECT TO MANDATORY REDEMPTION 6.95% $0 $0 $0 $0 ------------------------------ Sub-Totals $0 $0 $0 -------------------------------------------------------------------------------------------------------------------------- TOTAL $4,700,800 $4,700,800 BALANCE OF PREFERRED STOCK $4,704,421 -------------------------------------------------------------------------------------------------------------------------- NOTES (O) Scheduled redemptions to be excluded reflect those amounts to be redeemed prior to the anticipated effective date for the rates being requested. (P), (Q), and (R) Consistent with the Federal Energy Regulatory Commission's Uniform System of Accounts Order 390, SWEPCO records its preferred stock issuances net of any issuance expenses, premiums, or discounts. Gains or losses on preferred stock redemptions are not amortized. The entire gain or loss is immediately recognized as an adjustment to retained earnings. For rate making purposes these are recovered through amortization in rates. (Q) Unamortized balance of underwriter fees should also be provided here. (S) = (N) + (P) - (Q) + (R) --------------------------------------------------------------------------------------------------------------------------
SOUTHWESTERN ELECTRIC POWER COMPANY Exhibit WGH-1 WEIGHTED COST OF DEBT Page 4 of 5 December 31, 2000
------------------------------------------------------------------------------------------------------------------------------------ (A) (B) (C) (D) (E) (F) (G) (H) (I) (J) (K) (T, p.2) ------------------------------------------------------------------------------------------------------------------------------------ Under- Gain Writing (Loss) Net Book Value Sinking Principal Premium Fees and on Reac- Net Proceeds Including Series Issuance Maturity Interest Fund Amount or Issuance quired Proceeds as % Scheduled Date Date Rate (Y/N) at Issuance (Discount) Exp. Debt at Issuance of Par Maturities ------------------------------------------------------------------------------------------------------------------------------------ FIRST MORTGAGE BONDS A 11/1/76 11/1/06 6.200% N 7,100,000 (118,925) 177,704 0 6,803,371 95.82% 5,738,896 B 11/1/76 11/1/06 6.200% N 1,000,000 (16,750) 25,028 0 958,222 95.82% 991,827 V 6/1/92 6/1/04 7.750% N 40,000,000 (270,000) 152,214 0 39,577,786 98.94% 39,874,716 W 9/1/92 9/1/99 6.125% N 40,000,000 (474,800) 34,619 0 39,490,581 98.73% 0 X 9/1/92 9/1/07 7.000% N 90,000,000 (1,688,400) 77,893 0 88,233,707 98.04% 89,177,023 Y 2/1/93 2/1/03 6.625% N 55,000,000 (573,650) 493,115 0 53,933,235 98.06% 54,863,939 Z 7/1/93 7/1/23 7.250% N 45,000,000 (506,702) 498,787 0 43,994,511 97.77% 44,245,042 AA 10/1/93 4/1/00 5.250% N 45,000,000 (110,250) 308,273 0 44,581,477 99.07% 0 BB 10/1/93 10/1/25 6.875% N 80,000,000 (565,600) 748,041 0 78,686,359 98.36% 78,907,196 ------------ -------------- Sub-Totals 403,100,000 Sub-Totals 313,798,639 TRUST PREFERRED SECURITIES 7.875% 4/30/97 4/30/37 7.875% N 110,000,000 3,768,900 0 106,231,100 96.57% 106,576,385 SENIOR UNSECURED FLOATING RATE NOTES 3/1/00 3/1/02 6.970% N 150,000,000 0 640,237 0 149,359,763 99.57% 149,577,392 POLLUTION CONTROL BONDS 1978A 1/1/78 1/1/08 6.000% 16,200,000 (194,400) 314,650 0 15,690,950 96.86% 13,414,233 1991A 5/3/91 8/1/11 8.200% 17,125,000 0 417,265 0 16,707,735 97.56% 16,906,907 1991B 7/17/91 11/1/04 6.900% 12,290,000 0 363,824 0 11,926,176 97.04% 12,159,381 1992 11/24/92 1/1/19 7.600% 53,500,000 0 1,014,193 0 52,485,807 98.10% 52,797,903 1996 7/11/96 4/1/18 6.100% 81,700,000 (408,500) 1,945,305 0 79,346,195 97.12% 79,833,189 ------------ -------------- Sub-Totals 180,815,000 Sub-Totals 175,111,613 ----------------------------------------------------------------------------------------------------------------------------------- TOTAL $693,915,000 TOTAL $745,064,029 ------------------------------------------------------------------------------------------------------------------------------------ LOSS ON REACQUIRED DEBT NOT ASSOCIATED WITH A SPECIFIC REFUNDING ISSUE A. Annual Requirement = Debt Balance x Weighted Cost of Debt Debt Balance $745,064,029 x Weighted Cost of Debt 7.30% ------------- Annual Requirement $54,389,674 B. Adjusted Annual Requirement = Annual Requirement (see Adjustment 2A) + Amortization of Loss on Reacquired Debt Annual Requirement $54,389,674 ((a/c 189;257;1810.7307;2260.7307)X12) + Amortization of Loss on Reacquired Debt 2,900,340 ------------- = Adjusted Annual Requirement $57,290,014 C. Adjusted Balance = Debt Balance - Unamortized Loss on Reacquired Debt Debt Balance $745,064,029 (a/c 189;257;1810.7307;2260.7307) - Unamortized Loss on Reacquired Debt 22,626,330 ------------- = Adjusted Debt Balance $722,437,699 D. Adjusted Cost of Debt = Adjusted Annual Requirement (see Adjustment 2B) / Adjusted Debt Balance (see Adjustment 2C) = Adjusted Annual Requirement $57,290,014 / Adjusted Debt Balance $722,437,699 ------------- = Adjusted Cost of Debt 7.930% ------------- ------------------------------------------------------------------------------------------------------------------------------------
----------------------------- (L) (M) (N) ----------------------------- Issue as % Weighted of Total Cost of Average Book Value Debt Cost ----------------------------- 0.770% 6.519% 0.050% 0.133% 6.519% 0.010% 5.352% 7.888% 0.420% 0.000% 6.353% 0.000% 11.969% 7.216% 0.860% 7.364% 6.897% 0.510% 5.938% 7.437% 0.440% 0.000% 5.422% 0.000% 10.591% 7.004% 0.740% 14.304% 8.167% 1.170% 20.076% 7.203% 1.450% 1.800% 6.233% 0.110% 2.269% 8.451% 0.190% 1.632% 7.249% 0.120% 7.086% 7.770% 0.550% 10.715% 6.345% 0.680% ----------------------------- 100.000% 7.300% ----------------------------- SOUTHWESTERN ELECTRIC POWER COMPANY Exhibit WGH-1 WEIGHTED COST OF DEBT Page 5 of 5 December 31, 2000
------------------------------------------------------------------------------------------------------- (O) (P) (Q) (R) (S) (T) ------------------------------------------------------------------------------------------------------- Principal 226 181 189/257 Book Value Principal Excluding Unamortized Unamortized Unamortized Including Amount Scheduled Premium or Fees and Gain (Loss) on Scheduled Series Outstanding Maturities (Discount) Expenses Reacquired Debt Maturities ------------------------------------------------------------------------------------------------------- FIRST MORTGAGE BONDS A 5,795,000 5,650,000 (22,422) 33,682 0 5,738,896 B 1,000,000 1,000,000 (3,300) 4,873 0 991,827 V 40,000,000 40,000,000 0 125,284 0 39,874,716 W 0 0 0 0 0 0 X 90,000,000 90,000,000 (453,403) 369,574 0 89,177,023 Y 55,000,000 55,000,000 (21,894) 114,167 0 54,863,939 Z 45,000,000 45,000,000 (379,980) 374,978 0 44,245,042 AA 0 0 0 0 0 BB 80,000,000 80,000,000 (437,449) 655,355 0 78,907,196 0 ------------ ------------- ----------- ---------- ---- ------------- Sub-Totals $316,795,000 $316,650,000 ($1,318,448) $1,677,913 $0 $313,798,639 7.875% 110,000,000 110,000,000 3,423,615 106,576,385 150,000,000 150,000,000 422,608 149,577,392 POLLUTION CONTROL REVENUE BONDS 1978A 13,520,000 13,070,000 (40,417) 65,350 0 13,414,233 1991A 17,125,000 17,125,000 0 218,093 0 16,906,907 1991B 12,290,000 12,290,000 0 130,619 0 12,159,381 1992 53,500,000 53,500,000 0 702,097 0 52,797,903 1996 81,700,000 81,700,000 (323,982) 1,542,829 0 79,833,189 ------------ ------------- ----------- ---------- ---- ------------- Sub-Totals $178,135,000 $177,685,000 ($364,399) $2,658,988 $0 $175,111,613 ------------------------------------------------------------------------------------------------------ TOTALS $754,930,000 $754,335,000 ($1,682,847) $8,183,124 $0 $745,064,029 ------------------------------------------------------------------------------------------------------
SOUTHWESTERN ELECTRIC POWER COMPANY Exhibit WGH-2 WEIGHTED COST OF CAPITAL Page 1 of 3 December 31, 2000 AFTER ASSET TRANSFER -------------------------------------------------------------------------------- (A) (B) (C) (D) ------------------------------------------------------------------------- Estimated Page Amount Asset Line Description Reference Per Books Transfer -------------------------------------------------------------------------------- 1 Long-Term Debt WGH-2, p. 2 $722,437,699 ($150,000,000) 2 Preferred Stock WGH-1, p. 2 $2,697,319 $0 3 Common Stock Equity na $676,655,920 ($180,000,000) ------------------ 4 $1,401,790,938 ================== 5 Short-Term Debt ($127,590,000) ----------------- 6 ($457,590,000) ================= -------------------------------------------------------------------------------- ------------------------------------------------------------------------ (E) (F) (G) (H) ------------------------------------------------------------------------ Percent of Cost of Weighted Adjusted Total Capital Average Amount Capitalization Rate Cost of Capital ------------------------------------------------------------------------ $572,860,307 53.43% 8.13% 4.34% $2,697,319 0.25% 12.83% 0.03% $496,655,920 46.32% 11.10% 5.14% --------------------------------------- ------------------ $1,072,213,546 100.00% 9.52% ======================================= ================== ------------------------------------------------------------------------ (1) The retirement of $150M of Senior Unsecured Floating Rate Note results in a $149.6M reduction to Long-Term Debt due to unamortized discount and issuance expense balances. SOUTHWESTERN ELECTRIC POWER COMPANY Exhibit WGH-2 WEIGHTED COST OF DEBT Page 2 of 3 December 31, 2000
-------------------------------------------------------------------------------------------------- (A) (B) (C) (D) (E) (F) (G) (H) -------------------------------------------------------------------------------------------------- Under- Sinking Principal Premium Writing Series Issuance Maturity Interest Fund Amount or Fees and Date Date Rate (Y/N) at Issuance (Discount) Issuance Exp. -------------------------------------------------------------------------------------------------- FIRST MORTGAGE BONDS A 11/1/76 11/1/06 6.200% N 7,100,000 (118,925) 177,704 B 11/1/76 11/1/06 6.200% N 1,000,000 (16,750) 25,028 V 6/1/92 6/1/04 7.750% N 40,000,000 (270,000) 152,214 W 9/1/92 9/1/99 6.125% N 40,000,000 (474,800) 34,619 X 9/1/92 9/1/07 7.000% N 90,000,000 (1,688,400) 77,893 Y 2/1/93 2/1/03 6.625% N 55,000,000 (573,650) 493,115 Z 7/1/93 7/1/23 7.250% N 45,000,000 (506,702) 498,787 AA 10/1/93 4/1/00 5.250% N 45,000,000 (110,250) 308,273 BB 10/1/93 10/1/25 6.875% N 80,000,000 (565,600) 748,041 ---------------- Sub-Totals 403,100,000 TRUST PREFERRED SECURITIES 7.875% 4/30/97 4/30/37 7.875% N 110,000,000 3,768,900 SENIOR UNSECURED FLOATING RATE NOTES 3/1/00 Retired 6.970% N POLLUTION CONTROL BONDS 1978A 1/1/78 1/1/08 6.000% 16,200,000 (194,400) 314,650 1991A 5/3/91 8/1/11 8.200% 17,125,000 0 417,265 1991B 7/17/91 11/1/04 6.900% 12,290,000 0 363,824 1992 11/24/92 1/1/19 7.600% 53,500,000 0 1,014,193 1996 7/11/96 4/1/18 6.100% 81,700,000 (408,500) 1,945,305 ---------------- Sub-Totals 180,815,000 -------------------------------------------------------------------------------------------------- TOTAL $693,915,000 -------------------------------------------------------------------------------------------------- LOSS ON REACQUIRED DEBT NOT ASSOCIATED WITH A SPECIFIC REFUNDING ISSUE A. Annual Requirement = Debt Balance x Weighted Cost of Debt B. Adjusted Annual Requirement = Annual Requirement (see Adjustment 2A) + Amortization of Loss on Reacquired Debt ((a/c 189;257;1810.7307;2260.7307)X12) C. Adjusted Balance = Debt Balance - Unamortized Loss on Reacquired Debt (a/c 189;257;1810.7307;2260.7307) D. Adjusted Cost of Debt = Adjusted Annual Requirement (see Adjustment 2B) / Adjusted Debt Balance (see Adjustment 2C) --------------------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------- (I) (J) (K) (T, p.2) (L) (M) (N) ----------------------------------------------------------------------------------------- Gain Book Value (Loss) on Net Net Including Issue as % Weighted Reacquired Proceeds Proceeds Scheduled of Total Cost of Average Debt at Issuance as % of Par Maturities Book Value Debt Cost ----------------------------------------------------------------------------------------- 0 6,803,371 95.82% 5,738,896 0.964% 6.519% 0.060% 0 958,222 95.82% 991,827 0.167% 6.519% 0.010% 0 39,577,786 98.94% 39,874,716 6.696% 7.888% 0.530% 0 39,490,581 98.73% 0 0.000% 6.353% 0.000% 0 88,233,707 98.04% 89,177,023 14.975% 7.216% 1.080% 0 53,933,235 98.06% 54,863,939 9.213% 6.897% 0.640% 0 43,994,511 97.77% 44,245,042 7.430% 7.437% 0.550% 0 44,581,477 99.07% 0 0.000% 5.422% 0.000% 0 78,686,359 98.36% 78,907,196 13.251% 7.004% 0.930% ---------------- Sub-Totals 313,798,639 0 106,231,100 96.57% 106,576,385 17.897% 8.167% 1.460% 0 15,690,950 96.86% 13,414,233 2.253% 6.233% 0.140% 0 16,707,735 97.56% 16,906,907 2.839% 8.451% 0.240% 0 11,926,176 97.04% 12,159,381 2.042% 7.249% 0.150% 0 52,485,807 98.10% 52,797,903 8.866% 7.770% 0.690% 0 79,346,195 97.12% 79,833,189 13.406% 6.345% 0.850% ---------------- Sub-Totals 175,111,613 ----------------------------------------------------------------------------------------- TOTAL $595,486,637 100.000% 7.330% ----------------------------------------------------------------------------------------- Debt Balance $595,486,637 x Weighted Cost of Debt 7.33% ---------------- Annual Requirement $43,649,170 Annual Requirement $43,649,170 + Amortization of Loss on Required Debt 2,900,340 ---------------- = Adjusted Annual Requirement $46,549,510 Debt Balance $595,486,637 - Unamortized Loss on Reacquired Debt 22,626,330 ---------------- = Adjusted Debt Balance $572,860,307 = Adjusted Annual Requirement $46,549,510 / Adjusted Debt Balance $572,860,307 ---------------- = Adjusted Cost of Debt 8.130% ---------------- -----------------------------------------------------------------------------------------
Exhibit WGH-2 Page 3 of 3 ------------------------------------------------------------------------------ (O) (P) (Q) ------------------------------------------------------------------------------ 226 Principal Principal Unamortized Amount Excluding Scheduled Premium or Series Outstanding Maturities (Discount) ------------------------------------------------------------------------------ FIRST MORTGAGE BONDS A 5,795,000 5,650,000 (22,422) B 1,000,000 1,000,000 (3,300) V 40,000,000 40,000,000 0 W 0 0 0 X 90,000,000 90,000,000 (453,403) Y 55,000,000 55,000,000 (21,894) Z 45,000,000 45,000,000 (379,980) AA 0 0 BB 80,000,000 80,000,000 (437,449) 0 ---------------------- --------------------- ------------------ Sub-Totals $316,795,000 $316,650,000 ($1,318,448) 7.875% 110,000,000 110,000,000 POLLUTION CONTROL REVENUE BONDS 1978A 13,520,000 13,070,000 (40,417) 1991A 17,125,000 17,125,000 0 1991B 12,290,000 12,290,000 0 1992 53,500,000 53,500,000 0 1996 81,700,000 81,700,000 (323,982) ---------------------- --------------------- ------------------ Sub-Totals $178,135,000 $177,685,000 ($364,399) ------------------------------------------------------------------------------ TOTALS $604,930,000 $604,335,000 ($1,682,847) ------------------------------------------------------------------------------ ------------------------------------------------------------------------------ ------------------------------------------------------------------------ (R) (S) (T) ------------------------------------------------------------------------ 181 189/257 Book Value Unamortized Unamortized Including Fees and Gain (Loss) on Scheduled Expenses Reacquired Debt Maturities ------------------------------------------------------------------------ 33,682 0 5,738,896 4,873 0 991,827 125,284 0 39,874,716 0 0 0 369,574 0 89,177,023 114,167 0 54,863,939 374,978 0 44,245,042 0 0 0 655,355 0 78,907,196 --------------------- --------------------- --------------------- $1,677,913 $0 $313,798,639 3,423,615 106,576,385 65,350 0 13,414,233 218,093 0 16,906,907 130,619 0 12,159,381 702,097 0 52,797,903 1,542,829 0 79,833,189 --------------------- --------------------- --------------------- $2,658,988 $0 $175,111,613 ------------------------------------------------------------------------ $7,760,516 $0 $595,486,637 ------------------------------------------------------------------------ ------------------------------------------------------------------------ Exhibit WGH-3 Page 1 of 1 SOUTHWESTERN ELECTRIC POWER COMPANY BLENDED COST OF CAPITAL FOR COMBINED SWEPCO AND SWEPCO TEXAS EDC AFTER ASSET TRANSFER AS OF DECEMBER 31, 2000
(A) (B) (C) BEFORE ASSET TRANSFER --------------------------------------------- Cost of Amount % Capital --------------------------------------------- (000's) --------------------------------------------------------------------------------------------- SWEPCO INTEGRATED UTILITY Common Stock Equity 676,656 48.27% 11.10% Preferred Stock 2,697 0.19% 12.83% Long-term Debt 722,438 51.54% 7.93% ------------------------------------------------ Total 1,401,791 100.00% =============================== Short-term Debt WACC 9.47% =========== --------------------------------------------------------------------------------------------- --------------------------------------------------------------------------------------------- SWEPCO Texas EDC Common Stock Equity Preferred Stock Long-term Debt Total WACC --------------------------------------------------------------------------------------------- --------------------------------------------------------------------------------------------- BLENDED SWEPCO AFTER ASSET TRANSFER Common Stock Equity Preferred Stock Long-term Debt Total BLENDED WACC --------------------------------------------------------------------------------------------- (D) (E) (F) (G) AFTER ASSET TRANSFER ------------------------------------------------- Capital Cost of Reductions Amount % Capital -------------- ------------------------------------------------- (000's) (000's) ------------------------------------------------------------------------- (180,000) 496,656 46.32% 11.10% 2,697 0.25% 12.83% (150,000) 572,861 53.43% 8.13% ---------------- ----------------------------------------------- (330,000) 1,072,214 100.00% ============================== (127,590) ---------------- (457,590) ================ 9.52% ============= ------------------------------------------------------------------------- ------------------------------------------------------------------------- 183,036 40.00% 11.25% - 0.00% 0.00% 274,554 60.00% 8.12% ----------------------------------------------- 457,590 100.00% ============================== 9.37% ============= ------------------------------------------------------------------------- ------------------------------------------------------------------------- 679,692 44.43% 11.14% 2,697 0.18% 12.83% 847,415 55.39% 8.13% ----------------------------------------------- 1,529,804 100.00% ============================== 9.47% ============= -------------------------------------------------------------------------
BEFORE THE LOUISIANA PUBLIC SERVICE COMMISSION LPSC DOCKET NOS. U-21453, U-20925, U-22092 (SUBDOCKET C) SOUTHWESTERN ELECTRIC POWER COMPANY'S BUSINESS SEPARATION PLAN DIRECT TESTIMONY OF WENDY G. HARGUS FOR SOUTHWESTERN ELECTRIC POWER COMPANY SEPTEMBER 2001 DOCKET NOS. U-21453, U-20925, WENDY G. HARGUS U-22092 (SUBDOCKET C) DIRECT TESTIMONY 1 TESTIMONY INDEX SUBJECT PAGE I. INTRODUCTION...............................................................3 II. PURPOSE OF TESTIMONY......................................................6 III. CAPITAL STRUCTURE AND COST OF CAPITAL....................................6 IV. OTHER FINANCIAL ISSUES...................................................14 EXHIBITS EXHIBIT WGH-1 SWEPCO Weighted Cost of Capital at December 31, 2000 EXHIBIT WGH-2 SWEPCO Pro Forma Weighted Cost of Capital EXHIBIT WGH-3 Blended Cost of Capital for Combined SWEPCO and SWEPCO Texas EDC after Asset Transfer DOCKET NOS. U-21453, U-20925, WENDY G. HARGUS U-22092 (SUBDOCKET C) DIRECT TESTIMONY 2 1 BEFORE THE 2 LOUISIANA PUBLIC SERVICE COMMISSION 3 LPSC DOCKET NOS. U-21453, 4 U-20925, U-22092 (SUBDOCKET C) 5 6 SOUTHWESTERN ELECTRIC POWER COMPANY'S 7 BUSINESS SEPARATION PLAN 8 9 DIRECT TESTIMONY OF 10 WENDY G. HARGUS 11 12 FOR 13 SOUTHWESTERN ELECTRIC POWER COMPANY 14 15 SEPTEMBER 2001 16 17 I. INTRODUCTION 18 Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS. 19 A. My name is Wendy G. Hargus. My business address is 1616 Woodall Rodgers 20 Freeway, Dallas, Texas 75202. 21 BY WHOM ARE YOU EMPLOYED AND IN WHAT CAPACITY? 22 I am employed by American Electric Power Service Corporation (AEPSC), a 23 subsidiary of American Electric Power Company, Inc. (AEP) as Assistant Treasurer
DOCKET NOS. U-21453, U-20925, WENDY G. HARGUS U-22092 (SUBDOCKET C) DIRECT TESTIMONY 3 1 and Vice President, Treasury Operations of AEP and its subsidiaries including 2 Southwestern Electric Power Company (SWEPCO or Company). Prior to the merger 3 with AEP, I was Treasurer of Central and South West Corporation (CSW) and its 4 subsidiaries. 5 Q. PLEASE DESCRIBE YOUR RESPONSIBILITIES IN YOUR PRESENT 6 POSITION WITH THE COMPANY. 7 A. As AEP's Assistant Treasurer, I am responsible for treasury operations including 8 short-term funding and cash management. In addition, I will continue to be involved 9 in the completion of the required structural and functional unbundling 10 of the former CSW subsidiaries. 11 Q. PLEASE GIVE A BRIEF STATEMENT OF YOUR PROFESSIONAL AND 12 EDUCATIONAL QUALIFICATIONS. 13 A. I have a Bachelor of Business Administration degree with a concentration in 14 Accounting from McMurry University and a Master of Science degree with a 15 concentration in Accounting from Texas Tech University. 16 I have worked for the AEP and CSW for 21 years in a variety of positions in 17 the finance and accounting areas. I began at West Texas Utilities Company (WTU) 18 with responsibility for financial planning and analysis. While at WTU I also held the 19 positions of Assistant to the Treasurer with additional responsibilities of testimony 20 preparation for rate filing applications and issuance of long-term debt and preferred 21 stock, and Assistant to the Controller with responsibility for all financial reporting, 22 planning and analysis for the company.
DOCKET NOS. U-21453, U-20925, WENDY G. HARGUS U-22092 (SUBDOCKET C) DIRECT TESTIMONY 4 1 In 1986, I transferred to Central and South West Services, Inc. (CSWS) in the 2 Financial Accounting area and was responsible for preparing consolidated financial 3 statements for CSW and benefit plan accounting. I have also held positions as 4 Strategic Planning Analyst, Director of Investor Relations, Director of Strategic 5 Planning and Controller for CSW. Until June 2000, I was Treasurer for CSW and its 6 subsidiaries. As a result of the merger with AEP, I am Assistant Treasurer for AEP 7 and its subsidiaries, including SWEPCO. 8 I am a Certified Public Accountant licensed to practice in the State of Texas 9 and a member of the American Institute of Certified Public Accountants, the Texas 10 Society of Certified Public Accountants, the American Women's Society of Certified 11 Public Accountants, the Association for Financial Professionals and the Financial 12 Executives Institute. 13 Q. HAVE YOU PREVIOUSLY FILED TESTIMONY? 14 A. Yes. I have filed testimony in the following cases in Texas: Docket Nos. 22352, 15 22353 and 22354, the unbundled cost of service filings for the three AEP operating 16 companies in Texas; and Docket No. 21953, the business separation plan in Texas. I 17 also testified in Docket No. 21528, CPL's stranded cost securitization filing and in 18 Docket No. 12700, the CSW/El Paso Electric merger. 19 Q. DO YOU HAVE ANY EXHIBITS TO YOUR TESTIMONY THAT YOU 20 SPONSOR IN THIS FILING? 21 A. Yes. I sponsor the following exhibits: 22 EXHIBIT WGH-1 SWEPCO Weighted Cost of Capital at December 31, 2000
DOCKET NOS. U-21453, U-20925, WENDY G. HARGUS U-22092 (SUBDOCKET C) DIRECT TESTIMONY 5 1 EXHIBIT WGH-2 SWEPCO Pro Forma Weighted Cost of Capital 2 EXHIBIT WGH-3 Blended Cost of Capital for Combined SWEPCO and 3 SWEPCO Texas EDC after Asset Transfer 4 Q. ARE THE TESTIMONY AND THE RELATED EXHIBITS TRUE AND 5 CORRECT TO THE BEST OF YOUR KNOWLEDGE AND BELIEF? 6 A. Yes, they are. 7 8 II. PURPOSE OF TESTIMONY 9 Q. PLEASE DESCRIBE THE PURPOSE OF YOUR TESTIMONY. 10 A. The purpose of my testimony is to describe the financial aspects of SWEPCO's 11 proposed business separation plan. I will discuss the impact of SWEPCO's proposed business 12 separation plan on SWEPCO's capital structure and cost of capital. In addition, 13 I will discuss the treatment of SWEPCO's existing securities. 14 15 III. CAPITAL STRUCTURE AND COST OF CAPITAL 16 Q. PLEASE DESCRIBE THE EXISTING CAPITAL STRUCTURE AND BOND 17 RATINGS OF SWEPCO.
DOCKET NOS. U-21453, U-20925, WENDY G. HARGUS U-22092 (SUBDOCKET C) DIRECT TESTIMONY 6 1 A. Shown below are the historical capital structures and current bond ratings for 2 SWEPCO: Year Year Year Ended Ended Ended Average 12/31/00 12/31/99 12/31/98 98 to 00 -------- -------- -------- -------- Common Equity 48.3% 52.3% 50.9% 50.5% Preferred Stock 0.2% 0.3% 0.3% 0.3% Long-Term Debt 51.5% 47.4% 48.8% 49.2% ------ ------ ------ ------ Total 100.0% 100.0% 100.0% 100.0% 3 SENIOR SECURED BOND RATINGS 4 S&P MOODY'S FITCH/D&P 5 A A1 A+ 6 Q. WHAT IS SWEPCO'S CAPITAL STRUCTURE GOAL? 7 A. AEP's goal is to manage the capital structures and financial performance of its utility 8 subsidiaries to maintain strong bond ratings. AEP targets capital structures that help 9 our subsidiaries maintain these ratings, so as to minimize capital costs. 10 Q. WILL ANY OF SWEPCO'S OUTSTANDING DEBT OR PREFERRED STOCK 11 HAVE TO BE RETIRED AS A RESULT OF THE ASSET TRANSFERS 12 NECESSARY TO COMPLY WITH TEXAS RESTRUCTURING 13 REQUIREMENTS? 14 A. Yes. A portion of SWEPCO's existing securities will be retired as part of this 15 transaction. When SWEPCO transfers Texas transmission and distribution (T &D) 16 assets to the SWEPCO Texas Energy Delivery Company (SWEPCO Texas EDC), the 17 SWEPCO Texas EDC will transfer cash equal to the total capitalization of those assets 18 to SWEPCO. That cash will be used to retire a portion of SWEPCO's current debt 19 and common equity, generally in the same proportion as the existing capital structure.
DOCKET NOS. U-21453, U-20925, WENDY G. HARGUS U-22092 (SUBDOCKET C) DIRECT TESTIMONY 7 1 However, SWEPCO's Texas T&D assets make up a small enough portion of 2 SWEPCO's total assets so that they can be transferred without violating any of the 3 restrictive covenants of SWEPCO's securities. In other words, the transfer of assets 4 will not require SWEPCO to retire all of its existing first mortgage bonds and 5 pollution control bonds. 6 Q. WHAT WILL BE THE IMPACT ON SWEPCO'S CAPITAL STRUCTURE AND 7 COST OF CAPITAL AS A RESULT OF STRUCTURAL UNBUNDLING 8 REQUIRED IN TEXAS? 9 A. It is not possible at this time to precisely know the impact on SWEPCO's capital 10 structure and cost of capital. EXHIBITS WGH-l and WGH-2 show the expected 11 minimal impact on the capital structure and weighted average cost of capital (WACC) 12 of SWEPCO as a result of structural unbundling in Texas. As shown in EXHIBIT 13 WGH-2 the transfer of Texas T&D assets from SWEPCO to SWEPCO Texas EDC 14 will result in the retirement of a portion of both the existing debt and equity supporting 15 those assets. SWEPCO plans to retire capital in the most prudent manner so that there 16 will be virtually no change from its then current capital structure mix or cost of capital. 17 Q. WHAT CAPITAL DO YOU EXPECT TO RETIRE AS A RESULT OF THE 18 ASSET TRANSFER? 19 A. SWEPCO currently expects to retire a combination of debt and equity to minimize the 20 impact on capital structure and cost of capital. There are a number of factors to 21 consider when determining which of the multiple debt issues to retire. Overall cost is 22 the primary factor that will be used to determine which securities to retire. Overall
DOCKET NOS. U-21453, U-20925, WENDY G. HARGUS U-22092 (SUBDOCKET C) DIRECT TESTIMONY 8 1 cost includes any one-time transaction costs required to retire securities (such as call 2 premiums or the cost to tender or defease). These one-time costs are sometimes very 3 large and are impacted by the then current debt markets. In order to minimize the 4 cost of restructuring, SWEPCO expects to retire only unsecured debt and short-term 5 debt that can be redeemed without one-time transaction costs (as shown in EXHIBIT 6 WGH-2). 7 Q. HOW DID YOU DETERMINE THAT THERE WOULD BE ONLY MINIMAL 8 IMPACT ON SWEPCO'S CAPITAL STRUCTURE AND WACC? 9 A. I used the existing December 31, 2000 capital structure and WACC to demonstrate 10 the costs both before and after the asset transfers. The table below shows SWEPCO's 11 last approved WACC in Docket No. U-23029-A and the estimated WACC before and 12 after the asset transfer: --------------------------------------------------------------------- WACC Source ---- ------ --------------------------------------------------------------------- Docket No. U-23029-A 9.61% December 29, 1999 Order --------------------------------------------------------------------- Before Asset Transfer 9.47% Exhibit WGH-1 --------------------------------------------------------------------- After Asset Transfer 9.52% Exhibit WGH-2 --------------------------------------------------------------------- 13 The supporting detail and calculations are shown in EXHIBITS WGH-l and WGH-2 14 and demonstrate that there will be minimal impact on SWEPCO's capital structure and 15 WACC. 16 Q. DESCRIBE SWEPCO'S CAPITAL STRUCTURE AND WACC BEFORE THE 17 ASSET TRANSFER. 18 A. EXHIBIT WGH-1 presents the actual capital structure and WACC as of December 19 31, 2000 before the asset transfer. The summary table on page 1 provides the 20 calculation for the actual WACC of 9.47% and pages 2-5 provide the detail for the
DOCKET NOS. U-21453, U-20925, WENDY G. HARGUS U-22092 (SUBDOCKET C) DIRECT TESTIMONY 9 1 actual cost of debt and preferred stock. The cost of equity used for this calculation is 2 the last allowed return on equity approved by the Louisiana Public Service 3 Commission in Docket No. U-23029-A. 4 Q. HOW DID YOU ESTIMATE THE PRO FORMA WACC AFTER ASSETS ARE 5 TRANSFERRED TO THE SWEPCO TEXAS EDC? 6 A. The detailed calculations are presented in EXHIBIT WGH-2. To estimate the pro 7 forma WACC after the asset transfer, I used the estimated total capitalization of 8 $457.6 million (as presented in Attachment H-8 of the July 24, 2001 FERC filing in 9 Docket No. EC01-130-000. This amount is an estimate and is subject to change as 10 the actual amounts to transfer are finalized) as the amount of capital necessary to be 11 retired. The only long-term debt that can currently be retired without one-time 12 transaction costs is the $150 million floating rate note. Accordingly, long-term debt 13 was reduced by $150 million and equity was reduced by $180 million. The remainder 14 was used to pay down short-term debt. 15 These reductions result in minimal change in capital structure and WACC. The 16 capital structure ratios change slightly as a result of these changes with a 48% equity 17 ratio before the asset transfers and 46% after the asset transfers. The cost of debt 18 increases slightly from 7.93% to 8.13% as a result of these changes, but the overall 19 WACC only changes by a very minimal amount as can be seen in the comparison table 20 on the previous page. 21 Q. WHY IS THE WEIGHTED COST OF DEBT PROJECTED TO INCREASE 22 SLIGHTLY WHEN YOU RETIRE THE ESTIMATED AMOUNT OF DEBT?
DOCKET NOS. U-21453, U-20925, WENDY G. HARGUS U-22092 (SUBDOCKET C) DIRECT TESTIMONY 10 1 A. The weighted cost of debt can be impacted by three factors: the interest rate of the 2 debt issue retired; any one-time transaction costs of the debt issue retired; and the 3 smaller remaining balance of debt. First, if the interest rate on the retired debt is lower 4 than the average cost of debt, the new average cost of debt will increase. Likewise, if 5 the interest rate on the retired debt is higher than the average cost of debt, the new 6 average cost of debt will decrease. Second, if there are one-time costs to retire the 7 securities, those costs are included in the unamortized loss on reacquired debt, and the 8 overall cost of debt is also increased. Third, the amortization of the loss on reacquired 9 debt and the unamortized balance become a larger percent of the reduced amount of 10 outstanding debt. 11 As shown in EXHIBIT WGH-2, the weighted cost of debt is projected to 12 increase slightly from 7.93% to 8.12% as a result of the first and third reasons 13 described above - the interest rate on this debt is slightly under the average and the 14 resulting debt balance is smaller. None of the changes described results in a significant 15 change in the cost of debt or WACC as demonstrated in EXHIBIT WGH-2. 16 Q. WILL SWEPCO'S PROJECTED CAPITAL STRUCTURE AND WACC CHANGE 17 OVER TIME? 18 A. Yes. As mentioned above, as debt issues mature, they must be retired or replaced with 19 new securities which may be higher or lower cost depending on the financial markets 20 at the time. Also, any new capital needs must be financed with new securities and any 21 excess cash generated by operations will be used to retire securities and pay dividends. 22 All of these items are part of ongoing operations and will impact the capital structure
DOCKET NOS. U-21453, U-20925, WENDY G. HARGUS U-22092 (SUBDOCKET C) DIRECT TESTIMONY 11 1 and WACC over time. In the past, SWEPCO has done a good job of managing its 2 capital structure and WACC and has taken advantage of good financial markets by 3 refinancing higher cost securities to reduce the overall capital costs. EXHIBIT WGH- 4 2 simply provides an estimate of the WACC at a point in time. In the normal course of 5 business, this cost will change over time as the Company's capitalization and securities 6 outstanding change. 7 Q. IS SWEPCO'S WEIGHTED COST OF PREFERRED STOCK IMPACTED BY 8 THE ASSET TRANSFER? 9 A. No, the weighted cost of preferred stock is not affected by the asset transfer because 10 the amount of preferred stock outstanding does not change. The calculation of the 11 weighted cost of preferred stock is shown in EXHIBIT WGH-1, pages 2 and 3. 12 Q. WHAT WILL BE THE REGULATED WACC FOR THE NEW SWEPCO TEXAS 13 EDC? 14 A. The settlement order in the SWEPCO Texas EDC Unbundled Cost of Service 15 proceeding mandates that the cost of capital be based on a capital structure of 60% 16 debt and 40% equity for Texas regulatory purposes. The allowed return on equity is 17 11.25% and the cost of debt is 8.12%. These requirements result in the following 18 WACC:
DOCKET NOS. U-21453, U-20925, WENDY G. HARGUS U-22092 (SUBDOCKET C) DIRECT TESTIMONY 12 1 2 Capital Weighted 3 Structure Cost Cost --------- ---- ---- 4 Equity 40% 11.25% 4.50% 5 Debt 60% 8.12% 4.87% ---- ----- 6 Total 100% 9.37% ==== ===== 7 Q. HOW DOES THIS COMPARE TO THE WACC FOR THE REMAINING 8 INTEGRATED SWEPCO? 9 A. The regulated WACC for the SWEPCO Texas EDC of 9.37% is lower than the 10 WACC expected for the remaining integrated SWEPCO of 9.52% outlined earlier in 11 this testimony primarily because of the lower percentage of equity in the SWEPCO 12 Texas EDC approved capital structure. There are also slight differences in the cost of 13 debt and the cost of equity that impact the calculated WACC. 14 Q. WILL THE ACTUAL CAPITAL STRUCTURE AND COST OF CAPITAL FOR 15 THE NEW SWEPCO TEXAS EDC BE THE SAME AS THE STRUCTURE 16 APPROVED BY THE PUBLIC UTILITY COMMISSION OF TEXAS (PUCT)? 17 A. Not necessarily. However, when the new company is financed we will attempt to 18 balance the requirements to maintain solid credit quality with the 60% debt ratio 19 required by the PUCT. One of the overall goals for the SWEPCO Texas EDC will be 20 to minimize the cost of capital while maintaining good credit quality. Over time we 21 would expect that SWEPCO Texas EDC's actual financing would be able to reach the 22 capital structure required by the PUCT. In addition, the actual cost of debt will also 23 differ from the approved amount depending on the capital market conditions when we 24 actually issue the new debt. 25 Q. FOR THE PURPOSE OF SETTING TOTAL TRANSMISSION COSTS FOR
DOCKET NOS. U-21453, U-20925, WENDY G. HARGUS U-22092 (SUBDOCKET C) DIRECT TESTIMONY 13 1 SWEPCO'S TRANSMISSION ASSETS, WHAT COST OF CAPITAL SHOULD 2 BE CONSIDERED? 3 A. Mr. Potter's testimony explains that total transmission costs are determined by 4 combining the transmission of SWEPCO and SWEPCO Texas EDC. The cost of 5 capital that will be used is a blended cost of capital for the two companies. The table 6 below and EXHIBIT WGH-3 show the current estimate for the blended cost for the 7 combined capital of the remaining integrated SWEPCO and SWEPCO Texas EDC. 8 As you can see, the blended WACC is equal to the WACC for SWEPCO before the 9 asset transfer. 10 WACC 11 Before Asset Transfer: ---- 12 SWEPCO 9.47% 13 After Asset Transfer: 14 SWEPCO 9.52% 15 SWEPCO Texas EDC 9.37% 16 SWEPCO Total (Blended) 9.47% 17 18 IV. OTHER FINANCIAL ISSUES 19 Q. WILL SWEPCO ALLOCATE DEBT BETWEEN REGULATED AND 20 UNREGULATED ENTITIES? 21 A. No, SWEPCO does not anticipate the need to allocate any of its current outstanding 22 debt or preferred stock to any other affiliated entities. SWEPCO will remain an 23 integrated electric utility in order to continue to meet its obligation to serve in 24 Louisiana. The business separation plan will result in the transfer of Texas T&D assets 25 to the SWEPCO Texas EDC. SWEPCO will retain its generation assets and
DOCKET NOS. U-21453, U-20925, WENDY G. HARGUS U-22092 (SUBDOCKET C) DIRECT TESTIMONY 14 1 substantially all of its outstanding capital. As mentioned above, as a result of the 2 transfer of the Texas T&D assets, the total amount of capital outstanding at SWEPCO 3 is expected to be reduced by retiring specific securities. 4 Q. PLEASE SUMMARIZE YOUR TESTIMONY. 5 A. SWEPCO's proposed business separation plan will not materially impact SWEPCO's 6 Louisiana retail customers. As discussed above, SWEPCO will remain an integrated 7 electric utility serving in Louisiana and will retain most of its outstanding debt and 8 preferred securities. The only capital structure impact will be the transfer of Texas 9 T&D assets to the SWEPCO Texas EDC and the resulting retirement of a portion of 10 SWEPCO's outstanding debt and common equity. 11 Q. DOES THIS CONCLUDE YOUR DIRECT TESTIMONY? 12 A. Yes, it does.
DOCKET NOS. U-21453, U-20925, WENDY G. HARGUS U-22092 (SUBDOCKET C) DIRECT TESTIMONY 15 BEFORE THE LOUISIANA PUBLIC SERVICE COMMISSION LPSC DOCKET NOS. U-21453, U-20925, U-22092 (SUBDOCKET C) SOUTHWESTERN ELECTRIC POWER COMPANY'S BUSINESS SEPARATION PLAN DIRECT TESTIMONY OF CHRIS POTTER FOR SOUTHWESTERN ELECTRIC POWER COMPANY SEPTEMBER 2001 DOCKET NOS. U-21453, U-20925, CHRIS POTTER U-22092 (SUBDOCKET C) DIRECT TESTIMONY 1 TESTIMONY INDEX SUBJECT PAGE 1. INTRODUCTION .......................................................... 3 II. PURPOSE OF TESTIMONY .................................................. 5 III. COST ALLOCATION ISSUES ................................................ 6 IV. CONCLUSION ............................................................ 14 DOCKET NOS. U-21453, U-20925, CHRIS POTTER U-22092 (SUBDOCKET C) DIRECT TESTIMONY 2 1 BEFORE THE 2 LOUISIANA PUBLIC SERVICE COMMISSION 3 LPSC DOCKET NOS. U-21453, 4 U-20925, U-22092 (SUBDOCKET C) 5 6 SOUTHWESTERN ELECTRIC POWER COMPANY'S 7 BUSINESS SEPARATION PLAN 8 9 DIRECT TESTIMONY OF 10 CHRIS POTTER 11 12 FOR 13 SOUTHWESTERN ELECTRIC POWER COMPANY 14 15 SEPTEMBER 2001 16 17 I. INTRODUCTION 18 Q. WOULD YOU PLEASE STATE YOUR NAME, POSITION, AND BUSINESS 19 ADDRESS? 20 A. My name is Chris Potter. My position is Principal Regulatory Consultant in the 21 Regulated Pricing & Analysis department for American Electric Power Service 22 Corporation (AEPSC), a subsidiary of American Electric Power Company, Inc.
DOCKET NOS. U-21453, U-20925, CHRIS POTTER U-22092 (SUBDOCKET C) DIRECT TESTIMONY 3 1 (AEP). My business address is Williams Tower II, Two West Second Street, Tulsa, 2 Oklahoma (74103-3102.) 3 Q. WHAT ARE YOUR PRINCIPAL AREAS OF RESPONSIBILITY AS PRINCIPAL 4 REGULATORY CONSULTANT? 5 A. My responsibilities as Principal Regulatory Consultant are to manage pricing and 6 costing resources for rate cases, regulatory filings and rulemakings, as well as provide 7 pricing and costing services to AEP and its subsidiary electric utility operating 8 companies in the areas of regulatory analysis, cost-of-service studies and rate design. I 9 am also responsible for assisting the AEP electric utility operating subsidiaries in the 10 preparation and coordination of filings before the Louisiana Public Service 11 Commission (LPSC or Commission), the Arkansas Public Service Commission 12 (APSC), the Federal Energy Regulatory Commission (FERC), the Oklahoma 13 Corporation Commission (OCC), and the Public Utility Commission of Texas 14 (PUCT). 15 Q. WHAT IS YOUR EDUCATIONAL AND PROFESSIONAL BACKGROUND? 16 A. I received my Bachelor of Business Administration degree from Corpus Christi State 17 University (CCSU). While attending CCSU I was employed by Central Power and 18 Light Company (CPL) as an intern in the Budgeting section of Accounting. In 19 November of 1991 I accepted the position of General Ledger coordinator for CPL. 20 My duties as General Ledger coordinator included monthly closing of CPL's financial 21 books, preparation of external financial statements and implementation of various 22 mainframe systems used in the day to day operations of CPL. In July of 1994 I
DOCKET NOS. U-21453, U-20925, CHRIS POTTER U-22092 (SUBDOCKET C) DIRECT TESTIMONY 4 1 transferred to Central and South West Services, Inc. (CSWS), as the Closing 2 Coordinator of CPL and Southwestern Electric Power Company (SWEPCO or 3 Company). In February of 1995 I was promoted to Accounting Consultant for CSWS 4 but maintained the same Closing Coordinator responsibilities. In March of 1995 I 5 transferred to the CSWS Pricing/Costing department as a Pricing/Costing Consultant. 6 In October of 1996 I was promoted to Project Manager in the Pricing/Costing 7 department and in May of 1999 I was promoted to Senior Project Manager. In June 8 of 2000, with the conclusion of the AEP/CSW merger, I accepted my current position 9 as Principal Regulatory Consultant for AEP. 10 Q. HAVE YOU PREVIOUSLY SPONSORED TESTIMONY BEFORE A 11 REGULATORY COMMISSION? 12 A. Yes. I have sponsored testimony before the LPSC, APSC and PUCT for SWEPCO, 13 before the OCC for Public Service Company of Oklahoma (PSO) and, before the 14 PUCT for CPL and West Texas Utilities Company. 15 16 II. PURPOSE OF TESTIMONY 17 Q. BRIEFLY OUTLINE THE PURPOSE OF YOUR TESTIMONY. 18 A. My testimony addresses the potential impact to Louisiana ratepayers resulting from the 19 anticipated restructuring and deregulation in Texas with regard to the traditional cost 20 of service studies and the impact on jurisdictional and retail allocation factors. 21 Q. WILL THE RESTRUCTURING IN TEXAS HAVE A MATERIAL IMPACT ON 22 THE LOUISIANA JURISDICTIONAL COST OF SERVICE STUDY?
DOCKET NOS. U-21453, U-20925, CHRIS POTTER U-22092 (SUBDOCKET C) DIRECT TESTIMONY 5 1 A. No. The Louisiana Commission has a legitimate concern to ensure compliance with 2 Texas industry restructuring rules and regulations does not materially affect the costs 3 SWEPCO incurs in providing services to the Louisiana jurisdiction. However, the 4 SWEPCO Business Separation Plan (SWEPCO BSP) does not contemplate that 5 SWEPCO's retail customers in Louisiana will be materially affected by the 6 restructuring activities in Texas. The SWEPCO BSP allows the Company to 7 implement restructuring in Texas without materially affecting the costs paid by 8 SWEPCO's other retail jurisdictions. 9 10 III. COST ALLOCATION ISSUES 11 Q. HOW DID SWEPCO ALLOCATE PRODUCTION RELATED COSTS TO THE 12 JURISDICTIONS IN THE LAST LPSC RATE PROCEEDING? 13 A. In SWEPCO's last cost of service study filed in Louisiana (Docket No. U-23029), 14 production demand related costs were allocated to the jurisdictions utilizing the Four 15 Coincident Peak (4CP) methodology. The 4CP methodology was also utilized in the 16 allocation of production costs in SWEPCO's last rate review before the APSC, 17 (Docket No. 98-339-U), as well as in the Unbundled Cost of Service proceeding 18 before the PUCT (Docket No. 22353). 19 Q. HOW DID SWEPCO ALLOCATE NON-PRODUCTION RELATED COSTS TO 20 THE JURISDICTIONS IN THE LAST LPSC RATE PROCEEDING? 21 A. In SWEPCO's last cost of service study filed in Louisiana, transmission demand 22 related costs were allocated to the jurisdictions utilizing the 4CP methodology.
DOCKET NOS. U-21453, U-20925, CHRIS POTTER U-22092 (SUBDOCKET C) DIRECT TESTIMONY 6 1 Distribution related investment was directly assigned to the jurisdictions based on the 2 physical location of the assets (situs basis). Customer related costs were allocated on 3 the basis of either year-end number of customers or a weighted year-end number of 4 customers. While many allocation factors are utilized in a cost of service study, these 5 allocation factors allocate the vast majority of costs. 6 Q. WHY DID SWEPCO UTILIZE THESE JURISDICTIONAL ALLOCATION 7 METHODOLOGIES IN THE LAST LOUISIANA COST OF SERVICE STUDY? 8 A. The 4 CP method used for production and transmission demand allocation accurately 9 reflects the system peak demands that are considered in the planning and construction 10 of those facilities. The SWEPCO system load has consistently been characterized by 11 pronounced summer peak demands in the four summer months of June through 12 September. Therefore, it is most appropriate to allocate these costs based upon the 4 13 CP methodology. The situs basis for assigning distribution costs allows facilities 14 located in Louisiana to be directly assigned to the Louisiana jurisdiction, where the 15 facilities are actually located and utilized in the provision of distribution-related 16 services. Likewise, the situs basis ensures that distribution facilities not located in 17 Louisiana are assigned to either Texas or Arkansas and not to the Louisiana retail 18 customers. Customer-related costs vary with the number of customers served and 19 should therefore be allocated based upon the number of customers served. 20 Q. HOW DOES THE PRODUCTION JURISDICTIONAL ALLOCATION 21 METHODOLOGY USED IN THE LAST SWEPCO LOUISIANA COST STUDY 22 CHANGE AS A RESULT OF THE UNBUNDLING INITIATIVES IN TEXAS?
DOCKET NOS. U-21453, U-20925, CHRIS POTTER U-22092 (SUBDOCKET C) DIRECT TESTIMONY 7 1 A. While the production allocation methodology does not change, as part of its BSP 2 SWEPCO is proposing a one time allocation of the production related investment and 3 costs (operation and maintenance, depreciation, etc.) between the regulated 4 jurisdictions of Arkansas and Louisiana and the competitive Texas retail and wholesale 5 jurisdictions. 6 Q. PLEASE EXPLAIN SWEPCO's PROPOSED FIXED ALLOCATION OF 7 GENERATION RELATED COSTS. 8 A. As discussed in Sections 4.1.1 and 4.1.2 of the Unit Power Sales Agreement between 9 SWEPCO and the AEP Power Marketing Affiliate (PMA) as filed in FERC Docket 10 No. ER01-2668-000 on July 24, 2001, the capacity assigned to the PMA will be based 11 on the 4CP calculation for the year 2000, the most recent data available. As discussed 12 above the 4CP allocation is consistent with the allocation methodology used in 13 SWEPCO's most recent rate reviews for all three of its retail jurisdictions. Based 14 upon the 2000 4CP data, regulated SWEPCO will be responsible for 45.54% of the 15 non-fuel related generation costs and the PMA will be responsible for the remaining 16 54.46% of those costs. SWEPCO proposes to freeze this allocation percentage for 17 future cost allocation purposes. 18 Q. WHY IS IT APPROPRIATE TO SET THE ALLOCATION OF GENERATION 19 RELATED COSTS AND INVESTMENTS AS A FIXED PERCENTAGE FOR THE 20 TEXAS RETAIL AND WHOLESALE CUSTOMERS? 21 A. By setting the allocation at a fixed percentage of SWEPCO's current generation 22 related assets the Louisiana and Arkansas retail customers will be isolated from the
DOCKET NOS. U-21453, U-20925, CHRIS POTTER U-22092 (SUBDOCKET C) DIRECT TESTIMONY 8 1 effect competition may have on the demand for SWEPCO's generation facilities. 2 Establishing the jurisdictional percentage split based on load data prior to retail 3 competition will ensure that the Louisiana and Arkansas retail customers will not be 4 responsible for any more nor any less than their fair share of SWEPCO's generation 5 costs. 6 Q. PLEASE DISCUSS THE COMPANY'S PROPOSAL TO ALLOCATE NON-FUEL 7 PRODUCTION-RELATED COSTS BETWEEN THE ARKANSAS AND 8 LOUISIANA RETAIL JURISDICTIONS AND THE PMA. 9 A. As mentioned previously, the allocation of non-fuel production costs to the Louisiana 10 and Arkansas retail jurisdictions will be set at 45.54%. Likewise, 54.46% of total non- 11 fuel production costs will be assigned to the PMA. Until such time as either Arkansas 12 or Louisiana decides to implement competition, the jurisdictional allocation of 45.54% 13 of SWEPCO's total non-fuel production-related costs between the Arkansas and 14 Louisiana retail jurisdictions will be based on the 4CP methodology utilizing 15 appropriate test year load data. However, when either Arkansas or Louisiana 16 implements competition, SWEPCO will propose the same methodology for 17 determining the fixed percentage split for the assignment of non-fuel 18 production-related costs to the remaining regulated jurisdiction. 19 Q. HOW WILL THE NON-PRODUCTION JURISDICTIONAL ALLOCATION 20 METHODOLOGIES USED IN THE LAST SWEPCO COST STUDY CHANGE AS 21 A RESULT OF THE UNBUNDLING INITIATIVES IN ARKANSAS AND 22 TEXAS?
DOCKET NOS. U-21453, U-20925, CHRIS POTTER U-22092 (SUBDOCKET C) DIRECT TESTIMONY 9 1 A. Industry restructuring should have minimal impact on the Company's non-production 2 jurisdictional allocation methodologies. However, there may be instances where 3 specific items can be directly assigned to a particular jurisdiction as a result of 4 restructuring requirements. AEP witness John Aaron discusses the accounting 5 changes resulting from restructuring in his direct testimony. SWEPCO intends to 6 utilize the same or similar allocation methodologies, including those utilized to allocate 7 costs between the retail and wholesale jurisdictions, used in the last LPSC filing unless 8 direct assignment is available or cost causation changes. If the cost causation factors 9 indicate that a change in allocation methodologies is warranted, SWEPCO will fully 10 support any such methodology change, which will be reviewed by the Commission in 11 SWEPCO's next rate filing. If a specific service is no longer provided in the Texas 12 jurisdiction as a result of restructuring, but continues to be provided to regulated 13 customers, the costs associated with that particular service will be directly assigned or 14 allocated to only the regulated jurisdictions. For example, if the SWEPCO Texas 15 Energy Delivery Company (SWEPCO Texas EDC) is no longer responsible for 16 issuing individual customer bills, the Company's expense incurred for postage 17 associated with mailing regulated customers' bills would be allocated only to the 18 remaining regulated jurisdictions. 19 Q. WILL RETAIL CUSTOMERS CHOOSING DIFFERENT SUPPLIERS IN TEXAS 20 DUE TO INDUSTRY RESTRUCTURING MATERIALLY AFFECT THE 21 AMOUNT OF NON-PRODUCTION RELATED COSTS JURISDICTIONALLY 22 ALLOCATED TO THE LOUISIANA RETAIL CUSTOMERS?
DOCKET NOS. U-21453, U-20925, CHRIS POTTER U-22092 (SUBDOCKET C) DIRECT TESTIMONY 10 1 A. No. Consistent with prior practice, SWEPCO proposes to continue to use the total 2 loads in the current SWEPCO service territories in the development of its non- 3 production jurisdictional allocation factors, regardless of whether a customer receives 4 energy from SWEPCO or a Retail Energy Provider (REP) in Texas. Loads 5 traditionally included in the development of the non-production jurisdictional 6 allocation factors will still be accounted for in the development of these factors, 7 regardless of whether a customer has a different supplier for their generation needs. 8 Q. WILL THE TRANSMISSION PORTION OF SWEPCO's COST STUDY CHANGE 9 AS A RESULT OF RESTRUCTURING INITIATIVES IN OTHER 10 JURISDICTIONS? 11 A. No. As discussed in the testimony of Mr. Baker, the SWEPCO transmission assets 12 and employees located in Texas will be transferred to the SWEPCO Texas EDC. 13 Also, as discussed in the testimony of Mr. John Aaron, the financial data from the 14 books of the SWEPCO Texas EDC and SWEPCO will be combined to obtain the total 15 transmission costs of the entire SWEPCO system. Combining the transmission 16 investments and costs will result in the calculation of total SWEPCO transmission 17 costs on a basis substantially the same as SWEPCO used in its last proceeding. As a 18 result, the potential for material effects on SWEPCO's jurisdictional allocation of 19 transmission-related costs to the Louisiana retail customers is minimized. 20 Q. WILL THE ASSIGNMENT OF DISTRIBUTION-RELATED INVESTMENT TO 21 THE LOUISIANA JURISDICTION BE AFFECTED AS A RESULT OF 22 RESTRUCTURING EFFORTS IN OTHER JURISDICTIONS?
DOCKET NOS. U-21453, U-20925, CHRIS POTTER U-22092 (SUBDOCKET C) DIRECT TESTIMONY 11 1 A. No. As discussed earlier in my testimony, SWEPCO jurisdictionally assigns 2 distribution-related investment to each of the three states in which SWEPCO operates 3 on a situs basis. Restructuring will not change the physical location of the distribution- 4 related investments; and as such, there should be little change in the amount of 5 distribution-related investment allocated to the Louisiana retail jurisdiction. 6 Q. WILL THERE BE AN EFFECT ON THE DISTRIBUTION-RELATED O&M 7 EXPENSES ASSIGNED TO THE LOUISIANA JURISDICTION? 8 A. Yes. Previously, distribution-related O&M costs were allocated to the jurisdictions 9 based on the respective plant accounts assigned to each jurisdiction. Because of 10 restructuring, certain O&M costs will now be directly assigned to the Texas 11 jurisdiction. As a result, the remaining O&M expenses will be allocated to the 12 Arkansas and Louisiana jurisdictions, consistent with past ratemaking treatment, based 13 upon the respective plant in each of the jurisdictions. 14 Q. WILL GENERAL PLANT, ADMINISTRATIVE AND GENERAL COSTS, AND 15 OTHER COMMON COSTS CONTINUE TO BE ALLOCATED BASED UPON 16 THE METHODOLOGIES UTILIZED IN THE LAST LPSC FILING? 17 A. Not necessarily. As a result of the restructuring initiatives, SWEPCO will be required 18 to keep more precise, jurisdictional-specific data to separate the bookkeeping of the 19 SWEPCO Texas EDC from the other SWEPCO jurisdictions. This separate 20 bookkeeping will allow SWEPCO to directly assign many of the costs, including 21 payroll and some O&M expenses to specific jurisdictions. Mr. Aaron discusses this 22 separation of costs in his direct testimony. If direct assignment is not available,
DOCKET NOS. U-21453, U-20925, CHRIS POTTER U-22092 (SUBDOCKET C) DIRECT TESTIMONY 12 1 SWEPCO intends to allocate these costs consistent with previously used 2 methodologies unless cost causation principles support a change. If the cost causation 3 factors indicate that a change in allocation methodologies is warranted, SWEPCO will 4 fully support any such methodology change, which will be reviewed by the 5 Commission in SWEPCO's next rate filing. 6 Q. WILL THE ALLOCATION OF COSTS TO THE LOUISIANA RETAIL 7 CUSTOMERS CHANGE AS A RESULT OF RESTRUCTURING ACTIVITIES IN 8 OTHER JURISDICTIONS? 9 A. No. Once the allocation of SWEPCO total company cost has been made to each of 10 the various jurisdictions, the same retail transmission and distribution allocation 11 methodologies used in the last LPSC filing would be used, unless the cost causation of 12 a particular item changes, requiring that a more appropriate allocator be used. If the 13 cost causation factors indicate that a change in allocation methodologies is warranted, 14 SWEPCO will fully support any such methodology change, which will be reviewed by 15 the Commission in SWEPCO's next rate filing. 16 Q. WHAT WILL THE IMPACT BE TO THE LOUISIANA JURISDICTION AS A 17 RESULT OF THE PROPOSED CHANGES OUTLINED ABOVE? 18 A. At this time, the exact dollar amount impact of the proposed changes in jurisdictional 19 allocation methodologies cannot be quantified. However, none of these allocation 20 methodologies changes are expected to have a material impact on the cost SWEPCO's 21 Louisiana retail customers will pay for electricity.
DOCKET NOS. U-21453, U-20925, CHRIS POTTER U-22092 (SUBDOCKET C) DIRECT TESTIMONY 13 1 Q. HOW DOES SWEPCO INTEND TO TREAT TRANSITION AND 2 TRANSACTION COSTS RESULTING FROM RESTRUCTURING ACTIVITIES 3 IN OTHER JURISDICTIONS? 4 A. It is the Company's intent to directly assign restructuring costs to the states that are 5 implementing restructuring, thereby adhering to cost causation principles. Since 6 Louisiana has not at this time determined that retail competition is in the public 7 interest, no costs from restructuring activities will be allocated to the Louisiana 8 jurisdiction, unless that cost provides a used and useful service to the Louisiana retail 9 customers. If Louisiana implements competition for generation and other services in 10 the future, SWEPCO will allocate an appropriate amount of transition costs to the 11 Louisiana jurisdiction. 12 13 IV. CONCLUSION 14 Q. WILL THE RATEPAYERS OF LOUISIANA BE MATERIALLY AFFECTED AS 15 A RESULT OF IMPLEMENTING COMPETITION IN OTHER SWEPCO 16 JURISDICTIONS? 17 A. No. By establishing the jurisdictional percentage split on a pre-competition load basis 18 for generation related costs, Louisiana retail customers will be protected from any 19 effect competition might have on the jurisdictional allocation of SWEPCO's 20 generation related costs. It is SWEPCO's intent to allocate Louisiana retail customers 21 non-production related costs, except as discussed in earlier in my testimony, in the
DOCKET NOS. U-21453, U-20925, CHRIS POTTER U-22092 (SUBDOCKET C) DIRECT TESTIMONY 14 1 same manner as if restructuring was not occurring in Texas. As a result, the effect on 2 SWEPCO's Louisiana customers should be minimal. 3 Q. DOES THIS CONCLUDE YOUR DIRECT TESTIMONY? 4 A. Yes, it does.
15 DOCKET NOS. U-21453, U-20925, CHRIS POTTER U-22092 (SUBDOCKET C) DIRECT TESTIMONY EX-99.D7 8 c22015_ex99-d7.txt APPLICATION TO TRANSFER JURISDICTIONAL ASSETS Exhibit 99.D-7 UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION American Electric Power Service Corporation ) Docket No. EC01-________________ APPLICATION OF AMERICAN ELECTRIC POWER SERVICE CORPORATION FOR AUTHORIZATION TO TRANSFER JURISDICTIONAL ASSETS Pursuant to Section 203 of the Federal Power Act (Act), 16 U.S.C. ss. 824b (1994), and Part 33 of the Regulations of the Federal Energy Regulatory Commission (Commission), as revised pursuant to Order No. 642, FERC Stats. & Regs. Paragraph 31,111 (2000), American Electric Power Service Corporation (AEPSC), acting on behalf of its affiliates, Central Power and Light Company (CPL), West Texas Utilities Company (WTU), Southwestern Electric Power Company (SWEPCO), Columbus Southern Power Company (CSP) and Ohio Power Company (OPCo), respectfully requests authority for CPL, WTU, SWEPCO, CSP and OPCo to transfer certain jurisdictional facilities to implement their respective plans to separate their generation and power marketing businesses from their transmission and distribution businesses in the states of Texas and Ohio. Acting on behalf of its affiliates, Appalachian Power Company (APCo) and Indiana Michigan Power Company (I&M), AEPSC further requests authority for the transfer by APCo and I&M(1) to a power marketing affiliate (PMA)(2) of their contractual rights and obligations under certain power supply agreements. Acting on behalf of I&M, APCo, OPCo, CSP and Kentucky Power Company (KPCo), AEPSC further requests authority for the transfer by AEPSC, as agent ---------- (1) AEPSC, CPL, WTU, SWEPCO, CSP, OPCo, APCo and I&M are hereinafter referred to collectively as the Applicants. (2) Throughout this Application names are used for affiliates of the Applicants that are intended to be descriptive of the functions such affiliates will serve after the reorganization of the AEP system to comply with the state restructuring laws of Ohio and Texas is completed. Such 2 for I&M, APCo, OPCo, CSP and KPCo, to PMA of certain wholesale power sales agreements with certain wholesale customers. All such transfers of jurisdictional facilities are hereinafter referred to collectively as the Transfers. The Transfers involve wholesale electricity sales contracts, or rights therein, that APCo, CSP, OPCo, I&M and AEPSC, as agent for certain American Electric Power Company, Inc. (AEP) operating companies, plan to assign to PMA,(3) a wholesale electricity sales contract that APCo will assign to OPCo, wholesale electricity sales contracts, or rights therein, that CPL and WTU will assign to power generation company (PGC affiliates, step-up transformers, circuit breakers, interconnection facilities and related facilities associated with generating units that CPL and WTU will transfer to such PGC affiliates, and transmission lines, interconnection agreements and other interstate transmission facilities that SWEPCO, CSP and OPCo will transfer to newly formed energy delivery company (EDC) affiliates that will be chartered to own, maintain and operate transmission and distribution facilities located in the states of Texas and Ohio. Exhibit C to this Application contains diagrams of the pre-Transfer and post-Transfer organizations of Applicants and their relevant affiliates. Exhibit G to this Application contains schedules that list the interconnection facilities associated with generating stations that CPL and WTU will transfer to their PGC affiliates and schedules that list the transmission facilities and interconnection agreements that SWEPCO, CSP and OPCo will transfer to newly formed EDC affiliates. Exhibit G also contains schedules that list the wholesale power sales contracts that ---------- (continued...) names are fictitious and used as a matter of descriptive convenience. The actual legal names of such affiliates will be determined as part of the implementation of such reorganization. (3) The assignment of such contracts is subject to A determination that such assignment will not result in adverse tax consequences to AEP. 3 CSP, OPCo, APCo, I&M and AEPSC, as agent for certain AEP operating companies, respectively, will assign to PMA and schedules that list the wholesale power sales contracts that CPL and WTU will assign to their newly formed PGC affiliates. 1. REASONS FOR THE TRANSFERS CPL, WTU and SWEPCO will make their Transfers to comply with the provisions of a Texas statute commonly referred to as S.B. 7.(4) S.B. 7 requires vertically integrated electric utilities to separate ownership of their generating and other power supply assets from ownership of their transmission and distribution assets no later than January 1, 2002. Under S.B. 7, vertically integrated utilities are generally obligated to disaggregate into at least three separate corporate units: (1) a PGC that will sell power and energy at wholesale; (2) an EDC that will own transmission and local distribution facilities, but is prohibited from owning power supply facilities or selling electricity; and (3) a Retail Electric Provider (REP) that will sell electricity to retail customers. By order issued July 7, 2000, the Public Utility Commission of Texas (PUCT) approved corporate separation plans CPL, WTU and SWEPCO filed to explain how they will comply with S.B. 7 (see Exhibit L to this Application). In their corporate separation plans, CPL and WTU proposed to transfer their respective generating facilities and associated jurisdictional facilities to separate, newly formed PGC affiliates and SWEPCO proposed to transfer its transmission and distribution facilities located in Texas to an EDC affiliate. CSP and OPCo will make their Transfers to comply with the provisions of an Ohio statute that provides for Competitive Retail Electric Service, commonly referred to as S.B.3.(5) The statute directs vertically integrated electric utilities that offer retail electric service in Ohio to separate their generating and other competitive operations (such as aggregation, marketing, and ---------- (4) Tex. Util. Code Ann. ss. ss. 39.001-909 (Vernon Supp. 2000). 4 brokering) and related assets from their transmission and distribution operations and assets. On September 28, 2000, the Public Utilities Commission of Ohio (PUCO) approved corporate separation plans CSP and OPCo filed to explain how they will comply with S.B. 3 (see Exhibit L to this Application). In their approved corporate separation plans, CSP and OPCo proposed, subject to receipt of federal regulatory approvals, to transfer their transmission and distribution assets and operations to EDC affiliates. The Transfers, which are described in more detail below and in Exhibit I, require the Commission's approval under Section 203 of the Act. As explained in Exhibit J, the Transfers and proposed restructuring of the Applicants will have no material adverse effect on the service provided to their respective wholesale customers, will not diminish competition, and will not hamper the ability of state or federal utility regulatory agencies to regulate the Applicants, or their newly formed affiliates that are subject to utility regulation under state or federal law. By separate filing (Section 205 Filing), the Applicants are submitting for Commission review under Section 205 of the Act certain power sales agreements pursuant to which OPCo, CSP and SWEPCO will sell power and energy to PMA. The restructuring of the operating company subsidiaries of AEP in Ohio and Texas and the related Transfers of jurisdictional assets 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. Separating the ownership and operation of generating facilities of the AEP operating companies that serve Ohio and Texas from ownership and operation of their transmission and distribution assets and the related public utility functions makes such generating capacity fully available to developing wholesale markets and thereby advances the ---------- (continued...) (5) Ohio Rev. Code Ann. ss. ss. 4928.01-67 (Anderson 2000). 5 electric utility restructuring policies of Ohio and Texas and the competition policies of this Commission. Combined with the development of Regional Transmission Organizations (RTOs), the corporate separation of the power supply and energy delivery businesses of AEP's Ohio and Texas operating companies will foster the establishment of a robust wholesale electricity market and concomitant production efficiencies that will benefit all consumers. The Transfers are part of AEP's continuing effort to promote competitive electricity markets. The AEP companies have long been leaders in the development of RTOs, strong advocates for competitive electric markets before federal and state policymakers, and active partners in state efforts to restructure retail markets. AEP operating companies have previously filed to transfer control of their transmission facilities to the Alliance and the Southwest Power Pool (SPP) RTO. Consistent with the Commission's recent orders concerning RTO development, the AEP operating companies are supporting the implementation of the Alliance on schedule and will advocate and support the SPP's participation in a larger RTO, as the Commission has recommended. A. REORGANIZATION OF THE AEP TEXAS OPERATING COMPANIES To comply with S.B. 7, CPL and WTU will contribute their respective generating assets to newly formed PGC affiliates, WTU PGC and CPL PGC.(6) Through a series of transactions described in Exhibit I, the stock of WTU PGC and CPL PGC will be contributed to Domestic Genco, a subsidiary of a new intermediate holding company subsidiary of AEP, Wholesale ---------- (6) CPL has committed to divest by June 2002 its Lon Hill Units 1-4, which have an aggregate generating capability of 546 MW, its Nueces Bay plant, which has a generating capability of 559 MW, and its Joslin Unit 1, which has a generating capability of 249 MW, subject to certain recall rights with respect to CPL's obligation to serve retail customers in the Electric Reliability Council of Texas (ERCOT). CPL made this commitment in connection with the PUCT proceedings brought to consider the merger of Central and South West Corporation (CSW) and AEP. 6 Holdco, which will own the common stock of AEP subsidiaries that are engaged in "unregulated" activities in competitive wholesale electricity markets.(7) CPL and WTU also will assign their existing contracts for wholesale electric sales to CPL PGC and WTU PGC, respectively. This will result in the customers served under such contracts being served from the same basic set of power supply resources that CPL or WTU would have used to serve such customers if S.B. 7 had not required CPL and WTU to disaggregate. The contracts to be assigned contain fuel adjustment clauses and transferring the contracts to the PGCs will enable the accurate tracking of actual fuel costs. SWEPCO will retain title to its generating assets because it provides bundled retail electric service in Louisiana, which to date has not adopted a retail competition policy or legislation, and in Arkansas, where SWEPCO is not obligated to separate ownership of its generating assets from its transmission and distribution assets.(8) SWEPCO also will retain its existing wholesale electric sales contracts, but will sell to PMA proportionate rights to capacity in each SWEPCO generating unit and certain capacity purchase agreements equal to the ratio to SWEPCO's calendar year 2000 summer month peak loads of the sum of the coincident loads represented by retail customers served in Texas and SWEPCO's wholesale requirements customers. Such capacity and associated energy will be made available to PMA under a Unit Power Sales Agreement that is being submitted for Commission review as part of the Section 205 Filing. To enable SWEPCO to continue to supply its wholesale requirements customers PMA will sell back to SWEPCO under a second Unit Power Sales Agreement the capacity and ---------- (7) CPL and WTU may delay the transfer of their stock in CPL PGC and WTU PGC until sometime after June 15, 2002, in order to avoid adverse tax consequences relating to intracorporate transfers after a merger. (8) The Arkansas legislature recently postponed the start of retail electric competition in Arkansas to a date no earlier than October 1, 2003 and no later than October 1, 2005. 7 associated energy needed for that purpose, which also is being submitted for Commission review as part of the Section 205 Filing.(9) CPL and WTU will retain their respective transmission and distribution assets and after transfer of their generating assets to CPL PGC and WTU PGC, CPL and WTU will operate as EDCs. On or before January 1, 2002, SWEPCO will contribute its transmission and distribution assets located in Texas and related business operations to a wholly owned EDC subsidiary, SWEPCO EDC, the stock of which will be transferred in a series of transactions described in Exhibit I to CSW, which now holds all of the common stock of CPL and WTU. As illustrated by the post-Transfer organizational chart contained in Exhibit C, CSW also will hold the common stock of other regulated subsidiaries of AEP. The transmission facilities of CPL and WTU that are located in the ERCOT region will be operated as part of the ERCOT network and a single control area under the supervision of ERCOT, which the PUCT has found meets the requirements of an independent transmission organization under Section 39.151 of S.B. 7. The transmission facilities that SWEPCO will transfer to SWEPCO EDC, as well as the transmission facilities located in Arkansas and Louisiana that SWEPCO will retain, and the non-ERCOT transmission facilities of WTU, are expected to be operated as part of a RTO.(10) ---------- (9) Until such time as the PUCT determines the power market in which SWEPCO operates to be competitive, SWEPCO REP will retain an obligation to continue to offer power supply to such large commercial and industrial customers at cost-based rates. The second Unit Power Sales Agreement contains provisions for the sale back to SWEPCO of capacity that will enable SWEPCO to furnish to SWEPCO REP the capacity it will need to meet this obligation. In the event the PUCT delays retail choice in SWEPCO's Texas service area altogether, the second Unit Power Sales Agreement further provides for the sale back to SWEPCO of capacity it will need to fulfill its continuing responsibility to serve Texas retail customers. (10) On April 27, 2001, as supplemented on May 29, 2001, SWEPCO, WTU and Public Service Company of Oklahoma (PSO) filed an application under Section 203 of the Act in Docket 8 Under S.B. 7, retail customers served by CPL, WTU and SWEPCO in Texas will become eligible for direct access to competing sellers of retail electricity supply by January 1, 2002. As illustrated on the post-Transfer organizational chart contained in Exhibit C to this Application, AEP will establish as a first-tier subsidiary an intermediate holding company, Retail Holdco, that will own the controlling interests in retail electric marketing entities (REPs) established to provide competitive retail electric services in Texas. Retail Holdco will control three REPs that on and after January 1, 2002, will offer retail electric service to the residential and small commercial customers formerly served by CPL, WTU and SWEPCO at rates that on a bundled basis are six percent less than the residential and small commercial customer rates in effect on December 31, 1999 (the "price to beat"). As a part of the Texas retail access program, the currently effective Texas retail rates of CPL, WTU and SWEPCO are frozen until December 31, 2001. On and after January 1, 2002, retail residential and small commercial customers formerly served by CPL, WTU and SWEPCO will be served either by the REPs associated with CPL, WTU and SWEPCO, respectively, at the "price to beat" established by the PUCT for their respective Texas service areas or by an alternative retail electric supplier not affiliated with the Applicants. ---------- (continued ... ) No. EC01-94-000, to transfer operational control of their transmission facilities located in the SPP to the SPP RTO. By order issued July 12, 2001 in Docket Nos. RT01-34-000, et al., 96 FERC paragraph 61,062 (2001), the Commission rejected such application because it found that the proposed SPP RTO did not meet the scope and configuration requirements of Order No. 2000. The AEP operating companies that own transmission facilities in the SPP region are currently participating in the mediation being conducted under Commission auspices. PSO, SWEPCO, and WTU support the participation of the SPP transmission owners in a larger RTO that will meet the scope requirements of Order No. 2000, as the Commission has recommended. 9 B. REORGANIZATION OF THE OHIO AEP OPERATING COMPANIES To comply with S.B. 3, CSP and OPCo will contribute their transmission and distribution assets to new EDC subsidiaries (CSP EDC and OPCo EDC).(11) The common stock of OPCo EDC and CSP EDC will be contributed to AEP. AEP, in turn, will contribute such common stock to CSW. Surviving CSP and OPCo will be PGCs whose common stock AEP will contribute to Domestic Genco through a series of transactions described in Exhibit I. CSP PGC will retain its contracts to serve wholesale requirements customers because such contracts contain fuel adjustment clauses that require the tracking of CSP PGC fuel costs. OPCo PGC will retain its contracts with Buckeye Power, Inc., under which OPCo, among other things, provides back-up and supplemental power to Buckeye, and with Buckeye's affiliate National Power Cooperative, Inc., under which OPCo provides similar power supply services. OPCo will, however, assign to APCo the contract under which OPCo supplies the power and energy requirements of Wheeling Power Company, an affiliated transmission and distribution utility that serves retail customers in West Virginia. APCo serves retail and wholesale customers in Virginia and West Virginia. Wheeling Power has agreed with the West Virginia Public Service Commission to modify its rates for retail service over a four-year period to make them equal to APCo's West Virginia retail rates, which are lower than Wheeling Power's currently effective retail rates. Assigning the Wheeling Power contract to APCo will result in Wheeling Power's obtaining its requirements for electricity from the same portfolio of power supply resources that underlie APCo's West Virginia retail rates. ---------- (11) The transmission facilities of CSP include Transmission Agreements among owners of certain Ohio generating facilities jointly owned by CSP, Dayton Power and Light Company and Cincinnati Gas and Electric Company, which are listed in Exhibit G. 10 Under S.B. 3, CSP EDC and OPCo EDC must serve as default suppliers to retail customers that do not choose an alternative power supplier. The rates Ohio retail residential customers will pay for default power supply after January 1, 2001 have been reduced by five percent from the power supply component of bundled rates in effect prior to that date. The rates for power supply that OPCo EDC and CSP EDC will charge all Ohio retail customers that do not choose an alternative supplier will be frozen for the first five years of retail competition, unless the PUCO finds that effective competition with respect to particular retail customer classes is occurring before the end of a five-year market development period. CSP and OPCo are participants in the Alliance Regional Transmission Organization and CSP EDC and OPCo EDC will take on the Alliance responsibilities of CSP and OPCo, respectively. (12) II. DESCRIPTION OF POWER SUPPLY ARRANGEMENTS The Transfers will necessitate new power supply arrangements to enable PMA to continue to serve the existing wholesale requirements customers of AEPSC, as agent for certain AEP operating companies, under the terms of the rate schedules listed on Exhibit G to this Application and to provide CSP EDC and OPCo EDC capacity and energy that they require to serve Ohio retail customers that are entitled to service at frozen rates during the Ohio market development period. PMA also plans to bid to supply capacity and energy needed by CPL REP, WTU REP and SWEPCO REP to serve Texas customers that do not choose alternative suppliers. If those bids are successful, PMA will enter into power supply agreements with its affiliated Texas REPs. ---------- (12) The Commission has approved the Alliance as an RTO in most respects. ALLIANCE COMPANIES, ET AL., 89 FERC paragraph 61,298 (1999); ALLIANCE COMPANIES, ET AL., 91 FERC paragraph 61,152 (2000); ALLIANCE COMPANIES, ET AL., 94 FERC paragraph 61,070 (2001); ALLIANCE COMPANIES, ET AL., 95 FERC paragraph 61,182(2001); ALLIANCE COMPANIES, ET AL., 96 FERC paragraph 61,052 (2001). 11 A. POWER SUPPLY AGREEMENTS BETWEEN PGCS AND PMA PMA will enter into a Power Supply Agreement (PSA) with each of Domestic Genco's PGC subsidiaries, CPL PGC, WTU PGC, OPCo PGC and CSP PGC. Such PSAs will entitle PMA to schedule and purchase the entire output of the PGCs' respective generating stations not needed to serve wholesale customers under contracts assigned to or retained by the PGCs. The PSAs under which PMA will purchase capacity and energy from CSP PGC and OPCo PGC are being submitted for Commission review as part of the Section 205 Filing. B. PMA'S SALES TO WHOLESALE CUSTOMERS OF AEPSC After the wholesale requirements power supply agreements of AEPSC, as agent for certain AEP operating companies, are assigned to PMA, PMA will provide service to the wholesale customers served under such contracts in accordance with the terms and conditions of and at the rates contained in such power supply agreements. C. PMA'S SALES TO RETAIL AFFILIATES In order to supply OPCo EDC and CSP EDC with capacity and energy required to serve Ohio retail customers that are entitled to service at frozen rates (default service) during the Ohio market development period, PMA will enter into default service supply agreements with OPCo EDC and CSP EDC, respectively. The contracts will be in place during the time that OPCo EDC and CSP EDC retain a default service obligation at frozen rates (through 2005 unless the PUCO ends the market development period earlier). These contracts will insure cost-based service to OPCo EDC and CSP EDC for forecasted default service demand and will be filed with the Commission in the near future. PMA also will bid to supply capacity and energy needed by the Texas REPs to meet their obligations to supply "price to beat" customers. 12 D. INTERCONNECTION AGREEMENTS Each of Domestic Genco's PGC subsidiaries that takes, or retains, title to generating stations formerly owned by a vertically integrated AEP operating company will enter into an Interconnection Agreement with the EDC subsidiary of AEP that owns the transmission system to which the PGC subsidiary's stations are connected. Such Interconnection Agreements will govern the operation and maintenance of the station interconnections. Such Interconnection Agreements will follow in substantial part the standard forms currently used by AEPSC, as agent for the AEP operating companies, and AEPSC plans to file such agreements with the Commission prior to December 31, 2001. E. ASSIGNMENT OF CERTAIN OTHER AGREEMENTS As part of the reorganization of the AEP system to implement the retail choice laws of Texas and Ohio, I&M, APCo, OPCo, and CSP will assign to PMA their rights and obligations under the Inter-Company Power Agreement, dated July 10, 1953 (OVEC Agreement), to PMA and I&M will assign to PMA its rights and obligations under a Unit Power Agreement between I&M and AEP Generating Company, dated March 31, 1982 (Rockport Agreement). AEP and CSP own interests in Ohio Valley Electric Corporation (OVEC), which supplies the power requirements of a U.S. Department of Energy (DOE) uranium enrichment plant located near Portsmouth, Ohio. APCo, OPCo, CSP and I&M are entitled by contract to receive from OVEC, and are obligated to pay for, power not required by DOE. The costs of such DOE power are not reflected in rates charged by APCo, OPCo, CSP and I&M to their retail or wholesale customers.(13) I&M is contractually entitled to 455 MW of AEP Generating Company's interest in Rockport Unit No. 1, which AEP Generating Company had previously committed to sell to an ---------- (13) In MONONGAHELA POWER COMPANY, 93 FERC Paragraph 62,117 (2000), the Commission approved a similar assignment of interests in the OVEC Agreement. 13 unaffiliated purchaser in a transaction that recently ended. Beginning January 1, 2005, I&M is also contractually entitled to receive from AEP Generating Company 195 MW of capacity from Rockport Unit No. 1 and associated energy and an additional 195 MW of capacity from Rockport Unit No. 2 and associated energy, all of which capacity is currently committed to a sale by AEP Generating Company to KPCo. The costs of I&M's entitlement to capacity and energy from such interests in Rockport Unit Nos. 1 and 2 are not reflected in I&M's rates to its retail or wholesale customers. The Transfers by APCo, CSP, OPCo and I&M to PMA of such rights to OVEC and Rockport Unit No. 1 output will serve to separate system power supply resources that are appropriately dedicated to the supply of traditional public utility customers from power supply resources that should be dedicated to competitive wholesale power markets. North Carolina Electric Membership Corporation (NCEMC) currently purchases capacity and energy from the AEP-East system under a Power Supply Agreement dated August 22, 1994, which terminates in 2010. Such sale is made from the system resources of APCo, KPCo, OPCo, CSP and I&M after their native load requirements are met. APCo will assign the NCEMC contract to OPCo, which after the reorganization of OPCo and CSP to comply with S.B. 3, will control power supply resources adequate to serve NCEMC. III. INFORMATION REQUIRED BY SECTIONS 33.2 AND 33.3 OF THE COMMISSION'S REGULATIONS Information required by Sections 33.2 and 33.3 of the Commission's regulations is set out below and in the referenced exhibits. To the extent necessary, AEPSC requests waiver of the Commission's regulations to permit the Commission to accept this Application as in sufficient compliance with the Commission's regulations. 14 A. NAMES AND ADDRESSES OF PRINCIPAL BUSINESS OFFICES American Electric Power Service Corporation 1 Riverside Plaza Columbus, Ohio 43215 Appalachian Power Company P.O. Box 2021 Roanoke, Virginia 24022 Columbus Southern Power Company 1 Riverside Plaza Columbus, Ohio 43215 Ohio Power Company 301 Cleveland Avenue, SW Canton, Ohio 44702 Indiana Michigan Power Company One Summit Square P.O. Box 60 Fort Wayne, Indiana 46801 Central Power and Light Company 539 North Caranchua Corpus Christi, Texas 78403 West Texas Utilities Company 301 Cypress Abilene, Texas 79601 Southwestern Electric Power Company 428 Travis Street P.O. Box 21106 Shreveport, Louisiana 71101 15 B. NAMES AND ADDRESSES OF PERSONS AUTHORIZED TO RECEIVE NOTICES AND COMMUNICATIONS WITH RESPECT TO THE APPLICATION Edward J. Brady, Esq. J. A. Bouknight Kevin F. Duffy, Esq. Douglas G. Green American Electric Power Service Steptoe & Johnson Corporation 1330 Connecticut Avenue, NW 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 jbouknight@steptoe.com ejbrady@aep.com dgreen@steptoe.com kfduffy@aep.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 C. PROPOSED ACCOUNTING ENTRIES Proposed accounting entries for the Transfers are included with Exhibit H hereto. D. FORM OF NOTICE A form of notice, in both hard copy and on diskette, suitable for publication in the Federal Register is included with this Application. E. EXHIBITS In accordance with Part 33 of the Commission's regulations, Exhibits A through L are attached to this Application. 16 IV. RELIEF REQUESTED For the reasons set forth herein, AEPSC respectfully requests waiver of the Commission's filing requirements as deemed necessary and that the Commission issue an order authorizing the Transfers no later than December 31, 2001. Respectfully submitted, AMERICAN ELECTRIC POWER SERVICE CORPORATION By: /s/ Edward J. Brady ---------------------------------------- Edward J. Brady, Esq. Kevin F. Duffy, Esq. American Electric Power Service Corporation 1 Riverside Plaza Columbus, Ohio 43215 614-223-1617 - voice 614-223-1687 - fax 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 J. A. Bouknight Douglas G. Green Steptoe & Johnson LLP 1330 Connecticut Avenue, NW Washington, DC 20036-1795 202-429-3000 - voice 202-429-3902 - fax Submitted: July 24, 2001 UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION American Electric Power Service Corporation ) Docket No. ECO1- -000 VERIFICATION STATE OF NEW YORK ) ) COUNTY OF NEW YORK ) NOW, BEFORE ME, the undersigned authority, personally came and appeared, J. Craig Baker, who, after first being duly sworn by me, did depose and say: That he is Senior Vice President - Regulation and Public Policy of American Electric Power Service Corporation, the Applicant in the above proceeding; that he has the authority to verify the foregoing Application on behalf of American Electric Power Service Corporation; that he has read said Application and knows the contents thereof; and that all of the statements contained in said Application are true and correct to the best of his knowledge and belief. /s/ J. Craig Baker ------------------------- J. Craig Baker SUBSCRIBED AND SWORN TO before me this 20th day of July, 2001. /s/ Karen Shelton ---------------------- Notary Public KAREN SHELTON NOTARY PUBLIC, STATE OF NEW York My Commission Expires: NO-01SH6018418 County of Residence: QUALIFIED IN NEW YORK COUNTY COMMISSION EXPIRES JAN. 11, 2003 [SEAL] NOTICE UNITED STATES OF AM[ERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION American Electric Power Service Corporation ) Docket No. ECO1- -000 NOTICE OF FILING Take notice that on July 24, 200 1, American Electric Power Service Corporation (AEPSC), acting on behalf of certain electric utility subsidiaries of American Electric Power Company, Inc., (AEP) submitted an application for approval for the transfer of certain jurisdictional facilities among AEP subsidiaries, pursuant to Section 203 of the Federal Power Act (Act), 16 U.S.C. ss. 824b (1994), and Part 33 of the Regulations of the Federal Energy Regulatory Commission (Commission), as reviscd pursuant to Order No. 642, FERC Stats. & Regs. paragraph 31,111 (2000). Such transfers are proposed to be made to comply with electric utility restructuring laws of Ohio and Texas and to foster the development of competitive electric markets consistent with such state laws. AEPSC states that a copy of the filing has been served on the public service commissions of Ohio, Texas, Arkansas, Indiana, Kentucky, Louisiana, Michigan, Tennessee, Virginia, West Virginia and Oklahoma. Any person desiring to be heard or to protest such filing should file a motion to intervene or protest with the Federal Energy Regulatory Commission, 888 First Street, N.E., Washington D.C. 20426, in accordance with Rules 211 and 214 of the Commission's Rules of Practice and Procedure (18 CFR 385.211 and 385.214). All such motions and protests should be filed on or before . Protests will be considered by the Commission to detennine the appropriate action to be taken, but will not serve to make protestants parties to the proceedings. Any person wishing to become a party must file a motion to intervene. Copies of this filing are on file with the Commission and are available for public inspection. This filing may also be viewed on the Internet at http://www.ferc.fed.us/online/rims/htm (call 202-208-2222 for assistance). David P. Boergers Secretary EXHIBIT A BUSINESS ACTIVITIES OF THE APPLICANTS A. CSP is a corporation organized and existing under the laws of the state of Ohio, and has its principal office in Columbus, Ohio. CSP is a wholly owned subsidiary of AEP. CSP is engaged in generating, transmitting and distributing electric energy to the public in central and southern Ohio and is a public utility under Section 201 of the Act. CSP owns 2,595 MW of coal-fired generating capacity, which includes 1,330 MW in generating facilities jointly owned with two unaffiliated utilities. CSP serves approximately 668,000 retail customers in Ohio. CSP also sells electricity to wholesale customers. B. OPCo is a corporation organized and existing under the laws of the state of Ohio, and has its principal office in Canton, Ohio. OPCo is a wholly owned subsidiary of AEP. OPCo is engaged in generating, transmitting and distributing electric energy to the public in northwestern, east central, eastern and southern Ohio and is a public utility under Section 201 of the Act. OPCo owns 8,464 MW of coal-fired generating capacity and 48 MW of hydroelectric generating capacity. OPCo serves approximately 696,000 retail customers in Ohio. OPCo also sells electricity to wholesale customers. C. APCo is a corporation organized and existing under the laws of the Commonwealth of Virginia, and has its principal office in Roanoke, Virginia. APCo is a wholly owned subsidiary of AEP. APCo is engaged in generating, transmitting and distributing electric energy to the public in southwestern Virginia and southern West Virginia and is a public utility under Section 201 of the Act. APCo owns 5,081 MW of coal-fired generating capacity and 777 MW of hydroelectric generating capacity. APCo supplies electricity at retail to approximately 909,000 customers. Approximately 53% of APCo's retail sales are to customers in Virginia and approximately 47% of such sales are to customers in West Virginia. APCo also sells electricity to wholesale customers. D. CPL is a corporation organized and existing under the laws of the state of Texas, and has its principal office in Corpus Christi, Texas. CPL is a wholly owned subsidiary of CSW, and an indirect subsidiary of AEP. CPL is engaged in generating, transmitting and distributing electric energy to the public in south Texas and is a public utility under Section 201 of the Act. CPL also owns an undivided 25.2% interest in STP Nuclear Operating Company, which operates and maintains the South Texas Project nuclear generating station (STP), of which CPL owns an undivided 25.2% interest, or approximately 630 MW. In addition to its undivided interest in STP, CPL owns 3,867 MW of coal- and gas-fired and hydroelectric generating capacity. CPL serves approximately 680,000 retail customers. CPL also sells electricity to wholesale customers. E. WTU is a corporation organized and existing under the laws of the state of Texas, and has its principal office in Abilene, Texas. WTU is a wholly owned subsidiary of CSW, and an indirect subsidiary of AEP. WTU is engaged in generating, transmitting and distributing electric energy to the public in west and central Texas and is a public utility under Section 201 of the Act. WTU owns 1,376 MW of coal- and gas-fired generating capacity, and 16 MW of wind and oil-fired generating capacity. WTU serves approximately 190,000 retail customers. WTU also sells electricity to wholesale customers. F. SWEPCO is a corporation organized and existing under the laws of the state of Delaware, and has its principal office in Shreveport, Louisiana. SWEPCO is a wholly owned subsidiary of CSW, and an indirect subsidiary of AEP. SWEPCO is engaged in generating, transmitting and distributing electric energy to the public in northeastern Texas, northwestern 2 Louisiana and western Arkansas and is a public utility under Section 201 of the Act. SWEPCO owns 3,645 MW of coal- and gas-fired generating capacity and 842 MW of lignite-fired generating capacity. SWEPCO serves approximately 428,000 retail customers. SWEPCO also sells electricity to wholesale customers. G. I&M is a corporation organized and existing under the laws of the state of Indiana, and has its principal office in Fort Wayne, Indiana. I&M is a wholly owned subsidiary of AEP. I&M is engaged in generating, transmitting and distributing electric energy to the public in northern and eastern Indiana and a portion of southwestern Michigan and is a public utility under Section 201 of the Act. I&M owns or leases 2,295 MW of coal-fired generating capacity and 2,110 MW of nuclear generating capacity and 11 MW of hydroelectric generating capacity. I&M serves approximately 565,000 retail customers. I&M also sells electricity to wholesale customers. H. KPCo is a corporation organized and existing under the laws of Kentucky. KPCo is a wholly owned subsidiary of AEP. KPCo is engaged in generating, transmitting and distributing electric energy to the public in eastern Kentucky and is a public utility under Section 201 of the Act. KPCo owns 1,060 MW of coal-fired generating capacity. KPCo serves approximately 172,000 retail customers. KPCo also sells electricity to wholesale customers. 3 EXHIBIT B LIST OF ENERGY SUBSIDIARIES AND ENERGY AFFILIATES AND THEIR BUSINESS ACTIVITIES There is attached to this Exhibit B a list of energy subsidiaries and energy affiliates and a general description of their business interests. EXHIBIT B Page 1 of 8 LIST OF ENERGY SUBSIDIARIES AND ENERGY AFFILIATES AND THEIR BUSINESS ACTIVITIES NAME OF COMPANY PERCENTAGE BUSINESS ACTIVITY OF OWNERSHIP AEP Generating Company 100 Generation AEP Power Marketing, Inc. 100 Power marketing AEP Pro Serv, Inc. 100 Consulting, projects and other non-regulated energy-related services AEP Retail Energy LLC 100 Retail and wholesale electricity American Electric Power Service Corporation 100 Management, professional and technical services Appalachian Power Company 98.7 Domestic electric utility Cedar Coal Co. 100 Coal Mining (inactive) Central Appalachian Coal Company 100 Coal Mining (inactive) Central Coal Company 100 Coal Mining (inactive) Southern Appalachian Coal Company 100 Coal Mining (inactive) West Virginia Power Company 100 Inactive Columbus Southern Power Company 100 Domestic electric utility Colomet, Inc. 100 Inactive Conesville Coal Preparation Company 100 Coal preparation Simco Inc. 100 Inactive Ohio Valley Electric Corporation 44.2 Generation EXHIBIT B PAGE 2 OF 8 Indiana Michigan Power Company 100 Domestic electric utility Blackhawk Coal Company 100 Coal mining (inactive) Price River Coal Company 100 Coal mining (inactive) Kentucky Power Company 100 Domestic electric utility Kingsport Power Company 100 Domestic electric utility Ohio Power Company 99.2 Domestic electric utility Indiana-Kentucky Electric Corporation 44.2 Generation Central and South West Corporation 100 Subsidiary holding company Central Power and Light Company 100 Domestic electric utility Public Service Company of Oklahoma 100 Domestic electric utility Ash Creek Mining Company 100 Inactive Southwestern Electric Power Company 100 Domestic electric utility The Arklahoma Corporation 47.6 Electric Transrnission Southwest Arkansas Utilities Corporation 100 Inactive West Texas Utilities Company 100 Domestic electric utility CSW Energy, Inc. 100 Independent Power CSW Development-I, Inc. 100 Independent Power Polk Power GP II, Inc. 50 Independent Power Polk Power GP, Inc. 50 Independent Power Polk Power Partners, LP 50 Independent Power EXHIBIT B Page 3 of 8 CSW Mulberry II, Inc. 100 Independent Power CSW Mulberry, Inc. 100 Independent Power Noah I Power GP, Inc. 100 Independent Power Noah I Power Partners, LP 95.5 Independent Power Brush Cogeneration Partners 50 Independent Power Orange Cogeneration GP II, Inc. 50 Independent Power Orange Cogeneration GP Inc. 50 Independent Power Orange Cogeneration Limited Partnership 50 Independent Power CSW Orange II, Inc. 100 Independent Power CSW Orange, Inc. 100 Independent Power Orange Cogen Funding Corp. 100 Independent Power Orange Holdings, Inc. 100 Inactive CSW Development -II, Inc. 100 Inactive CSW Ft. Lupton, Inc. 100 Independent Power Thermo Cogeneration Partnership, LP 50 Independent Power Newgulf Power Venture, Inc. 100 Independent Power CSW Sweeny GP I, Inc. 100 Independent Power CSW Sweeny GP II, Inc. 100 Independent Power CSW Sweeny LP I, Inc. 100 Independent Power CSW Sweeny LP II, Inc. 100 Independent Power EXHIBIT B PAGE 4 OF 8 Sweeny Cogeneration Limited Partnership 50 Independent Power CSW Development-3, Inc. 100 Inactive CSW Northwest GP, Inc. 100 Inactive CSW Northwest LP, Inc. 100 Inactive CSW Power Marketing, Inc. 100 Power Marketing CSW Nevada, Inc. 100 Inactive Diversified Energy Contractors Company, LLC 90 Consulting, projects and other non-regulated energy-related services DECCO II LLC 100 Consulting, projects and other non-regulated energy-related services Diversified Energy Contractors, LP 100 Consulting, projects and other non-regulated energy-related services Industry and Energy Associates, LLC 100 Consulting, projects and other non-regulated energy-related services CSW Frontera GP I, Inc. 100 Independent Power (inactive) CSW Frontera GP II, Inc. 100 Independent Power (inactive) CSW Frontera LP I, Inc. 100 Independent Power (inactive) CSW Frontera LP II, Inc. 100 Independent Power (inactive) CSW Eastex GP I, Inc. 100 Independent Power CSW Eastex GP II, Inc. 100 Independent Power Eastex Cogeneration Limited Partnership 100 Independent Power CSW Eastex LP I, Inc. 100 Independent Power EXHIBIT B PAGE 5 OF 8 CSW Eastex LP II, Inc. 100 Independent Power Southwestern Electric Wholesale Company 100 Inactive Enershop, Inc. 100 Consulting, projects and other non-regulated energy-related services Envirotherm, Inc. 100 Consulting, projects and other non-regulated energy-related services CSW Energy Services, Inc. 100 Consulting, projects and other non-regulated energy-related services Nuvest, L.L.C. 92.9 Consulting, projects and other non-regulated energy-related services National Temporary Services, Inc. 92.9 Consulting, projects and other non-regulated energy-related services Octagon Inc. 92.9 Consulting, projects and other non-regulated energy-related services Numanco, L.L.C. 92.9 Consulting, projects and other non-regulated energy-related services Power Systems Energy Services, Inc. 92.9 Consulting, projects and other non-regulated energy-related services NuSun, Inc. 92.9 Consulting, projects and other non-regulated energy-related services Sun Technical Services, Inc. 92.9 Consulting, projects and other non-regulated energy-related services Calibration Testing Corporation 92.9 Consulting, projects and other non-regulated energy-related services ESG Technical Services, L.L.C. 92.9 Consulting, projects and other non-regulated energy-related services EXHIBIT B PAGE 6 OF 8 ESG Manufacturing, L.L.C. 92.9 Consulting, projects and other non-regulated energy-related services National Environmental Services Technology L.L.C. 92.9 Consulting, projects and other non-regulated energy-related services ESG Indonesia, L.L.C. 92.9 Consulting, projects and other non-regulated energy-related services Advance Shielding Technologies, L.L.C. 92.9 Consulting, projects and other non-regulated energy-related services ESG, L.L.C. 50 Consulting, projects and other non-regulated energy-related services Wheeling Power Company 100 Domestic electric utility AEP C&I Company LLC 100 Retail wholesale electricity AEP Energy Management, LLC 100 Worldwide energy related investments, energy trading and other projects AEP Gas Power GP, LLC 100 Consulting, projects and other non-regulated energy-related services AEP Gas Power Systems, LLC 75 Consulting, projects and other non-regulated energy-related services AEP Ohio Commercial & Industrial Retail Company, LLC 100 Retail wholesale electricity AEP Ohio Retail Energy, LLC 100 Retail wholesale electricity AEP T&D Services, LLC 100 Consulting, projects and other non-regulated energy-related services AEP Texas Commercial & Industrial Retail GP, LLC 100 Retail wholesale electricity AEP Texas Commercial & Industrial Retail Limited Partnership 100 Retail wholesale electricity EXHIBIT B PAGE 7 OF 8 AEP Texas Retail GP, LLC 100 Retail wholesale electricity AEP Wind GP, LLC 100 Independent Power AEP Wind LP, LLC 100 Independent Power Dolet Hills Lignite Company, LLC 100 Coal mine operation Lectrix LLC 33.33 Worldwide energy related investments, energy trading and other projects Mutual Energy LLC 100 Retail wholesale electricity Mutual Energy Service Company, LLC 100 Retail wholesale electricity Mutual Energy CPL L.P. 100 Retail wholesale electricity Mutual Energy SWEPCO L.P. 100 Retail wholesale electricity Mutual Energy WTU L.P. 100 Retail wholesale electricity REP General Partner L.L.C. 100 Retail wholesale electricity REP Holdco Inc. 100 Retail wholesale electricity RC Training, LLC 48 Inactive RIKA Management Company, LLC 50 Substation Automation Systems Trent Wind Farm, L.P. 100 Independent Power Universal Power Products Company, LLC 48 Substation automation systems Cardinal Operating Company 50 Generation Automated Substation Development Company LLC 71 Substation automation systems Powerspan Corp. 9.8 Pollution Control Technology Development EXHIBIT B PAGE 8 OF 8 Houston Pipe Line Company 100 Gas LIG Pipeline Company 100 Gas EXHIBIT C ORGANIZATIONAL CHARTS There are attached to this Exhibit C Pre-Transfer and Post-Transfer organizational charts. Target Organizational Structure EXHIBIT C PAGE 1 OF 2
----------------- AEP ----------------- | +-------------------+-----------------------+------------------------+---------------------+ | | | | | ----------------- ----------------- ----------------- ----------------- ----------------- Regulated Texas AEP AEP Holdco AEP Resources/ REP Holdco Enterprises Service Corp (CSW) CSW International ----------------- ----------------- ----------------- ----------------- ----------------- | | +-------------------+-------------------+ +-----------------------------------+ | | | | | ------------- ----------------- ------------- | ------------- ------------- | +-- OPCo EDC APCo --+ Retail Wholesale Comm | ------------- ------------- | Holdco | | ------------- ----------------- ------------- | ------------- ------------- | | +-- CSP EDC I&M --+ +-----------------+--------------+---------------+ | ------------- ------------- | | | | | | | ------------- ------------ ----------- ------------- | ------------- ------------- | Marketing +-- CPL EDC KPCo --+ & Trading Domestic Gasco Pro Serv | ------------- ------------- | PMA Genco | | ------------- ------------ ----------- ------------- | ------------- ------------- | | +-- WTU EDC PSO --+ ------------- | ------------- | ------------- ------------- | WTU PGC --+-- OPCo PGC | | ------------- | ------------- | ------------- ------------- | | +-- KGSPT SWEPCO --+ ------------- | ------------- | ------------- ------------- | CPL PGC --+-- CSP PGC | | ------------- ------------- | ------------- ------------- | +-- WPCo AEG --+ | ------------- ------------- | | ------------- +-- SWEPCO Texas EDC -------------
Current Organizational Structure EXHIBIT C PAGE 2 OF 2 ---------- AEP ---------- | +------------------------+-----------------------+ | | | ------------ | ----------- ---------------- ------------- | APCo --+-- CSP AEP Service Corp CSW Parent ------------ | ----------- ---------------- ------------- | | ------------ | ----------- | | ------------- | ------------- I&M --+-- KPCo | ------------ | ----------- CPL --+-- PSO | ------------- | ------------- ------------ | ----------- | | ------------- | ------------- KGSPT --+-- OPCo | ------------ | ----------- SWEPCO --+-- WTU | ------------- | ------------- ------------ | ----------- | | ------------- | ------------- WPCo --+-- AEG CSW | CSW ------------ | ----------- International--+-- Energy | ------------- | ------------- ------------ | ----------- | AEP Energy | ------------- | ------------- Services --+-- Comm | ------------ | ----------- C3 Comm --+-- Credit | ------------- | ------------- ------------ | ----------- | AEP | ------------- Resources --+-- Pro Serv Texas ------------ | ----------- REP Holdco | ------------- | ----------- | +-- Retail ----------- EXHIBIT D OTHER BUSINESS ARRANGEMENTS The Transfers will not affect the business interests of the Applicants or their affiliates because they will effectuate an internal reorganization that will have no effect on external transactions except with respect to the provision of service under agreements that will be assigned as part of the Transfers. No new joint ventures, strategic alliances, tolling arrangements or other business arrangement with non-affiliated persons will be effected or affected in connection with the Transfers. See Exhibit J for a description of the Applicants' participation in regional transmission organizations. EXHIBIT E COMMON OFFICERS AND DIRECTORS Because the corporate reorganization for which approval is sought is internal and does not involve previously unaffiliated entities, Applicants request waiver of the requirement to file Exhibit E. Good cause exists for such waiver because the information to be reported on Exhibit E is not germane to the Commission's analysis of the Transfers. Applicants and their affiliates that will take title to jurisdictional facilities as the result of the Transfers are members of a registered public utility holding company system and, therefore, their officers and directors have automatic authorization to hold interlocking positions within the registered holding company system pursuant to 18 C.F.R.ss.45.9 (2000). EXHIBIT F DESCRIPTION OF CUSTOMERS There is attached to this Exhibit F a list of the wholesale customers that are served by the AEP operating companies. AEP WHOLESALE CUSTOMER LIST FERC 203 APPLICATION EXHIBIT F Page 1 of 3
CURRENTLY TO BE CUSTOMER LOCATION SERVED BY ASSIGNED TO TYPE -------------------------------------------- -------- ---------- ------------- ---- Arcadia Ohio AEPSC(c) PM AFFILIATE 1 Bloomdale Ohio AEPSC(c) PM AFFILIATE 1 Bryan Ohio AEPSC(c) PM AFFILIATE 1 Carey Ohio AEPSC(c) PM AFFILIATE 1 Clyde Ohio AEPSC(c) PM AFFILIATE 1 Cygnet Ohio AEPSC(c) PM AFFILIATE 1 Deshler Ohio AEPSC(c) PM AFFILIATE 1 Greenwich Ohio AEPSC(c) PM AFFILIATE 1 Ohio City Ohio AEPSC(c) PM AFFILIATE 1 Plymouth Ohio AEPSC(c) PM AFFILIATE 1 Republic Ohio AEPSC(c) PM AFFILIATE 1 St. Clairsville Ohio AEPSC(c) PM AFFILIATE 1 Shiloh Ohio AEPSC(c) PM AFFILIATE 1 Sycamore Ohio AEPSC(c) PM AFFILIATE 1 Wapakoneta Ohio AEPSC(c) PM AFFILIATE 1 Wharton Ohio AEPSC(c) PM AFFILIATE 1 City of Sturgis Michigan AEPSC(c) PM AFFILIATE 1 Radford Virginia AEPSC(c) PM AFFILIATE 1 North Carolina Electric Membership Co-op North Carolina APCO OPCO PGC 2 City of Weatherford (effective 1/1/02) Texas WTU WTU PGC 2 Brazos Electric Cooperative Texas WTU WTU PGC 2 City of Hearne Texas WTU WTU PGC 2 Coleman County Electric Cooperative(a) Texas WTU WTU PGC 2 Taylor Electric Cooperative(a) Texas WTU WTU PGC 2 Concho Valley Electric Cooperative(a) Texas WTU WTU PGC 2 Golden Spread Valley Electric Cooperative(a) Texas WTU WTU PGC 2 Pedernales Electric Cooperative (Formerly Kimble)(a) Texas WTU WTU PGC 2 Lighthouse Electric Cooperative(a) Texas WTU WTU PGC 2 Midwest Electric Cooperative(a) Texas WTU WTU PGC 2 Rio Grande Electric Cooperative-WPC(a) Texas WTU WTU PGC 2 Southwest Texas Electric Cooperative(a) Texas WTU WTU PGC 2 Stamford Electric Cooperative(a) Texas WTU WTU PGC 2 City of Robstown Texas CPL CPL PGC 3 South Texas Electric Cooperative Texas CPL CPL PGC 3 Pedernales Electric Cooperative (Formerly Kimble) Texas CPL CPL PGC 3 Wheeling Electric Power Company West Virginia OPCO APCO 3 Texas-New Mexico Power Company Texas WTU WTU PGC 3 City of Coleman Texas WTU WTU PGC 3 Rio Grande Electric Cooperative-TR1 Texas WTU WTU PGC 3 Tex-La Electric Cooperative Texas WTU WTU PGC 3 Western Farmers Electric Cooperative Texas WTU WTU PGC 3 City of Brady Texas WTU WTU PGC 3 Buckeye Power Ohio CSP CSP EDC 5 Buckeye Power Ohio OPCO OPCO EDC 5 Ohio Edison Ohio OPCO OPCO EDC 5
ACTUAL OR EARLIEST POSSIBLE NOTICE DATE NOTICE TERMINATION DATE REQUIREMENTS CAN BE PROVIDED FERC RATE SCHEDULE ------------------ ----------------- ----------------- ---------------------------------------------- 12/31/2005 Set Term N/A AEP FERC ELECT. TARIFF, VOL. NO. 5, SA NO. 153 12/31/2005 Set Term N/A AEP FERC ELECT. TARIFF, VOL. NO. 5, SA NO. 154 12/31/2005 Set Term N/A AEP FERC ELECT. TARIFF, VOL. NO. 5, SA NO. 155 12/31/2005 Set Term N/A AEP FERC ELECT. TARIFF, VOL. NO. 5, SA NO. 156 12/31/2005 Set Term N/A AEP FERC ELECT. TARIFF, VOL. NO. 5, SA NO. 157 12/31/2005 Set Term N/A AEP FERC ELECT. TARIFF, VOL. NO. 5, SA NO. 158 12/31/2005 Set Term N/A AEP FERC ELECT. TARIFF, VOL. NO. 5, SA NO. 159 12/31/2005 Set Term N/A AEP FERC ELECT. TARIFF, VOL. NO. 5, SA NO. 160 12/31/2005 Set Term N/A AEP FERC ELECT. TARIFF, VOL. NO. 5, SA NO. 161 12/31/2005 Set Term N/A AEP FERC ELECT. TARIFF, VOL. NO. 5, SA NO. 162 12/31/2005 Set Term N/A AEP FERC ELECT. TARIFF, VOL. NO. 5, SA NO. 163 12/31/2005 Set Term N/A AEP FERC ELECT. TARIFF, VOL. NO. 5, SA NO. 164 12/31/2005 Set Term N/A AEP FERC ELECT. TARIFF, VOL. NO. 5, SA NO. 165 12/31/2005 Set Term N/A AEP FERC ELECT. TARIFF, VOL. NO. 5, SA NO. 166 12/31/2005 Set Term N/A AEP FERC ELECT. TARIFF, VOL. NO. 5, SA NO. 167 12/31/2005 Set Term N/A AEP FERC ELECT. TARIFF, VOL. NO. 5, SA NO. 168 7/31/2004 Set Term N/A AEP FERC ELECT. TARIFF, VOL. NO. 5, SA NO. 233 6/30/2005 1 Year Notice 6/30/2004 AEP FERC ELECT. TARIFF, VOL. NO. 5, RS NO. 103 12/31/2010 Set Term N/A APCO FERC RS NO. 135 12/31/02 Evergreen 1 Year Notice 12/31/2001 CSW FERC ELECT. TARIFF, FIRST REV. 12/31/02 - per notice Notice Given to VOL. NO. 8, SA NO. 25 Terminate Effective 12/31/02 3/31/03 Evergreen 1 Year Notice Notice Given CSW FERC ELECT. TARIFF, FIRST REV. VOL. NO. 8, SA NO. 26 12/31/07 Evergreen 3 Years Notice 3/31/2002 WTU RS NO. 76 12/31/07 Evergreen 3 Years Notice 12/31/2004 WTU TARIFF NO. 9, FIRST REVISED SA NO. 1 12/31/07 Evergreen 3 Years Notice 12/31/2004 WTU TARIFF NO. 9, FIRST REVISED SA NO. 10 12/31/07 Evergreen 3 Years Notice 12/31/2004 WTU TARIFF NO. 9, FIRST REVISED SA NO. 2 12/31/07 Evergreen 3 Years Notice 12/31/2004 WTU TARIFF NO. 9, FIRST REVISED SA NO. 3 12/31/07 Evergreen 3 Years Notice 12/31/2004 WTU TARIFF NO. 9, FIRST REVISED SA NO. 4 12/31/07 Evergreen 3 Years Notice 12/31/2004 WTU TARIFF NO. 9, FIRST REVISED SA NO. 5 12/31/07 Evergreen 3 Years Notice 12/31/2004 WTU TARIFF NO. 9, FIRST REVISED SA NO. 6 12/31/07 Evergreen 3 Years Notice 12/31/2004 WTU TARIFF NO. 9, SA NO. 7 12/31/07 Evergreen 3 Years Notice 12/31/2004 WTU TARIFF NO. 9, SA NO. 8 4/15/03 - per notice Notice Given to 12/31/2004 WTU TARIFF NO. 9, SA NO. 9 Terminate Effective 4/15/03 Notice Given CPL RATE SCHEDULE NO. 70 Evergreen 5 Years Notice Anytime CPL TARIFF NO. 1, SA NO. 10 1/31/2002 - per notice Notice Given to Terminate Effective 1/31/02 Notice Given CPL TARIFF NO. 1, SA NO. 8 12/31/04 Evergreen 3 Years Notice 12/31/2001 OPCO FERC RS NO. 18 12/31/04 Evergreen 5 Year Rollover Provision w/3 Year Notification 12/31/2001 WTU RS NO. 39 7/11/02 Evergreen 1 Year Notice Before End of 5 Yr Extension 10/10/2001 WTU RS NO. 40 5/31/07 Evergreen 5 Years Notice 5/31/2002 WTU TARIFF NO. 1, FIRST REVISED SA NO. 19 12/31/09 Evergreen 5 Years Notice 12/31/2004 WTU TARIFF NO. 1, FIRST REVISED SA NO. 18 Evergreen 5 Years Notice Anytime WTU TARIFF NO. 1, SA NO. 13 12/16/2002 Notice Given to Terminate Effective Notice Given WTU TARIFF NO. 1, SA NO. 17 12/16/02 6/30/2003 Set Term N/A CSP FERC RS NO. 17 6/30/2003 Set Term N/A OPCO FERC RS NO. 70 8/1/2005 Set Term N/A OPCO FERC RS NO. 71
Types of Contracts: (1) Fixed Base Rates, No Fuel Clause (2) Fixed Base Rates, With Fuel Clause (3) Base Rates Subject to Change, With Fuel Clause (4) Formula Rate (5) Transmission Service AEP WHOLESALE CUSTOMER LIST FERC 203 APPLICATION EXHIBIT F Page 2 of 3
CURRENTLY TO BE CUSTOMER LOCATION SERVED BY ASSIGNED TO TYPE -------------------------------------------- -------- ---------- ------------- ---- West Va Power Company-subsidiary of Utiliticorp West Virginia AEPSC(c) N/A 1 Cleveland Public Power Ohio OPCO N/A 1 Hoosier Energy Indiana I&M N/A 1 AMP-Ohio Ohio OPCO N/A 1 Kingsport Power Company Tennessee APCO No Assignment 3 Central Virginia Electric Cooperative Virginia APCO No Assignment 3 Craig-Botetourt Electric Cooperative Virginia APCO No Assignment 3 Elk West Virginia APCO No Assignment 3 Elkhorn West Virginia APCO No Assignment 3 Kimball West Virginia APCO No Assignment 3 United West Virginia APCO No Assignment 3 War West Virginia APCO No Assignment 3 Virginia Polytechnic Institute & State University Virginia APCO No Assignment 3 Old Dominion Electric Cooperative-Whitehouse Virginia APCO No Assignment 3 Old Dominion Electric Cooperative-Lynch Virginia APCO No Assignment 3 Old Dominion Electric Cooperative-Evington Virginia APCO No Assignment 3 Union West Virginia APCO No Assignment 3 Black Diamond West Virginia APCO No Assignment 3 Magic Valley Electric Cooperative Texas CPL N/A 3 Medina Electric Cooperative Texas CPL N/A 3 Jackson Ohio CSP No Assignment 3 Westerville Ohio CSP No Assignment 3 Glouster Ohio CSP No Assignment 3 Mishawaka Indiana I&M No Assignment 3 Bluffton Indiana I&M No Assignment 3 Columbia City Indiana I&M No Assignment 3 Auburn Indiana I&M No Assignment 3 Avila Indiana I&M No Assignment 3 Garrett Indiana I&M No Assignment 3 Gas City Indiana I&M No Assignment 3 New Carlisle Indiana I&M No Assignment 3 Niles Michigan I&M No Assignment 3 Warren Indiana I&M No Assignment 3 South Haven Michigan I&M No Assignment 3 Paw Paw Michigan I&M No Assignment 3 United REMC-Wabash Indiana I&M No Assignment 3 Richmond Power & Light Indiana I&M No Assignment 3 Anderson Indiana I&M No Assignment 3 Frankton Indiana I&M No Assignment 3 Carolina Power & Light-Rockport Indiana I&M No Assignment 3 Olive Hill Kentucky KPCO No Assignment 3 Vanceburg Kentucky KPCO No Assignment 3 Western Farmers Electric Cooperative Oklahoma PSO No Assignment 3 City of South Coffeyville Oklahoma PSO No Assignment 3 City of Collinsville Oklahoma PSO No Assignment 3 Northeastern Oklahoma Electric Cooperative Oklahoma PSO No Assignment 3 City of Minden Louisiana SWEPCO No Assignment 3 City of Weatherford (through 12/31/01) Texas WTU N/A 3
ACTUAL OR EARLIEST POSSIBLE NOTICE DATE NOTICE TERMINATION DATE REQUIREMENTS CAN BE PROVIDED FERC RATE SCHEDULE ------------------ ----------------- ----------------- ---------------------------------------------- 12/31/2001 Set Term N/A AEP FERC ELECTRIC TARIFF VOL. NO. 5, SA NO. 144 8/31/2001 Set Term N/A AEPC FERC ELECTRIC TARIFF ORIGINAL VOL. NO. 2 SA NO. 101 12/31/2001 Set Term N/A I&M FERC ELECTRIC TARIFF NO. 6, SA NO. 2 12/31/2001 Set Term N/A OPCO FERC RS NO. 74 12/31/04 Evergreen 3 Years Notice 12/31/2001 APCO FERC RS NO. 0023 Notice given to Terminate 5/21/2002 Effective 5/21/02 Notice Given APCO FERC RS NO. 0099 2/27/03 Evergreen 1 Year Notice 2/27/2002 APCO FERC RS NO. 0102 12/1/2004 Evergreen 3 Years Notice 12/1/2001 APCO FERC RS NO. 0106/0114 (2 DELIVERY PTS) 12/1/2004 Evergreen 3 Years Notice 12/1/2001 APCO FERC RS NO. 0107/0108 (2 DELIVERY PTS) 12/1/2004 Evergreen 3 Years Notice 12/1/2001 APCO FERC RS NO. 0109 12/1/2004 Evergreen 3 Years Notice 12/1/2001 APCO FERC RS NO. 0110 12/1/2004 Evergreen 3 Years Notice 12/1/2001 APCO FERC RS NO. 0113 7/1/2007 Evergreen 3 Years Notice 7/1/2004 APCO FERC RS NO. 0119 Notice given to Terminate 11/17/2003 Effective 11/17/03 Notice Given APCO FERC RS NO. 0126 8/1/01 Evergreen 3 Years Notice 8/1/2001 APCO FERC RS NO. 0127 Notice given to Terminate 11/16/2003 Effective 11/16/03 Notice Given APCO FERC RS NO. 0136 12/1/2004 Evergreen 3 Years Notice 12/1/2001 APCO FERC RS NOS. 0111/0112 (2 DELIVERY PTS) 12/1/2004 Evergreen 3 Years Notice 12/1/2001 APCO FERC TARIFF WS-9, RS NOS. 0103/0104/0105 (3 DELIVERY PTS) Notice Given to Terminate 7/23/2001-per notice Effective 7/23/2001 Notice Given CPL TARIFF NO. 1, FIRST REVISED SA NO. 7 Notice Given to Terminate 10/1/2001-per notice Effective 10/01/01 Notice Given CPL TARIFF NO.1, SA NO. 9 Evergreen 90 Day Notice Anytime CSP FERC ELECTRIC TARIFF VOL. NO. 5, SA 02 12/31/04 Evergreen 3 Years Notice 12/31/2001 CSP FERC ELECTRIC TARIFF VOL. NO. 5, SA 03 Evergreen 90 Day Notice Anytime CSP FERC ELECTRIC TARIFF VOL. NO. 5, SA 04 12/31/03 Evergreen 18 Months Notice 6/30/2002 I&M FERC ELECTRIC TAFIFF ORIGINAL VOL. NO. 5, SA NO. 002 Prior to 6/30/02 for 12/31/03 12/31/03 Evergreen Termination 6/30/2002 I&M FERC ELECTRIC TARIFF ORIGINAL VOL. NO. 7, SA NO.003 12/31/02 Evergreen 1 Year Notice 12/31/2001 I&M FERC ELECTRIC TARIFF ORIGINAL VOL. NO. 7, SA NO. 004 11/23/09 Evergreen 3 Years Notice 11/23/2006 I&M FERC ELECTRIC TARIFF ORIGINAL VOL. NO. 7, SA NO. 013 12/31/03 Evergreen 18 Months Notice 6/30/2002 I&M FERC ELECTRIC TARIFF ORIGINAL VOL. NO. 7, SA NO. 014 12/31/03 Evergreen 18 Months Notice 6/30/2002 I&M FERC ELECTRIC TARIFF ORIGINAL VOL. NO. 7, SA NO. 016 12/31/03 Evergreen 18 Months Notice 6/30/2002 I&M FERC ELECTRIC TARIFF ORIGINAL VOL. NO. 7, SA NO. 017 12/31/03 Evergreen 18 Months Notice 6/30/2002 I&M FERC ELECTRIC TARIFF ORIGINAL VOL. NO. 7, SA NO. 018 12/31/03 Evergreen 18 Months Notice 6/30/2002 I&M FERC ELECTRIC TARIFF ORIGINAL VOL. NO. 7, SA NO. 019 12/31/03 Evergreen 18 Months Notice 6/30/2002 I&M FERC ELECTRIC TARIFF ORIGINAL VOL. NO. 7, SA NO. 020 12/31/03 Evergreen 18 Months Notice 6/30/2002 I&M FERC ELECTRIC TARIFF ORIGINAL VOL. NO. 7, SA NO. 021 12/31/03 Evergreen 18 Months Notice 6/30/2002 I&M FERC ELECTRIC TARIFF ORIGINAL VOL. NO. 9, SA NO. 003 1 Year Notice prior to 3 year 8/8/2010 Evergreen extension 8/8/2009 I&M FERC ELECTRIC TARIFF REVISED VOL. NO. 8, SA NO. 016 12/31/02 Evergreen 1 Years Notice 12/31/2001 I&M FERC RS NO. 70 12/31/02 Evergreen 1 Years Notice 12/31/2001 I&M FERC RS NO. 74 12/31/02 Evergreen 1 Years Notice 12/31/2001 I&M FERC RS NO. 74 12/31/2009 Set Term N/A I&M FERC RS NO. 77, APCO FERC RS NO. 24 12/31/05 Evergreen 4 Years Notice 12/31/2001 KPCO FERC ELECTRIC TARIFF ORIGINAL VOL. NO. 1 SA NO. 1 12/31/05 Evergreen 4 Years Notice 12/31/2001 KPCO FERC ELECTRIC TARIFF ORIGINAL VOL. NO. 2 SA NO. 2 5/31/2002 6 Months Notice 11/30/2001 PSO RS NO. 197 1/20/2003 1 Year Notice 1/20/2002 PSO RS NO. 234 9/30/2005 1 Year Notice 9/30/2001 PSO RS NO. 237 5/25/2005 Set Term N/A PSO RS NO. 240 4/30/05 Evergreen 3 Years Notice 4/30/2002 SWEPCO RS NO. 116 12/31/2001 Set Term N/A WTU RS NO. 73
Types of Contracts: (1) Fixed Base Rates, No Fuel Clause (2) Fixed Base Rates, With Fuel Clause (3) Base Rates Subject to Change, With Fuel Clause (4) Formula Rate (5) Transmission Service AEP WHOLESALE CUSTOMER LIST FERC 203 APPLICATION EXHIBIT F Page 3 of 3
CURRENTLY TO BE CUSTOMER LOCATION SERVED BY ASSIGNED TO TYPE -------------------------------------------- -------- ---------- ------------- ---- Bentonville Arkansas SWEPCO No Assignment 4 East Texas Electric Cooperative Texas SWEPCO No Assignment 4 Rayburn County Electric Cooperative(b) Texas SWEPCO No Assignment 4 Northeast Texas Electric Cooperative Texas SWEPCO No Assignment 4 Tex-La Electric Cooperative Texas SWEPCO No Assignment 4 Tex-La Electric Cooperative (ERCOT) Texas SWEPCO No Assignment 4 Hope Arkansas SWEPCO No Assignment 4 Buckeye Power Ohio OPCO No Assignment 4(d) Bedford Virginia AEPSC(c) No Assignment 5 Danville Virginia AEPSC(c) No Assignment 5 Martinsville Virginia AEPSC(c) No Assignment 5 Richlands Virginia AEPSC(c) No Assignment 5 Salem Virginia AEPSC(c) No Assignment 5 Oklahoma Municipal Power Authority Oklahoma PSO No Assignment 5 KAMO Electric Cooperative Oklahoma PSO No Assignment 5 Western Farmers Electric Cooperative Oklahoma PSO No Assignment 5 City of Lafayette Louisiana SWEPCO No Assignment 5 Arkansas Electric Cooperative Arkansas SWEPCO No Assignment 5 ACTUAL OR EARLIEST POSSIBLE NOTICE DATE NOTICE TERMINATION DATE REQUIREMENTS CAN BE PROVIDED FERC RATE SCHEDULE ------------------ ----------------- ----------------- ---------------------------------------------- 12/31/10 Evergreen 5 Years Notice 12/31/2005 SWEPCO FIRST REVISED RS NO. 109 12/31/17 Evergreen 5 Years Notice 12/31/2012 SWEPCO FIRST REVISED RS NO. 113 12/31/10 Evergreen 7 Years Notice 12/31/2003 SWEPCO RS NO. 111 12/31/2013 1 Year Notice 12/31/2012 SWEPCO RS NO. 119 12/31/17 Evergreen 5 Years Notice 12/31/2012 SWEPCO RS NO. 120 12/31/17 Evergreen 5 Years Notice 12/31/2012 SWEPCO RS NO. 120 12/31/07 Evergreen 3 Years Notice 12/31/2004 SWEPCO RS NO. 86 9/30/2012 Set Term N/A OPCO FERC RS NOS. 3, 69, 17 6/30/05 Evergreen 1 Year Notice 6/30/2004 AEP FERC ELECT. TARIFF, SECOND REV., VOL. NO. 6 SA NO. 181 6/30/05 Evergreen 1 Year Notice 6/30/2004 AEP FERC ELECT. TARIFF, SECOND REV., VOL. NO. 6 SA NO. 181 6/30/05 Evergreen 1 Year Notice 6/30/2004 AEP FERC ELECT. TARIFF, SECOND REV., VOL. NO. 6 SA NO. 181 6/30/05 Evergreen 1 Year Notice 6/30/2004 AEP FERC ELECT. TARIFF, SECOND REV., VOL. NO. 6 SA NO. 181 6/30/05 Evergreen 1 Year Notice 6/30/2004 AEP FERC ELECT. TARIFF, SECOND REV., VOL. NO. 6 SA NO. 181 Notice Given to Terminate 12/31/2003-per notice Effective 12/31/03 Notice Given PSO RS NO. 230 12/31/06 Evergreen 5 Years Notice 12/31/2001 PSO RS NO. 233 5/31/2004 2 Years Notice 5/31/2002 PSO RS NO. 238 Evergreen 45 Days Notice Anytime SWEPCO RS NO. 115 Notice Given to Terminate 12/31/2007-per notice Effective 12/31/07 Notice Given SWEPCO RS NO. 72
(a) customer, but not WTU, has right to terminate Dec. 31, 2004 upon 3 years notice (b) customer, but not SWEPCO, has right to terminate Dec. 31, 2008 upon 5 years notice (c) AEPSC acts as agent on behalf of its operating companies (d) Part owners of Cardinal Plant-Pricing Based on Cost Types of Contracts: (1) Fixed Base Rates, No Fuel Clause (2) Fixed Base Rates, With Fuel Clause (3) Base Rates Subject to Change, With Fuel Clause (4) Formula Rate (5) Transmission Service EXHIBIT G DESCRIPTION OF JURISDICTIONAL FACILITIES OF APPLICANTS, THEIR SUBSIDIARIES AND AFFILIATES The jurisdictional facilities of Applicants and their affiliates that will be affected by the Transfers consist of interstate transmission facilities, rate schedules for the sale of electric energy for resale in interstate commerce and for the transmission of energy in interstate commerce, accounts, books and records related to such sales, and step-up transformers, generating leads and other interconnection facilities necessary for interconnection to interstate transmission networks of generating facilities that are the subject of the Transfers. There are attached to this Exhibit G schedules that list the rate schedules to be transferred, schedules that describe the interconnection facilities associated with the generating stations that are the subject of the Transfers to be made by CPL and WTU and schedules that describe the interstate transmission facilities that are owned or controlled by SWEPCO, CSP, and OPCo and are the subject of the Transfers. Because the Transfers will not affect other jurisdictional facilities owned or controlled by the AEP operating companies, Applicants request waiver of the requirements of Exhibit G to describe such other jurisdictional facilities. EXHIBIT G - SCHEDULES Schedule G-1 Columbus Southern Power Company, Transfer of Jurisdictional Assets to CSP EDC Transmission Lines 132 kV and Above Schedule G-2 Columbus Southern Power Company, Transfer of Jurisdictional Assets to CSP EDC Transmission Lines Less Than 132 kV Schedule G-3 Columbus Southern Power Company, Transfer of Jurisdictional Assets to CSP EDC Transmission Substations Schedule G-4 Ohio Power Company, Transfer of Jurisdictional Assets to OPCo EDC Transmission Lines 132 kV and Above Schedule G-5 Ohio Power Company, Transfer of Jurisdictional Assets to OPCo EDC Transmission Lines Less Than 132 kV Schedule G-6 Ohio Power Company, Transfer of Jurisdictional Assets to OPCo EDC Transmission Substations Schedule G-7 Central Power and Light Company, Transfer of Jurisdictional Assets to CPL PGC Generation Related Equipment Schedule G-8 West Texas Utilities Company, Transfer of Jurisdictional Assets to WTU PGC Generation Related Equipment Schedule G-9 Southwestern Electric Power Company, Transfer of Jurisdictional Assets to SWEPCO EDC Transmission Substations Schedule G-10 Southwestern Electric Power Company, Transfer of Jurisdictional Assets to SWEPCO Texas EDC Transmission Lines Schedule G-11 American Electric Power Service Corporation, Power Sales/Service Agreements to be Assigned to Power Marketing Affiliate Schedule G-12 Appalachian Power Company, Power Sales/Service Agreements to be Assigned to OPCo PGC Schedule G-13 Central Power and Light, Power Sales/Service Agreements to be Assigned to CPL PGC Schedule G-14 Ohio Power Company, Power Sales/Service Agreements to be Assigned to APCo Schedule G-15 West Texas Utilities Company, Power Sales/Service Agreements to be Assigned to WTU PGC Schedule G-16 Columbus Southern Power Company, Interconnection and Transmission Agreements to be Assigned to CSP EDC Schedule G-17 Ohio Power Company, Interconnection and Transmission Agreements to be Assigned to OPCo EDC Schedule G-18 Southwestern Electric Power Company, Interconnection Agreements to be Assigned to SWEPCO EDC Schedule G-19 Indiana and Michigan Power Company, Transfer of Interests in Rockport Steam Electric Generating Plant Units Nos. 1 and 2 to Power Marketing Affiliate Schedule G-1 Page 1 of 5 COLUMBUS SOUTHERN POWER COMPANY TRANSFER OF JURISDICTIONAL ASSETS TO CSP EDC TRANSMISSION LINES 132 KV AND ABOVE ----------------------------------- ================================================================================ DESIGNATION VOLTAGE -------------------------------------------------------------------- LENGTH FROM TO OPERATING DESIGNED POLE MILES ================================================================================ LINES 132 KV AND ABOVE FULLY OWNED TRANS. LINES: BEATTY HAYDEN 345 345 0 BEATTY HAYDEN 345 345 17 BIXBY-CORRIDOR KIRK (TAP) 345 345 1 CONESVILLE CORRIDOR 345 345 54 HAYDEN HYATT 345 345 0 HAYDEN HYATT 345 345 0 HAYDEN HYATT 345 345 12 HAYDEN ROBERTS 345 345 6 HYATT POINT Z 345 345 0 HYATT POINT Z 345 345 0 HYATT POINT Z 345 345 0 POINT Z CORRIDOR 345 345 13 COMMONLY OWNED LINES: (A) BECKJORD PIERCE 345 345 0 PIERCE FOSTER 345 345 24 SUGARCREEK GREENE 345 345 8 SUGARCREEK GREENE 345 345 0 GREENE BEATTY 345 345 49 MARQUIS POINT X 345 345 46 STUART GREENE 345 345 79 STUART GREENE 345 345 1 STUART GREENE 345 345 1 STUART POINT M-KILLEN 345 345 13 STUART FOSTER 345 345 55 STUART FOSTER 345 345 1 FOSTER SUGARCREEK 345 345 27 STUART ZIMMER 345 345 35 ZIMMER PORT UNION 345 345 10 POINT O-KILLEN MARQUIS 345 345 32 POINT Y BEATTY 345 345 15 POINT Y BEATTY 345 345 0 0 0 0 COMMONLY OWNED LINES: (B) 0 0 0 BEATTY BIXBY 345 345 13 BIXBY TOWER 71 345 345 15 TOWER 71 CORRIDOR 345 345 22 STUART TOWER 2 345 345 0 TOWER 2 POINT Y 345 345 75 CONESVILLE TOWER 71 345 345 51 Schedule G-1 Page 2 of 5 COLUMBUS SOUTHERN POWER COMPANY TRANSFER OF JURISDICTIONAL ASSETS TO CSP EDC TRANSMISSION LINES 132 KV AND ABOVE ----------------------------------- ================================================================================ DESIGNATION VOLTAGE -------------------------------------------------------------------- LENGTH FROM TO OPERATING DESIGNED POLE MILES ================================================================================ TOWER 71 BIXBY 345 345 0 POINT X TOWER 27 345 345 17 TOWER 27 BIXBY 345 345 0 0 0 0 COMMONLY OWNED LINES: (C) 0 0 0 CONESVILLE POINT Z 345 345 57 0 0 0 COMMONLY OWNED LINES: (D) 0 0 0 POINT Z HYATT 345 345 9 POINT Z HYATT 345 345 2 POINT Z HYATT 345 345 0 0 0 0 COMMONLY OWNED LINES: (E) 0 0 0 STUART ZIMMER 345 345 1 ZIMMER RED BANK 345 345 33 RED BANK TERMINAL 345 345 7 ZIMMER PIERCE 345 345 1 ROBERTS BETHEL 138 138 0 ROBERTS BETHEL 138 138 5 ROBERTS KENNY 138 138 1 ROBERTS KENNY 138 138 3 BETHEL LINWORTH 138 138 0 BETHEL LINWORTH 138 138 2 PICWAY HARRISON 138 138 1 GROVES BEXLEY 138 138 4 BEXLEY ST. CLAIR 138 138 4 BIXBY LSII 138 138 1 BIXBY LSII 138 138 2 BIXBY LSII 138 138 0 BIXBY W.LANCASTER 138 138 18 BIXBY W.LANCASTER 138 138 0 BIXBY W.LANCASTER 138 138 1 POSTON ROSS 138 138 42 POSTON ROSS 138 138 1 ROSS DELANO 138 138 5 CIRCLEVILLE HARRISON 138 138 14 CIRCLEVILLE HARRISON 138 138 1 LSII MARION 138 138 2 LSII MARION 138 138 3 MARION CANAL 138 138 4 ST. CLAIR CLINTON 138 138 4 HARRISON MARION 138 138 7 HARRISON MARION 138 138 0 BIXBY GROVES-ASTOR 138 138 13 POSTON HARRISON 138 138 54 Schedule G-1 Page 3 of 5 COLUMBUS SOUTHERN POWER COMPANY TRANSFER OF JURISDICTIONAL ASSETS TO CSP EDC TRANSMISSION LINES 132 KV AND ABOVE ----------------------------------- ================================================================================ DESIGNATION VOLTAGE -------------------------------------------------------------------- LENGTH FROM TO OPERATING DESIGNED POLE MILES ================================================================================ BEATTY WILSON (EAST) 138 138 7 BEATTY WILSON (WEST) 138 138 0 BEATTY WILSON (WEST) 138 138 0 WAVERLY SARGENTS 138 138 16 WAVERLY ADAMS-SEAMAN 138 138 25 WAVERLY ADAMS-SEAMAN 138 138 11 CIRCLEVILLE SCIPPO 138 138 2 CIRCLEVILLE SCIPPO 138 138 1 POSTON LICK 138 138 0 POSTON LICK 138 138 35 WAVERLY LICK 138 138 0 WAVERLY LICK 138 138 16 WAVERLY LICK 138 138 11 MORSE GENOA-KARL 138 138 4 MORSE GENOA-KARL 138 138 5 MORSE GENOA-KARL 138 138 2 OSU HESS 138 138 1 WILSON FIFTH-NESS 138 138 3 WILSON FIFTH-NESS 138 138 2 WILSON ROBERTS 138 138 5 WILSON ROBERTS 138 138 0 WILSON ROBERTS 138 138 1 BIXBY BUCKEYE STEEL 138 138 3 BIXBY BUCKEYE STEEL 138 138 2 BIXBY BUCKEYE STEEL 138 138 1 GAY VINE 138 138 2 EAST BROAD GAHANNA 138 138 0 EAST BROAD GAHANNA 138 138 1 EAST BROAD GAHANNA 138 138 3 HYATT SAWMILL 138 138 0 HYATT SAWMILL 138 138 5 GAHANNA MORSE 138 138 5 GAHANNA MORSE 138 138 0 CORRIDOR MORSE-BLENDON 138 138 0 CORRIDOR MORSE-BLENDON 138 138 1 CORRIDOR MORSE 138 138 7 KIRK EAST BROAD 138 138 10 KIRK EAST BROAD 138 138 0 CANAL MOUND 138 138 2 CONESVILLE TRENT 138 138 52 CONESVILLE TRENT 138 138 0 TRENT DELAWARE 138 138 13 TRENT DELAWARE 138 138 0 ST. CLAIR MIFFLIN STELZER 138 138 7 KENNY KARL 138 138 1 Schedule G-1 Page 4 of 5 COLUMBUS SOUTHERN POWER COMPANY TRANSFER OF JURISDICTIONAL ASSETS TO CSP EDC TRANSMISSION LINES 132 KV AND ABOVE ----------------------------------- ================================================================================ DESIGNATION VOLTAGE -------------------------------------------------------------------- LENGTH FROM TO OPERATING DESIGNED POLE MILES ================================================================================ KENNY KARL 138 138 3 KENNY KARL 138 138 3 MORSE CLINTON 138 138 0 MORSE CLINTON 138 138 0 MORSE HUNTLEY-CLINTON 138 138 3 BIXBY GROVES 138 138 3 BIXBY GROVES 138 138 1 BIXBY GROVES 138 138 0 BIXBY GROVES 138 138 0 POSTON STROUDS RUN-CROOKSVILLE 138 138 0 POSTON STROUDS RUN-CROOKSVILLE 138 138 7 HYATT DELAWARE 138 138 4 BEATTY CANAL 138 138 11 CONESVILLE OHIO CENTRAL 138 138 12 EAST BROAD ASTOR 138 138 3 HARRISON BEATTY 138 138 8 HARRISON S. CENTRAL REA 138 138 0 BEATTY MCCOMB 138 138 2 MORSE STELZER 138 138 2 HUNTLEY LINWORTH 138 138 3 HYATT GENOA 138 138 5 BUCKEYE STEEL GAY 138 138 3 BUCKEYE STEEL GAY 138 138 1 POSTON ELLIOT-DEXTER 138 138 0 POSTON ELLIOT-DEXTER 138 138 7 HYATT HUNTLEY 138 138 12 LICK ADDISON 138 138 29 LICK ADDISON 138 138 0 SCIPPO SCIOTO TRAIL-DUPONT 138 138 1 SCIPPO SCIOTO TRAIL-DUPONT 138 138 0 SCIPPO SCIOTO TRAIL-DUPONT 138 138 1 DELANO SCIOTO TRAIL 138 138 11 DELANO SCIOTO TRAIL 138 138 1 SAWMILL BETHEL 138 138 0 SAWMILL BETHEL 138 138 5 MOUND ST. CLAIR 138 138 2 WAVERLY MULBERRY 138 138 12 WAVERLY MULBERRY 138 138 2 MCCOMB SULLIVANT-GAY 138 138 8 MULBERRY ROSS 138 138 0 MULBERRY ROSS 138 138 3 MULBERRY ROSS 138 138 1 EAST BROAD BEXLEY 138 138 6 HYATT ROSS 138 138 1 CORRIDOR GENOA 138 138 0 Schedule G-1 Page 5 of 5 COLUMBUS SOUTHERN POWER COMPANY TRANSFER OF JURISDICTIONAL ASSETS TO CSP EDC TRANSMISSION LINES 132 KV AND ABOVE ----------------------------------- ================================================================================ DESIGNATION VOLTAGE -------------------------------------------------------------------- LENGTH FROM TO OPERATING DESIGNED POLE MILES ================================================================================ CORRIDOR GAHANNA 138 138 1 KIRK W. MILLERSPORT 138 138 0 KIRK W. MILLERSPORT 138 138 0 CONESVILLE KIRK 138 138 0 CONESVILLE KIRK 138 138 38 CONESVILLE KIRK 138 138 8 HESS VINE 138 138 2 VINE CITY OF COLUMBUS EAST 138 138 1 POSTON W.LANCASTER 138 138 12 POSTON W.LANCASTER 138 138 0 POSTON W.LANCASTER 138 138 23 VINE CITY OF COLUMBUS WEST 138 138 1 ST. CLAIR VINE 138 138 1 ST. CLAIR VINE 138 138 1 CLINTON OSU 138 138 4 OSU HESS 138 138 1 SCIPPO HARGUS 138 138 1 SCIPPO EAST SCIPPO 138 138 0 EAST BROAD BEXLEY 138 138 0 DAVIDSON RD. ROBERTS-BETHEL 138 138 0 MORSE STELZER 138 138 2 (A) CSP OWNS 35% (B) CSP OWNS 33 1/3% (C) CSP OWNS 66.28% (D) CSP OWNS 83.14% (E) CSP OWNS 36% Schedule G-2 Page 1 of 2 COLUMBUS SOUTHERN POWER COMPANY TRANSFER OF JURISDICTIONAL ASSETS TO CSP EDC TRANSMISSION LINES LESS THAN 132 KV ----------------------------------- LINE NAME VOLTAGE MILES -------------------------------------------------------------------------------- Elliott - Lee 34 8.00 Floodwood - Berlin 34 32.13 Rutland - Buckeye Co-op 34 0.12 Bexley - Rockwell No. 2 40 0.58 Consolidated Stores Ext. 40 0.23 General Motors Ext. - South 40 0.38 Genoa Ext. 40 0.34 Groves Road - Livingston Avenue 40 2.89 Livingston - Bexley 40 2.28 McComb - Briggsdale 40 1.70 Parsons - Marion Road 40 5.16 Picway - Briggsdale 40 11.56 Picway - Parsons 40 5.42 Wilson - Briggsdale 40 5.20 Wilson - West 40 10.08 Rockwell Tie Line 40 0.46 Adams - Rarden 69 7.76 Ashley - Pedro 69 12.55 Bashan - Ravenswood 69 11.87 Beatty - Ballah Road 69 7.47 Beatty - Galloway 69 8.59 Berlin - Ross 69 32.42 Bethel - Dublin 69 3.21 Big Darby - South Central Co-op, Darbyville 69 0.37 Bloom Tap 69 1.32 Busch - Worthington Industries 69 0.81 Camden Avenue - Dyneer 69 0.07 Camp Sherman - Circleville 69 18.09 Coalton - Lick 69 4.40 Davon Ext. 69 0.95 Dow Chemical Ext. 69 0.13 Dublin - Sawmill 69 12.65 East Broad Street - Bexley 69 6.24 East Peebles - Adams Co-op 69 1.73 Echo Valley - Buckeye Co-op 69 0.28 Elliott - Meigs 69 20.00 Elliott - OU - Clark 69 2.25 Etna Ext. 69 1.63 Gahanna - Morse Road 69 5.05 Gavin - Addison 69 7.59 Gavin - DWAS 69 0.90 Gavin - Generator Lead No. 1 69 0.38 Schedule G-2 Page 2 of 2 COLUMBUS SOUTHERN POWER COMPANY TRANSFER OF JURISDICTIONAL ASSETS TO CSP EDC TRANSMISSION LINES LESS THAN 132 KV ----------------------------------- LINE NAME VOLTAGE MILES -------------------------------------------------------------------------------- General Motors Ext. - North 69 0.30 Ginger Tap 69 0.04 Greene - Beatty 69 19.98 Griffin Wheel Ext. 69 0.23 Huntley - Busch 69 0.39 Jackson Lake - Jefferson 69 0.52 Kirk - Watkins Road 69 1.22 Lazelle - Busch 69 1.16 Lick - Pedro 69 29.94 Marlon Road - Jenkins East 69 0.99 Marion Road - Jenkins West 69 1.64 Millbrook - Grace 69 0.62 North Galloway - West Jefferson 69 0.84 Pedro - Superior 69 0.16 Picway - Harrison 69 0.00 Picway - Madison 69 21.58 Poplar Flat - Bentonville 69 0.74 Poston - Floodwood 69 2.12 Poston - Trimble 69 9.71 Ross - Camp Sherman 69 3.43 Ross - Highland 69 41.58 Salisbury Extension 69 0.46 Sawmill - Lazelle 69 4.24 Seaman - Adams 69 8.38 Seaman - Sardinia 69 11.89 South Coshocton - Coshocton 69 0.82 South Fork - General Electric Hebron 69 0.62 South Seaman - Bentonville 69 15.12 South Stockport - Washington Co-op 69 5.09 South Webster - Buckeye Co-op 69 0.99 Strouds Run - Clark 69 3.90 Trent - Delaware Co-op, Lott 69 2.14 Waverly - Idaho 69 9.15 West Union - Copeland 69 1.38 Westerville - City of Westerville 69 0.03 Westerville - Genoa 69 1.91 Westerville - Huntley 69 3.83 Westerville Tap 69 0.04 Worthington Tap 69 0.02 Schedule G-3 Page 1 of 3 COLUMBUS SOUTHERN POWER COMPANY TRANSFER OF JURISDICTIONAL ASSETS TO CSP EDC VOLTAGE (IN MVA) CHARACTER OF ---------------------------- TRANSMISSION SUBSTATIONS SUBSTATION PRIMARY SECONDARY TERTIARY -------------------------------------------------------------------------------- WHOLLY OWNED SUBSTATIONS #66 CONESVILLE PLANT/CONESVILLE, OH ATTENDED-T 138 69 13 ATTENDED-T 138 69 4 UNATTENDED-T 138 69 12 #5 CORRIDOR/FRANKLIN CO., OH UNATTENDED-T 345 138 13 UNATTENDED-T 345 138 34.5 UNATTENDED-T 138 34 13 UNATTENDED-T 14 0 0 #7 MARION ROAD/COLUMBUS, OH UNATTENDED-T 138 40 13 UNATTENDED-T 13 13 0 UNATTENDED-T 40 13 0 #10 BEXLEY/COLUMBUS, OH UNATTENDED-T 138 40 13.8 UNATTENDED-T 138 13.8 13.8 UNATTENDED-T 13 13 0 UNATTENDED-T 13 0 0 #14 EAST BROAD ST/COLUMBUS, OH UNATTENDED-T 138 40 13.8 UNATTENDED-T 13.8 13 0 #19 HYATT/DELAWARE CO., OH UNATTENDED-T 345 138 13 #20 WILSON RD/COLUMBUS, OH UNATTENDED-T 138 40 13.8 UNATTENDED-T 138 13.8 13.8 UNATTENDED-T 13 13 0 #26 BETHEL RD/COLUMBUS, OH UNATTENDED-T 134.5 69.5 13.09 UNATTENDED-T 138 13.8 13.8 #31 SAWMILL/FRANKLIN, CO., OH UNATTENDED-T 13 0 0 UNATTENDED-T 13.8 0 0 UNATTENDED-T 138 34.5 13.8 UNATTENDED-T 134.5 34.5 13.8 UNATTENDED-T 135.4 69 13 #31 SAWMILL/FRANKLIN CO., OH UNATTENDED-T 138 69 13 #35 POSTON/ATHENS CO., OH UNATTENDED-T 138 69 13.39 UNATTENDED-T 69 13.2 0 #38 GROVES RD/COLUMBUS, OH UNATTENDED-T 138 13.8 0 UNATTENDED-T 138 13.8 13.8 UNATTENDED-T 40 13.8 0 UNATTENDED-T 34.5 13.8 0 UNATTENDED-T 138 40 13.8 #39 GENOA/WESTERVILLE, OH UNATTENDED-T 138 69 13 UNATTENDED-T 138 34.5 13.8 UNATTENDED-T 34.5 13 4 UNATTENDED-T 13 13 13 UNATTENDED-T 40 14.5 0 #41 ROBERTS/HILLIARD, OH UNATTENDED-T 138 13 0 UNATTENDED-T 345 138 13.8 UNATTENDED-T 13.2 0 0 #71 BIXBY/GROVEPORT, OH UNATTENDED-T 345 138 13 Schedule G-3 Page 2 of 3 COLUMBUS SOUTHERN POWER COMPANY TRANSFER OF JURISDICTIONAL ASSETS TO CSP EDC VOLTAGE (IN MVA) CHARACTER OF ---------------------------- TRANSMISSION SUBSTATIONS SUBSTATION PRIMARY SECONDARY TERTIARY -------------------------------------------------------------------------------- UNATTENDED-T 138 13.8 13.8 UNATTENDED-T 138 13.8 0 UNATTENDED-T 13 13 0 UNATTENDED-T 345 138 34.5 UNATTENDED-T 345 138 35 UNATTENDED-T 40 4 0 UNATTENDED-T 69 13.8 0 UNATTENDED-T 13.19 4 0 UNATTENDED-T 40 14.5 0 #74 BEATTY RD/GROVE CITY, OH UNATTENDED-T 345 138 13.8 UNATTENDED-T 138 13.8 13.8 UNATTENDED-T 138 69 13.8 UNATTENDED-T 13 0 0 UNATTENDED-T 345 138 34.5 #75 MCCOMB/GROVE CITY, OH UNATTENDED-T 138 40 13 UNATTENDED-T 13 13 0 #80 KIRK/PATASKALA, OH UNATTENDED-T 345 138 13 UNATTENDED-T 138 34.5 13 UNATTENDED-T 138 69 34 #247 WAVERLY/ WAVERLY OH UNATTENDED-T 138 69 13.19 UNATTENDED-T 13 13 0 UNATTENDED-T 138 69 13 UNATTENDED-T 69 12 0 #109 SLATE MILLS/CHILLICOTHE, OH UNATTENDED-T 69 13 0 #113 ELLIOT/ATHENS, OH UNATTENDED-T 138 69 13 UNATTENDED-T 13 13 0 #132 ADDISON/KANAUGA, OH UNATTENDED-T 69 13 0 UNATTENDED-T 138 69 13 #69 HARRISON/ PICKAWAY CTY, OH UNATTENDED-T 138 69 13.8 #149 CIRCLEVILLE/CIRCLEVILLE, OH UNATTENDED-T 138 69 13.19 UNATTENDED-T 138 13 0 UNATTENDED-T 13 13 0 #12 HUNTLEY/COLUMBUS, OH UNATTENDED-T 138 13.8 0 UNATTENDED-T 69 13.8 0 UNATTENDED-T 138 13.8 0 #158 SEAMAN/SEAMAN, OH UNATTENDED-T 69 13.8 0 UNATTENDED-T 69 13 0 UNATTENDED-T 138 69 13.2 UNATTENDED-T 40 13 0 #226 ROSS/CHILLICOTHE, OH UNATTENDED-T 138 69 13.19 UNATTENDED-T 13 13 0 UNATTENDED-T 138 13 0 UNATTENDED-T 69 13 0 UNATTENDED-T 13 13 0 #230 STROUDS RUN/ATHENS, OH UNATTENDED-T 138 69 13.19 UNATTENDED-T 138 69 12 Schedule G-3 Page 3 of 3 COLUMBUS SOUTHERN POWER COMPANY TRANSFER OF JURISDICTIONAL ASSETS TO CSP EDC VOLTAGE (IN MVA) CHARACTER OF ---------------------------- TRANSMISSION SUBSTATIONS SUBSTATION PRIMARY SECONDARY TERTIARY -------------------------------------------------------------------------------- UNATTENDED-T 13 13 0 #238 ADAMS/PEEBLES, OH UNATTENDED-T 138 69 13.2 UNATTENDED-T 13 13 0 #242 LICK/JACKSON, OH UNATTENDED-T 138 69 13.19 UNATTENDED-T 13 13 0 UNATTENDED-T 13.19 4.16 0 UNATTENDED-T 69 13.2 0 UNATTENDED-T 69 13 0 UNATTENDED-T 34.5 12 0 COMMONLY OWNED SUBSTATIONS #5 CORRIDOR/FRANKLIN CO., OH - NOTE A UNATTENDED-T 345 0 0 #52 STUART/ADAMS CO., OH - NOTE A SUPERVISORY 0 0 0 CONTROL-T 345 138 0 SEE NOTE E SUPERVISORY 0 0 0 CONTROL-T 345 0 0 #53 PIERCE/CLERMONT CO., OH - NOTE B ATTENDED-T 345 0 0 #59 GREENE/DAYTON, OH - NOTE B SUPERVISORY 0 0 0 CONTROL-T 345 0 0 #61 FOSTER/WARREN CO., OH - NOTE B UNATTENDED-T 345 0 0 #71 BIXBY/GROVEPORT, OH - NOTE A UNATTENDED-T 345 0 0 #74 BEATTY/GROVE CITY, OH - NOTES A & B UNATTENDED-T 345 0 0 #241 TERMINAL/CINCINNATI, OH - NOTE C ATTENDED-T 345 0 0 #243 PORT UNION/BUTLER CO., OH - NOTE C ATTENDED-T 345 0 0 #245 DON MARQUIS/PIKE CO, OH - NOTE B UNATTENDED-T 345 0 0 Schedule G-4 Page 1 of 7 OHIO POWER COMPANY TRANSFER OF JURISDICTIONAL ASSETS TO OPCO EDC TRANSMISSION LINES 132 KV AND ABOVE ----------------------------------- ================================================================================ DESIGNATION VOLTAGE -------------------------------------------------------------------- LENGTH FROM TO OPERATING DESIGNED POLE MILES ================================================================================ 0168 BAKER DON MARQUIS 765 765 26.41 0168 BAKER DON MARQUIS 765 765 10.32 0171 KAMMER DUMONT 765 765 100.19 0171 KAMMER DUMONT 765 765 126.14 0194 AMOS NORTH PROCTORVILLE 765 765 5.3 0195 GAVIN MARYSVILLE 765 765 124.4 0232 AMOS GAVIN 765 765 0.49 0233 GAVIN KAMMER 765 765 2.62 0263 KAMMER SOUTH CANTON 765 765 0.24 0263 KAMMER SOUTH CANTON 765 765 78.44 0269 NORTH PROCTORVILLE HANGING ROCK 765 765 25.99 0270 HANGING ROCK JEFFERSON 765 765 6.14 0047 SPORN MUSKINGUM 345 345 46.52 0048 MUSKINGUM CENTRAL 345 345 28.1 0048 MUSKINGUM CENTRAL 345 345 53.94 0052 CENTRAL EAST LIMA 0 345 2.68 0052 CENTRAL EAST LIMA 345 345 71.36 0070 EAST LIMA SORENSON 345 345 42.99 0079 MUSKINGUM TIDD 345 345 83.57 0088 KAMMER EXT. NO. 1 345 345 0.2 0088 KAMMER EXT. NO. 1 (WV) 345 345 0.38 0104 TIDD CANTON CENTRAL 345 345 37.29 0104 TIDD CANTON CENTRAL 345 345 14.21 0106 CANTON CENTRAL JUNIPER 345 345 4.06 0106 CANTON JUNIPER 345 345 1.36 0106 CANTON JUNIPER 345 345 0.55 0119 MUSKINGUM OHIO CENTRAL 345 345 30.75 0119 MUSKINGUM OHIO CENTRAL 345 345 12.51 0142 KAMMER EXT. NO. 2 345 345 0.15 0142 KAMMER EXT. NO. 2 (WV) 345 345 0.3 0161 OHIO CENTRAL FOSTORIA CENTRAL 345 345 100.53 0161 OHIO CENTRAL FOSTORIA CENTRAL 345 345 5.99 0162 FOSTORIA CENTRAL EAST LIMA 345 345 34.47 0162 FOSTORIA CENTRAL EAST LIMA 345 345 5.35 0163 FOSTORIA CENTRAL PEMBERVILLE 345 345 19.29 0166 SOUTH CANTON SAMMIS 345 345 0.74 0167 SOUTH CANTON STAR 345 345 0.69 0172 SOUTHWEST LIMA EXTEN 345 345 14.68 0173 SOUTHWEST LIMA MIAMI 345 345 18.04 0173 SOUTHWEST LIMA MIAMI 345 345 0.97 0208 TIDD COLLIER 345 345 0.31 0248 MARYSVILLE EXT.NO. 345 345 4.22 0249 MARYSVILLE EXT.NO. 345 345 4.84 0279 SOUTH CANTON CANTON CENTRAL 345 345 8.16 Schedule G-4 Page 2 of 7 OHIO POWER COMPANY TRANSFER OF JURISDICTIONAL ASSETS TO OPCO EDC TRANSMISSION LINES 132 KV AND ABOVE ----------------------------------- ================================================================================ DESIGNATION VOLTAGE -------------------------------------------------------------------- LENGTH FROM TO OPERATING DESIGNED POLE MILES ================================================================================ 0001 LIMA FT. WAYNE 138 138 0.1 0001 LIMA FT. WAYNE 138 138 43.58 0004 HOWARD ASHLAND 138 138 6.15 0004 HOWARD ASHLAND 138 138 1.84 0005 WINDSOR CANTON 138 138 54.38 0005 WINDSOR CANTON 138 138 0.08 0006 WINDSOR CANTON(WV) 138 138 0.32 0007 PHILO HOWARD 138 138 0.05 0007 PHILO HOWARD 138 138 80.73 0010 FOSTORIA PEMBERVILLE 138 138 18.49 0010 FOSTORIA PEMBERVILLE 138 138 0.06 0010 FOSTORIA PEMBERVILLE 138 138 0 0011 PHILO RUTLAND 138 138 65.7 0016 SOUTH POINT TURNER 138 138 0.48 0018 PHILO TORREY 138 138 70.73 0019 CROOKSVILLE WEST LANCASTER 138 138 30.7 0020 PHILO CANTON 138 138 74.04 0025 TIDD WAGENHALS 138 138 53.45 0028 PORTSMOUTH TRENTON NO. 2 138 138 76.97 0028 PORTSMOUTH TRENTON NO. 2 138 138 0.24 0028 PORTSMOUTH TRENTON NO. 2 138 138 0.45 0032 TRENTON MUNCIE 138 138 23.92 0033 RUTLAND SPORN 138 138 4.81 0034 SPORN SOUTH POINT 138 138 9.22 0034 SPORN SOUTH POINT 138 138 40.41 0036 SPORN PORTSMOUTH 138 138 0.05 0036 SPORN PORTSMOUTH 138 138 48.76 0037 HILLSBORO MAYSVILLE 138 138 33.55 0038 CROOKSVILLE NORTH NEWARK 138 138 30.67 0038 CROOKSVILLE NORTH NEWARK 138 138 0.58 0039 WEST LANCASTER SOUTH BALTIMORE 138 138 9.82 0041 NORTH NEWARK WEST MT. VERNON 138 138 20.28 0041 NORTH NEWARK WEST MT. VERNON 138 138 1.48 0042 SOUTH BALTIMORE NORTH NEWARK 138 138 21.04 0042 SOUTH BALTIMORE NORTH NEWARK 138 138 0.05 0042 SOUTH BALTIMORE NORTH NEWARK 138 138 0.08 0043 BELLEFONTE EXT. 138 138 2.8 0044 SUMMERFIELD NATRIUM 138 138 27.07 0045 PHILO MUSKINGUM 138 138 23.16 0046 MUSKINGUM SUMMERFIELD 138 138 25.31 0049 FOSTORIA EAST LIMA 138 138 0.06 0049 FOSTORIA EAST LIMA 138 138 40.77 0050 EAST LIMA LIMA 138 138 4.43 0055 TORREY WOOSTER 138 138 28.69 0056 WEST MT. VERNON SOUTH KENTON 138 138 59.06 0057 SOUTH KENTON STERLING 138 138 0 0057 SOUTH KENTON STERLING 138 138 28.4 Schedule G-4 Page 3 of 7 OHIO POWER COMPANY TRANSFER OF JURISDICTIONAL ASSETS TO OPCO EDC TRANSMISSION LINES 132 KV AND ABOVE ----------------------------------- ================================================================================ DESIGNATION VOLTAGE -------------------------------------------------------------------- LENGTH FROM TO OPERATING DESIGNED POLE MILES ================================================================================ 0058 SOUTH POINT PORTSMOUTH 138 138 0.04 0058 SOUTH POINT PORTSMOUTH 138 138 34.57 0059 PHILO CROOKSVILLE 138 138 15.37 0060 LIMA STERLING 138 138 5.96 0061 EAST LIMA WEST LIMA 138 138 0.15 0061 EAST LIMA WEST LIMA 138 138 11.19 0061 EAST LIMA WEST LIMA 138 138 1.05 0063 TORREY MASSILLON 138 138 0.29 0066 WAGENHALS WEST CANTON 138 138 9.16 0066 WAGENHALS WEST CANTON 138 138 0.85 0067 TORREY AKRON 138 138 0.28 0069 TIDD SOUTH CADIZ 138 138 16.59 0071 AKRON CANTON 138 138 3.75 0072 TIDD WEIRTON NO. 2 138 138 6.21 0072 TIDD WEIRTON NO. 2 138 138 0.05 0073 WEIRTON SOUTH TORONTO 69 138 0.48 0073 WEIRTON SOUTH TORONTO 138 138 0.14 0075 SPORN KAISER NO. 1 138 138 4.25 0076 LUCASVILLE SARGENTS 138 138 11.88 0078 TIDD WINDSOR JCT. 138 138 3.77 0080 NEWCOMERSTOWN SOUTH COSHOCTON 138 138 14.33 0081 FORD MOTOR EXT. 138 138 0.25 0086 SPORN KAISER NO. 2 138 138 5.67 0087 WINDSOR JUNCTION TILTONVILLE 138 138 3.81 0087 WINDSOR JUNCTION TILTONVILLE 138 138 0.3 0089 WEST PHILO EXT. NO. 1 138 138 0.05 0090 WEST PHILO EXT. NO. 1 138 138 0.13 0091 KAMMER OHIO FERRO ALLOWS 138 138 2.45 0091 KAMMER OHIO FERRO ALLOWS (WV) 138 138 0.71 0095 PORTSMOUTH TRENTON NO. 1 138 138 97.31 0095 PORTSMOUTH TRENTON NO. 1 138 138 1.04 0095 PORTSMOUTH TRENTON NO. 1 138 138 0.24 0096 THIVENER BUCKEYE CO-OP 138 138 6.16 0097 MERCERVILLE APPLE GROVE 138 138 5.11 0098 MILLWOOD EXT. 138 138 0.1 0101 THIVENER EXT. 138 138 0.09 0102 MEIGS EXT. NO. 1 138 138 0.1 0103 MEIGS EXT. NO. 2 138 138 0.17 0108 OHIO CENTRAL NORTH NEWARK 138 138 0.33 0108 OHIO CENTRAL NORTH NEWARK 138 138 21.3 0110 NORTH STRASBURG EXT. 138 138 0.06 0111 NORTH STRASBURG EXT. 138 138 0.06 0112 ZANESVILLE EXT. 138 138 6.48 0113 HOWARD BUCYRUS CENTER 138 138 16.3 0113 HOWARD BUCYRUS CENTER 138 138 0.27 0114 SOUTH PEMBERVILLE FREEMONT 138 138 14.18 0114 SOUTH PEMBERVILLE FREEMONT 138 138 1.29 Schedule G-4 Page 4 of 7 OHIO POWER COMPANY TRANSFER OF JURISDICTIONAL ASSETS TO OPCO EDC TRANSMISSION LINES 132 KV AND ABOVE ----------------------------------- ================================================================================ DESIGNATION VOLTAGE -------------------------------------------------------------------- LENGTH FROM TO OPERATING DESIGNED POLE MILES ================================================================================ 0115 SUMMERFIELD BERNE 138 138 3.46 0118 SOUTH COSHOCTON WOOSTER 138 138 39.51 0120 OHIO CENTRAL COSHOCTON JCT. 138 138 0.2 0120 OHIO CENTRAL COSHOCTON JCT. 138 138 14.52 0122 KAMMER ORMET NO. 1 138 138 1.71 0123 FINDLAY CENTER EXT. 138 138 6.66 0125 TIDD WEIRTON NO. 1 138 138 0.41 0126 ARROYO EAST LIVERPOOL 138 138 0.15 0128 TIDD NATRIUM 138 138 0.26 0129 HOWARD FOSTORIA 138 138 0.5 0129 HOWARD FOSTORIA 138 138 44.38 0130 EAST WHEELERSBURG TEXAS EASTERN 138 138 1.99 0131 KAMMER ORMET NO. 2 138 138 1.55 0133 SUNNYSIDE WAGENHALS NO. 1 138 138 1.44 0133 SUNNYSIDE WAGENHALS NO. 1 138 138 2.23 0134 TIDD WHEELING STEEL 138 138 5.12 0141 MILLBROOK SILOAM 138 138 1.6 0141 MILLBROOK SILOAM 138 138 0.05 0143 ZANESVILLE OHIO CENTRAL 138 138 10.33 0143 ZANESVILLE OHIO CENTRAL 138 138 1.87 0144 TORREY TIMKEN 138 138 0.8 0144 TORREY TIMKEN 138 138 0.86 0145 CANTON CENTRAL TIMKEN 138 138 0.74 0145 CANTON CENTRAL TIMKEN 138 138 5.52 0146 EAST LIMA WESTMINSTER 138 138 8.38 0147 SUINNYSIDE WAGENHALS NO. 2 138 138 2.21 0149 CANTON CENTRAL WAGENHALS 138 138 2.02 0151 SOUTH CANTON TORREY 138 138 1.26 0151 SOUTH CANTON TORREY 138 138 1.6 0152 MALAGA SPEIDEL 69 138 11.99 0153 BRIDGEVILLE EXT. 138 138 1.88 0156 TIFFIN CENTER EXT. 138 138 5.34 0156 TIFFIN CENTER EXT. 69 138 1.81 0158 ROBINSON PARK RICHLAND 138 138 14.94 0159 EAST LIMA RICHLAND 138 138 27.74 0164 FOSTORIA CENTRAL FOSTORIA 138 138 0.08 0164 FOSTORIA CENTRAL FOSTORIA 138 138 1.48 0169 SOUTH CALDWELL SOUTH CUMBERLAND 138 138 10.86 0170 HANGING ROCK EXT. 138 138 4.33 0174 CANTON CENTRAL BLUEBELL 138 138 0.36 0175 CANTON CENTRAL CLOVERDALE 138 138 0.38 0176 TIDD STEUBENVILLE 138 138 7.3 0177 SOUTHWEST LIMA STERLING 138 138 5.14 0177 SOUTHWEST LIMA STERLING 34 138 0.18 0177 SOUTHWEST LIMA STERLING 138 138 0.02 0177 SOUTHWEST LIMA STERLING 138 138 0.03 0178 SOUTHWEST LIMA WEST LIMA 138 138 0.88 Schedule G-4 Page 5 of 7 OHIO POWER COMPANY TRANSFER OF JURISDICTIONAL ASSETS TO OPCO EDC TRANSMISSION LINES 132 KV AND ABOVE ----------------------------------- ================================================================================ DESIGNATION VOLTAGE -------------------------------------------------------------------- LENGTH FROM TO OPERATING DESIGNED POLE MILES ================================================================================ 0180 OHIO CENTRAL EXT NO. 1 138 138 0.46 0181 OHIO CENTRAL EXT NO. 2 138 138 0.45 0182 SOUTH CANTON WEST CANTON 138 138 5.2 0182 SOUTH CANTON WEST CANTON 138 138 2.59 0182 SOUTH CANTON WEST CANTON 138 138 2.26 0183 KAMMER WEST BELLAIRE 138 138 12.85 0183 KAMMER WEST BELLAIRE 69 138 0.33 0186 EAST ZANESVILLE EXT. 138 138 0.04 0187 WEST BELLAIRE BRUES 138 138 4.26 0188 WEST BELLAIRE TILTONVILLE 138 138 11.49 0188 WEST BELLAIRE TILTONVILLE 138 138 0.5 0189 CROOKSVILLE TIE 138 138 0.2 0190 SOUTHWEST LIMA WEST MOULTON 138 138 13.33 0193 TIFFIN CENTER FREMONT CENTER 138 138 11.84 0193 TIFFIN CENTER FREMONT CENTER 138 138 0.7 0193 TIFFIN CENTER FREMONT CENTER 138 138 0.04 0196 FREMONT CENTER FREMONT 138 138 3.02 0196 FREMONT CENTER FREMONT 138 138 2.68 0198 N. PROCTORVILLE EAST HUNTINGTON 138 138 3.86 0198 N. PROCTORVILLE EAST HUNTINGTON 34 138 0.08 0200 CAMPBELL ROAD MIDWEST CO-OP 138 138 0.15 0201 N. PROCTORVILLE SOUTH POINT 138 138 0.04 0201 N. PROCTORVILLE SOUTH POINT 138 138 10.83 0202 MUSKINGUM WOLF CREEK 138 138 4.37 0202 MUSKINGUM WOLF CREEK 138 138 0.34 0203 SWITZER EXT. NO. 1 138 138 0.04 0204 SWITZER EXT. NO. 2 138 138 0.06 0210 BUCKLEY ROAD EXT. 138 138 0.09 0210 BUCKLEY ROAD EXT. 138 138 2.62 0213 WINDSOR EXT. NO. 2 0 138 0.11 0221 DARRAH NORTH PROCTORVILLE 138 138 3.51 0223 DEXTER MEIGS NO. 2 138 138 5.53 0224 NORTH RUTLAND MEIGS NO. 1 138 138 3.84 0225 AMITY ACADEMIA 138 138 0.14 0225 AMITY ACADEMIA 138 138 6.33 0226 ACADEMIA WEST MT. VERNON 138 138 0.15 0226 ACADEMIA WEST MT. VERNON 138 138 5.95 0229 CANNELVILLE GURNSEY MUSKINGUM C 138 138 0.11 0230 FAIRCREST EXT. 138 138 0.04 0235 WEST MILLERSPORT HEATH 138 138 11.85 0235 WEST MILLERSPORT HEATH 138 138 0.16 0238 NORTH PROCTORVILLE E 138 138 3.54 0240 NORTH CROWN CITY EXT. 138 138 0.24 0241 NORTH CROWN CITY EXT. 138 138 0.24 0242 HEATH EXT. NO. 2 138 138 1.29 0243 HEATH EXT, NO. 1 138 138 1.29 0244 EAST SIDE EXT. 138 138 0.24 Schedule G-4 Page 6 of 7 OHIO POWER COMPANY TRANSFER OF JURISDICTIONAL ASSETS TO OPCO EDC TRANSMISSION LINES 132 KV AND ABOVE ----------------------------------- ================================================================================ DESIGNATION VOLTAGE -------------------------------------------------------------------- LENGTH FROM TO OPERATING DESIGNED POLE MILES ================================================================================ 0244 EAST SIDE EXT. 138 138 0.08 0245 SOUTHEAST CANTON SUNNYSIDE 138 138 2.31 0247 SOUTHEAST CANTON WACO 138 138 2.12 0252 WEST DOVER EXT. NO. 138 138 0.1 0253 WEST DOVER EXT. NO. 138 138 0.09 0254 BUCKEYE CO-OP EXT. A 138 138 0.21 0257 GREENLAWN EXT. 138 138 1.09 0260 EAST PROCTORVILLE EX. 138 138 0.13 0264 FREMONT SANDUSKY BAY 69 138 12.13 0265 WEST DOVER SUGARCREEK 138 138 4.07 0267 NORTH PORTSMOUTH CENTRAL PORTSMOUTH 138 138 6.04 0273 BUCKLEY ROAD FREMONT CENTER 69 138 0.9 0274 WAYVIEW HOOVER NORTH 69 138 0.02 0274 WAYVIEW HOOVER NORTH 69 138 1.04 0275 WEST CANTON JCT. WAYVIEW 138 138 1.11 0275 WEST CANTON JCT. WAYVIEW 138 138 1.8 0275 WEST CANTON JCT. WAYVIEW 138 138 1.89 0276 BELDEN VILLAGE EXT. 138 138 1.51 0280 EAST AMSTERDAM CARROLL CO-OP 69 138 7.98 0282 SOUTH POINT TIE 138 138 0.09 0286 WEST CANTON TIE 138 138 0.07 0289 OHIO CENTRAL EXT. NO. 138 138 0.27 0290 SOUTH CANTON EXT. NO. 138 138 0.71 0294 SOUTH CANTON EXT. NO. 138 138 0.31 0295 BROADACRE EXT. 138 138 0.04 0307 WEST VAN WERT DELPHOS CENTER 69 138 1.7 0313 BUCKEYE COPOP EXT. W 138 138 0.85 0316 ORDANANCE JCT. EXT. 138 138 0.1 0317 GUERNSEY MUSKINGUM CO-OP EXT. 138 138 0.12 0318 BUCKEYE CO-OP EXT. M 138 138 0.15 0320 HEDDING ROAD MORROW CO-OP 138 138 0.09 0324 WEST MILLERSPORT SOUTH CENTRAL POWER 138 138 0.2 0325 SHELBY MUNICIPAL EXT. 138 138 0.53 0326 BLOOMFIELD GUERNSEY MUSKINGUM C 138 138 0.41 0327 NORTH CENTRAL CO-OP 138 138 0.45 0329 TYCOON EXT. 138 138 0.29 0331 LICKING CO-OP EXT. 138 138 0.04 0333 ASHLEY EXT. 69 138 0.62 0334 NORTH CHESHIRE EXT. N 138 138 0.38 0336 SHUFFEL ROAD TIMKEN RESEARCH 69 138 0.66 0337 TIMKEN, RICHVILLE EX 138 138 1.11 0338 CONESVILLE COAL PREP 138 138 0.63 0339 A.G.A. GAS EXT. 138 138 0.16 0342 EAST WOOSTER EXT. NO. 138 138 5.15 0343 EAST WOOSTER EXT. 138 138 0.18 0343 EAST WOOSTER EXT. 138 138 0.43 0344 WAGENHALS LTV STEEL NO. 1 138 138 0.65 Schedule G-4 Page 7 of 7 OHIO POWER COMPANY TRANSFER OF JURISDICTIONAL ASSETS TO OPCO EDC TRANSMISSION LINES 132 KV AND ABOVE ----------------------------------- ================================================================================ DESIGNATION VOLTAGE -------------------------------------------------------------------- LENGTH FROM TO OPERATING DESIGNED POLE MILES ================================================================================ 0345 WAGENHALS LTV STEEL NO. 2 138 138 0.68 0346 FOSTORIA TIE 138 138 0.02 0347 FOSTORIA CENTRAL EXT. 138 138 0.1 0348 FOSTORIA CENTRAL EXT. 138 138 0.1 0349 FOSTORIA POWER EXT. 138 138 0.1 0350 HANCOCK WOOD CO-OP 138 138 0.03 0351 EAST LEIPSIC EXT. 138 138 6.57 0352 BUCKEYE CO-OP EXT. 138 138 0.09 0353 STERLING FOUNDRY PARK 138 138 0.91 0354 GAVIN EXT. NO. 1 138 138 3.1 0355 GAVIN EXT. NO. 2 138 138 3.01 0358 LICKING REC. EXT. A 138 138 0.24 0359 BUCKHORN HOLMES 138 138 0.98 0360 ADAMS RUAL ELECTRIC 138 138 0.8 0361 RILEY CREEK PAULDING PUTNAM 138 138 1.2 0363 MEIGS NO. 2 WILKESVILLE 138 138 1.6 Schedule G-5 Page 1 of 17 OHIO POWER COMPANY TRANSFER OF JURISDICTIONAL ASSETS TO OPCO EDC TRANSMISSION LINES LESS THAN 132 KV ----------------------------------- LINE NAME VOLTAGE MILES -------------------------------------------------------------------------------- Allen Avenue - Hercules 23 0.78 Allen Avenue - Hercules (Cust. Owned) 23 0.14 Bush Place - Bonnot 23 0.17 Cannelsville - Guernsey - Muskingum Co-op 23 0.12 Distillery Road - Rubbermaid 23 0.35 Dunkirk - Arlington 23 6.54 East Sparta - Zoarville 23 7.02 East Street - General Electric 23 0.04 East Wheelersburg - Texas Eastern 23 1.99 Forest - North Forest 23 0.89 Fort Brown - Paulding Putnam Co-op - Roselms 23 8.20 Hancock Wood Co-op Ext. - Arlington 23 0.02 International Paper Ext. 23 0.12 James Meter - James Coal 23 1.25 Larry Toth Extension 23 0.48 LTV Steel South Div. Ext. 23 0.13 Nineteenth Street - Canton Drop Forge 23 1.29 Palmer - Wooster Rubber 23 0.06 Park Avenue Extension. Timken 23 0.25 Pekin - Augusta 23 10.67 Schroyer Avenue - Piedmont 23 1.35 Sparta - Sparta Pumping 23 0.42 Stanley Court - Piedmont 23 1.13 Sunnyside - Bryan Avenue 23 4.13 Sunnyside - Stanley Court 23 2.63 Sunnyside - Third Street East 23 1.42 Sunnyside - Third Street West 23 1.74 Timken Extension, Wooster 23 0.07 Timken - Gambrinus Line No. 1 23 1.38 Timken - Park Avenue 23 0.53 Timken - Timken Furnace No. 2 23 0.15 Timken - Timken Melt 23 0.27 Torrey - Bryan Avenue 23 0.64 Torrey - LTV Steel South Division 23 0.98 Torrey - Nineteenth Street 23 0.76 Torrey - Timken Gambrinus 23 1.06 Torrey - Timken Line No. 2 23 0.77 Torrey - Timken No. 3 23 1.40 Union Metal Junction - Union Metal 23 0.06 Wagenhals - Georgetown No. 1 23 0.16 Schedule G-5 Page 2 of 17 OHIO POWER COMPANY TRANSFER OF JURISDICTIONAL ASSETS TO OPCO EDC TRANSMISSION LINES LESS THAN 132 KV ----------------------------------- LINE NAME VOLTAGE MILES -------------------------------------------------------------------------------- Wagenhals - Georgetown No. 2 23 0.21 Waynesburg - Malvern 23 2.95 Wooster - Timken 23 0.18 Atlantic Avenue - Saint Ritas 34 0.76 Augusta - Ashland Pipeline 34 0.17 Bakersville - Frontier Power 34 0.69 Beaver - Buckeye Co-op 34 5.16 Belden Brick Ext. No. 1 34 0.10 Belden Brick Extension No. 2 34 0.18 Betz Ext. 34 0.18 Bolivar Tap 34 0.02 Brookfield - Central Ohio Coal 34 0.24 Cable Road - Lima Register 34 0.08 Caldwell - Cumberland 34 11.36 Cambridge - water Street 34 2.03 Cambridge Hospital Ext. 34 1.05 Cambridge Hospital Extn. 34 0.09 Charles Street Ext. 34 0.17 Cherry Street - Brown 34 0.01 Dana Corporation Tap 34 1.11 Derwent - Senecaville 34 2.62 Eagle Crusher Ext. 34 0.10 East Cambridge Ext. 34 0.26 East Coshocton - North Coshocton 34 1.58 East Delphos - Kossuth 34 15.63 East Logan - Lancaster 34 18.72 Elizabeth Street - Central Avenue 34 0.80 Fairdale - South Cambridge 34 3.53 Findlay - North Findlay 34 3.95 Findlay Center - Findlay Reservoir 34 6.00 Findlay Reservoir Pumping No. 1 Tap 34 0.01 Fort Steuben - Hammondsville 34 20.28 Franklin Furnace - Grays Branch 34 0.35 Frontier Power Ext. - Empire Coal 34 0.88 Goshen - Timken 34 3.06 Granville - Heath 34 0.77 Guernsey - Muskingum Co-op Ext. - Mount Sterling 34 0.04 Hammansburg - Buckeye Pipe 34 1.76 Hammondsville - Salineville 34 9.15 Hancock Wood Co-op Ext. - Airport 34 0.93 Hancock Wood Co-op Ext. - East Findlay 34 0.11 Schedule G-5 Page 3 of 17 OHIO POWER COMPANY TRANSFER OF JURISDICTIONAL ASSETS TO OPCO EDC TRANSMISSION LINES LESS THAN 132 KV ----------------------------------- LINE NAME VOLTAGE MILES -------------------------------------------------------------------------------- Hancock Wood Co-op Ext. - Henry 34 0.11 Harpster - DeCliff 34 11.98 Killbuck Junction - Glenmont 34 5.37 Killbuck Junction Extension 34 0.08 Lima - Elizabeth 34 2.00 Lima - South Side 34 5.24 Lima Pumping Ext. 34 0.39 Mcintosh Ext. 34 0.20 Metham - Frontier Power 34 0.39 Michael Avenue - Metokote 34 0.26 Mineral Siding - Antrim 34 10.18 Mix Plant Extension 34 0.08 Morgan's Run - Allegheny Pipe 34 6.41 Muskingum Mine School Ext. 34 0.07 N & W Railroad Ext. 34 0.02 N. & W. Railroad Ext. 34 0.16 National Lime and Stone Ext. 34 0.22 National Milling Ext. 34 0.28 New Boston Coke Ext. 34 0.02 New Liberty - Findlay 34 3.61 New Liberty - Findlay Center 34 7.69 New Liberty - McComb 34 6.92 New Liberty - North Baltimore 34 10.26 New Philadelphia - Dover 34 3.25 New Philadelphia - West New Philadelphia 34 2.55 Newcomerstown - Baltic 34 30.78 Newcomerstown - Cambridge 34 19.72 Newcomerstown - East Coshocton 34 12.83 North Baltimore - Portage 34 10.54 North Findlay - North Baltimore No. 2 34 7.95 North Portsmouth - Oertels Corners 34 4.73 Plaza - Eastman 34 1.77 Pleasant Street -Allied Chemical 34 1.00 Portage Extension 34 0.08 Robb Avenue - Spencerville Road 34 2.80 Robb Avenue Tie Line 34 0.06 Rockhill - Robb Avenue 34 1.00 Rutland - Hobson 34 3.35 Rutland - Pomeroy 34 7.57 Shawtown - Hancock Wood Co-op 34 0.01 Sixth Street - Hantech 34 1.10 Schedule G-5 Page 4 of 17 OHIO POWER COMPANY TRANSFER OF JURISDICTIONAL ASSETS TO OPCO EDC TRANSMISSION LINES LESS THAN 132 KV ----------------------------------- LINE NAME VOLTAGE MILES -------------------------------------------------------------------------------- South Belle Valley - Washington Co-op 34 4.68 South Coshocton - General Electric 34 1.05 South Coshocton - Killbuck, 34KV 34 1.61 South Killbuck - Holmes Wayne Co-op 34 0.05 South Mount Corey - Hancock Wood Co-op 34 0.01 South Point - Ethanol No. 1 34 0.95 South Point - Ethanol No. 2 34 1.80 South Warsaw - Frontier Power 34 3.73 Southside - Eaton 34 0.20 Southwest Lafayette - Frontier Power 34 0.25 Sterling - South Side 34 1.31 Sterling Ext. 34 0.35 Sugar Refinery Ext. 34 0.12 Sugarcreek - Baltic 34 5.68 Superior Metals Ext. 34 0.24 Totten Ext. 34 0.53 Viaduct - South Portsmouth 34 2.02 Vine Street - Central Avenue 34 1.32 Warner - Swasey Ext. 34 0.77 West Berlin - Benton 34 3.01 West Broadway - Norbalt Rubber 34 0.08 West Cambridge - Water Street 34 3.96 West Lafayette - Penn Michigan 34 0.73 West Melrose - Whirlpool 34 2.99 Wright Ext. 34 0.51 Yakley Road - Walnut Creek 34 0.32 Harvard Avenue - Owen Illinois 34 0.10 Shawnee Road - Midwest Co-op 34 4.94 South Coshocton - Banner 34 2.15 South Dover - Ridge Tool 34 1.22 Ash Avenue Tap 34.5 0.01 Poe Avenue Tap 34.5 0.01 East Cadiz - Cadiz 40 1.00 Euclid - Toronto 40 0.46 Guernsey - Muskingum Co-op Ext. - Chandlersville 40 0.12 Academia - Gambier 69 4.14 Alikanna - Steubenville Pumping 69 0.35 Allegheny Pipe 69kV Ext., Hopedale 69 0.71 Allendale - East End 69 1.51 Allendale - Fremont Center 69 17.39 Amsden - North Central Co-op 69 0.12 Schedule G-5 Page 5 of 17 OHIO POWER COMPANY TRANSFER OF JURISDICTIONAL ASSETS TO OPCO EDC TRANSMISSION LINES LESS THAN 132 KV ----------------------------------- LINE NAME VOLTAGE MILES -------------------------------------------------------------------------------- Amsterdam - Wolf Run 69 1.79 Anchor Hocking Ext. No. 2 69 0.04 Antrim - Londonderry 69 6.05 Arbor Street Ext. 69 0.26 ARCO Ext. - Marion 69 0.22 Armco 69kV Ext. 69 0.01 Ashland Pipe Ext., Kenton 69 2.89 Auglaze - Mark Center 69 14.51 Augusta - Summitville 69 3.93 Avondale Tap 69 0.02 Baltimore - Fairfield 69 0.30 Bannock Road - Flushing 69 7.72 Barmet Ext. 69 0.09 Barnsville - Summerfield 69 15.81 Bauer Road - East Wooster 69 0.70 Beall Avenue - Riffle Road 69 1.25 Beartown - West Wilmont 69 10.56 Belden - Lock Seventeen 69 1.64 Bellaire - Glencoe 69 16.55 Belmont Co-op Ext. - Beallsville 69 0.62 Belmont Co-op Ext. - Jewett 69 0.01 Belmont Co-op Ext. - Pipe Creek 69 0.45 Bernard Street - Northeast Findlay 69 2.85 Berwick Tap 69 0.01 Bethel - Hilliard 69 7.29 Billiar - West Wilmot 69 6.18 Birchard Avenue - West Fremont 69 0.11 Bliss Park Ext. 69 0.10 Blue Lick - Midwest Co-op 69 0.10 Bowerston - Leesville 69 1.80 Bowman Street Ext. 69 0.08 Bremen Bus 69 0.02 Brues - Bellaire 69 0.71 Brues - Martins Ferry 69 7.24 Brues - West Bellaire 69 0.54 Buckeye Road - Hover Park 69 3.41 Bucyrus - Swan Rubber 69 1.54 Bucyrus - Upper Sandusky 69 21.50 Bucyrus Center - Sandusky Avenue 69 4.29 Burns Ext. 69 0.78 Byesville - Glenwood 69 9.63 Schedule G-5 Page 6 of 17 OHIO POWER COMPANY TRANSFER OF JURISDICTIONAL ASSETS TO OPCO EDC TRANSMISSION LINES LESS THAN 132 KV ----------------------------------- LINE NAME VOLTAGE MILES -------------------------------------------------------------------------------- Byesville Tap 69 0.01 Cairo Tap 69 0.01 Calcutta - East Liverpool 69 3.75 Cambridge - East Cambridge 69 0.92 Cameron - Belmont Co-op 69 2.32 Canal Road - Wooster Jct. 69 7.34 Canton Alloys Ext. 69 0.19 Carroll Co-op Ext., Mohawk 69 0.40 Carrothers - Willard 69 16.23 Cassell Jct. - Guernsey Muskingum Co-op 69 0.07 Cavett - Paulding Putnam Co-op 69 7.62 Cecil Tap 69 0.01 Central Portsmouth - South Portsmouth 69 1.26 Central Portsmouth - Sugarhill 69 2.90 Central Portsmouth Ext. 69 0.06 Cessna - United Co-op 69 0.03 Chatfield - Carrothers 69 2.92 Chatfield Ext. 69 0.07 Chatham - Licking Co-op 69 0.04 Circle Green - Carroll Co-op Springfield 69 4.41 City of Saint Marys Tap 69 0.02 Clegg - South Glencoe 69 0.87 Conotton - Carroll Co-op 69 6.02 Coopermill - Norval Park 69 1.42 Coopermill - South Fultonham 69 8.43 Coopermill Ext. 69 0.04 Coshocton - North Coshocton 69 1.64 County Hospital - West Louisville 69 4.34 Crawfis College - Pandora 69 5.24 Crooksville - Somerset 69 10.07 Crooksville - South Fultonham 69 7.41 Cyclops - Ohio Central 69 13.67 D.T.R. Industries Ext. 69 0.40 Davis Street - Atlas Industries 69 0.42 Dayton Lane Ext. 69 0.50 Delphos - South Van Wert 69 14.44 Delphos Junction - East Delphos 69 2.32 Dennison - New Philadelphia 69 9.86 Dennison - Scio 69 15.54 Derwent Ext. 69 0.63 Diamond Specialty Ext. 69 0.32 Schedule G-5 Page 7 of 17 OHIO POWER COMPANY TRANSFER OF JURISDICTIONAL ASSETS TO OPCO EDC TRANSMISSION LINES LESS THAN 132 KV ----------------------------------- LINE NAME VOLTAGE MILES -------------------------------------------------------------------------------- Diamond Street - County Hospital 69 4.94 Dilles Bottom - Bellaire 69 10.49 Dillonvale - Amsterdam 69 21.01 Dillonvale - Boich Mining 69 7.92 Dillonvale - Robyville 69 5.80 Dover - Beartown 69 9.50 Dover - Sugarcreek 69 8.24 Dow Chemical Ext., Granville 69 0.58 Dueber Avenue - Eighth Street 69 1.99 Dueber Industry - Liquid Carbonic 69 0.06 Dunkirk - Ada 69 10.80 Dunkirk - Kenton 69 11.46 East Amsterdam - Carroll Co-op 69 7.96 East Berlin - Owens Illinois 69 0.58 East Cambridge - Byesville 69 3.03 East Cambridge - Senecaville 69 11.47 East Coshocton - Frontier Power 69 0.19 East Dover - Carroll Co-op 69 30.56 East Dover Ext. 69 1.36 East End Tap 69 0.01 East Fredericktown - Fredericktown 69 4.27 East Fredericktown - Licking Co-op - Mount Vernon 69 0.12 East Leipsic Ext. 69 6.57 East Lima - Lafayette 69 6.30 East Lima - Lima 69 4.42 East Logan - Southeast Logan 69 1.55 East Newark - North Newark 69 3.67 East Ottawa - Crawfis College 69 4.14 East Ottawa - Leipsic 69 5.33 East Ottoville - Paulding Putnam Co-op 69 0.03 East Proctorville Ext. 69 0.00 East Side Ext. 69 0.32 East Tiffin - Holmes Street 69 3.44 East Union Jct. - East Union 69 1.32 East Wooster Ext. No. 1 69 5.13 East Zanesville - Oakland 69 2.05 Eighth Street - Stadium Park 69 1.31 Elizabeth Ext. 69 0.72 Engineered Wire Products 69 0.45 Enterprise - South Central Power 69 0.03 Euclid - Toronto Paper 69 0.05 Schedule G-5 Page 8 of 17 OHIO POWER COMPANY TRANSFER OF JURISDICTIONAL ASSETS TO OPCO EDC TRANSMISSION LINES LESS THAN 132 KV ----------------------------------- LINE NAME VOLTAGE MILES -------------------------------------------------------------------------------- Evergreen - Licking Co-op 69 0.03 Excello Ext., Buckeye Road 69 0.09 Findlay - Fifth Street 69 1.79 Findlay - Woodcock 69 16.16 Findlay Center - Eastman 69 1.53 Flex Products Ext. 69 0.79 Fontaine - Kenton 69 2.40 Ford Motor Ext. 69 0.37 Forest - Dunkirk 69 7.99 Forest - McVitty 69 1.21 Fort Shawnee - Buckeye Pipe 69 0.45 Fort Steuben - High Street 69 0.55 Fort Steuben - Wheeling Steel 69 0.10 Fostoria - Central Extension No. 1 69 0.10 Fostoria - Hatton 69 6.01 Fostoria - North Belt 69 2.55 Fostoria North End - Bendix 69 0.23 Fostoria - Pemberville 69 18.68 Fostoria Central - East Lima 69 39.85 Franklin School - Holmes Wayne Co-op - Moreland 69 0.50 Fremont - North Fremont 69 2.68 Fremont - Sandusky Bay 69 12.25 Fremont Center - East Fremont 69 2.26 Fremont Center - Fremont 69 5.75 Frontier Power Co-op Ext. - Manning 69 1.39 Ginat Creek - Plymouth Heights 69 0.29 Glencoe - Norton 69 8.86 Glencoe - Speidel 69 25.36 Glenmont Jct. - Holmes Wayne Co-op - Stillwell 69 7.05 Granville - West Granville 69 4.36 Greely Ext. 69 1.75 Greer Steel Ext. No. 1 69 0.13 Greer Steel Ext. No. 2 69 0.10 Gros-Jean - South Wooster 69 0.07 Guernsey - Muskingum Co-op Ext. - Senecaville 69 0.01 Hammondsville - Carroll Co-Op 69 4.47 Hancock Wood Co-op - Townwood 69 0.02 Hancock Wood Co-op Ext. 69 0.02 Hancock Wood Co-op Ext. - Hatton 69 0.03 Hanging Rock - North Haverhill 69 2.77 Hanging Rock 69kV Ext. 69 0.18 Schedule G-5 Page 9 of 17 OHIO POWER COMPANY TRANSFER OF JURISDICTIONAL ASSETS TO OPCO EDC TRANSMISSION LINES LESS THAN 132 KV ----------------------------------- LINE NAME VOLTAGE MILES -------------------------------------------------------------------------------- Harmont Road - Mahoning Road 69 0.07 Harpster Pumping - Waldo 69 24.96 Harrisburg Road - Stadium Park 69 3.82 Harrisville - Pleasant Grove 69 1.87 Haverhill - East Haverhill 69 0.10 Haviland - Paulding 69 10.72 Haviland - South Hicksville 69 26.38 Haviland - West Van Wert 69 14.60 Haysport - K. O. Ext. 69 1.32 Heath - Southgate 69 2.04 High Street - Steubenville 69 3.85 High Street - West Alikanna 69 3.99 Hillndale Ext. 69 0.66 Hover Park - South Side 69 1.62 Howard - Bucyrus No.1 69 17.75 Howard - Bucyrus No. 2 69 18.77 Howard - Willard 69 13.72 Hunt - Licking Co-op 69 0.02 Ireland Mine 69 0.00 Ironton - Portsmouth 69 26.74 Jacksontown - Licking Co-op 69 0.11 Janet Court - Third Street 69 0.55 Kaiser Junction - Dow Chemical 69 4.10 Kaiser Junction - Heath 69 2.90 Kalida - Auglaize 69 23.60 Kalida - East Ottawa 69 10.37 Kalida - Ottoville 69 8.34 Kammer - West Powhatan 69 2.08 Kammer - West Powhatan No. 1 69 0.66 Kammer - West Powhatan No. 2 69 0.65 Lafayette - Ada 69 9.73 Lancaster - Anchor Hocking 69 1.11 Lancaster Junction - Ralston 69 3.07 Latty Junction - Paulding Putnam Co-op 69 0.03 Leatherwood - North Cambridge 69 0.63 Leipsic - McComb 69 11.65 Licking Co-op Extension - Hebron 69 0.16 Licking Co-op, Jelloway 69 0.03 Lima - Kalida 69 17.23 Linden Avenue Ext. 69 1.52 Londonderry - Smyrna 69 4.21 Schedule G-5 Page 10 of 17 OHIO POWER COMPANY TRANSFER OF JURISDICTIONAL ASSETS TO OPCO EDC TRANSMISSION LINES LESS THAN 132 KV ----------------------------------- LINE NAME VOLTAGE MILES -------------------------------------------------------------------------------- Longley - West Longley 69 0.39 Louisville Junction - Louisville 69 0.25 Mahoning Road - Cliftmont 69 1.01 Mahoning Road Ext. 69 0.03 Malvern - Pekin 69 5.28 Mansfield Road - Holmes Wayne Co-op 69 2.39 Mark Center - South Hicksville 69 8.83 Martin's Ferry - Tiltonville 69 5.04 Martin's Ferry - Wheeling Steel 69 0.11 McLuney - Rose Farm 69 1.73 Meigs - Coolville 69 24.31 Meigs - Gavin 69 7.09 Memorial Drive - Lancaster Junction 69 2.38 Mid Ohio Ext. 69 0.10 Midland - Plaza 69 1.54 Midway - Glencoe 69 6.51 Mill Street - Ridge Tool 69 1.08 Millbrook - Ashley 69 0.08 Millbrook - Offnere, 69 3.43 Millbrook - Siloam Tie Line 69 0.12 Millbrook Park - Scioto Trails 69 4.29 Miller - Jewett 69 4.92 Millersburg - South Millersburg 69 2.91 Moreland Junction - Billiar 69 21.66 Moreland Junction - Shreve 69 6.50 Moscow - Frontier Power 69 1.24 Mound - Rockwell 69 0.07 Moundsville - Dilles Bottom 69 4.07 Mount Vernon - Howard 69 25.86 Mount Vernon - North Newark 69 22.60 Moxahala Avenue - Hughes Street 69 1.53 Muskingum River - South Rokeby 69 21.28 New Lexington - Crooksville 69 8.55 New Lexington - Shawnee 69 8.58 Newark - East Newark 69 2.15 Newark - Kaiser Junction 69 2.64 Newark - Owens 69 0.97 Newark - Seroco Ave 69 1.44 Newark - Thornville 69 10.51 Newark Center - Licking Co-op 69 3.18 Newark Center - Southeast Newark 69 3.21 Schedule G-5 Page 11 of 17 OHIO POWER COMPANY TRANSFER OF JURISDICTIONAL ASSETS TO OPCO EDC TRANSMISSION LINES LESS THAN 132 KV ----------------------------------- LINE NAME VOLTAGE MILES -------------------------------------------------------------------------------- Newark Center Extension 69 0.04 Newcomerstown - Dennison 69 20.38 Newcomerstown - West New Philadelphia 69 35.02 No. 10 Station Extension 69 4.20 No. 25 Station Extension 69 0.01 No. 8 Station Extension 69 0.33 North Antwerp - East Antwerp 69 1.75 North Bloomville - North Central Co-op 69 8.07 North Byesville - South Cambridge 69 0.44 North Canton - Hoover 69 0.60 North Canton Ext. 69 2.97 North Columbus Grove - Paulding Putnam Co-op 69 0.10 North Continental - Paulding Putnam Co-op 69 7.72 North Coshocton - Cyclops 69 6.51 North Coshocton Tie Line 69 0.07 North Crestwood - Tall Timbers 69 0.96 North Crown City - Crown City 69 3.02 North Crown City - Crown City Mining 69 0.05 North Delphos - Ottoville 69 2.84 North Delphos - South Delphos 69 5.20 North Dillon - Dillon Road 69 0.19 North Findlay - North Baltimore No. 1 69 7.77 North Findlay - North Main 69 0.90 North Findlay Extension 69 0.05 North Fremont - East Fremont 69 2.91 North Galion - West Galion 69 3.62 North Hicksville - Northwestern Co-Op 69 1.41 North Hicksville Extension 69 0.10 North Ironton Extension 69 0.25 North Kalida - Paulding Putnam Co-op 69 0.04 North McConnelsville - South Rokeby 69 0.24 North Minford - Minford 69 1.69 North Mount Vernon Extension 69 0.71 North Muskingum - Muskingum Mine 69 1.01 North Muskingum - West Malta 69 8.38 North Newark - Owens 69 1.14 North Newark - South Grandville 69 8.15 North Newport Ext. 69 0.02 North Portsmouth - Sugarhill 69 6.91 North Stone Creek - Frontier Power 69 0.05 North Waldo - Waldo 69 3.95 Schedule G-5 Page 12 of 17 OHIO POWER COMPANY TRANSFER OF JURISDICTIONAL ASSETS TO OPCO EDC TRANSMISSION LINES LESS THAN 132 KV ----------------------------------- LINE NAME VOLTAGE MILES -------------------------------------------------------------------------------- North Wellsville - Calcutta 69 6.44 North Wellsville - Hammondsville 69 6.82 North Wellsville - Second Street 69 3.65 North Wharton - Hancock Wood Co-op 69 4.57 North Wintersville - Two Ridge 69 1.77 North Woodcock - Pandora 69 6.37 North Woodcock - Woodcock 69 7.30 North Wooster Tap 69 0.03 Northeast Canton - Diamond Street 69 3.45 Norton - Cravat 69 0.05 Norton - Somerton 69 25.00 Oak Hill - Holmes Wayne Co-op 69 7.48 Oakland Extension 69 0.06 Oertels Comers - Beaver 69 12.31 Oneida - Colfor 69 0.51 Orrville Road - North Wayne 69 4.71 Ottawa - Columbus Grove 69 6.92 Ottawa - East Ottawa 69 1.56 Owens Corning Extension - Grandville 69 0.39 Parlett - East Cadiz 69 7.48 Paulding - Mark Center 69 11.84 Paulding Putnam Co-op Extension - Antwerp 69 0.35 Pittsburgh Avenue Extension 69 0.21 Plaza Extension 69 0.04 Pleasant City - Cumberland 69 6.95 Pleasantville - Baltimore 69 6.06 Pratt - Phillips 69 0.09 Pratt Extension 69 0.28 Provident - Bannock Road 69 3.68 R&F Coal Extension, Georgetown 69 0.12 R.S.S. Extension 69 0.39 Raceland - Dow Chemical 69 5.55 Racine Hydro Extension 69 4.08 Ralston - North Logan 69 15.24 Randell Bearing Extension 69 0.13 Rawson - Standard Oil 69 0.03 Reedurban Extension 69 0.47 Ripley - Licking Co-op 69 12.81 Robyville - Midway 69 6.72 Robyville - South Cadiz 69 5.71 Rockhill - Industrial 69 1.12 Schedule G-5 Page 13 of 17 OHIO POWER COMPANY TRANSFER OF JURISDICTIONAL ASSETS TO OPCO EDC TRANSMISSION LINES LESS THAN 132 KV ----------------------------------- LINE NAME VOLTAGE MILES -------------------------------------------------------------------------------- Rockhill - Woodcock 69 14.49 Rosemount Extension 69 0.24 Royal Avenue - Wean United 69 0.13 S.B.C. Ext. 69 0.51 Saint Clair Avenue - State Line 69 3.25 Saint Stephens - North Central Co-op 69 0.02 Salineville - Summitville 69 5.36 Salt Fork - Guernsey Muskingum Co-Op 69 1.20 Saltillo - South Fultonham 69 5.92 Schoenbrunn Extension 69 0.56 Schroyer Avenue - Cherry Avenue 69 1.52 Scio - Jewett 69 6.72 Scioto Trail - Offnere 69 1.96 Second Street - Saint Clair Avenue 69 1.26 Seneca Wire 69kV Extension 69 0.26 Sharp Road - Range Road 69 1.43 Sharp Road Extention 69 0.02 Shawnee Road - Buckeye Road 69 2.10 Shawnee Road - Wapakoneta 69 8.92 Shelby Copperweld Steel 69 0.42 Sheridan - Buckeye Co-op 69 3.51 Shie Hill - Holmes Wayne Co-op 69 4.10 Shinnick Street - Oakland 69 2.14 Shreve - Big Prairie 69 3.07 Shreve - Holmes Wayne Co-op 69 4.13 Sidle Road - South Van Wert 69 1.89 Sifco Extension, Byesville 69 0.22 Somerset - Texas Eastern 69 1.27 Somerton Extension 69 0.04 South Amsterdam - Carroll Co-op 69 0.13 South Baltimore - Baltimore 69 2.19 South Cadiz - Consolidation Coal 69 1.20 South Cadiz - East Cadiz 69 1.99 South Cambridge - Chapman 69 1.57 South Cambridge - Sheild Alloy 69 0.03 South Carey - North Central Co-op 69 2.52 South Cecil - General Portland 69 0.33 South Coshocton - Killbuck 69 22.50 South Cumberland - Dragline 69 2.44 South Cumberland - Renrock Tie Line 69 7.86 South Delphos - Delphos 69 1.96 Schedule G-5 Page 14 of 17 OHIO POWER COMPANY TRANSFER OF JURISDICTIONAL ASSETS TO OPCO EDC TRANSMISSION LINES LESS THAN 132 KV ----------------------------------- LINE NAME VOLTAGE MILES -------------------------------------------------------------------------------- South Fultonham - Mount Sterling 69 7.18 South Gambrinus Road - Luntz 69 0.61 South Granville - West Granville 69 1.98 South Hicksville - North Hicksville 69 1.38 South Hicksville - Robison Park Tie Line 69 2.40 South Kenton - Fontaine 69 2.54 South Kenton - Kenton 69 2.83 South Kenton - United Co-op 69 3.81 South Kossuth - West Moulton 69 7.95 South Lancaster - East Lancaster 69 1.49 South Lancaster - Ralston 69 3.94 South Lancaster Extension 69 0.52 South Malvern - Carroll Co-Op 69 2.65 South Point - East Huntington 69 9.42 South Point - Ironton 69 10.33 South Rokeby - Gould No. 1 69 0.04 South Rokeby - Gould No. 2 69 0.05 South Tiffin - Carey 69 13.03 South Toronto - Euclid 69 1.13 South Toronto - Toronto 69 1.92 South Toronto Extension No. 1 69 1.05 South Upper Sandusky - Guardian 69 0.46 South Vanlue Extension 69 0.23 Southgate - Newark 69 3.57 Southgate - Seroco Avenue 69 1.89 Southwest Van Wert - South Convoy 69 3.48 Speidel - Barnesville 69 3.51 Sporn 69kV Start Up 69 0.54 Standard Oil Extension Fostoria 69 0.27 Standard Oil Extension, Lima 69 0.12 Stanley Court - Northeast Canton 69 3.15 Steubenville - Wintersville 69 3.02 Stone Street - North Fremont 69 0.71 Stony Hollow Ext. 69 0.09 Stratton Ext. 69 0.21 Stratton Juction - Stratton 69 1.08 Sugarcreek - Millersburg 69 17.06 Sugarhill - Friendship 69 6.57 Summerfield - Derwent 69 13.80 Summerfield - Texas Eastern 69 2.54 Sunnyside - East Sparta 69 9.47 Schedule G-5 Page 15 of 17 OHIO POWER COMPANY TRANSFER OF JURISDICTIONAL ASSETS TO OPCO EDC TRANSMISSION LINES LESS THAN 132 KV ----------------------------------- LINE NAME VOLTAGE MILES -------------------------------------------------------------------------------- Switzer - Belmont Co-op, Powhatan 69 0.05 Switzer - Belmont Co-op, Woodsfield 69 13.83 Thornville - Lancaster 69 19.21 Thornville - New Lexington (Newark) 69 5.89 Thornville - New Lexington (Zanesville) 69 11.25 Tidd - Fort Steuben 69 7.09 Tidd - Tiltonsville 69 8.32 Tiffin - Fostoria 69 12.83 Tiffin - Fremont Center 69 19.38 Tiffin - Howard 69 36.12 Tiffin - South Tiffin 69 3.51 Tiffin Center - Maule Road 69 3.30 Tiffin Center Ext. 69kV 69 0.15 Tiffin Tap Off Extension No. 1 69 0.02 Tiffin Tap Off Extension No. 2 69 0.02 Tiltonville - Dillonvale 69 4.73 Tiltonville - Wheeling Steel No. 1 69 0.49 Tiltonville - Wheeling Steel No. 2 69 0.59 Tipple - Renrock 69 10.62 Torrey - Deuber Avenue 69 2.62 Torrey - Myers Lake 69 2.81 Unionvale - Nelms No. 1 69 0.41 United Co-op Extension Ada 69 0.00 Upper Sandusky - Forest 69 11.27 Upper Sandusky - Harpster Pumping 69 9.65 Van Wert - Haviland 69 10.05 Van Wert - South Van Wert 69 1.12 Van Wert Ext. 69 1.94 Wagenhals - Cherry Avenue 69 3.33 Wagenhals - Pekin 69 15.55 Wagenhals - Stanley Court 69 2.51 Wagenhals - West Louisville 69 4.61 Wakefield - Beaver 69 10.98 Waller - Central Portsmouth 69 0.83 Wapakoneta - West Moulton 69 8.40 Warwood - Glenns Run 69 1.13 Washington - Dilles Bottom 69 1.41 Wayview - North Canton 69 2.86 Wayview Tie Line 69 0.12 Welsh - Sharon Valley 69 0.93 West Alikanna - Wintersville 69 3.22 Schedule G-5 Page 16 of 17 OHIO POWER COMPANY TRANSFER OF JURISDICTIONAL ASSETS TO OPCO EDC TRANSMISSION LINES LESS THAN 132 KV ----------------------------------- LINE NAME VOLTAGE MILES -------------------------------------------------------------------------------- West Bellaire Ext. 69 0.51 West Bellville - Bellville 69 1.87 West Bowerstown - Carroll Co-op 69 0.60 West Brilliant - Weirton Construction 69 0.12 West Byesville Ext. 69 0.88 West Caldwell - Noble Correctional 69 0.65 West Cambridge - Fairdale 69 6.70 West Canton - Thirtieth Street 69 1.99 West Coshocton - North Coshocton 69 2.85 West Dover Ext. 69 0.20 West Granville - Etna 69 9.08 West Hebron - Dow Chemical 69 2.51 West Lancaster - Anchor Hocking 69 1.29 West Lancaster - Memorial Drive 69 3.11 West Malta - North McConnelsville 69 2.07 West Monroe Street - Monroe Street 69 1.69 West Moreland - South Moreland 69 1.16 West Mount Vernon - Mount Vernon 69 2.87 West Nashville - Holmes Wayne Co-op 69 1.35 West New Philadelphia - Dover 69 1.96 West New Philadelphia - East Dover 69 3.92 West New Philadelphia - New Philadelphia 69 2.36 West New Philadelphia Ext. 69 0.05 West Ottawa - Paulding Putnam Co-op 69 5.41 West Powhatan - North American No. 1 69 0.03 West Powhatan - North American No. 2 69 0.04 West Rockaway - North Central Co-op 69 8.32 West Roseville - Roseville 69 0.18 West Shadyside - Shadyside 69 1.76 West Smithville - Smithville 69 0.06 West Upper Sandusky - North Upper Sandusky 69 1.83 West Van Wert - Ohio City 69 5.42 West Wilmont - Holmes Wayne Co-op 69 0.02 West Wooster - East Wooster 69 10.62 Whirlpool Ext. 69 0.14 Willard - Greenwich 69 10.21 Williston Avenue Tap 69 0.01 Willowgrove - Belmont Co-op 69 0.09 Windsor - Glencoe 69 18.92 Windsor - Wilson Avenue 69 4.99 Windsor Ext. 69 0.40 Schedule G-5 Page 17 of 17 OHIO POWER COMPANY TRANSFER OF JURISDICTIONAL ASSETS TO OPCO EDC TRANSMISSION LINES LESS THAN 132 KV ----------------------------------- LINE NAME VOLTAGE MILES -------------------------------------------------------------------------------- Wolf Run - East Springfield 69 1.85 Wooster - Beall Ave 69 1.70 Wooster - Canal Road 69 3.08 Wooster - Moreland Jct. 69 4.73 Wooster -West Wooster 69 2.71 Yellowcreek - East Leipsic 69 1.09 Zanesville - Coopermill 69 1.78 Zanesville - Linden Avenue 69 2.80 Zanesville - Shinnick 69 1.26 Zion - Glass Rock 69 4.80 Blackjack Road Ext. 69 0.05 East Lansing - Lansing 69 3.53 East Logan - Shawnee 69 13.72 South Coshocton - Clow 69 0.25 South Cumberland - Cumberland 69 3.96 South Millersburg - Killbuck Junction 69 2.29 Fish Creek - McElroy 69 0.53 South Central Co-op - Deer Creek 69 2.44 North Hicksville - Butler 69 2.33 Schedule G-6 Page 1 of 6 OHIO POWER COMPANY TRANSFER OF JURISDICTIONAL ASSETS TO OPCO EDC VOLTAGE (IN MVA) CHARACTER OF ---------------------------- TRANSMISSION SUBSTATIONS SUBSTATION PRIMARY SECONDARY TERTIARY -------------------------------------------------------------------------------- CARDINAL PLANT/BRILLIANT, OH ATTENDED-T 138 23 0 ATTENDED-T 13.19 4 0 ATTENDED-T 24 4 0 ATTENDED-T 24 4 4 ATTENDED-T 345 24 0 ATTENDED-T 345 23 0 ATTENDED-T 138 6.9 0 ATTENDED-T 26 6.9 0 ATTENDED-T 13.8 0.6 0 GAVIN 1 AAS ATTENDED-T 138 13.8 0 ATTENDED-T 138 4 0 GAVIN 138KV ATTENDED-T 138 69 12 KAMMER 345KV/MOUNDSVILLE, WV ATTENDED-T 345 138 13.8 ATTENDED-T 345 138 12 KAMMER 400 YARD ATTENDED-T 765 345 34.5 ATTENDED-T 34.5 34.5 3 ATTENDED-T 34.5 12 0 KAMMER 765KV/MOUNDSVILLE, WV ATTENDED-T 765 500 34.5 ATTENDED-T 765 765 0 ATTENDED-T 34.5 34.5 0 ATTENDED-T 13.8 12 0 MUSKINGUM 138KV/ZANESVILLE, OH ATTENDED-T 345 138 12 ATTENDED-T 138 69 12 ACADEMIA/MT VERNON, OH UNATTENDED-T 138 69 12 UNATTENDED-T 23 12 0 ADA UNATTENDED-T 68.8 13.09 0 BUCYRUS CENTER/BUCYRUS, OH UNATTENDED-T 135.4 69.5 13.09 UNATTENDED-T 68.8 13.09 0 CALDWELL/MCCONNELSVILLE, OH UNATTENDED-T 138 34.5 0 UNATTENDED-T 138 12 0 UNATTENDED-T 34.5 4 0 CANAL RD/WOOSTER, OH UNATTENDED-T 138 69 23 UNATTENDED-T 23 4 0 CANTON CENTRAL/CANTON, OH UNATTENDED-T 345 138 12 CENTRAL PORTSMOUTH/PORTSMOUTH, OH UNATTENDED-T 69 12 0 UNATTENDED-T 138 69 34.5 UNATTENDED-T 34.5 7.2 0 CHATFIELD/BUCYRUS, OH UNATTENDED-T 135.4 69.5 13.09 CLIFMONT AVE. UNATTENDED-T 69 12 0 CROOKSVILLE/ZANESVILLE, OH UNATTENDED-T 69 4 0 UNATTENDED-T 138 69 12 DENNISON/CANTON, OH UNATTENDED-T 69 34.5 7.5 UNATTENDED-T 69 12 0 UNATTENDED-T 34.5 4 0 DON MARQUIS (OP) (OVEC) UNATTENDED-T 765 345 34.5 Schedule G-6 Page 2 of 6 OHIO POWER COMPANY TRANSFER OF JURISDICTIONAL ASSETS TO OPCO EDC VOLTAGE (IN MVA) CHARACTER OF ---------------------------- TRANSMISSION SUBSTATIONS SUBSTATION PRIMARY SECONDARY TERTIARY -------------------------------------------------------------------------------- UNATTENDED-T 345 34.5 0 DUNKIRK/LIMA, OH UNATTENDED-T 69 23 0 UNATTENDED-T 66 13.2 0 UNATTENDED-T 69.3 25 0 UNATTENDED-T 69 12 0 EAST AMSTERDAM/STEUBENVILLE, OH UNATTENDED-T 138 69 12 EAST CAMBRIDGE/ZANESVILLE, OH UNATTENDED-T 69 34.5 0 EAST CANTON UNATTENDED-T 69 12 0 EAST FREMONT UNATTENDED-T 67 13.09 0 UNATTENDED-T 67 4.36 0 EAST LIMA/LIMA, OH UNATTENDED-T 138 69 12 UNATTENDED-T 345 138 12 UNATTENDED-T 13 5.6 0 EAST LIVERPOOL/STEUBENVILLE, OH UNATTENDED-T 138 69 12 EAST OTTAWA /LIMA, OH UNATTENDED-T 70 35 0 EAST WOOSTER/WOOSTER, OH UNATTENDED-T 138 69 12 UNATTENDED-T 138 23 0 UNATTENDED-T 23 12 0 EAST ZANESVILLE/ZANESVILLE, OH UNATTENDED-T 138 69 12 FINDLAY CENTER/FOSTORIA, OH UNATTENDED-T 135.4 69.5 35 UNATTENDED-T 36.37 2.4 0 FOREST UNATTENDED-T 65.85 23.99 4.16 UNATTENDED-T 65.85 23.99 4.65 UNATTENDED-T 67 13.09 0 FOSTORIA CENTRAL UNATTENDED-T 345 138 13.8 UNATTENDED-T 339 137.5 13.8 FREMONT CENTER UNATTENDED-T 135.4 40.17 13.09 UNATTENDED-T 69 12 0 FREMONT/FOSTORIA, OH UNATTENDED-T 135.4 69.5 13.09 UNATTENDED-T 23.5 13.09 0 GREENLAWN/FOSTORIA, OH UNATTENDED-T 138 69 12 GREER/CANTON, OH UNATTENDED-T 34.5 12 0 UNATTENDED-T 69 34.5 0 HAMMONDSVILLE/STEUBENVILLE, OH UNATTENDED-T 69 23 0 UNATTENDED-T 69 12 0 HANGING ROCK/PORTSMOUTH, OH UNATTENDED-T 138 69 34.5 HANGING ROCK 765KV UNATTENDED-T 765 765 0 HARPSTER/BUCYRUS, OH UNATTENDED-T 70 35 0 HAVILAND/LIMA, OH UNATTENDED-T 135.4 69.5 13.09 UNATTENDED-T 132 69 34.65 UNATTENDED-T 135.6 13.09 0 HEATH/LANCASTER, OH UNATTENDED-T 138 69 12 UNATTENDED-T 138 34.5 0 UNATTENDED-T 69 4 0 HOWARD/BUCYRUS, OH UNATTENDED-T 69 12 0 UNATTENDED-T 138 69 11 KALIDIA UNATTENDED-T 68.8 13.09 0 Schedule G-6 Page 3 of 6 OHIO POWER COMPANY TRANSFER OF JURISDICTIONAL ASSETS TO OPCO EDC VOLTAGE (IN MVA) CHARACTER OF ---------------------------- TRANSMISSION SUBSTATIONS SUBSTATION PRIMARY SECONDARY TERTIARY -------------------------------------------------------------------------------- UNATTENDED-T 70 35 0 MALVERN/CANTON, OH UNATTENDED-T 138 69 12 UNATTENDED-T 138 23 12 UNATTENDED-T 23 12 0 MARYSVILLE 765KV UNATTENDED-T 765 345 34.5 UNATTENDED-T 765 765 0 UNATTENDED-T 765 345 12 MILLBROOK PARK/PORTSMOUTH, OH UNATTENDED-T 138 69 34.5 UNATTENDED-T 138 34.5 11 UNATTENDED-T 138 34.5 0 UNATTENDED-T 138 12 0 UNATTENDED-T 34.5 12 0 UNATTENDED-T 34.5 34.5 0 NEW LIBERTY UNATTENDED-T 132 34.5 0 UNATTENDED-T 34.4 7.2 0 UNATTENDED-T 138 7.55 0 NEWARK/ZANESVILLE, OH UNATTENDED-T 69 4 0 NEWARK CENTER/ZANESVILLE, OH UNATTENDED-T 138 69 12 NEWCOMERSTOWN/COSHOCTON, OH UNATTENDED-T 69 34.5 12 UNATTENDED-T 138 69 12 UNATTENDED-T 23 12 0 UNATTENDED-T 69 34.5 0 UNATTENDED-T 138 34.5 0 UNATTENDED-T 23 4 0 NORTH COSHOCTON/COSHOCTON, OH UNATTENDED-T 69 12 0 UNATTENDED-T 69 34.5 12 NORTH CROWN CITY-GAVIN/CHESHIRE, OH UNATTENDED-T 138 69 13.2 UNATTENDED-T 35 12 0 NORTH DELPHOS/LIMA, OH UNATTENDED-T 138 69 35 NORTH FINDLAY/FOSTORIA, OH UNATTENDED-T 135.4 35 0 UNATTENDED-T 135.4 69.5 0 UNATTENDED-T 35.86 4.33 0 NORTH MUSKINGUM/MCCONNELSVILLE, OH UNATTENDED-T 138 69 12 NORTH NEWARK/ZANESVILLE, OH UNATTENDED-T 138 69 4 UNATTENDED-T 69 4 0 UNATTENDED-T 69 12 0 NORTH PORTSMOUTH/PORTSMOUTH, OH UNATTENDED-T 138 69 34.5 NORTH PROCTORVILLE/PORTSMOUTH, OH UNATTENDED-T 765 138 13.8 NORTH WALDO/WALDO, OH UNATTENDED-T 67 13.9 0 UNATTENDED-T 132 69 7.2 NORTH WOODCOCK/LIMA, OH UNATTENDED-T 135.4 69.5 35.5 UNATTENDED-T 35.3 4.16 0 NORTHEAST CANTON/CANTON, OH UNATTENDED-T 23 12 0 UNATTENDED-T 138 69 12 NORTHEAST FINDLAY/FOSTORIA, OH UNATTENDED-T 135.6 36.2 0 OHIO CENTRAL/ZANESVILLE, OH UNATTENDED-T 345 138 12 OHIO CENTRAL/ZANESVILLE, OH UNATTENDED-T 138 69 12 Schedule G-6 Page 4 of 6 OHIO POWER COMPANY TRANSFER OF JURISDICTIONAL ASSETS TO OPCO EDC VOLTAGE (IN MVA) CHARACTER OF ---------------------------- TRANSMISSION SUBSTATIONS SUBSTATION PRIMARY SECONDARY TERTIARY -------------------------------------------------------------------------------- OHIO CENTRAL UNATTENDED-T 138 69 4 UNATTENDED-T 34.5 12 0 UNATTENDED-T 69 34.5 0 UNATTENDED-T 23 12 0 UNATTENDED-T 138 12 0 UNATTENDED-T 23 4 0 PEKIN/CANTON, OH UNATTENDED-T 69 12 0 UNATTENDED-T 69 23 0 PLEASANT ST/PORTSMOUTH, OH UNATTENDED-T 69 12 0 UNATTENDED-T 69 34.5 0 REEDURBAN/CANTON, OH UNATTENDED-T 138 12 0 UNATTENDED-T 138 69 12 UNATTENDED-T 69 4 0 ROCKHILL UNATTENDED-T 132 34.65 11 UNATTENDED-T 132 19.05 6.35 UNATTENDED-T 34.4 13.09 0 UNATTENDED-T 139.2 35 13.2 UNATTENDED-T 34.4 4.36 0 UNATTENDED-T 135.4 69.5 35 RUTLAND-GAVIN/CHESHIRE, OH UNATTENDED-T 138 34.5 0 SCHROYER AVE/CANTON, OH UNATTENDED-T 69 4 0 UNATTENDED-T 69 23 12 UNATTENDED-T 69 12 0 SHARP RD/MT VERNON, OH UNATTENDED-T 138 69 12 SHAWNEE RD/LIMA, OH UNATTENDED-T 138 69 34.5 UNATTENDED-T 132 13.09 0 UNATTENDED-T 34.4 2.52 0 SOMERTON/BELMONT, OH UNATTENDED-T 138 69 12 SOUTH BALTIMORE/LANCASTER, OH UNATTENDED-T 138 69 4 SOUTH CADIZ/STEUBENVILLE, OH UNATTENDED-T 69 12 0 UNATTENDED-T 138 69 12 SOUTH CAMBRIDGE UNATTENDED-T 69 34.5 0 UNATTENDED-T 69 34.5 12 SOUTH CANTON/CANTON, OH UNATTENDED-T 345 138 34.5 UNATTENDED-T 138 12 0 UNATTENDED-T 765 345 34.5 UNATTENDED-T 34.5 12 0 SOUTH COSHOCTON/COSHOCTON, OH UNATTENDED-T 138 69 12 UNATTENDED-T 69 34.5 12 UNATTENDED-T 138 34.5 0 UNATTENDED-T 34.5 12 0 SOUTH CUMBERLAND/MCCONNELSVILLE, OH UNATTENDED-T 138 69 34.5 UNATTENDED-T 138 25 0 UNATTENDED-T 34.5 4 0 SOUTH HICKSVILLE/LIMA, OH UNATTENDED-T 135.4 69.5 13.09 SOUTH KENTON UNATTENDED-T 135 70 24.6 UNATTENDED-T 22 2.4 0 Schedule G-6 Page 5 of 6 OHIO POWER COMPANY TRANSFER OF JURISDICTIONAL ASSETS TO OPCO EDC VOLTAGE (IN MVA) CHARACTER OF ---------------------------- TRANSMISSION SUBSTATIONS SUBSTATION PRIMARY SECONDARY TERTIARY -------------------------------------------------------------------------------- UNATTENDED-T 132 45 0 SOUTH LANCASTER/LANCASTER, OH UNATTENDED-T 138 69 12 UNATTENDED-T 138 69 34.5 SOUTH MILLERSBURG/WOOSTER, OH UNATTENDED-T 138 34.5 7.2 SOUTH POINT/PORTSMOUTH, OH UNATTENDED-T 138 69 34.5 UNATTENDED-T 138 34.5 0 UNATTENDED-T 34.5 12 0 SOUTH TIFFIN UNATTENDED-T 132 69.3 6.9 SOUTH TORONTO STEUBENVILLE, OH UNATTENDED-T 138 69 12 SOUTHEAST CANTON/CANTON, OH UNATTENDED-T 345 138 34.5 STANLEY COURT/CANTON, OH UNATTENDED-T 69 12 0 UNATTENDED-T 69 23 4 STERLING/LIMA, OH UNATTENDED-T 138 34.5 0 UNATTENDED-T 138 34.5 11 STEUBENVILLE/STEUBENVILLE, OH UNATTENDED-T 138 69 12 UNATTENDED-T 23 12 0 SUMMERFIELD/BELMONT, OH UNATTENDED-T 138 69 6.9 SUNNYSIDE/CANTON, OH UNATTENDED-T 138 12 0 UNATTENDED-T 138 23 0 UNATTENDED-T 138 23 6.9 SWITZER/BELMONT, OH UNATTENDED-T 138 69 12 TIFFIN CENTER/FOSTORIA, OH UNATTENDED-T 135.4 69.5 13.09 TILTONSVILLE/BELMONT, OH UNATTENDED-T 138 69 12 UNATTENDED-T 69 12 0 TIMKEN/CANTON, OH UNATTENDED-T 138 23 0 UNATTENDED-T 138 23 12 TIMKEN MERCY UNATTENDED-T 69 4 0 TORREY UNATTENDED-T 138 23 12 UNATTENDED-T 138 23 11 UNATTENDED-T 138 69 12 UNATTENDED-T 69 12 0 UNATTENDED-T 23 12 0 WAGENHALS UNATTENDED-T 138 69 23 WAKEFIELD UNATTENDED-T 34.5 4 0 UNATTENDED-T 138 34.5 12 WAYVIEW/CANTON, OH UNATTENDED-T 138 12 0 UNATTENDED-T 138 69 12 WEST BELLAIRE/BELMONT, OH UNATTENDED-T 138 69 12 UNATTENDED-T 345 138 12 WEST CAMBRIDGE/ZANESVILLE, OH UNATTENDED-T 138 69 12 UNATTENDED-T 138 34.5 0 WEST CANTON/CANTON,OH UNATTENDED-T 138 34.5 0 UNATTENDED-T 138 12 0 UNATTENDED-T 138 69 12 UNATTENDED-T 69 34.5 0 WEST COSHOCTON/COSHOCTON,OH UNATTENDED-T 138 69 12 WEST DOVER/DOVER,OH UNATTENDED-T 138 69 12 Schedule G-6 Page 6 of 6 OHIO POWER COMPANY TRANSFER OF JURISDICTIONAL ASSETS TO OPCO EDC VOLTAGE (IN MVA) CHARACTER OF ---------------------------- TRANSMISSION SUBSTATIONS SUBSTATION PRIMARY SECONDARY TERTIARY -------------------------------------------------------------------------------- WEST END FOSTORIA/FOSTORIA,OH UNATTENDED-T 71.73 4.33 0 UNATTENDED-T 67 4.36 0 UNATTENDED-T 135.4 69.5 13.09 WEST HEBRON/LANCASTER,OH UNATTENDED-T 138 69 34.5 UNATTENDED-T 34.5 34.5 0 WEST LANCASTER/LANCASTER,OH UNATTENDED-T 138 69 12 UNATTENDED-T 138 69 7.10 WEST LIMA/LIMA,OH UNATTENDED-T 135.4 35 0 WEST MELROSE/FOSTORIA,OH UNATTENDED-T 34.4 13.09 0 WEST MILLERSPORT/LANCASTER,OH UNATTENDED-T 345 138 12 WEST MOUTON/LIMA,OH UNATTENDED-T 135.4 69.5 13.09 UNATTENDED-T 23.9 4.33 0 WEST MT VERNON/MT VERNON,OH UNATTENDED-T 138 69 4 WEST NEW PHILADELPHIA/CANTON,OH UNATTENDED-T 138 69 7.19 UNATTENDED-T 138 69 12 UNATTENDED-T 138 12 0 UNATTENDED-T 138 34.5 4 WEST VAN WERT/LlMA,OH UNATTENDED-T 70 35 0 WOOSTER/WOOSTER,OH UNATTENDED-T 23 4 0 UNATTENDED-T 138 69 12 UNATTENDED-T 23 12 0 UNATTENDED-T 138 23 0 ZANESVILLE/ZANESVILLE,OH UNATTENDED-T 138 23 0 UNATTENDED-T 138 69 12 UNATTENDED-T 23 12 0 UNATTENDED-T 69 34.5 0 Schedule G-7 Page 1 of 2 CENTRAL POWER AND LIGHT COMPANY TRANSFER OF JURISDICTIONAL ASSETS TO CPL PGC GENERATION RELATED EQUIPMENT
T REGION POWER PLANT UNIT # EQUIPMENT TO BE TRANSFERRED DEVICE # ------------------------------------------------------------------------------------------------------- Corpus Christi Coleto Creek 1 Generator Step-up Transformer (GSU) GSU leads to breaker Circuit Breaker 9880 1 Res. Aux. Leads Circuit Breaker 9870 Corpus Christi Barney Davis 1 GSU GSU leads to breaker Circuit Breaker 9510 2 GSU GSU leads to breaker Circuit Breaker 9700 1 & 2 Res. Aux. Leads Circuit Breaker 9520 Corpus Christi J.L. Bates 1 GSU GSU leads to breaker Circuit Breaker 4440 2 GSU GSU leads to breaker Circuit Breaker 4700 1 & 2 Res. Aux. Leads Circuit Breaker 4450 Corpus Christi La Palma 2 GSU (auto) GSU leads to breaker Circuit Breaker 40 4 GSU GSU leads to breaker Circuit Breaker 80 5 GSU GSU leads to breaker Circuit Breaker 110 6 GSU GSU leads to breaker Circuit Breaker 4940 7 GSU GSU leads to breaker Circuit Breaker 5805 All Res. Aux. Leads Circuit Breaker 4840 Corpus Christi Laredo 1 GSU GSU leads to breaker Circuit Breaker 2410 2 GSU GSU leads to breaker Circuit Breaker 985 3 GSU GSU leads to breaker Circuit Breaker 9415 3 Res. Aux. leads Circuit Breaker 9435 1 & 2 Res. Aux. Leads Circuit Breaker 2430 Corpus Christi Lon Hill 1 GSU
Schedule G-7 Page 2 of 2 CENTRAL POWER AND LIGHT COMPANY TRANSFER OF JURISDICTIONAL ASSETS TO CPL PGC GENERATION RELATED EQUIPMENT
T REGION POWER PLANT UNIT # EQUIPMENT TO BE TRANSFERRED DEVICE # ------------------------------------------------------------------------------------------------------- GSU leads to breaker Circuit Breaker 5810 2 GSU GSU leads to breaker Circuit Breaker 5790 1 & 2 Res. Aux. Leads Circuit Breaker 5680 3 GSU GSU leads to breaker Circuit Breaker 5690 4 GSU GSU leads to breaker Circuit Breaker 7055 3 & 4 Res. Aux. Leads Circuit Breaker 8130 Corpus Christi Nueces Bay 5 GSU GSU leads to breaker Circuit Breaker 2130 6 GSU GSU leads to breaker Circuit Breaker 9210 7 GSU GSU leads to breaker Circuit Breaker 9355 6 & 7 Res. Aux. Leads Circuit Breaker 9190 Corpus Christi Victoria 3 GSU GSU leads to breaker Circuit Breaker 5150 4 GSU GSU leads to breaker Circuit Breaker 6880 5 GSU GSU leads to breaker Circuit Breaker 6120 6 GSU GSU leads to breaker Circuit Breaker 6555 5 & 6 Res. Aux. Leads Circuit Breaker 7000 Corpus Christi Eagle Pass Hydro 1 GSU leads to breaker Circuit Breaker 160A 2 GSU leads to breaker Circuit Breaker 170A 3 GSU leads to breaker Circuit Breaker 180A Corpus Christi E.S. Joslin 1 GSU GSU leads to breaker Circuit Breaker 8365 1 Res. Aux. Leads Circuit Breaker 8355
Schedule G-8 Page 1 of 2 WEST TEXAS UTILITIES COMPANY TRANSFER OF JURISDICTIONAL ASSETS TO WTU PGC GENERATION RELATED EQUIPMENT
T REGION POWER PLANT UNIT # EQUIPMENT TO BE TRANSFERRED DEVICE # ------------------------------------------------------------------------------------------------------- Corpus Christi Abilene Plant 3 Unit leads to breaker Circuit Breaker 1540 4 Unit leads to breaker Circuit Breaker 1560 3 Res. Aux. Leads Circuit Breaker 430 4 Res. Aux. Leads Circuit Breaker 431 Corpus Christi Ft. Phantom 1 GSU GSU leads to breaker Circuit Breaker 4750 2 GSU GSU leads to breaker Circuit Breaker 4980 1 Res. Aux. Leads Disconnect Switch 4753 Corpus Christi Lk. Pauline 1 GSU GSU leads to breaker Circuit Breaker 2545 2 GSU GSU leads to breaker Circuit Breaker 1435 1 & 2 Disconnect Switch 2547 Circuit Breaker 2580 Circuit Breaker 3705 Corpus Christi Oak Creek 1 GSU GSU leads to breaker Circuit Breaker 3200 1 Res. Aux. Leads Disconnect Switch 3222 Corpus Christi Oklaunion 1 GSU GSU leads to breaker Disconnect Switch 5608 Circuit Breaker 5600 1 Res. Aux. leads Corpus Christi Paint Creek 1 GSU GSU leads to breaker Circuit Breaker 1660 2 Circuit Breaker 1785 3 GSU GSU leads to breaker Circuit Breaker 1880 4 GSU GSU leads to breaker Circuit Breaker 4475 All Res. Aux. Leads Circuit Breaker 1650 Corpus Christi Rio Pecos 4 GSU GSU leads to breaker Circuit Breaker 640 5 GSU GSU leads to breaker
Schedule G-8 Page 2 of 2 WEST TEXAS UTILITIES COMPANY TRANSFER OF JURISDICTIONAL ASSETS TO WTU PGC GENERATION RELATED EQUIPMENT
T REGION POWER PLANT UNIT # EQUIPMENT TO BE TRANSFERRED DEVICE # ------------------------------------------------------------------------------------------------------- Circuit Breaker 3000 6 GSU GSU leads to breaker Circuit Breaker 4000 All Res. Aux. Leads Fuses and Disconnect Switch 3003 Corpus Christi San Angelo PS 1 GSU GSU leads to breaker Circuit Breaker 3600 2 GSU GSU leads to breaker Disconnect Switch 3601 Circuit Breaker 6105 All Res. Aux. Leads Disconnect Switch 3607
Schedule G-9 Page 1 of 1 SOUTHWESTERN ELECTRIC POWER COMPANY TRANSFER OF JURISDICTIONAL ASSETS TO SWEPCO EDC VOLTAGE (IN MVA) CHARACTER OF ---------------------------- TRANSMISSION SUBSTATIONS SUBSTATION PRIMARY SECONDARY TERTIARY -------------------------------------------------------------------------------- BANN TRANSMISSION 138 69 0 CROCKETT TRANSMISSION 345 138 13.8 DIANA TRANSMISSION 345 138 13.8 LAKE LAMOND TRANSMISSION 138 69 12.5 LONE STAR SOUTH TRANSMISSION 138 69 0 MARSHALL TRANSMISSION 138 69 13.2 N.W. HENDERSON TRANSMISSION 138 69 0 N.W. TEXARKANA TRANSMISSION 345 138 0 NORTH MINEOLA TRANSMISSION 138 69 7.2 NORTH NEW BOSTON TRANSMISSION 138 69 0 OVERTON TRANSMISSION 138 69 13.2 PERDUE TRANSMISSION 138 69 0 PETTY TRANSMISSION 138 69 0 PIRKEY PLANT TRANSMISSION 345 138 13.8 PITTSBURG TRANSMISSION 138 69 0 ROCK HILL TRANSMISSION 138 69 13.2 TENASKA-RUSK COUNTY -SWITCHES/ TRANSMISSION 345 0 0 BREAKERS -SERVES INTERCONNECTION FOR INDEPENDENT POWER PRODUCER WELSH PLANT SWITCHING STATION TRANSMISSION 34.5 34.5 0 WELSH HVDC TRANSMISSION 345 0 0 WEST ATLANTA TRANSMISSION 138 69 0 WHITNEY * (ATTENDED) 138 69 12.5 WILKES PLANT TRANSMISSION 345 138 13.8 TENAHA TRANSMISSION 138 0 0 SCHEDULE G-10 PAGE 1 OF 2 SOUTHWESTERN ELECTRIC POWER COMPANY TRANSFER OF JURISDICTIONAL ASSETS TO SWEPCO TEXAS EDC TRANSMISSION LINES kV LINE # MILES STATE -------------------------------------------------------------------------------- Atlanta-Hughes Sprngs 69 201 29.1 TX Beckville-Carthage 69 202 8.9 TX Carthage-Murvall Tap 69 202 3.8 TX Bloomburg-Atlanta 69 203 8.0 TX Karnack Switching Station-Woodlawn 69 205 9.6 TX Jefferson Sub-Tex/La state line toward Superior 69 205 21.3 TX Perdue-Gilmer 69 206 11.4 TX Perdue-Clarksville North circuit 69 206 7.0 TX Kilgore-Clarksville 69 207 14.1 TX Longview-Clarksville 69 208 18.3 TX Hughes Spngs-Dngerfld-Mt Plsnt 69 209 23.3 TX Whitney-Overton 69 210 28.6 TX Perdue-Mineola 69 211 29.8 TX Perdue-Clarksville South circuit 69 211 7.3 TX Mineola-Quitman-Mt. Pleasant 69 212 85.0 TX New Boston-Mt. Pleasant 69 213 46.9 TX Hooks-Bann 69 213 7.1 TX Taylor St-39th-Bann 69 213 14.7 TX Grand Saline-Quitman 69 214 24.4 TX Mineola-Grand Saline 69 214 14.0 TX Overton-Turnertown (from tap off conc str to south) 69 215 8.3 TX Rockbill to N.W. Henderson 69 215 30.8 TX Marshall-Blocker Tap 69 215 5.3 TX Blocker Tap-Rockhill 69 215 12.4 TX Hughes Springs-Lone Star-Jenkins 69 216 18.5 TX Evenside to Sawmill,etc. 69 217 12.7 TX Pittsburg-Gilmer 69 218 24.5 TX Mt Plsnt-Petty 69 218 2.1 TX Lake Lamond-SE L'view-Whitney 69 219 13.6 TX Rockhill to Carthage 69 221 16.0 TX Lake Lamond-Airline-L'view Hts 69 222 13.7 TX Bann-Taylor St 69 223 7.0 TX Winnfield-Mt.Vernon 69 224 7.4 TX Waskom-Karnack Swtchng 69 225 17.4 TX S.E. Longview-Knox Lee 69 226 5.9 TX Eylau-Bann 69 227 4.3 TX Pittsburg-Winnsboro 69 229 20.0 TX Evenside to Poynter 69 231 3.9 TX Evenside to N. W. Henderson 69 233 6.4 TX Burford Survey-Naples 69 234 6.1 TX N.Mineola-Rayburn Country 138 198 16.6 TX Center-Carthage T 138 200 29.1 TX Center-Texas state line-to Logansport 138 204 16.8 TX NW Henderson-Overton 138 215 13.2 TX Pittsburg-Petty 138 218 9.7 TX Lone Star So-Pittsburg 138 220 17.7 TX Bann-N. New Boston 138 228 17.9 TX Rockhill-Tx/La state line toward Logansport 138 230 35.7 TX NW Texarkana-Ark/Tx state line toward Sugarhill 138 235 11.1 TX Perdue-North Mineola 138 236 30.4 TX Perdue-Knox Lee 138 237 37.9 TX Diana-Perdue 138 238 21.9 TX Knox Lee-NW Henderson 138 239 17.9 TX SCHEDULE G-10 PAGE 2 OF 2 SOUTHWESTERN ELECTRIC POWER COMPANY TRANSFER OF JURISDICTIONAL ASSETS TO SWEPCO TEXAS EDC TRANSMISSION LINES kV LINE # MILES STATE -------------------------------------------------------------------------------- Wilkes-Jefferson Sw Sta 138 240 11.1 TX Ark/Tex state line-NW Tex-Bann-W.Atl-Wilkes 138 241 65.3 TX Jefferson Sw Sta-Marshall-Pirkey-Knox Lee 138 241 38.9 TX Knox Lee-Overton 138 241 23.9 TX Jefferson Sw Sta-Tex/La state line toward Lieberman 138 242 28.1 TX Knox Lee-Whitney 138kv 138 243 13.4 TX Whitney-Pirkey-Marshall 138 243 24.4 TX Pirkey-S.E. Marshall 138 244 10.5 TX SE Marshall-Scottsville-Tex/La state line toward Longwood 138 244 18.8 TX Rockhill-Knox Lee 138 245 16.3 TX Rockhill to Tex-La state line toward Spngridge 138 245 27.4 TX Wilkes-Bryan's Mill 138 246 27.0 TX Bryan's Mill-N.New Boston 138 246 19.8 TX N.New Boston-Ark/Tx state line toward Patterson 138 246 5.9 TX Wilkes-rear of Jeff Sw Sta toward W. Atlanta 138 247 32.0 TX Lone Star So-Wilkes 138 248 11.0 TX Whitney-Pliler-Diana-Lone Star So 138 249 36.2 TX Wilkes-Petty 138 250 34.1 TX Eastex-Harrison Rd 138 277 9.6 TX Diana-Springhill-Lake Lamond 138 278 23.0 TX Welsh-Monticello 345 199 15.9 TX Lydia-NW Texarkana 345 270 32.2 TX Wilkes-Tex/La State line toward Longwood 345 271 38.4 TX Diana-Tex/La state line toward SW Shreveport 345 272 57.3 TX Pirkey-Diana 345 273 24.8 TX Pirkey-Walker Co 345 274 129.2 TX TOTAL LINE MILES IN TEXAS 1698.9 Schedule G-11 Page 1 of 1 AMERICAN ELECTRIC POWER SERVICE CORPORATION POWER SALES/SERVICE AGREEMENTS TO BE ASSIGNED TO PMA AGREEMENT NAME FERC RATE SCHEDULE DESIGNATION Service Agreement With The City Of AEP Electric Tariff Vol. No. 5, Radford, Virginia, Dated January 12, 1998 Service Agreement No. 103 Power Sales Service Agreement With AEP Electric Tariff Vol. No. 5, The Village Of Arcadia, Dated August 3, 1998 Service Agreement No. 153 Power Sales Service Agreement With The Village AEP Electric Tariff Vol. No. 5, Of Bloomdale, Dated March 24, 1998 Service Agreement No. 154 Power Sales Service Agreement With The City Of AEP Electric Tariff Vol. No. 5, Bryan, Dated August 3, 1998 Service Agreement No. 155 Power Sales Service Agreement With The Village AEP Electric Tariff Vol. No. 5, Of Carey, Dated March 2, 1998 Service Agreement No. 156 Power Sales Service Agreement With The City Of AEP Electric Tariff Vol. No. 5, Clyde, Dated March 4, 1998 Service Agreement No. 157 Power Sales Service Agreement With The Village AEP Electric Tariff Vol. No. 5, Of Cygnet, Dated August 3, 1998 Service Agreement No. 158 Power Sales Service Agreement With The Village AEP Electric Tariff Vol. No. 5, Of Deshler, Dated March 9, 1998 Service Agreement No. 159 Power Sales Service Agreement With The Village AEP Electric Tariff Vol. No. 5, Of Greenwich, Dated April 21, 1998 Service Agreement No. 160 Power Sales Service Agreement With The Village AEP Electric Tariff Vol. No. 5, Of Ohio City, Dated August 3, 1998 Service Agreement No. 161 Power Sales Service Agreement With The Village AEP Electric Tariff Vol. No. 5, Of Plymouth, Dated August 3, 1998 Service Agreement No. 162 Power Sales Service Agreement With The Village AEP Electric Tariff Vol. No. 5, Of Republic, Dated March 15, 1998 Service Agreement No. 163 Power Sales Service Agreement With The City Of AEP Electric Tariff Vol. No. 5, Saint Clairsville, dated August 3, 1998 Service Agreement No. 164 Power Sales Service Agreement With The Village AEP Electric Tariff Vol. No. 5, Of Shiloh, Dated August 3, 1998 Service Agreement No. 165 Power Sales Service Agreement With The Village AEP Electric Tariff Vol. No. 5, Of Sycamore, Dated August 3, 1998 Service Agreement No. 166 Power Sales Service Agreement With The City Of AEP Electric Tariff Vol. No. 5, Wapakoneta, Dated June 24, 1998 Service Agreement No. 167 Power Sales Service Agreement With The Village AEP Electric Tariff Vol. No. 5, Of Wharton, Dated March 16, 1998 Service Agreement No. 168 Service Agreement With City Of Sturgis, AEP Electric Tariff Vol. No. 5, Dated July 14, 1999 Service Agreement No. 233 Schedule G-12 Page 1 of 1 APPALACHIAN POWER COMPANY POWER SALES/SERVICE AGREEMENTS TO BE ASSIGNED TO OPCO PGC AGREEMENT NAME FERC RATE SCHEDULE DESIGNATION -------------------------------------------------------------------------------- Power Supply Agreement Between Appalachian APCO Rate Schedule No. 135 Power Company And North Carolina Electric Membership Corporation, Dated August 22, 1994 Schedule G-13 Page 1 of 1 CENTRAL POWER AND LIGHT COMPANY POWER SALES/SERVICE AGREEMENTS TO BE ASSIGNED TO CPL PGC AGREEMENT NAME FERC RATE SCHEDULE DESIGNATION -------------------------------------------------------------------------------- Electric Service Contract By And Between Central Power And Light Company And City of Robstown, Texas, Dated May 14, 1984 CPL Rate Schedule No. 70 -------------------------------------------------------------------------------- Service Agreement Between Central Power And Light Company And Pedernales CPL Tariff No. 1, Electric Cooperative, Inc. Service Agreement No. 8 -------------------------------------------------------------------------------- Service Agreement Between Central Power And Light Company and South Texas CPL Tariff No. 1, Electric Cooperative, Inc. Service Agreement No. 10 -------------------------------------------------------------------------------- Schedule G-14 Page 1 of 1 OHIO POWER COMPANY POWER SALES/SERVICE AGREEMENTS TO BE ASSIGNED TO APCO AGREEMENT NAME FERC RATE SCHEDULE DESIGNATION -------------------------------------------------------------------------------- Interconnection Agreement Between The Ohio OPCO Rate Schedule No. 18 Power Company And Wheeling Electric Company, Dated February 24, 1949 -------------------------------------------------------------------------------- Schedule G-15 Page 1 of 1 WEST TEXAS UTILITIES COMPANY POWER SALES/SERVICE AGREEMENTS TO BE ASSIGNED TO WTU PGC FERC RATE SCHEDULE AGREEMENT NAME DESIGNATION -------------------------------------------------------------------------------- First Revised Agreement For Sale And Purchase Of Power And Associated Energy And Responsive Reserves Between West Texas Utilities Company CSW FERC Electric Tariff, And Brazos Electric Cooperative, Inc. Under First Revised Volume No. 8, Market-Based Rate Power Sales Tariff Of West First Revised Service Texas Utilities Company, Dated August 29, 2000 Agreement No. 26 -------------------------------------------------------------------------------- Power Supply Agreement Between West Texas Utilities Company And The City Of Hearne, Texas, Dated August 25, 1997 WTU Rate Schedule No. 76 -------------------------------------------------------------------------------- Service Agreement Between West Texas Utilities WTU Tariff No. 9, Company And Coleman County Electric First Revised Service Cooperative, Inc., Dated September 30, 1997 Agreement No. 1 -------------------------------------------------------------------------------- Service Agreement Between West Texas Utilities WTU Tariff No. 9, Company And Concho Valley Electric First Revised Service Cooperative, Inc., Dated September 18, 1997 Agreement No. 2 -------------------------------------------------------------------------------- Service Agreement Between West Texas Utilities WTU Tariff No. 9, Company And Golden Spread Valley Electric First Revised Service Cooperative, Inc., Dated September 30, 1997 Agreement No. 3 -------------------------------------------------------------------------------- Service Agreement Between West Texas Utilities WTU Tariff No. 9, Company And Lighthouse Electric First Revised Service Cooperative, Inc., Dated September 25, 1997 Agreement No. 5 -------------------------------------------------------------------------------- Service Agreement Between West Texas Utilities WTU Tariff No. 9, Company and Midwest Electric Cooperative, Inc., First Revised Service Dated September 16, 1997 Agreement No. 6 -------------------------------------------------------------------------------- Service Agreement Between West Texas Utilities WTU Tariff No. 9, Company And Pedernales Electric Cooperative, Inc. First Revised Service (formerly Kimble), Dated September 24, 1997 Agreement No. 4 -------------------------------------------------------------------------------- Service Agreement Between West Texas Utilities Company And Rio Grande Electric Cooperative, Inc., WTU Tariff No. 9, Dated September 30, 1997 Service Agreement No. 7 -------------------------------------------------------------------------------- Service Agreement Between West Texas Utilities Company And Southwest Texas Electric WTU Tariff No. 9, Cooperative, Inc., Dated September 30, 1997 Service Agreement No. 8 -------------------------------------------------------------------------------- Service Agreement Between West Texas Utilities Company And Stamford Electric Cooperative, Inc., WTU Tariff No. 9, Dated September 30, 1997 Service Agreement No. 9 -------------------------------------------------------------------------------- Service Agreement Between West Texas Utilities WTU Tariff No. 9, Company And Taylor Electric Cooperative, Inc., First Revised Service Dated September 30, 1997 Agreement No. 10 -------------------------------------------------------------------------------- Service Agreement Between West Texas Utilities WTU Tariff No. 1, Company And City of Brady, Dated July 22, 1993 Service Agreement No. 17 -------------------------------------------------------------------------------- Agreement For Electric Service With The City of Coleman, Texas, dated March 28, 1977 WTU Rate Schedule No. 40 -------------------------------------------------------------------------------- Power Supply Agreement Between West Texas Utilities CSW FERC Electric Tariff, Company And The City of Weatherford, Texas, First Revised Volume No. 8, Dated June 21, 1996 First Revised Service Agreement No. 25 -------------------------------------------------------------------------------- Service Agreement Between West Texas Utilities Company and Rio Grande Electric Cooperative, Inc., WTU Tariff No. 1, Dated April 8, 1994 Service Agreement No. 19 -------------------------------------------------------------------------------- Restated And Amended Service Agreement Between West Texas Utilities Company and Tex-La Electric WTU Tariff No. 1, Cooperative of Texas, Inc., Dated June 15, 2000 Service Agreement No. 18 -------------------------------------------------------------------------------- Agreement Between West Texas Utilities Company And Texas-New Mexico Power Company WTU Rate Schedule No. 39 -------------------------------------------------------------------------------- Service Agreement Between West Texas Utilities Company And Western Farmers Electric WTU Tariff No. 1, Cooperative, Inc. Service Agreement No. 13 -------------------------------------------------------------------------------- Schedule G-16 Page 1 of 1 COLUMBUS SOUTHERN POWER COMPANY INTERCONNECTION AND TRANSMISSION AGREEMENTS TO BE ASSIGNED TO CSP EDC FERC RATE SCHEDULE AGREEMENT NAME DESIGNATION -------------------------------------------------------------------------------- Interconnection Agreement Between City of Columbus, Ohio and Columbus Southern Power Company, Dated January 1, 1988 FERC Rate Schedule No. 37 -------------------------------------------------------------------------------- Interconnection Agreement Between The Cincinnati Gas & Electric Company and Columbus Southern Power Company, Dated April 1, 1977 FERC Rate Schedule No. 26 -------------------------------------------------------------------------------- Interconnection Agreement Between The Dayton Power & Light Company and Columbus Southern Power Company, Dated March 1, 1977 FERC Rate Schedule No. 29 -------------------------------------------------------------------------------- Interconnection Agreement Between Ohio Edison Company and Columbus Southern Power Company, Dated May 15, 1977 FERC Rate Schedule No. 27 -------------------------------------------------------------------------------- Power Delivery Agreement Between Buckeye Power, Inc., The Cincinnati Gas & Electric Company, Columbus and Southern Ohio Electric Company, The Dayton Power and Light Company, Monongahela Power Company, Ohio Power Company and The Toleda Edison Company, Dated January 1, 1968 FERC Rate Schedule No. 17(1) -------------------------------------------------------------------------------- Basic Transmission Agreement Between the Cincinnati Gas & Electric Company, the Dayton Power and Light Company and Columbus and Southern Ohio Electric Company Re Beckjord-Greene Line, Dated October 1, 1964, as supplemented and amended -------------------------------------------------------------------------------- Basic Transmission Agreement No. 2 (Stuart Transmission) Between the Cincinnati Gas & Electric Company, Columbus and Southern Ohio Electric Company and the Dayton Power and Light Company, Dated December 29, 1966, as supplemented and amended -------------------------------------------------------------------------------- Basic Transmission Agreement No. 3 (Conesville Unit 4 Transmission) Between the Cincinnati Gas & Electric Company, Columbus and Southern Ohio Electric Company and the Dayton Power and Light Company, Dated March 1, 1973, as supplemented and amended -------------------------------------------------------------------------------- Basic Transmission Agreement No. 4 (Zimmer Transmission) Between the Cincinnati Gas & Electric Company, Columbus and Southern Ohio Electric Company and the Dayton Power and Light Company, Dated January 1, 1982, as supplemented and amended -------------------------------------------------------------------------------- (1) Pre-888 Network Transmission Service Schedule G-17 Page 1 of 1 OHIO POWER COMPANY INTERCONNECTION AND TRANSMISSION AGREEMENTS TO BE ASSIGNED TO OPCO EDC FERC RATE SCHEDULE AGREEMENT NAME DESIGNATION -------------------------------------------------------------------------------- Agreement Between Monongahela Power Company, West Penn Power Company and Appalachian Power Company, Ohio Power Company, Wheeling Power Company, Dated June 1, 1971 FERC Rate Schedule No. 73 -------------------------------------------------------------------------------- Agreement Between American Municipal Power-Ohio, Inc and Ohio Power Company, Dated April 1, 1974 FERC Rate Schedule No. 74 -------------------------------------------------------------------------------- Agreement Between The Cleveland Electric Illuminating Company and Ohio Power Company, Dated June 14, 1962 FERC Rate Schedule No. 31 -------------------------------------------------------------------------------- Modification No. 5 to Facilities and Operating Agreement Dated as of May 1, 1967 Between The Dayton Power and Light Company and Ohio Power Company, Dated January 15, 1976 FERC Rate Schedule No. 36 -------------------------------------------------------------------------------- Agreement Between Duquesne Light Company and Ohio Power Company, Dated September 6, 1962 FERC Rate Schedule No. 33 -------------------------------------------------------------------------------- Agreement Between Kentucky Utilities Company and Ohio Power Company, Dated January 17, 1950 FERC Rate Schedule No. 22 -------------------------------------------------------------------------------- Agreement Between Ohio Edison Company and Ohio Power Company, Dated January 1, 1952 FERC Rate Schedule No. 25 -------------------------------------------------------------------------------- Agreement Between Toledo Edison Company and Ohio Power Company, Dated December 1, 1965 FERC Rate Schedule No. 35 -------------------------------------------------------------------------------- Power Delivery Agreement Between Buckeye Power, Inc, The Cincinnati Gas & Electric Company, Columbus and Southern Ohio Electric Company, The Dayton Power and Light Company, Monongahela Power Company, Ohio Power Company and The Toleda Edison Company, Dated January 1, 1968 FERC Rate Schedule No. 70(1) -------------------------------------------------------------------------------- Agreement Between Ohio Edison Company and Ohio Power Company, Dated June 20, 1968 FERC Rate Schedule No. 71(1) -------------------------------------------------------------------------------- Agreement Between Wheeling Power Company and Ohio Wheeling Power Company Power Company, Dated December 7, 1966 FERC Rate Schedule No. 6(2) -------------------------------------------------------------------------------- Transmission Facilities Agreement Between Wheeling FERC Rate Schedule No. 30 Power Company and Ohio Power Company, and Wheeling Power Company Dated March 1, 1963 FERC Rate Schedule No. 4 -------------------------------------------------------------------------------- (1) Pre-888 Network Transmission Service (2) Transmission Facilities Agreements Schedule G-18 Page 1 of 1 SOUTHWESTERN ELECTRIC POWER COMPANY INTERCONNECTION AGREEMENTS TO BE ASSIGNED TO SWEPCO EDC FERC RATE SCHEDULE AGREEMENT NAME DESIGNATION -------------------------------------------------------------------------------- Restated And Amended Interconnection Agreement Between Gulf States Utilities Company And Southwestern Electric Power Company, Dated January 1, 1989 SWEPCO Rate Schedule No. 106 -------------------------------------------------------------------------------- Transmission And Interconnection Agreement Among Southwestern Electric Power Company And Rayburn Rayburn Country Electric Country Electric Cooperative, Inc. And East Texas Cooperative, Inc., Electric Cooperative, Inc., Dated July 13, 1994 Rate Schedule No. 2 -------------------------------------------------------------------------------- Schedule G-19 Page 1 of 1 INDIANA MICHIGAN POWER COMPANY TRANSFER OF INTERESTS IN ROCKPORT STEAM ELECTRIC GENERATING UNITS NOS. 1 AND 2 TO PMA INTERESTS TO BE ASSIGNED -------------------------------------------------------------------------------- As of the date of execution of the related Assignment Agreement, 70% of I&M's rights, interests, duties and obligations to the power (and energy associated therewith) from the Rockport Unit No. 1 to which I&M shall be entitled from AEP Generating Company (AEG) under the Unit Power Agreement between I&M and AEG dated March 31, 1982. -------------------------------------------------------------------------------- As of January 1, 2005, 30% of its rights, interests, duties and obligations in and to the power (and energy associated therewith) from the Rockport Plant to which I&M shall be entitled from AEG under the Unit Power Agreement between I&M and AEG dated March 31, 1982. -------------------------------------------------------------------------------- EXHIBIT H JURISDICTIONAL FACILITIES AND SECURITIES ASSOCIATED WITH OR AFFECTED BY THE TRANSFERS, CONSIDERATION FOR THE TRANSFERS, AND EFFECT OF THE TRANSFERS ON JURISDICTIONAL FACILITIES AND SECURITIES See Exhibit G for a description of the jurisdictional facilities that will be affected by the Transfers. The Transfers do not involve a sale or disposition to an unaffiliated purchaser and therefore do not raise any issue of consideration for the transaction. The Transfers will be made to comply with state laws and the jurisdictional facilities to be transferred will be transferred at book value. The transactions that will be effected to accomplish the Transfers of jurisdictional assets are detailed in the Description of Jurisdictional Transfers submitted as Exhibit I. Proposed accounting entries for the Transfers are attached to this Exhibit H. Applicants request waiver of the requirement to provide information regarding the effect of the Transfers on securities issued or to be issued by the Applicants or their affiliates in connection with the Transfers. Under Section 318 of the Act, the Securities and Exchange Commission has jurisdiction over such matters pursuant to Sections 6, 9 and 10 of the 1935 Act and as reported in Exhibit L, Applicants and their affiliates have filed an Application-Declaration on Form U-1 with the SEC seeking authority and approval for the securities transactions that are incident to the Transfers. EXHIBIT H - SCHEDULES Narrative, Pages 1-7 Narrative Supporting the Determination of Assets and Liability Account Balances to be Corporately Separated Schedule H-1 Central Power and Light Company, Unbundled Balance Sheet -- Estimated and Unaudited Assets, December 31, 2000 Schedule H-2 Central Power and Light Company, Unbundled Balance Sheet - Estimated and Unaudited Capital & Liabilities, December 31, 2000 Schedule H-3 Columbus Southern Power Company, Unbundled Balance Sheet -- Estimated and Unaudited Assets, December 31, 2000 Schedule H-4 Columbus Southern Power Company, Unbundled Balance Sheet -- Estimated and Unaudited Capital & Liabilities, December 31, 2000 Schedule H-5 Ohio Power Company, Unbundled Balance Sheet - Estimated and Unaudited Assets, December 31, 2000 Schedule H-6 Ohio Power Company, Unbundled Balance Sheet - Estimated and Unaudited Capital & Liabilities, December 31, 2000 Schedule H-7 Southwestern Electric Power Company, Unbundled Balance Sheet -- Estimated and Unaudited Assets, December 31, 2000 Schedule H-8 Southwestern Electric Power Company, Unbundled Balance Sheet -- Estimated and Unaudited Capital & Liabilities, December 31, 2000 Schedule H-9 West Texas Utilities Company, Unbundled Balance Sheet -- Estimated and Unaudited Assets, December 31, 2000 Schedule H-10 West Texas Utilities Company, Unbundled Balance Sheet -- Estimated and Unaudited Capital & Liabilities, December 31, 2000
Schedule H-11 Section 5, Part C -- Journal Entries, Transfer of Central Power and Light Company Assets to be Recorded on the Books of Central Power and Light Company Schedule H-12 Section 5, Part C -- Journal Entries, Transfer of Central Power and Light Company Assets to be Recorded on the Books of Central and South West Corporation Schedule H-13 Section 5, Part C -- Journal Entries, Transfer of Central Power and Light Company Assets to be Recorded on the Books of Central Power and Light Genco Schedule H-14 Section 5, Part C -- Journal Entries, Transfer of Central Power and Light Company Assets to be Recorded on the Books of AEP Company, Inc. Schedule H-15 Section 5, Part C -- Journal Entries, Transfer of Central Power and Light Company Assets to be Recorded on the Books of AEP Non-Regulated Holdco Schedule H-16 Section 5, Part C -- Journal Entries, Transfer of Columbus Southern Power Company Assets to be Recorded on the Books of Columbus Southern Power Company Schedule H-17 Section 5, Part C -- Journal Entries, Transfer of Columbus Southern Power Company Assets to be Recorded on the Books of Columbus Southern Wiresco Schedule H-18 Section 5, Part C -- Journal Entries, Transfer of Columbus Southern Power Company Assets to be Recorded on the Books of AEP Company, Inc. Schedule H-19 Section 5, Part C -- Journal Entries, Transfer of Columbus Southern Power Company Assets to be Recorded on the Books of Central and South West Corporation Schedule H-20 Section 5, Part C -- Journal Entries, Transfer of Columbus Southern Power Company Assets to be Recorded on the Books of AEP Non-Regulated Holdco Schedule H-21 Section 5, Part C -- Journal Entries, Transfer of Ohio Power Company Assets to be Recorded on the Books of Ohio Power Company
Schedule H-22 Section 5, Part C -- Journal Entries, Transfer of Ohio Power Company Assets to be Recorded on the Books of Ohio Power Wiresco Schedule H-23 Section 5, Part C -- Journal Entries, Transfer of Ohio Power Company Assets to be Recorded on the Books of AEP Company, Inc. Schedule H-24 Section 5, Part C -- Journal Entries, Transfer of Ohio Power Company Assets to be Recorded on the Books of Central and South West Corporation Schedule H-25 Section 5, Part C -- Journal Entries, Transfer of Ohio Power Company Assets to be Recorded on the Books of AEP Non-Regulated Holdco Schedule H-26 Section 5, Part C -- Journal Entries, Transfer of Southwestern Electric Power Company Assets to be Recorded on the Books of Southwestern Electric Power Company Schedule H-27 Section 5, Part C -- Journal Entries, Transfer of Southwestern Electric Power Company Assets to be Recorded on the Books of Southwestern Electric Power Texas Wiresco Schedule H-28 Section 5, Part C -- Journal Entries, Transfer of Southwestern Electric Power Company Assets to be Recorded on the Books of Central and South West Corporation Schedule H-29 Section 5, Part C -- Journal Entries, Transfer of West Texas Utilities Company Assets to be Recorded on the Books of West Texas Utilities Company Schedule H-30 Section 5, Part C -- Journal Entries, Transfer of West Texas Utilities Company Assets to be Recorded on the Books of Central and South West Corporation Schedule H-31 Section 5, Part C -- Journal Entries, Transfer of West Texas Utilities Company Assets to be Recorded on the Books of West Texas Utilities Genco Schedule H-32 Section 5, Part C -- Journal Entries, Transfer of West Texas Utilities Company Assets to be Recorded on the Books of AEP Company, Inc.
Schedule H-33 Section 5, Part C--Journal Entries, Transfer of West Texas Utilities Company Assets to be Recorded on the Books of AEP Non-Regulated Holdco
NARRATIVE SUPPORTING THE DETERMINATION OF ASSETS AND LIABILITY ACCOUNT BALANCES TO BE CORPORATELY SEPARATED INTRODUCTION Presented in this filing as Exhibit H are the unbundled Balance Sheets for Ohio Power Company, Columbus Southern Power Company, Central Power and Light Company, West Texas Utilities Company and Southwestern Electric Power Company. The balance sheet asset and liability account balances at December 31, 2000 were separated into estimated amounts applicable to the generation function and amounts applicable to the wires function. For Southwestern Electric Power Company, a further separation was made to assign the wires applicable to the Texas operations apart from the wires applicable to the Louisiana and Arkansas operations. While these estimated balances reasonably represent the expected assets, liabilities and total capitalization of the separate entities, the actual account balances at the time of corporate separation will be different and the methods employed will be more detailed and precise. This document describes the approach AEP intends to take when it separates the balance sheet account balances for Ohio Power Company, Columbus Southern Power Company, Central Power and Light Company, West Texas Utilities Company and Southwestern Electric Power Company at the time those companies legally separate. ACCOUNTS 101-106 Owned electric plant has been recorded in plant accounts which identify it as production, transmission, distribution or general plant. The production, transmission and distribution plant account balances will be directly assigned to the Generation Company or the Wires Company as appropriate. General plant account balances will be analyzed in detail and, whenever possible, directly assigned based on the function and/or location of the asset. General plant account balances, which cannot be directly assigned, will be allocated based on the relationship of the owned asset balances directly assigned to the Generation Company and the Wires Company. Similarly, leased electric plant account balances will be either directly assigned based on the function and/or location of the asset or allocated if not directly assignable. An exception is generation step-up transformers (GSUs) and the associated circuit breakers, which were recorded as transmission assets on the books of the Company at December 31, 2000. The balances related to GSUs and the associated circuit breakers will be assigned to the Generation Company. ACCOUNT 107 Construction Work in Progress will be segregated according to the function and/or location associated with each individual construction project. ACCOUNTS 108, 111 AND 115 Accumulated Provision for Depreciation and Accumulated Provision for Amortization of Electric Utility Plant, except for General Plant related balances, will be directly assigned based on historical functional balances. Accumulated Provision for Depreciation and Accumulated Provision for Amortization of Electric Utility Plant related to General Plant will be allocated based on the final assignment of General Plant balances. ACCOUNTS 120.1 THROUGH 120.5 Nuclear Fuel will be directly assigned to the Generation Company. ACCOUNTS 121 AND 122 Non-utility Plant and the associated Accumulated Provision for Depreciation and Amortization will be assigned based on the function to which the non-utility plant pertains. ACCOUNTS 123 AND 123.1 Investments in Associated Companies and Subsidiary Companies will be directly assigned to the function which that investment serves. Currently, Ohio Power Company and Columbus Southern Power Company Investments in Associated Companies and Subsidiary Companies relate predominantly to coal mining and coal preparation facilities, which are generation related. Currently, Investments in Associated Companies and Subsidiary Companies for Southwestern Electric Power Company relate predominantly to non-Texas transmission and distribution facilities. ACCOUNT 124 Other Investments will be directly assigned or allocated based on an appropriate allocation factor such as employee count or plant in service. ACCOUNT 125-128 Special Funds will be directly assigned or allocated based on an appropriate allocation factor such as employee count or plant in service. 2 ACCOUNT 131 The allocation of Cash and other finance and capital related accounts will be determined at the time of corporate separation and will depend on, among other things, the amount of other assets and liabilities assigned to each company. Hereafter, such allocations will be referred to as a "finance/capital" related allocation. ACCOUNTS 132-135 Special Deposits and Working Funds will be directly assigned or allocated based on an appropriate allocation factor such as finance/capital (see Account 131), employee count, or plant in service. ACCOUNT 141 Employee-related notes receivable will be assigned to the companies for which the employees work. Other notes receivable will be allocated in conjunction with the finance/capital allocation method (see Account 131). ACCOUNT 142 - Customer Accounts Receivable related to wholesale sales will be assigned to the Generation Company for the generation component and the Wires Company for the transmission component. Customer Accounts Receivable related to transmission sales will be directly assigned to the Wires Company. Customer Accounts Receivable related to retail electric sales will be allocated to both the Generation Company and the Wires Company based on unbundled tariffs. ACCOUNT 143 Other Accounts Receivable will be directly assigned as appropriate. ACCOUNT 144 Accumulated Provision for Uncollectible Accounts related to retail electric sales will be allocated to the Generation Company and Wires Company based on the allocation of Customer Accounts Receivable related to retail electric sales (see Account 142). Any provision related directly to wholesale trading will be assigned to the Generation Company. ACCOUNT 146 Accounts Receivable from Associated Companies will be directly assigned as appropriate. 3 ACCOUNTS 151 AND 152 Fuel Stock and Fuel Stock Expenses Undistributed will be directly assigned to the Generation Company. ACCOUNT 154 Plant Materials and Operating Supplies will be directly assigned to the Generation Company and Wires Company according to their storeroom functional affiliation. ACCOUNT 158 Allowances will be directly assigned to the Generation Company. ACCOUNT 163 Stores Expense Undistributed will be directly assigned according to the related storeroom functional affiliation. ACCOUNT 165 Prepayments will be directly assigned as appropriate or allocated based on an appropriate allocation factor such as employee count or plant in service. ACCOUNT 172 Rents Receivable will be directly assigned to the same company assigned the related asset. ACCOUNT 173 Accrued Utility Revenue will be allocated to the Generation Company and Wires Company based on unbundled tariffs. ACCOUNT 174 Miscellaneous Current and Accrued Assets will be directly assigned or allocated based on an appropriate allocation factor such as employee count or plant in service. ACCOUNT 181 Unamortized Debt Expenses will be assigned in the same manner as the allocation of debt. 4 ACCOUNT 182.3 Regulatory Assets will be assigned to the Wires Company. ACCOUNTS 183-186 Preliminary Survey and Investigation Charges, Clearing Accounts, Temporary Facilities and Miscellaneous Deferred Debits will be directly assigned or allocated based on an appropriate allocation factor such as employee count or plant in service. ACCOUNT 189 Unamortized Loss on Reacquired Debt will be assigned to the Wires Company. ACCOUNT 190 Accumulated Deferred Income Taxes will be directly assigned based on the assignment of the balance sheet account associated with each book/tax temporary difference. ACCOUNTS 201-226 Common Stock Issued, Preferred Stock Issued, Premium on Capital Stock, Other Paid-in Capital, Bonds, Advances from Associated Companies, Other Long Term Debt and Unamortized Discount on Long Term Debt will be determined based on the actual financing of the companies. Retained Earnings for the existing companies will be reduced by the amount of the dividend that is declared in the formation of the new companies. The new companies will start with zero Retained Earnings. ACCOUNT 227 Obligations Under Capital Lease - Noncurrent will be directly assigned based on the functionalization of the corresponding leased assets less accumulated amortization. ACCOUNT 228.2 Accumulated Provision for Injuries and Damages will be directly assigned or allocated based on an appropriate allocation factor such as employee count or plant in service. 5 ACCOUNT 228.3 Accumulated Provision for Pensions and Benefits will be directly assigned based on actuarial studies or other appropriate methods. ACCOUNT 228.4 Accumulated Miscellaneous Operating Provisions will be directly assigned or allocated based on an appropriate allocation factor such as employee count or plant in service. ACCOUNTS 232, 233 AND 234 Accounts Payable, Notes Payable to Associated Companies and Accounts Payable to Associated Companies will be directly assigned or allocated based on an appropriate allocation factor such as employee count or plant in service. ACCOUNT 235 Customer Deposits related to retail electric sales will be directly assigned to the Wires Company. Deposits related to wholesale trading will be directly assigned to the Generation Company. ACCOUNT 236 Taxes Accrued will be directly assigned or allocated based on an appropriate allocation factor such as employee count or plant in service. ACCOUNT 237 Interest Accrued will be directly assigned in accordance with the debt. ACCOUNT 238 Dividends Declared will be directly assigned to the company that declared the dividend. ACCOUNT 241 Tax Collections Payable will be directly assigned or allocated based on an appropriate allocation factor such as employee count or electric sales. 6 ACCOUNT 242 Miscellaneous Current and Accrued Liabilities will be directly assigned or allocated based on an appropriate allocation factor such as employee count, electric sales, leased assets, finance/capital (see Account 131), or plant in service. ACCOUNT 243 Obligations Under Capital Lease - Current will be assigned based on the functionalization of the corresponding leased assets. ACCOUNT 252 Customer Advances for Construction will be directly assigned to the Wires Company. ACCOUNT 253 Other Deferred Credits will be directly assigned or allocated based on an appropriate allocation factor such as employee count, electric sales, finance/capital (see Account 131), or plant in service. ACCOUNT 254 Other Regulatory Liabilities will be directly assigned to the Wires Company. ACCOUNT 255 Accumulated Deferred Investment Tax Credits will be allocated based on the functionalization of the property that generated the investment tax credits. ACCOUNTS 281-283 Accumulated Deferred Income Taxes will be directly assigned based on the assignment of the balance sheet account associated with each book/tax temporary difference. 7 Schedule H-1 Page 1 of 1 CENTRAL POWER AND LIGHT UNBUNDLED BALANCE SHEET - ESTIMATED AND UNAUDITED ASSETS DECEMBER 31, 2000 IN THOUSANDS
CENTRAL POWER AND LIGHT PRO FORMA PRO FORMA TOTAL COMPANY GENERATION WIRES PER FERC FORM 1 COMPANY COMPANY ------------------------------------------------------- UTILITY PLANT Utility Plant (101-106,114) 5,217,312 2,938,285 2,279,027 Construction Work in Progress (107) 138,273 27,359 110,914 TOTAL Utility Plant (Enter Total of lines 2 and 3) 5,355,585 2,965,644 2,389,941 (Less) Accum. Prov. for Depr. Amort. Depl. (108, 111, 115) 2,108,937 1,445,891 663,046 Net Utility Plant (Enter Total of line 4 less 5) 3,246,648 1,519,753 1,726,895 Nuclear Fuel (120.1-120.4, 120.6) 236,859 236,859 0 (Less) Accum. Prov. for Amort. of Nucl. Fuel Assemblies (120.5) 204,952 204,952 0 NET NUCLEAR FUEL (ENTER TOTAL OF LINE 7 LESS 8) 31,907 31,907 0 NET UTILITY PLANT (ENTER TOTAL OF LINES 6 AND 9) 3,278,555 1,551,660 1,726,895 OTHER PROPERTY AND INVESTMENTS Nonutility Property (121) 3,535 3,535 0 (Less) Accum. Prov. for Depr. and Amort. (122) 1,197 1,197 0 Other Investments (124) 70,890 69,496 1,394 Special Funds (125-128) 93,592 93,592 0 TOTAL Other Property and Investments (Total of lines 14-17,19-21) 166,820 165,426 1,394 CURRENT AND ACCRUED ASSETS Cash (131) 4,094 2,844 1,250 Special Deposits (132-134) 3,487 3,487 0 Working Fund (135) 79 77 2 Temporary Cash Investments (136) 6,594 4,443 2,151 Notes Receivable (141) 261 224 37 Customer Accounts Receivable (142) 62,991 7,576 55,415 Other Accounts Receivable (143) 2,435 757 1,678 Accounts Receivable from Assoc. Companies (146) 31,272 1,208 30,004 Fuel Stock (151) 22,684 22,684 0 Fuel Stock Expenses Undistributed (152) 158 158 0 Plant Materials and Operating Supplies (154) 52,428 43,335 9,093 Stores Expense Undistributed (163) 680 680 0 Prepayments (165) 44,882 11,451 33,431 Rents Receivable (172) 425 0 425 Accrued Utility Revenues (173) 49,760 0 49,760 Miscellaneous Current and Accrued Assets (174) 481,204 481,204 0 TOTAL Current and Accrued Assets (Enter Total of lines 24 thru 51) 763,434 580,188 183,246 DEFERRED DEBITS Unamortized Debt Expenses (181) 12,177 9,760 2,417 Other Regulatory Assets (182.3) 1,265,559 0 1,265,559 Clearing Accounts (184) 1,945 132 1,813 Miscellaneous Deferred Debits (186) 131,575 3,291 128,284 Unamortized Loss on Reaquired Debt (189) 12,790 0 12,790 Accumulated Deferred Income Taxes (190) 67,184 55,796 11,388 TOTAL Deferred Debits (Enter Total of lines 64 thru 67) 1,491,230 68,979 1,422,251 TOTAL Assets and Other Debits (Enter Total of lines 10,11,12,22,52,68) 5,700,039 2,366,253 3,333,786
Schedule H-2 Page 1 of 1 CONTRAL POWER AND LIGHT UNBUNDLED BALANCE SHEET - ESTIMATED AND UNAUDITED CAPITAL & LIABILITIES DECEMBER 31, 2000 IN THOUSANDS
CENTRAL POWER AND LIGHT PRO FORMA PRO FORMA TOTAL COMPANY GENERATION WIRES PER FERC FORM 1 COMPANY COMPANY ------------------------------------------------------- PROPRIETARY CAPITAL Common Stock Issued (201) 168,888 Preferred Stock Issued (204) 5,951 Premium on Capital Stock (207) 15 Other Paid-In Capital (208-211) 408,086 Retained Earnings (215, 215.1, 216) 789,133 TOTAL Proprietary Capital (Enter Total of lines 2 thru 13) 1,372,073 LONG-TERM DEBT Bonds(221) 1,104,820 Advances from Associated Companies (223) 153,139 Other Long-Term Debt (224) 350,000 (Less) Unamortized Discount on Long-Term Debt-Debit (226) 261 TOTAL Long-Term Debt (Enter Total of lines 16 thru 21) 1,607,698 TOTAL Capitalization 2,979,771 386,126 2,593,645 OTHER NONCURRENT LIABILITIES Accumulated Provision for Property Insurance (228.1) 3,264 1,814 1,449 Accumulated Provision for Pensions and Benefits (228.3) 3,579 788 2,791 Accumulated Miscellaneous Operating Provisions (228.4) 2,683 2,683 0 TOTAL OTHER Noncurrent LIABILITIES (ENTER TOTAL OF LINES 24 THRU 29) 9,526 5,286 4,240 CURRENT AND ACCRUED LIABILITIES Accounts Payable (232) 128,967 114,139 14,818 Notes Payable to Associated Companies (233) 269,712 186,059 83,653 Accounts Payable to Associated Companies (234) 90,722 42,649 48,073 Customer Deposits (235) 17,617 0 17,617 Taxes Accrued (236) 55,526 36,458 19,068 Interest Accrued (237) 26,217 19,252 6,965 Dividends Declared (238) 40 0 40 Matured Long-Term Debt (239) 0 0 0 Tax Collections Payable (241) 4,869 34 4,835 Miscellaneous Current and Accrued Liabilities (242) 504,728 494,983 9,745 TOTAL Current & Accrued Liabilities (Enter Total of lines 32 thru 44) 1,098,388 893,573 204,815 DEFERRED CREDITS Customer Advances for Construction (252) 2,059 0 2,059 Accumulated Deferred Investment Tax Credits (255) 128,099 113,531 14,568 Other Deferred Credits (253) 66,254 65,907 347 Other Regulatory Liabilities (254) 105,944 0 105,944 Unamortized Gain on Reaquired Debt (257) 17 0 17 Accumulated Deferred Income Taxes (281-283) 1,309,981 901,830 408,151 TOTAL DEFERRED CREDITS (ENTER TOTAL OF LINES 47 THRU 53) 1,612,354 1,081,268 531,086 TOTAL Liab and Other Credits (Enter Total of lines 14,22,30,45,54) 5,700,039 2,366,253 3,333,786
Schedule H-3 Page 1 of 1 COLUMBUS SOUTHERN POWER COMPANY UNBUNDLED BALANCE SHEET - ESTIMATED AND UNAUDITED ASSETS DECEMBER 31, 2000 IN THOUSANDS
COLUMBUS SOUTHERN PRO FORMA PRO FORMA TOTAL COMPANY GENERATION WIRES PER FERC FORM 1 COMPANY COMPANY -------------------------------------------------- UTILITY PLANT Utility Plant (101-106, 114) 3,149,130 1,606,488 1,542,642 Construction Work in Progress (107) 89,297 19,582 69,715 TOTAL Utility Plant (Enter Total of lines 2 and 3) 3,238,427 1,626,070 1,612,357 (Less) Accum. Prov. for Depr. Amort. Depl. (108, 111, 115) 1,272,776 650,581 622,195 NET UTILITY PLANT (ENTER TOTAL OF LINE 4 LESS 5) 1,965,651 975,489 990,162 NET UTILITY PLANT (ENTER TOTAL OF LINES 6 AND 9) 1,965,651 975,489 990,162 OTHER PROPERTY AND INVESTMENTS Nonutility Property (121) 18,517 9,531 8,986 (Less) Accum. Prov. for Depr. and Amort. (122) 3,333 2,798 535 Investments in Associated Companies (123) 430 430 0 Investment in Subsidiary Companies (123.1) 4,275 4,275 0 Other Investments (124) 194,472 181,611 12,861 Special Funds (125-128) 27 14 13 TOTAL Other Property and Investments (Total of lines 14-17,19-21) 214,388 193,063 21,325 CURRENT AND ACCRUED ASSETS Cash (131) 10,103 6,373 3,730 Special Deposits (132-134) 26 16 10 Working Fund (135) 1,464 921 543 Notes Receivable (141) 2 1 1 Customer Accounts Receivable (142) 73,710 71,721 1,989 Other Accounts Receivable (143) 18,632 13,170 5,462 (Less) Accum. Prov. for Uncollectible Acct.-Credit (144) 659 635 24 Notes Receivable from Associated Companies (145) 0 0 0 Accounts Receivable from Assoc. Companies (146) 55,426 48,483 6,943 Fuel Stock (151) 12,976 12,976 0 Fuel Stock Expenses Undistributed (152) 150 150 0 Plant Materials and Operating Supplies (154) 18,345 13,322 5,023 Allowances (158.1 and 158.2) 18,809 18,809 0 Stores Expense Undistributed (163) (34) (34) 0 Prepayments (165) 31,419 16,329 15,090 Rents Receivable (172) 78 0 78 Accrued Utility Revenues (173) 9,638 7,365 2,273 Miscellaneous Current and Accrued Assets (174) 1,101,301 1,090,116 11,185 TOTAL CURRENT AND ACCRUED ASSETS (ENTER TOTAL OF LINES 24 THRU 51) 1,351,386 1,299,083 52,303 DEFERRED DEBITS Unamortized Debt Expenses (181) 1,978 1,741 237 Other Regulatory Assets (182.3) 301,764 0 301,764 Prelim. Survey and Investigation Charges (Electric) (183) 10 5 5 Clearing Accounts (184) 676 284 392 Temporary Facilities (185) 23 12 11 Miscellaneous Deferred Debits (186) 74,997 41,582 33,415 Unamortized Loss on Reaquired Debt (189) 8,339 0 8,339 Accumulated Deferred Income Taxes (190) 67,107 54,646 32,461 TOTAL Deferred Debits (Enter Total of lines 54 thru 67) 474,894 98,270 376,624 TOTAL ASSETS AND OTHER DEBITS (ENTER TOTAL OF LINES 10,11,12,22,52,68) 4,006,319 2,565,905 1,440,414
COLUMBUS SOUTHERN POWER COMPANY SCHEDULE H-4 UNBUNDLED BALANCE SHEET -- ESTIMATED AND UNAUDITED PAGE 1 OF 2 CAPITAL & LIABILITIES DECEMBER 31, 2000 IN THOUSANDS
COLUMBUS SOUTHERN PRO FORMA PRO FORMA TOTAL COMPANY GENERATION WIRES PER FERC FORM 1 COMPANY COMPANY -------------------------------------------------- PROPRIETARY CAPITAL Common Stock Issued (201) 41,026 Preferred Stock Issued (204) 15,000 Premium on Capital Stock (207) 257,892 Other Paid-In Capital (208-211) 315,461 Retained Earnings (215, 215.1, 216) 97,173 Unappropriated Undistributed Subsidiary Earnings (216.1) 1,896 TOTAL Proprietary Capital (Enter Total of lines 2 thru 13) 728,448 LONG-TERM DEBT Bonds(221) 654,000 Other Long-Term Debt (224) 252,245 (Less) Unamortized Discount on Long-Term Debt-Debit (226) 6,629 TOTAL LONG-TERM DEBT (ENTER TOTAL OF LINES 16 THRU 21) 899,616 TOTAL CAPITALIZATION 1,628,064 612,480 1,015,584 OTHER NONCURRENT LIABILITIES Obligations Under Capital Leases - Noncurrent (227) 35,034 12,660 22,374 Accumulated Provision for Pensions and Benefits (228.3) 5,527 1,522 4,005 Accumulated Miscellaneous Operating Provisions (228.4) 4,815 0 4,815 TOTAL OTHER Noncurrent Liabilities (Enter Total of lines 24 thru 29) 45,376 14,182 31,194
COLUMBUS SOUTHERN POWER COMPANY SCHEDULE H-4 UNBUNDLED BALANCE SHEET -- ESTIMATED AND UNAUDITED PAGE 2 OF 2 CAPITAL & LIABILITIES DECEMBER 31, 2000 IN THOUSANDS
COLUMBUS SOUTHERN PRO FORMA PRO FORMA TOTAL COMPANY GENERATION WIRES PER FERC FORM 1 COMPANY COMPANY -------------------------------------------------- CURRENT AND ACCRUED LIABILITIES Accounts Payable (232) 89,465 80,226 9,239 Notes Payable to Associated Companies (233) 90,959 57,376 33,583 Accounts Payable to Associated Companies (234) 80,054 55,103 24,951 Customer Deposits (235) 4,851 0 4,851 Taxes Accrued (236) 162,217 92,067 70,150 Interest Accrued (237) 13,332 8,002 5,330 Dividends Declared (238) 262 262 0 Tax Collections Payable (241) 879 239 640 Miscellaneous Current and Accrued Liabilities (242) 1,161,654 1,141,345 20,309 Obligations Under Capital Leases-Current (243) 7,522 2,718 4,804 TOTAL CURRENT & Accrued Liabilities (Enter Total of lines 32 thru 44) 1,611,195 1,437,338 173,857 DEFERRED CREDITS Customer Advances for Construction (252) 775 0 775 Accumulated Deferred Investment Tax Credits (255) 41,212 27,126 14,086 Other Deferred Credits (253) 138,536 138,444 92 Other Regulatory Liabilities (254) 30,384 0 30,384 Accumulated Deferred Income Taxes (281-283) 510,777 336,335 174,442 TOTAL Deferred Credits (Enter Total of lines 47 thru 53) 721,684 501,905 219,779 TOTAL LIAB AND OTHER CREDITS (ENTER TOTAL OF LINES 14,22,30,45,54) 4,006,319 2,565,905 1,440,414
OHIO POWER COMPANY SCHEDULE H-5 UNBUNDLED BALANCE SHEET -- ESTIMATED AND UNAUDITED PAGE 1 OF 1 ASSETS DECEMBER 31, 2000 IN THOUSANDS
OHIO POWER PRO FORMA PRO FORMA TOTAL COMPANY GENERATION WIRES PER FERC FORM 1 COMPANY COMPANY -------------------------------------------------- UTILITY PLANT Utility Plant (101-106,114) 4,865,894 2,880,858 1,985,036 Construction Work in Progress (107) 195,086 153,637 41,449 TOTAL Utility Plant (Enter Total of lines 2 and 3) 5,060,980 3,034,495 2,026,485 (Less) Accum. Prov. for Depr. Amort. Depl. (108, 111, 115) 2,297,082 1,600,041 697,041 Net Utility Plant (Enter Total of line 4 less 5) 2,763,897 1,434,454 1,329,443 NET UTILITY PLANT (ENTER TOTAL OF LINES 6 AND 9) 2,763,897 1,434,454 1,329,443 OTHER PROPERTY AND INVESTMENTS Nonutility Property (121) 23,561 19,489 4,072 (Less) Accum. Prov. for Depr. and Amort. (122) 12,419 10,153 2,266 Investment in Subsidiary Companies (123.1) 56,254 56,254 0 Other Investments (124) 299,987 290,199 9,788 Special Funds (125-128) 39 23 16 TOTAL OTHER PROPERTY AND INVESTMENTS (TOTAL OF LINES 14-17,19-21) 367,422 355,812 11,610 CURRENT AND ACCRUED ASSETS Cash (131) 8,585 6,456 2,129 Special Deposits (132-134) 16,301 16,149 152 Working Fund (135) 5,101 5,090 11 Notes Receivable (141) 72 54 18 Customer Accounts Receivable (142) 139,732 131,293 8,439 Other Accounts Receivable (143) 26,299 20,120 6,179 (Less) Accum. Prov. for Uncollectible Acct.-Credit (144) 1,054 1,022 32 Notes Receivable from Associated Companies (145) 0 0 0 Accounts Receivable from Assoc. Companies (146) 125,253 107,115 18,138 Fuel Stock (151) 79,452 79,452 0 Fuel Stock Expenses Undistributed (152) 1,668 1,668 0 Plant Materials and Operating Supplies (154) 43,005 33,325 9,680 Allowances (158.1 and 158.2) 32,201 32,201 0 Stores Expense Undistributed (163) 786 786 0 Prepayments (165) 29,061 17,261 11,800 Rents Receivable (172) 98 0 98 Accrued Utlilty Revenues (173) 263 215 48 Miscellaneous Current and Accrued Assets (174) 1,620,188 1,618,484 1,704 TOTAL CURRENT AND ACCRUED ASSETS (ENTER TOTAL OF LINES 24 THRU 51) 2,127,011 2,068,647 58,364 DEFERRED DEBITS Unamortized Debt Expenses (181) 3,963 3,701 262 Other Regulatory Assets (182.3) 748,089 0 748,089 Prelim. Survey and Investigation Charges (Electric) (183) 2 1 1 Clearing Accounts (184) 856 504 352 Temporary Facilities (185) 12 7 5 Miscellaneous Deferred Debits (186) 91,701 52,305 39,396 Unamortized Loss on Reaquired Debt (189) 6,106 0 6,106 Accumulated Deferred Income Taxes (190) 131,018 93,114 37,904 TOTAL DEFERRED DEBITS (ENTER TOTAL OF LINES 54 THRU 67) 981,747 149,632 832,115 TOTAL ASSETS AND OTHER DEBITS (ENTER TOTAL OF LINES 10,11,12,22,52,68) 6,240,077 4,008,545 2,231,532
OHIO POWER COMPANY SCHEDULE H-6 UNBUNDLED BALANCE SHEET -- ESTIMATED AND UNAUDITED PAGE 1 OF 1 CAPITAL & LIABILITIES DECEMBER 31, 2000 IN THOUSANDS
OHIO POWER PRO FORMA PRO FORMA TOTAL COMPANY GENERATION WIRES PER FERC FORM 1 COMPANY COMPANY -------------------------------------------------- PROPRIETARY CAPITAL Common Stock Issued (201) 321,201 Preferred Stock Issued (204) 25,498 Premium on Capital Stock (207) 729 Other Paid-in Capital (208-211) 461,753 Retained Earnings (215, 215.1, 216) 387,393 Unappropriated Undistributed Subsidiary Earnings (216.1) 10,694 TOTAL PROPRIETARY CAPITAL (ENTER TOTAL OF LINES 2 THRU 13) 1,207,268 LONG-TERM DEBT Bonds(221) 452,485 Other Long-Term Debt (224) 710,225 (Less) Unamortized Discount on Long-Term Debt-Debit (226) 9,723 TOTAL LONG-TERM DEBT (ENTER TOTAL OF LINES 16 THRU 21) 1,152,987 TOTAL CAPITALIZATION 2,360,255 665,279 1,694,976 OTHER NONCURRENT LIABILITIES Obligations Under Capital Leases - Noncurrent (227) 80,267 70,043 10,224 Accumulated Provision for Injuries and Damages (228.2) 24 14 10 Accumulated Provision for Pensions and Benefits (228.3) 13,862 6,912 6,950 Accumulated Miscellaneous Operating Provisions (228.4) 5,191 74 5,117 TOTAL OTHER NONCURRENT LIABILITIES (ENTER TOTAL OF LINES 24 THRU 29) 99,344 77,043 22,301 CURRENT AND ACCRUED LIABILITIES Accounts Payable (232) 165,206 144,509 20,697 Notes Payable to Associated Companies (233) 167,190 125,719 41,471 Accounts Payable to Associated Companies (234) 207,626 147,272 60,354 Customer Deposits (235) 39,736 35,113 4,623 Taxes Accrued (236) 174,643 100,563 74,080 Interest Accrued (237) 17,599 13,143 4,456 Tax Collections Payable (241) 1,856 903 953 Miscellaneous Current and Accrued Liabilities (242) 1,765,328 1,733,241 32,087 Obligations Under Capital Leases-Current (243) 14,224 12,412 1,812 TOTAL CURRENT & ACCRUED LIABILITIES (ENTER TOTAL OF LINES 32 THRU 44) 2,553,408 2,312,875 240,533 DEFERRED CREDITS Accumulated Deferred Investment Tax Credits (255) 25,214 15,164 10,050 Other Deferred Credits (253) 218,126 217,261 865 Other Regulatory Liabilities (254) 39,497 0 39,497 Accumulated Deferred Income Taxes (281-283) 944,233 720,923 223,310 TOTAL Deferred Credits (Enter Total of lines 47 thru 53) 1,227,070 953,348 273,722 TOTAL LIAB AND OTHER CREDITS (ENTER TOTAL OF LINES 14,22,30,45,54) 6,240,077 4,008,545 2,231,532
SOUTHWESTERN ELECTRIC POWER COMPANY SCHEDULE H-7 UNBUNDLED BALANCE SHEET -- ESTIMATED AND UNAUDITED PAGE 1 OF 2 ASSETS DECEMBER 31, 2000 IN THOUSANDS
SOUTHWESTERN ELECTRIC POWER PRO FORMA SOUTHWESTERN ELECTRIC POWER TOTAL COMPANY TEXAS WIRES EXCLUDING PER FERC FORM 1 COMPANY TEXAS WIRES COMPANY -------------------------------------------------------------------- Utility Plant (101-106,114) 3,261,028 809,018 2,452,010 Construction Work in Progress (107) 57,995 17,683 40,312 TOTAL Utility Plant (Enter Total of lines 2 and 3) 3,319,023 826,701 2,492,322 (Less) Accum. Prov. for Depr. Amort. Depl. (108, 111, 115) 1,457,005 278,417 1,178,588 Net Utility Plant (Enter Total of line 4 less 5) 1,862,018 548,284 1,313,734 Nuclear Fuel (120.1-120.4, 120.6) 0 0 0 (Less) Accum. Prov. for Amort. of Nucl. Fuel Assemblies (120.5) 0 0 0 NET NUCLEAR FUEL (ENTER TOTAL OF LINE 7 LESS 8) 0 0 0 NET UTILITY PLANT (ENTER TOTAL OF LINES 6 AND 9) 1,862,018 548,284 1,313,734 Utility Plant Adjustments (116) 0 0 0 Gas Stored Underground - Noncurrent (117) 0 0 0 OTHER PROPERTY AND INVESTMENTS 0 Nonutility Property (121) 4,233 113 4,120 (Less) Accum. Prov. for Depr. and Amort. (122) 0 0 0 Investments in Associated Companies (123) 0 0 0 Investment in Subsidiary Companies (123.1) 196 0 196 (For Cost of Account 123.1, See Footnote Page 224, line 42) 0 0 0 Noncurrent Portion of Allowances 0 0 0 Other Investments (124) 67,726 845 66,831 Special Funds (125-128) 0 0 0 TOTAL OTHER PROPERTY AND INVESTMENTS (TOTAL OF LINES 14-17,19-21) 72,155 958 71,197 CURRENT AND ACCRUED ASSETS Cash (131) 673 110 563 Special Deposits (132-134) 1,027 315 712 Working Fund (135) 207 35 172 Temporary Cash Investments (136) 0 0 0 Notes Receivable (141) 85 0 85 Customer Accounts Receivable (142) 22,704 2,314 20,390 Other Accounts Receivable (143) 18,127 1,022 17,105 (Less) Accum. Prov. for Uncollectible Acct.-Credit (144) 0 0 0 Notes Receivable from Associated Companies (145) 0 0 0 Accounts Receivable from Assoc. Companies (146) 11,419 0 11,419 Fuel Stock (151) 39,480 0 39,480 Fuel Stock Expenses Undistributed (152) 544 0 544
SOUTHWESTERN ELECTRIC POWER COMPANY SCHEDULE H-7 UNBUNDLED BALANCE SHEET -- ESTIMATED AND UNAUDITED PAGE 2 OF 2 ASSETS DECEMBER 31, 2000 IN THOUSANDS
SOUTHWESTERN ELECTRIC POWER PRO FORMA SOUTHWESTERN ELECTRIC POWER TOTAL COMPANY TEXAS WIRES EXCLUDING PER FERC FORM 1 COMPANY TEXAS WIRES COMPANY -------------------------------------------------------------------- Residuals (Elec) and Extracted Products (153) 0 0 0 Plant Materials and Operating Supplies (154) 25,137 2,427 22,710 Merchandise (155) 0 0 0 Other Materials and Supplies (156) 0 0 0 Nuclear Materials Held for Sale (157) 0 0 0 Allowances (158.1 and 158.2) 0 0 0 (Less) Noncurrent Portion of Allowances 0 0 0 Stores Expense Undistributed (163) 0 0 0 Gas Stored Underground - Current (164.1) 0 0 0 Liquefied Natural Gas Stored and Held for Processing (164.2-164.3) 0 0 0 Prepayments (165) 50,684 13,768 36,916 Advances for Gas (166-167) 0 0 0 Interest and Dividends Receivable (171) 225 95 130 Rents Receivable (172) 257 109 148 Accrued Utility Revenues (173) 12,283 1,186 11,097 Miscellaneous Current and Accrued Assets (174) 460,019 0 460,019 TOTAL CURRENT AND ACCRUED ASSETS (ENTER TOTAL OF LINES 24 THRU 51) 642,871 21,381 621,490 DEFERRED DEBITS Unamortized Debt Expenses (181) 8,183 1,326 6,857 Extraordinary Property Losses (182.1) 0 0 0 Unrecovered Plant and Regulatory Study Costs (182.2) 0 0 0 Other Regulatory Assets (182.3) 94,839 16,654 78,185 Prelim. Survey and Investigation Charges (Electric) (183) 0 0 0 Prelim. Sur. and Invest. Charges (Gas) (183.1, 183.2) 0 0 0 Clearing Accounts (184) 1,195 436 759 Temporary Facilities (185) 0 0 0 Miscellaneous Deferred Debits (186) 34,715 20,237 14,478 Def. Losses from Disposition of Utility Plt. (187) 0 0 0 Research, Devel. and Demonstration Expend. (188) 0 0 0 Unamortized Loss on Reaquired Debt (189) 23,059 10,314 12,745 Accumulated Deferred Income Taxes (190) 47,615 11,981 35,634 Unrecovered Purchased Gas Costs (191) 0 0 0 TOTAL DEFERRED DEBITS (ENTER TOTAL OF LINES 54 THRU 67) 209,606 60,948 148,658 TOTAL ASSETS AND OTHER DEBITS (ENTER TOTAL OF LINES 10,11,12,22,52,68) 2,786,650 631,571 2,155,079
SOUTHWESTERN ELECTRIC POWER COMPANY SCHEDULE H-8 UNBUNDLED BALANCE SHEET -- ESTIMATED AND UNAUDITED PAGE 1 OF 1 CAPITAL & LIABILITIES DECEMBER 31, 2000 IN THOUSANDS
SOUTHWESTERN ELECTRIC POWER PRO FORMA SOUTHWESTERN ELECTRIC POWER TOTAL COMPANY TEXAS WIRES EXCLUDING PER FERC FORM 1 COMPANY TEXAS WIRES COMPANY -------------------------------------------------------------------- PROPRIETARY CAPITAL Common Stock Issued (201) 135,660 Preferred Stock Issued (204) 4,701 Premium on Capital Stock (207) 4 Other Paid-in Capital (208-211) 247,475 Retained Earnings (215, 215.1, 216) 291,356 Unappropriated Undistributed Subsidiary Earnings (216.1) 158 TOTAL PROPRIETARY CAPITAL (ENTER TOTAL OF LINES 2 THRU 13) 679,354 LONG-TERM DEBT Bonds (221) 494,930 Advances from Associated Companies (223) 113,402 Other Long-Term Debt (224) 150,000 Unamortized Premium on Long-Term Debt (225) 2,716 (Less) Unamortized Discount on Long-Term Debt-Debit (226) 1,683 TOTAL LONG-TERM DEBT (ENTER TOTAL OF LINES 16 THRU 21) 759,365 TOTAL CAPITALIZATION 1,438,719 457,590 981,129 OTHER NONCURRENT LIABILITIES 0 0 0 Accumulated Provision for Pensions and Benefits (228.3) 3,612 1,012 2,600 Accumulated Provision for Rate Refunds (229) 0 0 0 TOTAL OTHER Noncurrent Liabilities (Enter Total of lines 24 thru 29) 3,612 1,012 2,600 CURRENT AND ACCRUED LIABILITIES Accounts Payable (232) 107,748 5,978 101,770 Notes Payable to Associated Companies (233) 16,822 4,381 12,441 Accounts Payable to Associated Companies (234) 48,305 7,096 41,209 Customer Deposits (235) 16,432 6,648 9,784 Taxes Accrued (236) 11,223 6,887 4,336 Interest Accrued (237) 13,198 4,820 8,378 Dividends Declared (238) 57 0 57 Tax Collections Payable (241) 3,950 712 3,238 Miscellaneous Current and Accrued Liabilities (242) 488,545 2,987 485,558 TOTAL CURRENT & ACCRUED LIABILITIES (ENTER TOTAL OF LINES 32 THRU 44) 706,280 39,509 666,771 DEFERRED CREDITS Accumulated Deferred Investment Tax Credits (255) 53,167 12,778 40,389 Other Deferred Credits (253) 68,597 0 68,597 Other Regulatory Liabilities (254) 69,023 19,016 50,007 Unamortized Gain on Reaquired Debt (257) 433 151 282 Accumulated Deferred Income Taxes (281-283) 446,819 101,516 345,303 TOTAL DEFERRED CREDITS (ENTER TOTAL OF LINES 47 THRU 53) 638,039 133,461 504,578 TOTAL LIAB AND OTHER CREDITS (ENTER TOTAL OF LINES 14,22,30,45,54) 2,786,650 631,571 2,155,079
WEST TEXAS UTILTIES SCHEDULE H-9 UNBUNDLED BALANCE SHEET -- ESTIMATED AND UNAUDITED PAGE 1 OF 1 ASSETS DECEMBER 31, 2000 IN THOUSANDS
WEST TEXAS UTILTIES PRO FORMA PRO FORMA TOTAL COMPANY GENERATION WIRES PER FERC FORM 1 COMPANY COMPANY -------------------------------------------------------------------- UTILITY PLANT Utility Plant (101-106, 114) 1,194,515 442,607 751,908 Construction Work in Progress (107) 34,824 16,846 17,978 TOTAL Utility Plant (Enter Total of lines 2 and 3) 1,229,339 459,453 769,886 (Less) Accum. Prov. for Depr. Amort. Depl. (108, 111, 115) 515,041 210,985 304,056 NET UTILITY PLANT (ENTER TOTAL OF LINE 4 LESS 5) 714,298 248,468 465,830 NET UTILITY PLANT (ENTER TOTAL OF LINES 6 AND 9) 714,298 248,468 465,830 OTHER PROPERTY AND INVESTMENTS Nonutility Property (121) 1,163 310 853 (Less) Accum. Prov. for Depr. and Amort. (122) 296 0 296 Other Investments (124) 20,944 20,944 0 TOTAL OTHER PROPERTY AND INVESTMENTS (TOTAL OF LINES 14-17,19-21) 21,811 21,254 557 CURRENT AND ACCRUED ASSETS Cash (131) 2,796 1,352 1,444 Special Deposits (132-134) 4,143 1,628 2,515 Working Fund (135) 2 2 0 Customer Accounts Receivable (142) 33,109 5,116 27,993 Other Accounts Receivable (143) 3,000 1,550 1,450 (Less) Accum. Prov. for Uncollectible Acct.-Credit (144) 180 0 180 Accounts Receivable from Assoc. Companies (146) 16,095 12,740 3,355 Fuel Stock (151) 12,104 12,104 0 Fuel Stock Expenses Undistributed (152) 70 70 0 Plant Materials and Operating Supplies (154) 10,510 6,646 3,864 Stores Expense Undistributed (163) 0 0 0 Prepayments (165) 23,138 7,205 15,933 Rents Receivable (172) 0 0 0 Accrued Utility Revenues (173) 9,011 0 9,011 Miscellaneous Current and Accrued Assets (174) 152,174 152,174 0 TOTAL CURRENT AND ACCRUED ASSETS (ENTER TOTAL OF LINES 24 THRU 51) 265,972 200,587 65,385 DEFERRED DEBITS Unamortized Debt Expenses (181) 1,520 1,110 410 Other Regulatory Assets (182.3) 27,573 0 27,573 Clearing Accounts (184) 706 69 637 Miscellaneous Deferred Debits (186) 68,827 48 68,779 Unamortized Loss on Reaquired Debt (189) 11,298 0 11,298 Accumulated Deferred Income Taxes (190) 16,604 12,525 4,079 TOTAL DEFERRED DEBITS (ENTER TOTAL OF LINES 54 THRU 67) 126,528 13,752 112,776 TOTAL ASSETS AND OTHER DEBITS (ENTER TOTAL OF LINES 10,11,12,22,52,68) 1,128,609 484,061 644,548
WEST TEXAS UTILTIES SCHEDULE H-10 UNBUNDLED BALANCE SHEET -- ESTIMATED AND UNAUDITED PAGE 1 OF 1 ASSETS DECEMBER 31, 2000 IN THOUSANDS
WEST TEXAS UTILTIES PRO FORMA PRO FORMA TOTAL COMPANY GENERATION WIRES PER FERC FORM 1 COMPANY COMPANY -------------------------------------------------------------------- PROPRIETARY CAPITAL Common Stock Issued (201) 137,214 Preferred Stock Issued (204) 2,367 Premium on Capital Stock (207) 115 Other Paid-in Capital (208-211) 3,321 Retained Earnings (215, 215.1, 216) 121,502 TOTAL PROPRIETARY CAPITAL (ENTER TOTAL OF LINES 2 THRU 13) 264,519 LONG-TERM DEBT Bonds (221) 256,310 Advances from Associated Companies (223) 0 Other Long-Term Debt (224) 0 (Less) Unamortized Discount on Long-Term Debt-Debit (226) 466 TOTAL LONG-TERM DEBT (ENTER TOTAL OF LINES 16 THRU 21) 255,844 TOTAL CAPITALIZATION 520,363 150,622 369,741 OTHER NONCURRENT LIABILITIES Accumulated Provision for Pensions and Benefits (228.3) 3,440 1,218 2,222 Accumulated Provision for Rate Refunds (229) 0 0 0 TOTAL OTHER NONCURRENT LIABILITIES (ENTER TOTAL OF LINES 24 THRU 29) 3,440 1,218 2,222 CURRENT AND ACCRUED LIABILITIES Accounts Payable (232) 45,562 21,590 23,972 Notes Payable to Associated Companies (233) 58,578 16,774 41,804 Accounts Payable to Associated Companies (234) 51,223 20,218 31,005 Customer Deposits (235) 2,659 0 2,659 Taxes Accrued (236) 18,901 6,718 12,183 Interest Accrued (237) 3,717 1,274 2,443 Dividends Declared (238) 26 0 26 Tax Collections Payable (241) 937 231 706 Miscellaneous Current and Accrued Liabilities (242) 161,861 157,789 4,072 TOTAL CURRENT & ACCRUED LIABILITIES (ENTER TOTAL OF LINES 32 THRU 44) 343,464 224,594 118,870 DEFERRED CREDITS Accumulated Deferred Investment Tax Credits (255) 24,052 9,237 14,815 Other Deferred Credits (263) 20,992 20,800 192 Other Regulatory Liabilities (254) 42,562 0 42,562 Unamortized Gain on Reaquired Debt (257) 94 9 85 Accumulated Deferred Income Taxes (281-283) 173,642 77,581 96,061 TOTAL DEFERRED CREDITS (ENTER TOTAL OF LINES 47 THRU 53) 261,342 107,627 153,715 TOTAL LIAB AND OTHER CREDITS (ENTER TOTAL OF LINES 14,22,30,45,54) 1,128,609 484,061 644,548
AMERICAN ELECTRIC POWER SERVICE CORPORATION Schedule H-11 FERC DOCKET NO. EC01-________ Page 1 of 2 TRANSFER OF JURISDICTIONAL ASSETS SECTION 5, PART C JOURNAL ENTRIES TRANSFER OF CENTRAL POWER AND LIGHT COMPANY ASSETS (IN $ THOUSANDS BASED ON 12/31/2000 ESTIMATED AMOUNTS) A. TO BE RECORDED ON THE BOOKS OF CENTRAL POWER AND LIGHT COMPANY: ---------------------------------------------------------------
CREATE GENCO SUBSIDIARY ----------------------- ACCOUNT DESCRIPTION DR CR ------- ----------- -- -- 108 ACCUM PROVISION FOR DEPRECIATION AND DEPL 1,445,891 120.5 ACCUM PROVISION FOR AMORTIZATION OF NUCLEAR FUEL 204,952 122 ACCUM PROVISION FOR DEPRECIATION AND DEPL 1,197 123.1&221-226 INV IN SUBS COS & LONG-TERM DEBT 386,126 228.1 ACCUM PROVISION FOR PROPERTY INSURANCE 1,814 228.3 ACCUM PROVISION FOR PENSIONS AND BENEFITS 788 228.4 ACCUM MISCELLANEOUS OPERATING PROVISIONS 2,683 232 ACCOUNTS PAYABLE l14,139 233 NOTES PAYABLE TO ASSOCIATED COMPANIES 186,059 234 ACCOUNTS PAYABLE TO ASSOCIATED COMPANIES 42,649 236 TAXES ACCRUED 36,458 237 INTEREST ACCRUED 19,252 241 TAX COLLECTIONS PAYABLE 34 242 MISC CURRENT AND ACCRUED LIABILITIES 494,983 253 OTHER DEFERRED CREDITS 65,907 255 ACCUMULATED DEFERRED INVESTMENT TAX CREDITS 113,531 281-283 ACCUMULATED DEFERRED INCOME TAXES 901,830 101-106,114 UTILITY PLANT 2,938,285 107 CONSTRUCTION WORK IN PROGRESS 21,359 120.1-120.4 NUCLEAR FUEL 236,859 121 NONUTILITY PROPERTY 3,535 124 OTHER INVESTMENTS 69,496 125-128 SPECIAL FUNDS 93,592 131 CASH 2,844 132-134 SPECIAL DEPOSITS 3,487 135 WORKING FUND 77 136 TEMPORARY CASH INVESTMENTS 4,443 141 NOTES RECEIVABLE 224 142 CUSTOMER ACCOUNTS RECEIVABLE 7,576 143 OTHER ACCOUNTS RECEIVABLE 757 146 ACCOUNTS RECEIVABLE FROM ASSOCIATED COS 1,268 151 FUEL STOCK 22,684 152 FUEL STOCK EXPENSES UNDISTRIBUTED 158 154 PLANT MATERIALS AND OPERATING SUPPLIES 43,335 163 STORES EXPENSE UNDISTRIBUTED 680 165 PREPAYMENTS 11,451 174 MISCELLANEOUS CURRENT AND ACCRUED ASSETS 481,204 181 UNAMORTIZED DEBT EXPENSE 9,760 184 CLEARING ACCOUNTS 132 186 MISCELLANEOUS DEFERRED DEBITS 3,291 190 ACCUMULATED DEFERRED INCOME TAXES 55,796
TO RECORD THE CREATION OF A GENCO SUBSIDIARY OF CENTRAL POWER AND LIGHT COMPANY. AMERICAN ELECTRIC POWER SERVICE CORPORATION Schedule H-11 FERC DOCKET NO. EC01-________ Page 2 of 2 TRANSFER OF JURISDICTIONAL ASSETS SECTION 5, PART C JOURNAL ENTRIES TRANSFER OF CENTRAL POWER AND LIGHT COMPANY ASSETS (IN $ THOUSANDS BASED ON 12/31/2000 ESTIMATED AMOUNTS) A. TO BE RECORDED ON THE BOOKS OF CENTRAL POWER AND LIGHT COMPANY: --------------------------------------------------------------- DIVIDEND GENCO SUBSIDIARY TO CENTRAL AND SOUTH WEST CORPORATION --------------------------------------------------------------- ACCOUNT DESCRIPTION DR CR ------- ----------- -- -- 438 DIVIDENDS DECLARED - RET EARNINGS XXX,XXX 238 DIVIDENDS DECLARED - LIABILITY XXX,XXX TO RECORD THE DECLARATION OF A DIVIDEND FROM CENTRAL POWER AND LIGHT COMPANY TO CENTRAL AND SOUTH WEST CORPORATION FOR THE NET ASSETS OF THE CENTRAL POWER AND LIGHT COMPANY GENCO SUBSIDIARY. TRANSFER GENCO INVESTMENT TO CENTRAL AND SOUTH WEST CORPORATION --------------------------------------------------------------- ACCOUNT DESCRIPTION DR CR ------- ----------- -- -- 238 DIVIDENDS DECLARED - LIABILITY 123.1 INVESTMENT IN SUBSIDIARY COS - CPL GENCO XXX,XXX TO RECORD THE TRANSFER OF THE INVESTMENT OF CENTRAL POWER AND LIGHT COMPANY IN GENCO TO CENTRAL AND SOUTH WEST CORPORATION TO SATISFY THE DIVIDEND DECLARATION. CLOSE DIVIDEND TO RETAINED EARNINGS ----------------------------------- ACCOUNT DESCRIPTION DR CR ------- ----------- -- -- 216 RETAINED EARNINGS XXX,XXX 438 DIVIDENDS DECLARED XXX,XXX TO CLOSE THE DIVIDEND DECLARATION ON CENTRAL POWER AND LIGHT COMPANY TO RETAINED EARNINGS. AMERICAN ELECTRIC POWER SERVICE CORPORATION Schedule H-12 FERC DOCKET NO. EC01-________ Page 1 of 1 TRANSFER OF JURISDICTIONAL ASSETS SECTION 5, PART C JOURNAL ENTRIES TRANSFER OF CENTRAL POWER AND LIGHT COMPANY ASSETS (IN $ THOUSANDS BASED ON 12/31/2000 ESTIMATED AMOUNTS) AA. TO BE RECORDED ON THE BOOKS OF CENTRAL AND SOUTH WEST CORPORATION: ------------------------------------------------------------------ DIVIDEND GENCO SUBSIDIARY TO AEP, INC ------------------------------------- ACCOUNT DESCRIPTION DR CR ------- ----------- -- -- 438 DIVIDENDS DECLARED - RET EARNINGS XXX,XXX 238 DIVIDENDS DECLARED - LIABILITY XXX,XXX TO RECORD THE DECLARATION OF A DIVIDEND FROM CENTRAL AND SOUTH WEST CORPORATION TO THE AEP CO., INC. FOR THE NET ASSETS OF THE CENTRAL POWER AND LIGHT COMPANY GENCO SUBSIDIARY. TRANSFER GENCO INVESTMENT TO AEP, INC ------------------------------------- ACCOUNT DESCRIPTION DR CR ------- ----------- -- -- 238 DIVIDENDS DECLARED - LIABILITY XXX,XXX 123.1 INVESTMENT IN SUBSIDIARY COS - CPL GENCO XXX,XXX TO RECORD THE TRANSFER OF THE INVESTMENT OF CENTRAL AND SOUTH WEST CORPORATION IN GENCO TO AEP, CO., INC. TO SATISFY THE DIVIDEND DECLARATION. CLOSE DIVIDEND TO RETAINED EARNINGS ----------------------------------- ACCOUNT DESCRIPTION DR CR ------- ----------- -- -- 216 RETAINED EARNINGS XXX,XXX 438 DIVIDENDS DECLARED XXX,XXX TO CLOSE THE DIVIDEND DECLARATION ON CENTRAL AND SOUTH WEST CORPORATION TO RETAINED EARNINGS. AMERICAN ELECTRIC POWER SERVICE CORPORATION Schedule H-13 FERC DOCKET NO. EC01-________ Page 1 of 1 TRANSFER OF JURISDICTIONAL ASSETS SECTION 5, PART C JOURNAL ENTRIES TRANSFER OF CENTRAL POWER AND LIGHT COMPANY ASSETS (IN $ THOUSANDS BASED ON 12/31/2000 ESTIMATED AMOUNTS) B. TO BE RECORDED ON THE BOOKS OF CENTRAL POWER AND LIGHT GENCO: -------------------------------------------------------------
CREATE GENCO SUBSIDIARY ACCOUNT DESCRIPTION DR CR -------- --------------- --- --- 101-106,114 UTILITY PLANT 2,938,285 107 CONSTRUCTION WORK IN PROGRESS 27,359 120.1-120.4 NUCLEAR FUEL 236,859 121 NONUTILITY PROPERTY 3,535 124 OTHER INVESTMENTS 69,496 125-128 SPECIAL FUNDS 93,592 131 CASH 2,844 132-134 SPECIAL DEPOSITS 3,487 135 WORKING FUND 77 136 TEMPORARY CASH INVESTMENTS 4,443 141 NOTES RECEIVABLE 224 142 CUSTOMER ACCOUNTS RECEIVABLE 7,576 143 OTHER ACCOUNTS RECEIVABLE 757 146 ACCOUNTS RECEIVABLE FROM ASSOCIATED COS 1,268 151 FUEL STOCK 22,684 152 FUEL STOCK EXPENSES UNDISTRIBUTED 158 154 PLANT MATERIALS AND OPERATING SUPPLIES 43,335 163 STORES EXPENSE UNDISTRIBUTED 680 165 PREPAYMENTS 11,451 174 MISCELLANEOUS CURRENT AND ACCRUED ASSETS 481,204 181 UNAMORTIZED DEBT EXPENSE 9,760 184 CLEARING ACCOUNTS 132 186 MISCELLANEOUS DEFERRED DEBITS 3,291 190 ACCUMULATED DEFERRED INCOME TAXES 55,796 108 ACCUM PROVISION FOR DEPRECIATION AND DEPL l,445,891 120.5 ACCUM PROVISION FOR AMORTIZATION OF NUCLEAR FUEL 204,952 122 ACCUM PROVISION FOR DEPRECIATION AND DEPL 1,197 201-226 COMMON STOCK/OTH PAID IN CAPITAL/LONG-TERM DEBT 386,126 228.1 ACCUM PROVISION FOR PROPERTY INSURANCE 1,814 228.3 ACCUM PROVISION FOR PENSIONS AND BENEFITS 788 228.4 ACCUM MISCELLANEOUS OPERATING PROVISIONS 2,683 232 ACCOUNTS PAYABLE 114,139 233 NOTES PAYABLE TO ASSOCIATED COMPANIES 186,059 234 ACCOUNTS PAYABLE TO ASSOCIATED COMPANIES 42,649 236 TAXES ACCRUED 36,458 237 INTEREST ACCRUED 19,252 241 TAX COLLECTIONS PAYABLE 34 242 MISC CURRENT AND ACCRUED LIABILITIES 494,983 253 OTHER DEFERRED CREDITS 65,907 255 ACCUMULATED DEFERRED INVESTMENT TAX CREDITS 113,531 281-283 ACCUMULATED DEFERRED INCOME TAXES 901,830
TO RECORD THE CREATION OF A GENCO SUBSIDIARY OF CENTRAL POWER AND LIGHT COMPANY. AMERICAN ELECTRIC POWER SERVICE CORPORATION Schedule H-14 FERC DOCKET NO. EC01-________ Page 1 of 1 TRANSFER OF JURISDICTIONAL ASSETS SECTION 5, PART C JOURNAL ENTRIES TRANSFER OF CENTRAL POWER AND LIGHT COMPANY ASSETS (IN $ THOUSANDS BASED ON 12/31/2000 ESTIMATED AMOUNTS) C. TO BE RECORDED ON THE BOOKS OF AEP COMPANY, INC.: -------------------------------------------------
DIVIDEND OF GENCO ----------------- ACCOUNT DESCRIPTION DR CR ------- ----------- -- -- 171 DIVIDENDS RECEIVABLE - AFFILIATED XXX,XXX 123.1 INVESTMENT IN SUB COS - CSW CORP XXX,XXX TO RECORD A DIVIDEND RECEIVABLE FROM CENTRAL AND SOUTH WEST CORPORATION EQUAL TO THE NET ASSETS OF THE CENTRAL POWER AND LIGHT COMPANY GENCO SUBSIDIARY. INVESTMENT IN GENCO ------------------- ACCOUNT DESCRIPTION DR CR ------- ----------- -- -- 123.1 INVESTMENT IN SUBSIDIARY COS - CPL GENCO XXX,XXX 171 DIVIDENDS RECEIVABLE XXX,XXX TO RECORD THE INVESTMENT IN CENTRAL POWER AND LIGHT GENCO IN SETTLEMENT OF THE DIVIDEND PAYABLE FROM CENTRAL AND SOUTH WEST CORPORATION. CONTRIBUTE GENCO TO NON-REGULATED HOLDCO ---------------------------------------- ACCOUNT DESCRIPTION DR CR ------- ----------- -- -- 123.1 INVESTMENT IN SUBSIDIARY COS - AEP NON-REG HOLDCO XXX,XXX 123.1 INVESTMENT IN SUBSIDIARY COS - CPL GENCO XXX,XXX TO RECORD CONTRIBUTION OF CENTRAL POWER AND LIGHT GENCO TO THE NON-REGULATED HOLDCO.
AMERICAN ELECTRIC POWER SERVICE CORPORATION Schedule H-15 FERC DOCKET NO. EC01-________ Page 1 of 1 TRANSFER OF JURISDICTIONAL ASSETS SECTION 5, PART C JOURNAL ENTRIES TRANSFER OF CENTRAL POWER AND LIGHT COMPANY ASSETS (IN $ THOUSANDS BASED ON 12/31/2000 ESTIMATED AMOUNTS) D. TO BE RECORDED ON THE BOOKS OF AEP NON-REGULATED HOLDCO: -------------------------------------------------------
CONTRIBUTION OF GENCO --------------------- ACCOUNT DESCRIPTION DR CR ------- ----------- -- -- 123-1 INVESTMENT IN SUBSIDIARY COS - CPL GENCO XXX,XXX 201,208-211 COMMON STOCK - OTHER PAID IN CAPITAL XXX,XXX TO RECORD AEP'S CONTRIBUTION OF ITS INVESTMENT IN THE CENTRAL POWER AND LIGHT GENCO TO AEFS NON-REGULATED HOLDCO.
AMERICAN ELECTRIC POWER SERVICE CORPORATION Schedule H-16 FERC DOCKET NO. EC01-__________ Page 1 of 2 TRANSFER OF JURISDICTIONAL ASSETS SECTION 5, PART C JOURNAL ENTRIES TRANSFER OF COLUMBUS SOUTHERN POWER COMPANY ASSETS (IN $ THOUSANDS BASED ON 12/31/2000 ESTIMATED AMOUNTS) A. TO BE RECORDED ON THE BOOKS OF COLUMBUS SOUTHERN POWER COMPANY: ---------------------------------------------------------------
CREATE WIRESCO SUBSIDIARY ------------------------- ACCOUNT DESCRIPTION DR CR ------- ----------- -- -- 108 ACCUM PROVISION FOR DEPRECIATION AND DEPL 122 ACCUM PROVISION FOR DEPRECIATION AND DEPL 535 123.1&221-226 INV IN SUBS COS & LONG-TERM DEBT 1,015,584 144 ACCUM PROVISION FOR UNCOLLECTIBLE ACCOUNTS 24 227 OBLIGATIONS UNDER CAPITAL LEASE 22,374 228.2 ACCUM PROVISION FOR INJURIES AND DAMAGES 0 228.3 ACCUM PROVISION FOR PENSIONS AND BENEFITS 4,005 228.4 ACCUM MISCELLANEOUS OPERATING PROVISIONS 4,815 232 ACCOUNTS PAYABLE 9,239 233 NOTES PAYABLE TO ASSOCIATED COMPANIES 33,583 234 ACCOUNTS PAYABLE TO ASSOCIATED COMPANIES 24,951 235 CUSTOMER DEPOSITS 4,851 236 TAXES ACCRUED 70,150 237 INTEREST ACCRUED 5,330 241 TAX COLLECTIONS PAYABLE 640 242 MISC CURRENT AND ACCRUED LIABILITIES 20,309 243 OBLIGATIONS UNDER CAPITAL LEASE - CURRENT 4,804 252 CUSTOMER ADVANCES FOR CONSTRUCTION 775 253 OTHER DEFERRED CREDITS 92 254 OTHER REGULATORY LIABILITIES 30,384 255 ACCUMULATED DEFERRED INVESTMENT TAX CREDITS 14,086 281-283 ACCUMULATED DEFERRED INCOME TAXES 174,442 101-106,114 UTILITY PLANT 1,542,642 107 CONSTRUCTION WORK IN PROGRESS 69,715 121 NONUTILITY PROPERTY 8,986 124 OTHER INVESTMENTS 12,861 125-128 SPECIAL FUNDS 13 131 CASH 3,730 132-134 SPECIAL DEPOSITS 10 135 WORKING FUND 543 141 NOTES RECEIVABLE 1 142 CUSTOMER ACCOUNTS RECEIVABLE 1,989 143 OTHER ACCOUNTS RECEIVABLE 5,462 146 ACCOUNTS RECEIVABLE FROM ASSOCIATED COS 6,943 154 PLANT MATERIALS AND OPERATING SUPPLIES 5,023 165 PREPAYMENTS 15,090 172 RENTS RECEIVABLE 78 173 UNBILLED REVENUE 2,273 174 MISCELLANEOUS CURRENT AND ACCRUED ASSETS 11,185 181 UNAMORTIZED DEBT EXPENSE 237 182.3 OTHER REGULATORY ASSETS 301,764 183 PRELIM SURVEY AND INVESTIGATION CHARGES 5 184 CLEARING ACCOUNTS 392 185 TEMPORARY FACILITIES 11 186 MISCELLANEOUS DEFERRED DEBITS 33,415 189 UNAMORTIZED LOSS ON REACQUIRED DEBT 8,339 190 ACCUMULATED DEFERRED INCOME TAXES 32,461
TO RECORD THE CREATION OF A WIRESCO SUBSIDIARY OF COLUMBUS SOUTHERN POWER COMPANY. AMERICAN ELECTRIC POWER SERVICE CORPORATION Schedule H-16 FERC DOCKET NO. EC01-________ Page 2 of 2 TRANSFER OF JURISDICTIONAL ASSETS SECTION 5, PART C JOURNAL ENTRIES TRANSFER OF COLUMBUS SOUTHERN POWER COMPANY ASSETS (IN $ THOUSANDS BASED ON 12/31/2000 ESTIMATED AMOUNTS) A. TO BE RECORDED ON THE BOOKS OF COLUMBUS SOUTHERN POWER COMPANY. --------------------------------------------------------------
DIVIDEND WIRESCO SUBSIDIARY TO AEP, INC --------------------------------------- ACCOUNT DESCRIPTION DR CR -------- ----------- -- -- 207 PREMIUM ON CAPITAL STOCK XXX,XXX 208-211 PAID-IN CAPITAL XXX,XXX 438 DIVIDENDS DECLARED - RET EARNINGS XXX,XXX 238 DIVIDENDS DECLARED - LIABILITY XXX,XXX TO RECORD THE DECLARATION OF A DIVIDEND FROM COLUMBUS SOUTHERN POWER COMPANY TO THE AEP CO., INC. FOR THE NET ASSETS OF THE COLUMBUS SOUTHERN POWER COMPANY WIRESCO SUBSIDIARY. TRANSFER WIRESCO INVESTMENT TO AEP. INC --------------------------------------- ACCOUNT DESCRIPTION DR CR -------- ----------- -- -- 238 DIVIDENDS DECLARED - LIABILITY XXX,XXX 123.1 INVESTMENT IN SUBSIDIARY COS - CSP WIRESCO XXX,XXX TO RECORD THE TRANSFER OF THE INVESTMENT OF COLUMBUS SOUTHERN POWER COMPANY IN WIRESCO TO AEP, CO., INC. TO SATISFY THE DIVIDEND DECLARATION. CLOSE DIVIDEND TO RETAINED EARNINGS ----------------------------------- ACCOUNT DESCRIPTION DR CR -------- ----------- -- -- 216 RETAINED EARNINGS XXX,XXX 438 DIVIDENDS DECLARED XXX,XXX TO CLOSE THE DIVIDEND DECLARATION ON COLUMBUS SOUTHERN POWER COMPANY TO RETAINED EARNINGS.
AMERICAN ELECTRIC POWER SERVICE CORPORATION Schedule H-17 FERC DOCKET NO. EC01-_________ Page 1 of 1 TRANSFER OF JURISDICTIONAL ASSETS SECTION 5, PART C JOURNAL ENTRIES TRANSFER OF COLUMBUS SOUTHERN POWER COMPANY ASSETS (IN $ THOUSANDS BASED ON 12/31/2000 ESTIMATED AMOUNTS) B. TO BE RECORDED ON THE BOOKS OF COLUMBUS SOUTHERN WIRESCO: ---------------------------------------------------------
CREATE WIRESCO SUBSIDIARY ------------------------- ACCOUNT DESCRIPTION DR CR -------- ----------- -- -- 101-406,114 UTILITY PLANT 1,542,642 107 CONSTRUCTION WORK IN PROGRESS 69,715 121 NONUTILITY PROPERTY 81986 124 OTHER INVESTMENTS 12,881 125-128 SPECIAL FUNDS 13 131 CASH 3,730 132-134 SPECIAL DEPOSITS 10 135 WORKING FUND 543 141 NOTES RECEIVABLE 1 142 CUSTOMER ACCOUNTS RECEIVABLE 1,989 143 OTHER ACCOUNTS RECEIVABLE 5,462 146 ACCOUNTS RECEIVABLE FROM ASSOCIATED COS 6,943 154 PLANT MATERIALS AND OPERATING SUPPLIES 5,023 165 PREPAYMENTS 15,090 172 RENTS RECEIVABLE 78 173 UNBILLED REVENUE 2,273 174 MISCELLANEOUS CURRENT AND ACCRUED ASSETS 11,135 181 UNAMORTIZED DEBT EXPENSE 237 182.3 OTHER REGULATORY ASSETS 301,764 183 PRELIM SURVEY AND INVESTIGATION CHARGES 5 184 CLEARING ACCOUNTS 392 185 TEMPORARY FACILITIES 11 186 MISCELLANEOUS DEFERRED DEBITS 33,415 189 UNAMORTIZED LOSS ON REACQUIRED DEBT 8,339 190 ACCUMULATED DEFERRED INCOME TAXES 32,461 108 ACCUM PROVISION FOR DEPRECIATION AND DEPL 622,195 122 ACCUM PROVISION FOR DEPRECIATION AND DEPL 535 144 ACCUM PROVISION FOR UNCOLLECTIBLE ACCOUNTS 24 201-226 COMMON STOCK/OTH PAID IN CAPITAL/LONG-TERM DEBT 1,015,584 227 OBLIGATIONS UNDER CAPITAL LEASE 22,374 228.2 ACCUM PROVISION FOR INJURIES AND DAMAGES 0 228.3 ACCUM PROVISION FOR PENSIONS AND BENEFITS 4,005 228.4 ACCUM MISCELLANEOUS OPERATING PROVISIONS 4,815 232 ACCOUNTS PAYABLE 9,239 233 NOTES PAYABLE TO ASSOCIATED COMPANIES 33,583 234 ACCOUNTS PAYABLE TO ASSOCIATED COMPANIES 24,951 235 CUSTOMER DEPOSITS 4,051 236 TAXES ACCRUED 70,150 237 INTEREST ACCRUED 5,330 241 TAX COLLECTIONS PAYABLE 640 242 MISC CURRENT AND ACCRUED LIABILITIES 20,309 243 OBLIGATIONS UNDER CAPITAL LEASE - CURRENT 4,804 252 CUSTOMER ADVANCES FOR CONSTRUCTION 775 253 OTHER DEFERRED CREDITS 92 254 OTHER REGULATORY LIABILITIES 30,384 255 ACCUMULATED DEFERRED INVESTMENT TAX CREDITS 14,086 281-283 ACCUMULATED DEFERRED INCOME TAXES 174,442 TO RECORD THE CREATION OF A WIRESCO SUBSIDIARY OF COLUMBUS SOUTHERN POWER COMPANY.
AMERICAN ELECTRIC POWER SERVICE CORPORATION Schedule H-18 FERC DOCKET NO. EC01-__________ Page 1 of 1 TRANSFER OF JURISDICTIONAL ASSETS SECTION 5, PART C JOURNAL ENTRIES TRANSFER OF COLUMBUS SOUTHERN POWER COMPANY ASSETS (IN $ THOUSANDS BASED ON 12/31/2000 ESTIMATED AMOUNTS) C. TO BE RECORDED ON THE BOOKS OF AEP COMPANY, INC.: -------------------------------------------------
DIVIDEND OF WIRESCO ------------------- ACCOUNT DESCRIPTION DR CR ------- ----------- -- -- 171 DIVIDENDS RECEIVABLE - AFFILIATED XXX,XXX 123.1 INVESTMENT IN SUB COS - COLUMBUS SOUTHERN POWER XXX,XXX TO RECORD A DIVIDEND RECEIVABLE FROM COLUMBUS SOUTHERN POWER COMPANY EQUAL TO THE NET ASSETS OF THE COLUMBUS SOUTHERN POWER COMPANY WIRESCO, SUBSIDIARY. INVESTMENT IN WIRESCO --------------------- ACCOUNT DESCRIPTION DR CR ------- ----------- -- -- 123.1 INVESTMENT IN SUBSIDIARY COS - CSP WIRESCO XXX,XXX 171 DIVIDENDS RECEIVABLE XXX,XXX TO RECORD THE INVESTMENT IN COLUMBUS SOUTHERN POWER WIRESCO IN SETTLEMENT OF THE DIVIDEND PAYABLE FROM COLUMBUS SOUTHERN POWER COMPANY. CONTRIBUTE WIRESCO TO CENTRAL SOUTH WEST CORPORATION ---------------------------------------------------- ACCOUNT DESCRIPTION DR CR ------- ----------- -- -- 123.1 INVESTMENT IN SUBSIDIARY COS - CSW CORP XXX,XXX 123.1 INVESTMENT IN SUBSIDIARY COS - CSP WIRESCO XXX,XXX TO RECORD CONTRIBUTION OF COLUMBUS SOUTHERN POWER WIRESCO TO THE REGULATED HOLDING COMPANY, CENTRAL AND SOUTH WEST CORPORATION. CONTRIBUTE GENCO TO NON-REGULATED HOLDCO ---------------------------------------- ACCOUNT DESCRIPTION DR CR ------- ----------- -- -- 123.1 INVESTMENT IN SUBSIDIARY COS - AEP NON-REG HOLDCO XXX,XXX 123.1 INVESTMENT IN SUBSIDIARY COS - CSP GENCO XXX,XXX TO RECORD CONTRIBUTION OF COLUMBUS SOUTHERN POWER GENCO TO THE NON-REGULATED HOLDCO.
AMERICAN ELECTRIC POWER SERVICE CORPORATION Schedule H-19 FERC DOCKET NO. EC01-_________ Page 1 of 1 TRANSFER OF JURISDICTIONAL ASSETS SECTION 5, PART C JOURNAL ENTRIES TRANSFER OF COLUMBUS SOUTHERN POWER COMPANY ASSETS (IN $ THOUSANDS BASED ON 12/31/2000 ESTIMATED AMOUNTS) D. TO BE RECORDED ON THE BOOKS OF CENTRAL AND SOUTH WEST CORPORATION: ------------------------------------------------------------------
CONTRIBUTION OF WIRESCO ----------------------- ACCOUNT DESCRIPTION DR CR ------- ----------- -- -- 123.1 INVESTMENT IN SUBSIDIARY COS - CSP WIRESCO XXX,XXX 201,208-211 COMMON STOCK - OTHER PAID IN CAPITAL XXX,XXX TO RECORD AEP'S CONTRIBUTION OF ITS INVESTMENT IN THE COLUMBUS SOUTHERN POWER WIRES COMPANY TO AEP'S REGULATED HOLDING COMPANY, CENTRAL AND SOUTH WEST CORPORATION.
AMERICAN ELECTRIC POWER SERVICE CORPORATION Schedule H-20 FERC DOCKET NO. EC01-__________ Page 1 of 1 TRANSFER OF JURISDICTIONAL ASSETS SECTION 5, PART C JOURNAL ENTRIES TRANSFER OF COLUMBUS SOUTHERN POWER COMPANY ASSETS (IN $ THOUSANDS BASED ON 12/31/2000 ESTIMATED AMOUNTS) E. TO BE RECORDED ON THE BOOKS OF AEP NON-REGULATED HOLDCO: --------------------------------------------------------
CONTRIBUTION OF GENCO --------------------- ACCOUNT DESCRIPTION DR CR ------- ----------- -- -- 123.1 INVESTMENT IN SUBSIDIARY COS - CSP GENCO XXX,XXX 201,208-211 COMMON STOCK - OTHER PAID IN CAPITAL XXX,XXX TO RECORD AEP'S CONTRIBUTION OF ITS INVESTMENT IN THE COLUMBUS SOUTHERN POWER GENCO TO AEP'S NON-REGULATED HOLDCO.
AMERICAN ELECTRIC POWER SERVICE CORPORATION Schedule H-21 FERC DOCKET NO. EC01-________ Page 1 of 2 TRANSFER OF JURISDICTIONAL ASSETS SECTION 5, PART C JOURNAL ENTRIES TRANSFER OF OHIO POWER COMPANY ASSETS (IN $ MILLIONS $ THOUSANDS BASED ON 12/31/2000 ESTIMATED AMOUNTS) A. TO BE RECORDED ON THE BOOKS OF OHIO POWER COMPANY: --------------------------------------------------
CREATE WIRESCO SUBSIDIARY ------------------------- ACCOUNT DESCRIPTION DR CR ------- ----------- -- -- 108 ACCUM PROVISION FOR DEPRECIATION AND DEPL 697,041 122 ACCUM PROVISION FOR DEPRECIATION AND DEPL 2,266 123.1&221-226 INV IN SUBS COS & LONG-TERM DEBT 1,694,976 144 ACCUM PROVISION FOR UNCOLLECTIBLE ACCOUNTS 32 227 OBLIGATIONS UNDER CAPITAL LEASE 10,224 228.2 ACCUM PROVISION FOR INJURIES AND DAMAGES 10 228.3 ACCUM PROVISION FOR PENSIONS AND BENEFITS 61950 228.4 ACCUM MISCELLANEOUS OPERATING PROVISIONS 5.117 232 ACCOUNTS PAYABLE 20,697 233 NOTES PAYABLE TO ASSOCIATED COMPANIES 41,471 234 ACCOUNTS PAYABLE TO ASSOCIATED COMPANIES 60,364 235 CUSTOMER DEPOSITS 4,623 236 TAXES ACCRUED 74,080 237 INTEREST ACCRUED 4,456 241 TAX COLLECTIONS PAYABLE 953 242 MISC CURRENT AND ACCRUED LIABILITIES 32,087 243 OBLIGATIONS UNDER CAPITAL LEASE - CURRENT 1,812 252 CUSTOMER ADVANCES FOR CONSTRUCTION 0 253 OTHER DEFERRED CREDITS 865 254 OTHER REGULATORY LIABILITIES 39,497 255 ACCUMULATED DEFERRED INVESTMENT TAX CREDITS 10,050 281-283 ACCUMULATED DEFERRED INCOME TAXES 223,310 101-106,114 UTILITY PLANT 1,985,035 107 CONSTRUCTION WORK IN PROGRESS 41,449 121 NONUTILITY PROPERTY 4,072 124 OTHER INVESTMENTS 9,788 125-128 SPECIAL FUNDS 16 131 CASH 2,129 132-134 SPECIAL DEPOSITS 152 135 WORKING FUND 11 141 NOTES RECEIVABLE 18 142 CUSTOMER ACCOUNTS RECEIVABLE 8,439 143 OTHER ACCOUNTS RECEIVABLE 6,179 146 ACCOUNTS RECEIVABLE FROM ASSOCIATED COS 18,138 154 PLANT MATERIALS AND OPERATING SUPPLIES 9,680 165 PREPAYMENTS 11,800 172 RENTS RECEIVABLE 98 173 UNBILLED REVENUE 48 174 MISCELLANEOUS CURRENT AND ACCRUED ASSETS 1,704 181 UNAMORTIZED DEBT EXPENSE 262 182.3 OTHER REGULATORY ASSETS 748,089 183 PRELIM SURVEY AND INVESTIGATION CHARGES 1 184 CLEARING ACCOUNTS 352 185 TEMPORARY FACILITIES 5 186 MISCELLANEOUS DEFERRED DEBITS 39,396 189 UNAMORTIZED LOSS ON REACQUIRED DEBT 6,106 190 ACCUMULATED DEFERRED INCOME TAXES 37,904 TO RECORD THE CREATION OF A WIRESCO SUBSIDIARY OF OHIO POWER COMPANY.
AMERICAN ELECTRIC POWER SERVICE CORPORATION Schedule H-21 FERC DOCKET NO. EC01-_________ Page 2 of 2 TRANSFER OF JURISDICTIONAL ASSETS SECTION 5, PART C JOURNAL ENTRIES TRANSFER OF OHIO POWER COMPANY ASSETS (IN $ MILLIONS $ THOUSANDS BASED ON 12/31/2000 ESTIMATED AMOUNTS) A. TO BE RECORDED ON THE B0OKS OF OHIO POWER COMPANY: ---------------------------------------------------
DIVIDEND WIRESCO SUBSIDIARY TO AEP, INC --------------------------------------- ACCOUNT DESCRIPTION DR CR ------- ------------ -- -- 208-211 PAID-IN CAPITAL XXX,XXX 438 DIVIDENDS DECLARED - RET EARNINGS XXX,XXX 238 DIVIDENDS DECLARED - LIABILITY XXX,XXX TO RECORD THE DECLARATION OF A DIVIDEND FROM OHIO POWER COMPANY TO THE AEP CO., INC. FOR THE NET ASSETS OF THE OHIO POWER COMPANY WIRESCO SUBSIDIARY. TRANSFER WIRESCO INVESTMENT TO AEP, INC --------------------------------------- ACCOUNT DESCRIPTION DR CR ------- ------------ -- -- 238 DIVIDENDS DECLARED - LIABILITY XXX,XXX 123.1 INVESTMENT IN SUBSIDIARY COS - OPCO WIRESCO XXX,XXX TO RECORD THE TRANSFER OF THE INVESTMENT OF OHIO POWER COMPANY IN WIRESCO TO AEP, CO., INC. TO SATISFY THE DIVIDEND DECLARATION. CLOSE DIVIDEND TO RETAINED EARNINGS ----------------------------------- ACCOUNT DESCRIPTION DR CR ------- ------------ -- -- 216 RETAINED EARNINGS XXX,XXX 438 DIVIDENDS DECLARED XXX,XXX TO CLOSE THE DIVIDEND DECLARATION ON OHIO POWER COMPANY TO RETAINED EARNINGS.
AMERICAN ELECTRIC POWER SERVICE CORPORATION Schedule H-22 FERC DOCKET NO. EC01-____________ Page 1 of 1 TRANSFER OF JURISDICTIONAL ASSETS SECTION 5, PART C JOURNAL ENTRIES TRANSFER OF OHIO POWER COMPANY ASSETS (IN $ MILLIONS $ THOUSANDS BASED ON 12/31/2000 ESTIMATED AMOUNTS) B. TO BE RECORDED ON THE BOOKS OF OHIO POWER WIRESCO: --------------------------------------------------
CREATE WIRESCO SUBSIDIARY ------------------------- ACCOUNT DESCRIPTION DR CR ------- ----------- -- -- 101-106, 114 UTILITY PLANT 1,985,035 107 CONSTRUCTION WORK IN PROGRESS 41,449 121 NONUTILITY PROPERTY 4,072 124 OTHER INVESTMENTS 9,788 125-128 SPECIAL FUNDS 16 131 CASH 2,129 132-134 SPECIAL DEPOSITS 152 135 WORKING FUND 11 141 NOTES RECEIVABLE 18 142 CUSTOMER ACCOUNTS RECEIVABLE 8,439 143 OTHER ACCOUNTS RECEIVABLE 6,179 146 ACCOUNTS RECEIVABLE FROM ASSOCIATED COS 18,138 154 PLANT MATERIALS AND OPERATING SUPPLIES 9,680 165 PREPAYMENTS 11,800 172 RENTS RECEIVABLE 98 173 UNBILLED REVENUE 48 174 MISCELLANEOUS CURRENT AND ACCRUED ASSETS 1,704 181 UNAMORTIZED DEBT EXPENSE 262 182.3 OTHER REGULATORY ASSETS 748,089 183 PRELIM SURVEY AND INVESTIGATION CHARGES 1 184 CLEARING ACCOUNTS 352 185 TEMPORARY FACILITIES 5 186 MISCELLANEOUS DEFERRED DEBITS 39,396 189 UNAMORTIZED LOSS ON REACQUIRED DEBT 6,106 190 ACCUMULATED DEFERRED INCOME TAXES 37,904 108 ACCUM PROVISION FOR DEPRECIATION AND DEPL 697,041 122 ACCUM PROVISION FOR DEPRECIATION AND DEPL 2,266 144 ACCUM PROVISION FOR UNCOLLECTIBLE ACCOUNTS 32 201-226 COMMON STOCK/OTH PAID IN CAPITAL/LONG-TERM DEBT 1,694,976 227 OBLIGATIONS UNDER CAPITAL LEASE 10,224 228.2 ACCUM PROVISION FOR INJURIES AND DAMAGES 10 228.3 ACCUM PROVISION FOR PENSIONS AND BENEFITS 6,950 228.4 ACCUM MISCELLANEOUS OPERATING PROVISIONS 5,117 232 ACCOUNTS PAYABLE 20,697 233 NOTES PAYABLE TO ASSOCIATED COMPANIES 41,471 234 ACCOUNTS PAYABLE TO ASSOCIATED COMPANIES 60,354 235 CUSTOMER DEPOSITS 4,523 236 TAXES ACCRUED 74,080 237 INTEREST ACCRUED 4,456 241 TAX COLLECTIONS PAYABLE 953 242 MISC CURRENT AND ACCRUED LIAABILITIES 32,087 243 OBLIGATIONS UNDER CAPITAL LEASE - CURRENT 1,812 252 CUSTOMER ADVANCES FOR CONSTRUCTION 0 253 OTHER DEFERRED CREDITS 865 254 OTHER REGULATORY LIABILITIES 39,497 255 ACCUMULATED DEFERRED INVESTMENT TAX CREDITS 10,050 281-283 ACCUMULATED DEFERRED INCOME TAXES 223,310 TO RECORD THE CREATION OF A WIRESCO SUBSIDIARY OF OHIO POWER COMPANY.
AMERICAN ELECTRIC POWER SERVICE CORPORATION Schedule H-23 FERC DOCKET NO. EC01-________ Page 1 of 1 TRANSFER OF JURISDICTIONAL ASSETS SECTION 5, PART C JOURNAL ENTRIES TRANSFER OF OHIO POWER COMPANY ASSETS (IN $ MILLIONS $ THOUSANDS BASED ON 12/31/2000 ESTIMATED AMOUNTS) C. TO BE RECORDED ON THE BOOKS OF AEP COMPANY, INC.: -------------------------------------------------
DIVIDEND OF WIRESCO ------------------- ACCOUNT DESCRIPTION DR CR ------- ----------- -- -- 171 DIVIDENDS RECEIVABLE - AFFILIATED XXX,XXX 123.1 INVESTMENT IN SUB COS - OHIO POWER XXX,XXXX TO RECORD A DIVIDEND RECEIVABLE FROM OHIO POWER COMPANY EQUAL TO THE NET ASSETS OF THE OHIO POWER COMPANY WIRESCO SUBSIDIARY. INVESTMENT IN WIRESCO --------------------- ACCOUNT DESCRIPTION DR CR ------- ----------- -- -- 123.1 INVESTMENT IN SUBSIDIARY COS - OPCO WIRESCO XXX,XXX 171 DIVIDENDS RECEIVABLE XXX,XXX TO RECORD THE INVESTMENT IN OHIO POWER WIRESCO IN SETTLEMENT OF THE DIVIDEND PAYABLE FROM OHIO POWER COMPANY. CONTRIBUTE WIRESCO TO CENTRAL AND SOUTH WEST CORPORATION -------------------------------------------------------- ACCOUNT DESCRIPTION DR CR ------- ----------- -- -- 123.1 INVESTMENT IN SUBSIDIARY COS - CSW CORP XXX,XXX 123.1 INVESTMENT IN SUBSIDIARY COS - OPCO WIRESCO XXX,XXX TO RECORD CONTRIBUTION OF OHIO POWER WIRESCO TO THE REGULATED HOLDING COMPANY, CENTRAL AND SOUTH WEST CORPORATION. CONTRIBUTE GENCO TO NON-REGULATED HOLDCO ---------------------------------------- ACCOUNT DESCRIPTION DR CR ------- ----------- -- -- 123.1 INVESTMENT IN SUBSIDIARY COS - AEP NON-REG HOLDCO XXX,XXX 123.1 INVESTMENT IN SUBSIDIARY COS - OPCO GENCO XXX,XXX TO RECORD CONTRIBUTION OF OHIO POWER GENCO TO THE NON-REGULATED HOLDCO
AMERICAN ELECTRIC POWER SERVICE CORPORATION Schedule H-24 FERC DOCKET NO. EC01-________ Page 1 of 1 TRANSFER OF JURISDICTIONAL ASSETS SECTION 5, PART C JOURNAL ENTRIES TRANSFER OF OHIO POWER COMPANY ASSETS (IN $ MILLIONS $ THOUSANDS BASED ON 12/31/2000 ESTIMATED AMOUNTS) D. TO BE RECORDED ON THE BOOKS OF CENTRAL AND SOUTH WEST CORPORATION: ------------------------------------------------------------------
CONTRIBUTION OF WIRESCO ----------------------- ACCOUNT DESCRIPTION DR CR ------- ----------- -- -- 123.1 INVESTMENT IN SUBSIDIARY COS - OPCO WIRESCO XXX,XXX 201,208-211 COMMON STOCK - OTHER PAID IN CAPITAL XXX,XXX TO RECORD AEP'S CONTRIBUTION OF ITS INVESTMENT IN THE OHIO POWER WIRES COMPANY TO AEP'S REGULATED HOLDING COMPANY, CENTRAL AND SOUTH WEST CORPORATION.
AMERICAN ELECTRIC POWER SERVICE CORPORATION Schedule H-25 FERC DOCKET NO. EC01-________ Page 1 of 1 TRANSFER OF JURISDICTIONAL ASSETS SECTION 5, PART C JOURNAL ENTRIES TRANSFER OF OHIO POWER COMPANY ASSETS (IN $ MILLIONS $ THOUSANDS BASED ON 12/31/2000 ESTIMATED AMOUNTS) E. TO BE RECORDED ON THE BOOKS OF AEP NON-REGULATED HOLDCO: --------------------------------------------------------
CONTRIBUTION OF GENCO --------------------- ACCOUNT DESCRIPTION DR CR ------- ------------ -- -- 123.1 INVESTMENT IN SUBSIDIARY COS - OPCO GENCO XXX,XXX 201,208-211 COMMON STOCK - OTHER PAID IN CAPITAL XXX,XXX TO RECORD AEP'S CONTRIBUTION OF ITS INVESTMENT IN THE OHIO POWER GENCO TO AEP'S NON-REGULATED HOLDCO.
AMERICAN ELECTRIC POWER SERVICE CORPORATION Schedule H-26 FERC DOCKET NO. EC01 -__________ Page 1 of 2 TRANSFER OF JURISDICTIONAL ASSETS SECTION 5, PART C JOURNAL ENTRIES TRANSFER OF SOUTHWESTERN ELECTRIC POWER COMPANY ASSETS (IN $ THOUSANDS BASED ON 12/31/2000 ESTIMATED AMOUNTS) A. TO 13E RECORDED ON THE BOOKS OF SOUTHWESTERN ELECTRIC POWER COMPANY: --------------------------------------------------------------------
CREATE TEXAS WIRESCO SUBSIDIARY ------------------------------- ACCOUNT DESCRIPTION DR CR ------- ----------- -- -- 108 ACCUM PROVISION FOR DEPRECIATION AND DEPL 278,417 123.1&221-228 INV IN SUBS COS & LONG-TERM DEBT 457,590 228.3 ACCUM PROVISION FOR PENSIONS AND BENEFITS 1,012 232 ACCOUNTS PAYABLE 59,713 233 NOTES PAYABLE TO ASSOCIATED COMPANIES 4,381 234 ACCOUNTS PAYABLE TO ASSOCIATED COMPANIES 7,098 235 CUSTOMER DEPOSITS 6,648 236 TAXES ACCRUED 6,887 237 INTEREST ACCRUED 4,820 241 TAX COLLECTIONS PAYABLE 712 242 MISC CURRENT AND ACCRUED LIABILITIES 2,986 254 OTHER REGULATORY LIABILITIES 19,016 255 ACCUMULATED DEFERRED INVESTMENT TAX CREDITS 12,778 257 UNAMORTIZED GAIN ON REACQUIRED DEBT 151 281-283 ACCUMULATED DEFERRED INCOME TAXES 101,516 101-106,114 UTILITY PLANT 809,018 107 CONSTRUCTION WORK IN PROGRESS 17,683 121 NONUTILITY PROPERTY 113 124 OTHER INVESTMENTS 845 131 CASH 110 132-134 SPECIAL DEPOSITS 315 135 WORKING FUND 35 142 CUSTOMER ACCOUNTS RECEIVABLE 2,314 143 OTHER ACCOUNTS RECEIVABLE 1,022 146 ACCOUNTS RECEIVABLE FROM ASSOCIATED COS 0 154 PLANT MATERIALS AND OPERATING SUPPLIES 2,427 165 PREPAYMENTS 13,768 171 INTEREST AND DIVIDENDS RECEIVABLE 95 172 RENTS RECEIVABLE 109 173 UNBILLED REVENUE 1,186 174 MISCELLANEOUS CURRENT AND ACCRUED ASSETS 0 181 UNAMORTIZED DEBT EXPENSE 1,326 182.3 OTHER REGULATORY ASSETS 16,654 184 CLEARING ACCOUNTS 436 186 MISCELLANEOUS DEFERRED DEBITS 20,237 189 UNAMORTIZED LOSS ON REACQUIRED DEBT 10,314 190 ACCUMULATED DEFERRED INCOME TAXES 11,981 TO RECORD THE CREATION OF A WIRESCO SUBSIDIARY OF SOUTHWESTERN ELECTRIC POWER COMPANY.
AMERICAN ELECTRIC POWER SERVICE CORPORATION Schedule H-26 FERC DOCKET NO. EC01 -_____________ Page 2 of 2 TRANSFER OF JURISDICTIONAL ASSETS SECTION 5, PART C JOURNAL ENTRIES TRANSFER OF SOUTHWESTERN ELECTRIC POWER COMPANY ASSETS (IN $ THOUSANDS BASED ON 12/31/2000 ESTIMATED AMOUNTS) A. TO BE RECORDED ON THE BOOKS OF SOUTHWESTERN ELECTRIC POWER COMPANY: -------------------------------------------------------------------
DIVIDEND TEXAS WIRESCO SUBSIDIARY TO CENTRAL AND SOUTH WEST CORPORATION ----------------------------------------------------------------------- ACCOUNT DESCRIPTION DR CR ------- ----------- -- -- 438 DIVIDENDS DECLARED - RET EARNINGS XXX,XXX 238 DIVIDENDS DECLARED - LIABILITY XXX,XXX TO RECORD THE DECLARATION OF A DIVIDEND FROM SOUTHWESTERN ELECTRIC POWER COMPANY TO CENTRAL AND SOUTH WEST CORPORATION FOR THE NET ASSETS OF THE SOUTHWESTERN ELECTRIC POWER COMPANY TEXAS WIRESCO SUBSIDIARY. TRANSFER TEXAS WIRESCO, INVESTMENT TO CENTRAL AND SOUTH WEST CORPORATION ------------------------------------------------------------------------ ACCOUNT DESCRIPTION DR CR ------- ----------- -- -- 238 DIVIDENDS DECLARED - LIABILITY XXX,XXX 123.1 INVESTMENT IN SUBSIDIARY COS - SWEPCO TEXAS WIRESCO XXX,XXX TO RECORD THE TRANSFER OF THE INVESTMENT OF SOUTHWESTERN ELECTRIC POWER COMPANY TEXAS WIRESCO TO CENTRAL AND SOUTH WEST CORPORATION TO SATISFY THE DIVIDEND DECLARATION. CLOSE-DIVIDEND TO RETAINED EARNINGS ----------------------------------- ACCOUNT DESCRIPTION DR CR ------- ----------- -- -- 216 RETAINED EARNINGS XXX,XXX 438 DIVIDENDS DECLARED XXX,XXX TO CLOSE THE DIVIDEND DECLARATION ON SOUTHWESTERN ELECTRIC POWER COMPANY TO RETAINED EARNINGS.
AMERICAN ELECTRIC POWER SERVICE CORPORATION Schedule H-27 FERC DOCKET NO. EC01-_________ Page 1 of 1 TRANSFER OF JURISDICTIONAL ASSETS SECTION 5, PART C JOURNAL ENTRIES TRANSFER OF SOUTHWESTERN ELECTRIC POWER COMPANY ASSETS (IN $ THOUSANDS BASED ON 12/31/2000 ESTIMATED AMOUNTS) B. TO BE RECORDED ON THE BOOKS OF SOUTHWESTERN ELECTRIC POWER ----------------------------------------------------------
TEXAS WIRESCO: -------------- CREATE TEXAS WIRESCO SUBSIDIARY ------------------------------- ACCOUNT DESCRIPTION DR CR ------- ----------- -- -- 101-106, 114 UTILITY PLANT 809,018 107 CONSTRUCTION WORK IN PROGRESS 17,683 121 NONUTILITY PROPERTY 113 124 OTHER INVESTMENTS 845 131 CASH 110 132-134 SPECIAL DEPOSITS 315 135 WORKING FUND 35 142 CUSTOMER ACCOUNTS RECEIVABLE 2,314 143 OTHER ACCOUNTS RECEIVABLE 1,022 146 ACCOUNTS RECEIVABLE FROM ASSOCIATED COS 0 154 PLANT MATERIALS AND OPERATING SUPPLIES 2,427 165 PREPAYMENTS 13,768 171 INTEREST AND DIVIDENDS RECEIVABLE 95 172 RENTS RECEIVABLE 109 173 UNBILLED REVENUE 1,186 174 MISCELLANEOUS CURRENT AND ACCRUED ASSETS 0 181 UNAMORTIZED DEBT EXPENSE 1,326 182.3 OTHER REGULATORY ASSETS 16,654 184 CLEARING ACCOUNTS 436 186 MISCELLANEOUS DEFERRED DEBITS 20,237 189 UNAMORTIZED LOSS ON REACQUIRED DEBT 10,314 190 ACCUMULATED DEFERRED INCOME TAXES 11,981 108 ACCUM PROVISION FOR DEPRECIATION AND DEPL 278,417 201-226 COMMON STOCK/OTH PAID IN CAPITAL/LONG-TERM DEBT 457,590 228.3 ACCUM PROVISION FOR PENSIONS AND BENEFITS 1,012 232 ACCOUNTS PAYABLE 5,978 233 NOTES PAYABLE TO ASSOCIATED COMPANIES 4,381 234 ACCOUNTS PAYABLE TO ASSOCIATED COMPANIES 7,096 235 CUSTOMER DEPOSITS 6,648 236 TAXES ACCRUED 6,887 237 INTEREST ACCRUED 4,820 241 TAX COLLECTIONS PAYABLE 712 242 MISC CURRENT AND ACCRUED LIABILITIES 2,986 254 OTHER REGULATORY LIABILITIES 19,016 255 ACCUMULATED DEFERRED INVESTMENT TAX CREDITS 12,778 257 UNAMORTIZED GAIN ON REACQUIRED DEBT 151 281-283 ACCUMULATED DEFERRED INCOME TAXES 101,516 TO RECORD THE CREATION OF A TEXAS WIRESCO SUBSIDIARY OF SOUTHWESTERN ELECTRIC POWER COMPANY.
AMERICAN ELECTRIC POWER SERVICE CORPORATION Schedule H-28 FERC DOCKET NO. EC01-________ Page 1 of 1 TRANSFER OF JURISDICTIONAL ASSETS SECTION 5, PART C JOURNAL ENTRIES TRANSFER OF SOUTHWESTERN ELECTRIC POWER COMPANY ASSETS (IN $ THOUSANDS BASED ON 12/31/2000 ESTIMATED AMOUNTS) C. TO BE RECORDED ON THE BOOKS OF CENTRAL AND SOUTH WEST CORPORATION: ------------------------------------------------------------------
DIVIDEND OF TEXAS WIRESCO ------------------------- ACCOUNT DESCRIPTION DR CR ------- ----------- -- -- 171 DIVIDENDS RECEIVABLE -AFFILIATED XXX,XXX 123.1 INVESTMENT IN SUBSIDIARY COS - SWEPCO XXX,XXX TO RECORD A DIVIDEND RECEIVABLE FROM SOUTHWESTERN ELECTRIC POWER COMPANY EQUAL TO THE NET ASSETS OF THE SOUTHWESTERN ELECTRIC POWER COMPANY TEXAS WIRESCO SUBSIDIARY. INVESTMENT IN WIRESCO ---------------------- ACCOUNT DESCRIPTION DR CR ------- ----------- -- -- 123.1 INVESTMENT IN SUBSIDIARY COS - SWEPCO TEXAS WIRESCO XXX,XXX 171 DIVIDENDS RECEIVABLE XXX,XXX TO RECORD THE INVESTMENT IN SOUTHWESTERN ELECTRIC POWER TEXAS WIRESCO IN SETTLEMENT OF THE DIVIDEND PAYABLE FROM SOUTHWESTERN ELECTRIC POWER COMPANY.
AMERICAN ELECTRIC POWER SERVICE CORPORATION Schedule H-29 FERC DOCKET NO. EC01-________ Page 1 of 2 TRANSFER OF JURISDICTIONAL ASSETS SECTION 5, PART C JOURNAL ENTRIES TRANSFER OF WEST TEXAS UTILITIES COMPANY ASSETS (IN $ THOUSANDS BASED ON 12/31/2000 ESTIMATED AMOUNTS) A. TO BE RECORDED ON THE BOOKS OF WEST TEXAS UTILITIES COMPANY: ------------------------------------------------------------
CREATE GENCO SUBSIDIARY ----------------------- ACCOUNT DESCRIPTION DR CR ------- ----------- --- --- 108 ACCUM PROVISION FOR DEPRECIATION AND DEPL 210,985 123.1&221-228 INV IN SUBS COS & LONG-TERM DEBT 150,669 228.3 ACCUM PROVISION FOR PENSIONS AND BENEFITS 1,218 232 ACCOUNTS PAYABLE 21,590 233 NOTES PAYABLE TO ASSOCIATED COMPANIES 18,774 234 ACCOUNTS PAYABLE TO ASSOCIATED COMPANIES 20,218 236 TAXES ACCRUED 6,718 237 INTEREST ACCRUED 1,274 241 TAX COLLECTION$ PAYABLE 231 242 MISC CURRENT AND ACCRUED LIABILITIES 157,789 253 OTHER DEFERRED CREDITS 20,800 255 ACCUMULATED DEFERRED INVESTMENT TAX CREDITS 9,237 257 UNAMORTIZED GAIN ON REACQUIRED DEBT 9 281-283 ACCUMULATED DEFERRED INCOME TAXES 77,581 101-108,114 UTILITY PLANT 442,607 107 CONSTRUCTION WORK IN PROGRESS 16,846 121 NONUTILITY PROPERTY 310 124 OTHER INVESTMENTS 20,944 131 CASH 1,352 132-134 SPECIAL DEPOSITS 1,628 135 WORKING FUND 2 142 CUSTOMER ACCOUNTS RECEIVABLE 5,116 143 OTHER ACCOUNTS RECEIVABLE 1,550 146 ACCOUNTS RECEIVABLE FROM ASSOCIATED COS 12,740 151 FUEL STOCK 12,104 152 FUEL STOCK EXPENSES UNDISTRIBUTED 70 154 PLANT MATERIALS AND OPERATING SUPPLIES 6,546 165 PREPAYMENTS 7,205 174 MISCELLANEOUS CURRENT AND ACCRUED ASSETS 152,174 181 UNAMORTIZED DEBT EXPENSE 1,110 184 CLEARING ACCOUNTS 69 186 MISCELLANEOUS DEFERRED DEBITS 48 190 ACCUMULATED DEFERRED INCOME TAXES 12,525 226 UNAMORTIZED PREMIUM ON LONG TERM DEBT 47 TO RECORD THE CREATION OF A GENCO SUBSIDIARY OF WEST TEXAS UTILITIES COMPANY.
AMERICAN ELECTRIC POWER SERVICE CORPORATION Schedule H-29 FERC DOCKET NO. EC01-_______________ Page 2 of 2 TRANSFER OF JURISDICTIONAL ASSETS SECTION 5, PART C JOURNAL ENTRIES TRANSFER OF WEST TEXAS UTILITIES COMPANY ASSETS (IN $ THOUSANDS BASED ON 12/31/2000 ESTIMATED AMOUNTS) A. TO BE RECORDED ON THE BOOKS OF WEST TEXAS UTILITIES COMPANY: ------------------------------------------------------------
DIVIDEND GENCO SUBSIDIARY TO CSW, INC ------------------------------------- ACCOUNT DESCRIPTION DR CR ------- ----------- -- -- 207-211 PAID-IN CAPITAL XXX,XXX 438 DIVIDENDS DECLARED - RET EARNINGS XXX,XXX 238 DIVIDENDS DECLARED - LIABILITY XXX,XXX TO RECORD THE DECLARATION OF A DIVIDEND FROM WEST TEXAS UTILITIES COMPANY TO THE CSW, INC. FOR THE NET ASSETS OF THE WEST TEXAS UTILITIES COMPANY GENCO SUBSIDIARY. TRANSFER GENCO INVESTMENT TO CSW, INC ------------------------------------- ACCOUNT DESCRIPTION DR CR ------- ----------- -- -- 238 DIVIDENDS DECLARED - LIABILITY XXX,XXX 123.1 INVESTMENT IN SUBSIDIARY COS - WTU GENCO XXX,XXX TO RECORD THE TRANSFER OF THE INVESTMENT OF WEST TEXAS UTILITIES COMPANY IN GENCO TO CSW, INC. TO SATISFY THE DIVIDEND DECLARATION. CLOSE DIVIDEND TO RETAINED EARNINGS ----------------------------------- ACCOUNT DESCRIPTION DR CR ------- ----------- -- -- 216 RETAINED EARNINGS XXX,XXX 438 DIVIDENDS DECLARED XXX,XXX TO CLOSE THE DIVIDEND DECLARATION ON WEST TEXAS UTILITIES COMPANY TO RETAINED EARNINGS.
AMERICAN ELECTRIC POWER SERVICE CORPORATION Schedule H-30 FERC DOCKET NO. EC01-_____________ Page 1 of 1 TRANSFER OF JURISDICTIONAL ASSETS SECTION 5, PART C JOURNAL ENTRIES TRANSFER OF WEST TEXAS UTILITIES COMPANY ASSETS (IN $ THOUSANDS BASED ON 12/31/2000 ESTIMATED AMOUNTS) AA. TO BE RECORDED ON THE BOOKS OF CENTRAL AND SOUTH WEST CORPORATION: ------------------------------------------------------------------ DIVIDEND GENCO SUBSIDIARY TO AEP, INC -------------------------------------
ACCOUNT DESCRIPTION DR CR ------- ----------- -- -- 438 DIVIDENDS DECLARED - RET EARNINGS XXX,XXX 238 DIVIDENDS DECLARED - LIABILITY XXX,XXX TO RECORD THE DECLARATION OF A DIVIDEND FROM CENTRAL AND SOUTH WEST CORPORATION TO THE AEP CO., INC. FOR THE NET ASSETS OF THE WEST TEXAS UTILITIES COMPANY GENCO SUBSIDIARY. TRANSFER GENCO INVESTMENT TO AEP, INC ------------------------------------- ACCOUNT DESCRIPTION DR CR ------- ----------- -- -- 238 DIVIDENDS DECLARED - LIABILITY XXX,XXX 123.1 INVESTMENT IN SUBSIDIARY COS - WTU GENCO XXX,XXX TO RECORD THE TRANSFER OF THE INVESTMENT OF CENTRAL AND SOUTH WEST CORPORATION IN GENCO TO AEP, CO., INC. TO SATISFY THE DIVIDEND DECLARATION. CLOSE DIVIDEND TO RETAINED EARNINGS ----------------------------------- ACCOUNT DESCRIPTION DR CR ------- ----------- -- -- 216 RETAINED EARNINGS XXX,XXX 438 DIVIDENDS DECLARED XXX,XXX
TO CLOSE THE DIVIDEND DECLARATION ON CENTRAL AND SOUTH WEST CORPORATION TO RETAINED EARNINGS. AMERICAN ELECTRIC POWER SERVICE CORPORATION Schedule H-31 FERC DOCKET NO. EC01-________ Page 1 of 1 TRANSFER OF JURISDICTIONAL ASSETS SECTION 5, PART C JOURNAL ENTRIES TRANSFER OF WEST TEXAS UTILITIES COMPANY ASSETS (IN $ THOUSANDS BASED ON 12/31/2000 ESTIMATED AMOUNTS) B. TO BE RECORDED ON THE BOOKS OF WEST TEXAS UTILITIES GENCO: ----------------------------------------------------------
CREATE GENCO SUBSIDIARY ----------------------- ACCOUNT DESCRIPTION DR CR ------- ----------- -- -- 101-106,114 UTILITY PLANT 442,607 107 CONSTRUCTION WORK IN PROGRESS 16,846 121 NONUTILITY PROPERTY 310 124 OTHER INVESTMENTS 20,944 131 CASH 1,352 132-134 SPECIAL DEPOSITS 1,628 135 WORKING FUND 2 142 CUSTOMER ACCOUNTS RECEIVABLE 5,116 143 OTHER ACCOUNTS RECEIVABLE 1,550 146 ACCOUNTS RECEIVABLE FROM ASSOCIATED COS 12,740 151 FUEL STOCK 12,104 152 FUEL STOCK EXPENSES UNDISTRIBUTED 70 154 PLANT MATERIALS AND OPERATING SUPPLIES 6,646 165 PREPAYMENTS 7,205 174 MISCELLANEOUS CURRENT AND ACCRUED ASSETS 152,174 181 UNAMORTIZED DEBT EXPENSE 1,110 184 CLEARING ACCOUNTS 69 186 MISCELLANEOUS DEFERRED DEBITS 48 190 ACCUMULATED DEFERRED INCOME TAXES 12,525 226 UNAMORTIZED PREMIUM ON LONG TERM DEBT 47 108 ACCUM PROVISION FOR DEPRECIATION AND DEPL 210,985 201-226 COMMON STOCK/OTH PAID IN CAPITAL/LONG-TERM DEBT 150,669 228.3 ACCUM PROVISION FOR PENSIONS AND BENEFITS 1,218 232 ACCOUNTS PAYABLE 21,590 233 NOTES PAYABLE TO ASSOCIATED COMPANIES 16,774 234 ACCOUNTS PAYABLE TO ASSOCIATED COMPANIES 20,218 236 TAXES ACCRUED 6,718 237 INTEREST ACCRUED 1,274 241 TAX COLLECTIONS PAYABLE 231 242 MISC CURRENT AND ACCRUED LIABILITIES 157,789 253 OTHER DEFERRED CREDITS 20,800 255 ACCUMULATED DEFERRED INVESTMENT TAX CREDITS 9,237 257 UNAMORTIZED GAIN ON REACQUIRED DEBT 9 281-283 ACCUMULATED DEFERRED INCOME TAXES 77,581 TO RECORD THE CREATION OF A GENCO SUBSIDIARY OF WEST TEXAS UTILITIES COMPANY.
AMERICAN ELECTRIC POWER SERVICE CORPORATION Schedule H-32 FERC DOCKET NO. EC01-________ Page 1 of 1 TRANSFER OF JURISDICTIONAL ASSETS SECTION 5, PART C JOURNAL ENTRIES TRANSFER OF WEST TEXAS UTILITIES COMPANY ASSETS (IN $ THOUSANDS BASED ON 12/31/2000 ESTIMATED AMOUNTS) C. TO BE RECORDED ON THE BOOKS OF AEP COMPANY, INC: ------------------------------------------------ DIVIDEND OF GENCO -----------------
ACCOUNT DESCRIPTION DR CR ------- ----------- -- -- 171 DIVIDENDS RECEIVABLE -AFFILIATED XXX,XXX 123.1 INVESTMENT IN SUB COS - CSW CORP XXX,XXX TO RECORD A DIVIDEND RECEIVABLE FROM CENTRAL AND SOUTH WEST CORPORATION EQUAL TO THE NET ASSETS OF THE WEST TEXAS UTILITIES COMPANY GENCO SUBSIDIARY. INVESTMENT IN GENCO ------------------- ACCOUNT DESCRIPTION DR CR ------- ----------- -- -- 123.1 INVESTMENT IN SUBSIDIARY COS - WTU GENCO XXX,XXX 171 DIVIDENDS RECEIVABLE XXX,XXX TO RECORD THE INVESTMENT IN WEST TEXAS UTILITIES GENCO IN SETTLEMENT OF THE DIVIDEND PAYABLE FROM CENTRAL AND SOUTH WEST CORPORATION. CONTRIBUTE GENCO TO NON-REGULATED HOLDCO ---------------------------------------- ACCOUNT DESCRIPTION DR CR ------- ----------- -- -- 123.1 INVESTMENT IN SUBSIDIARY COS - AEP NON-REG HOLDCO XXX,XXX 123.1 INVESTMENT IN SUBSIDIARY COS - WTU GENCO XXX,XXX
TO RECORD CONTRIBUTION OF WEST TEXAS UTILITIES GENCO TO THE NON-REGULATED HOLDCO. AMERICAN ELECTRIC POWER SERVICE CORPORATION Schedule H-33 FERC DOCKET NO. EC01-______________ Page 1 of 1 TRANSFER OF JURISDICTIONAL ASSETS SECTION 5, PART C JOURNAL ENTRIES TRANSFER OF WEST TEXAS UTILITIES COMPANY ASSETS (IN $ THOUSANDS BASED ON 12/31/2000 ESTIMATED AMOUNTS) D. TO BE RECORDED ON THE BOOKS OF AEP NON-REGULATED HOLDCO: -------------------------------------------------------- CONTRIBUTION OF GENCO ---------------------
ACCOUNT DESCRIPTION DR CR ------- ----------- -- -- 123.1 INVESTMENT IN SUBSIDIARY COS - WTU GENCO XXX,XXX 201,208-211 COMMON STOCK - OTHER PAID IN CAPITAL XXX,XXX
TO RECORD AEP'S CONTRIBUTION OF ITS INVESTMENT IN THE WEST TEXAS UTILITIES GENCO TO AEP'S NON-REGULATED HOLDCO. EXHIBIT I DESCRIPTION OF TRANSFERS This Description of Transfers describes the transactions that will be carried out in order to accomplish the required separation of the generating assets and transmission and distribution assets of CPL, WTU, SWEPCO, OPCo and CSP to comply with the electric utility restructuring laws of Texas and Ohio and associated assignments of jurisdictional rate schedules. Generally, because such transactions involve asset transfers within the AEP registered electric holding company system, no agreements are necessary to accomplish such transactions other than counter-party consents to assignments. Such transactions will be accomplished upon receipt of all necessary regulatory approvals and any required counter-party consents as part of an overall plan of AEP to separate its regulated utility businesses from generating, power marketing and related businesses that are either unregulated or subject to light-handed regulation by the Federal Energy Regulatory Commission (FERC) from its regulated energy delivery (transmission and distribution) businesses. AEP has established or will establish several intermediate holding companies that will be used to reorganize its businesses in this manner. AEP will hold all of the common stock of three relevant first-tier subsidiaries: (1) Central and South West Corporation (CSW), which will be the holding company for AEP's regulated businesses, including vertically integrated electric utilities in states that continue to regulate electric utilities in the traditional manner and transmission and distribution (energy delivery) companies that result from the corporate separation of CPL, WTU, SWEPCO, OPCo and CSP; (2) AEP Retail Holdco, Inc., a first-tier AEP subsidiary that will be the holding company for AEP's competitive retail energy marketing businesses in Texas; and (3) AEP Enterprises, Inc., which, among other things, will be the holding company for AEP's unregulated or lightly regulated foreign and domestic power generation and marketing businesses, including the power generation companies that will result from the corporate separation of CPL, WTU, OPCo and CSP. AEP has established or will establish a second-tier holding company, AEP Wholesale Holding Company, Inc. (Wholesale Holdco), that will control the common stock of a third-tier holding company, AEP Domestic Generation Holding Company, Inc. (Domestic Genco), that will hold the common stock of the power generating companies that result from the corporate separation of CPL, WTU, OPCo and CSP. AEP Retail Holdco, Inc., AEP Enterprises, Inc., AEP Wholesale Holdco, Inc., AEP Domestic Generation Holding Company, Inc. and the other corporate names used in this Description of Transfers for affiliates of the existing AEP operating companies are all placeholder names, which are being used for descriptive convenience pending implementation of AEP's business reorganization plans. A.I. CORPORATE SEPARATION OF CPL To comply with the Texas electric restructuring law, by January 1, 2002 CPL will transfer title to its generating station assets to a newly formed wholly owned subsidiary, CPL Generation Company (CPL Genco), in exchange for 100% of the capital stock of such subsidiary. CPL will then contribute or dividend the shares of CPL Genco to its parent, CSW, which will in turn contribute or dividend the shares to its parent, AEP. AEP will contribute the CPL Genco shares to AEP Enterprises in exchange for a portion of AEP Enterprises' capital stock. AEP Enterprises will contribute the shares to Wholesale Holdco in exchange for a portion of Wholesale Holdco's capital stock, which in turn will contribute the shares to Domestic Genco 2 in exchange for a portion of Domestic Genco's capital stock. The transfer by CPL of the shares of CPL Genco to CSW (and the contemplated subsequent Transfers) may be delayed until sometime after June 15, 2002 in order to avoid adverse tax consequences relating to intra-corporate transfers of assets following a merger. CPL Genco will form a wholly owned limited liability company (CPL General Partner LLC) which, in turn, will form a limited partnership (CPL Genco LP) of which it will be the general partner. CPL Genco will transfer title to all of its generating assets to CPL Genco LP in exchange for all of the limited partnership interests of CPL Genco LP. CPL will continue to hold title to its transmission and distribution assets and will function as an EDC after corporate separation is complete. CSW will continue to own all of the common stock of CPL. CPL will also transfer certain regulatory assets to a newly formed subsidiary, CPL Securitization Company (Securico), in exchange for 100% of the capital stock of Securico. Securico will issue bonds that will be amortized directly from the cash flow resulting from transition charges collected by CPL EDC related to regulatory assets held by Securico. Bond proceeds will be distributed to CPL EDC, which will retire debt with a portion of such proceeds and dividend the remainder to CSW, which in turn will dividend such funds to AEP. AEP has established (as a wholly owned subsidiary of Retail Holdco) a Retail Electric Provider (CPL REP) that will offer retail electric service to "price to beat" customers formerly served by CPL. A.II. POWER SUPPLY AGREEMENTS Subject to obtaining regulatory approval and any necessary counter-party consents, CPL will assign to CPL Genco its existing wholesale power supply agreements. Once the corporate 3 separation of CPL has occurred, CPL Genco, the unbundled generation company, will enter into a power supply agreement with PMA to sell capacity and energy from its generating facilities not needed to serve wholesale customers under the assigned contracts. CPL REP may enter into a contract with PMA for capacity and energy to serve Texas "price-to-beat" customers in CPL's service territory. B.I. CORPORATE SEPARATION OF WTC To comply with the Texas electric restructuring law, by January 1, 2002 WTU will transfer title to its generating station assets to a newly formed wholly owned subsidiary, WTU Generation Company (WTU Genco), in exchange for 100% of the capital stock of such subsidiary. WTU will then contribute or dividend the shares of WTU Genco to its parent, CSW, which will in turn contribute or dividend the shares to its parent, AEP. AEP will contribute the WTU Genco shares to AEP Enterprises in exchange for a portion of AEP Enterprises' capital stock. AEP Enterprises will contribute the shares to Wholesale Holdco in exchange for a portion of Wholesale Holdco's capital stock, which in turn will contribute the shares to Domestic Genco in exchange for a portion of Domestic Genco's capital stock. The transfer by CPL of the shares of CPL Genco to CSW (and the contemplated subsequent Transfers) may be delayed until sometime after June 15, 2002 in order to avoid adverse tax consequences relating to intra-corporate transfers of assets following a merger. WTU Genco, will form a wholly owned limited liability company (WTU General Partner LLC) which, in turn, will form a limited partnership (WTU Genco LP) of which it will be the general partner. WTU Genco will transfer title to all of its generating assets to WTU Genco LP in exchange for all of the limited partnership interests of WTU Genco LP. 4 WTC will continue to hold title to its transmission and distribution assets and will function as an EDC after corporate separation is complete. CSW will continue to hold the common stock of WTU. AEP has established (as a wholly owned subsidiary of Retail Holdco) a Retail Electric Provider (WTU REP) that will offer retail electric service to "price to beat" customers formerly served by WTU. B.II. POWER SUPPLY AGREEMENTS; Subject to obtaining regulatory approval and any necessary counter-party consents, WTU will assign to WTU Genco its existing wholesale power supply agreements. Once the corporate separation of WTU has occurred, WTU Genco, the unbundled generation company will enter into a power supply agreement with PMA to sell capacity and energy from its generating facilities not needed to serve wholesale customers under the assigned contracts. WTU REP may enter into a contract with PMA for capacity and energy to serve Texas "price to beat" customers in WTU's service territory. C.I. FORMATION OF SWEPCO EDC To comply with the Texas electric restructuring statute, by January 1, 2002 SWEPCO will transfer title to its transmission and distribution assets, including interconnection agreements with neighboring utility systems, located in Texas and related business operations to a newly formed wholly owned subsidiary, SWEPCO EDC, in exchange for 100% of the capital stock of such subsidiary and then contribute or dividend the shares of SWEPCO EDC to SWEPCO's parent, CSW. CSW will continue to hold all of the common stock of SWEPCO. SWEPCO will retain title to its transmission and distribution assets located in Louisiana and Arkansas and all of its generating plants. SWEPCO provides bundled retail electric service 5 in Louisiana, which to date has not adopted a retail competition policy or legislation, and in Arkansas, where SWEPCO is not obligated to separate ownership of its generating assets from its transmission and distribution assets. SWEPCO will also retain its existing contracts with wholesale requirements customers. AEP has established (as a wholly owned subsidiary of Retail Holdco) a Retail Electric Provider (SWEPCO REP) that will offer retail electric service to Texas retail customers formerly served by SWEPCO. C.II. POWER SUPPLY AGREEMENTS Once the corporate separation of SWEPCO has occurred, SWEPCO, the integrated utility, will enter into power supply agreements with PMA. SWEPCO will make capacity and associated energy available to PMA under a Unit Power Sales Agreement that is being submitted for Commission review as part of the Section 205 Filing. To enable SWEPCO or SWEPCO REP to continue to serve its wholesale requirements customers and its Texas retail customers having loads of 1 MW or more during the transition to full retail competition in SWEPCO's Texas service area PMA will sell back to SWEPCO under a second Unit Power Sales Agreement the capacity and associated energy needed for those purposes, which also is being submitted for Commission review as part of the Section 205 Filing. SWEPCO REP may enter into a contract with PMA to procure power and energy needed to serve Texas "price to beat" customers in SWEPCO's Texas service territory. If and when such an affiliate contract is developed, it will be filed with the Commission. D.I. CORPORATE SEPARATION OF OPCO OPCo will transfer its transmission and distribution assets, including interconnection agreements with neighboring utility systems, to a newly formed wholly owned subsidiary, OPCo Energy Deliver Company (OPCo EDC), in exchange for 100% of the capital stock of such 6 subsidiary and then contribute or dividend the shares of OPCo EDC to its parent, AEP. AEP will contribute all of the capital stock of the OPCo EDC to CSW. OPCo will retain title to its generating station assets. AEP will contribute the common stock of OPCo, all of which AEP now owns, to AEP Enterprises in exchange for a portion of AEP Enterprises' capital stock. AEP Enterprises will contribute the OPCo stock to Wholesale Holdco in exchange for capital stock of Wholesale Holdco and Wholesale Holdco will contribute the shares to Domestic Genco in exchange for capital stock of Domestic Genco. D.II. POWER SUPPLY AGREEMENTS Once the corporate separation of OPCo has occurred, OPCo PGC (the unbundled generation company) will enter into a power supply agreement with PMA to sell capacity and energy from its generating facilities not needed to serve Buckeye Power, Inc. or its affiliate National Power Cooperative, Inc. OPCo EDC will enter into several power supply agreements with PMA to provide to OPCo EDC capacity and energy needed to provide default service to retail customers. A. DEFAULT SUPPLY AGREEMENT TERM: January 1, 2002 through December 31, 2005 or the end of the Ohio Market Development Period, whichever occurs sooner. BUYER: OPCo EDC SELLER: PMA GENERAL PURPOSE: To ensure a reliable supply of electric power for cost-based default retail electric service provided by the OPCo EDC to retail customers that do not choose alternate electric power suppliers during the Ohio Market Development Period. B. INTERRUPTIBLE POWER AGREEMENT 7 TERM: January 1, 2002 through December 31, 2005 or the end of the Ohio Market Development Period, whichever occurs sooner. BUYER: OPCo EDC SELLER: PMA GENERAL PURPOSE: To ensure a reliable supply of wholesale power for cost-based default interruptible retail electric service provided by OPCo EDC to retail interruptible service customers that do not choose alternate electric power suppliers during the Ohio Market Development Period. C. CENTURY POWER AGREEMENT TERM: January 1, 2002 through July 31, 2003 BUYER: OPCo EDC SELLER: PMA GENERAL PURPOSE: To ensure a supply of electric power for service by OPCo EDC to Century Aluminum, a retail customer of OPCo EDC, through July 31, 2003, OPCo EDC will enter into an Agreement to purchase wholesale power and related products from PMA. E.I. CORPORATE SEPARATION OF CSP CSP will transfer its transmission and distribution assets, including interconnection agreements with neighboring utility systems, to a newly formed wholly owned subsidiary, CSP Energy Delivery Company (CSP EDC), in exchange for 100% of the capital stock of such subsidiary and then contribute or dividend the shares of CSP EDC to its parent, AEP. AEP will contribute all of the capital stock of the CSP EDC to CSW. CSP will retain title to its generation station assets. AEP will contribute the common stock of CSP, all of which AEP now owns, to AEP Enterprises in exchange for a portion of AEP 8 Enterprises' capital stock. AEP Enterprises will contribute the CSP stock to Wholesale Holdco in exchange for capital stock of Wholesale Holdco and Wholesale Holdco will contribute the shares to Domestic Genco in exchange for capital stock of Domestic Genco. E.II. POWER SUPPLY AGREEMENTS Once the corporate separation of CSP has occurred, CSP (the unbundled generation company) will enter into a power supply agreement with PMA to sell capacity and energy from its generating facilities not needed to serve CSP's wholesale customers. CSP EDC will enter into several power supply agreements with PMA to provide to CSP EDC capacity and energy needed to provide default service to retail customers. A. DEFAULT SUPPLY AGREEMENT TERM: January 1, 2002 through December 31, 2005 or the end of the Ohio Market Development Period, whichever occurs sooner. BUYER: CSP EDC SELLER: PMA GENERAL PURPOSE: To ensure a reliable supply of electric power for cost-based default retail electric service provided by CSP EDC to retail customers that do not choose alternate electric power suppliers during the Ohio Market Development Period. B. INTERRUPTIBLE POWER AGREEMENT TERM: January 1, 2002 through December 31, 2005 or the end of the Ohio Market Development Period, whichever occurs sooner. BUYER: CSP EDC SELLER: PMA 9 GENERAL PURPOSE: To ensure a reliable supply of wholesale power for cost-based default interruptible retail electric service provided by CSP EDC to retail interruptible customers that do not choose alternate electric power suppliers during the Ohio Market development period. F. OTHER TRANSFERS OPCo will assign to APCo the power sales agreement under which OPCo currently supplies its affiliate Wheeling Power Company its requirements for electricity needed to serve retail customers in West Virginia using the form of Assignment attached as Annex 1 to this Exhibit I. APCo will assign to OPCo PGC its Power Supply Agreement with the North Carolina Electric Membership Cooperative using the form of assignment attached as Annex 2 to this Exhibit I. I&M will assign its interests to generating capacity in Rockport Unit Nos. 1 and 2 owned by AEP Generating Company to PMA using the form of Assignment attached as Annex 3 to this Exhibit I. APCo, OPCo, CSP and I&M will assign to PMA their interests in the OVEC Agreement using the form of Assignment attached as Annex 4 to this Exhibit I. AEPSC will assign to PMA its contracts to serve the wholesale customers listed on Exhibit G using the form of Assignment attached as Annex 5 to this Exhibit I, a form that will be also be used by CPL and WTU to assign their wholesale agreements to CPL PGC and WTU PGC, respectively. 10 Exhibit I Annex 1 Page 1 of 3 WHEELING ASSIGNMENT AGREEMENT THIS WHEELING ASSIGNMENT AGREEMENT ("Assignment Agreement") is made and entered into as of this _________________ day of ______________ by and between The Ohio Power Company ("OPCo"), a corporation organized under the laws of the State of Ohio, and Appalachian Power Company ("APCo'), a corporation organized under the laws of the Commonwealth of Virginia (hereinafter referred to collectively as the "Parties" and individually as "Party"). Wheeling Electric Company ("Wheeling"), a corporation organized under the laws of the State of West Virginia, is also executing this Assignment Agreement to evidence its consent thereto. WITNESSETH WHEREAS, OPCo and Wheeling have entered into an Interconnection Agreement, dated as of February 24, 1949, as modified and supplemented through Supplement No. 21 ("Interconnection Agreement"), pursuant to which OPCo provides firm and curtailable power and associated energy, and back-up and maintenance service, in amounts as required by Wheeling; WHEREAS, OPCo desires to assign, transfer, and delegate to APCo and APCo is willing to accept assignment, transfer, and delegation from OPCo, of all of OPCo's rights, interests, duties, and obligations under the Interconnection Agreement, pursuant to the terms of this Assignment Agreement; WHEREAS, Article 17 of the Interconnection Agreement provides that the Interconnection Agreement may be assigned; and WHEREAS, Wheeling desires to give its consent to the assignment, transfer, and delegation of OPCO's rights, interests, duties, and obligations under the Interconnection Agreement to APCo. NOW, THEREFORE, in consideration of the premises and mutual covenants set forth herein, the Parties agree as follows: 1. OPCo hereby assigns, transfers, and delegates to APCo all of OPCo's rights, interests, duties, and obligations under the Interconnection Agreement. Effective as of the date this Assignment Agreement is executed by the Parties, APCo agrees to assume all of the rights, interests, duties, and obligations under the Interconnection Agreement. 2. Each of the Parties warrants and represents that the execution and delivery of this Assignment Agreement has been duly authorized, and upon execution and delivery by such Party, shall be a valid and binding agreement, enforceable according to its terms. 3. This Assignment Agreement supersedes all previous representations, understandings, negotiations, and agreements, either written or oral, between the Parties or their representatives Exhibit I Annex 1 Page 2 of 3 with respect to the subject matter hereof, and constitutes the entire agreement of the Parties with respect to the subject matter hereof. 4. This Assignment Agreement is made subject to all existing and future applicable federal, state, and local laws and to all existing and future duly promulgated orders or other duly authorized actions of governmental authorities having jurisdiction over the matters set forth in this Assignment Agreement. 5. The interpretation and performance of this Assignment Agreement shall be in accordance with the laws of the State of Ohio, excluding conflicts of law principles that would require the application of the laws of a different jurisdiction. 6. The numbered paragraphs contained in this Assignment Agreement are solely for the convenience of the Parties and should not be used or relied upon in any manner in the construction or interpretation of this Assignment Agreement. 7. If any provision of this Assignment Agreement is found to be invalid, illegal, or unenforceable by reason of any existing or subsequently enacted legislation or by decree of a court of competent jurisdiction, such legislation or decree shall not impair, invalidate, or nullify the remainder of this Assignment Agreement, which shall remain in full force and effect. In such circumstances, the Parties agree to negotiate in good faith to replace such provision and restore the relative allocation of economic risks and benefits between the Parties as reflected herein. 8. This Assignment Agreement may be executed in any number of counterparts, each of which shall be an original, but all of which together shall constitute one and the same instrument. IN WITNESS WHEREOF, the Parties have executed this Assignment Agreement as of the date set forth at the beginning of this Assignment Agreement. THE OHIO POWER COMPANY BY:____________________________ APPALACHIAN POWER COMPANY BY:____________________________ -2- Exhibit I Annex 1 Page 3 of 3 CONSENT BY WHEELING Wheeling is executing this Assignment Agreement to evidence its consent to the assignment, transfer, and delegation from OPCo to APCo of all of OPCo's rights, interests, duties, and obligations under the Interconnection Agreement, pursuant to the terms of this Assignment Agreement, effective as of the date set forth at the beginning of this Assignment Agreement, and that from and after such date OPCo shall be relieved of its obligations under the Interconnection Agreement, which shall be assumed by APCo. WHEELING ELECTRIC COMPANY BY:______________________________ -3- Exhibit I Annex 2 Page 1 of 3 NCEMC ASSIGNMENT AGREEMENT THIS NCEMC ASSIGNMENT AGREEMENT ("Assignment Agreement") is made and entered into as of this ____________________ day of ________________ by and between The Ohio Power Company ("OPCo"), a corporation organized under the laws of the State of Ohio, and Appalachian Power Company ("APCo"), a corporation organized under the laws of the Commonwealth of Virginia (hereinafter referred to collectively as the "Parties" and individually as "Party"). North Carolina Electric Membership Corporation ("NCEMC"), a corporation organized under the laws of the State of North Carolina, also is executing this Assignment Agreement to evidence its consent thereto. WITNESSETH WHEREAS, APCo and NCEMC have entered into a Power Supply Agreement, dated as of August 22, 1994, as heretofore amended, modified and supplemented, pursuant to which APCo provides up to 205 MW of capacity and associated energy in amounts scheduled by NCEMC; WHEREAS, APCo desires to assign, transfer, and delegate to OPCo and OPCo is willing to accept assignment, transfer, and delegation from APCo of all of APCo's rights, interests, duties, and obligations under the Power Supply Agreement, pursuant to the terms of this Assignment Agreement; WHEREAS, Article 10 of the Power Supply Agreement provides that the Power Supply Agreement may be assigned; and WHEREAS, NCEMC desires to give its consent to the assignment, transfer, and delegation of APCo's rights, interests, duties, and obligations under the Power Supply Agreement to OPCo. NOW, THEREFORE, in consideration of the premises and mutual covenants set forth herein, the Parties agree as follows: 1. APCo hereby assigns, transfers, and delegates to OPCo all of APCo's rights, interests, duties, and obligations under the Power Supply Agreement. Effective as of January 1, 2002, OPCo agrees to assume all of the rights, interests, duties, and obligations of APCo under the Power Supply Agreement. 2. Each of the Parties warrants and represents that the execution and delivery of this Assignment Agreement has been duly authorized, and upon execution and delivery by such Party, shall be a valid and binding agreement, enforceable according to its terms. 3. This Assignment Agreement supersedes all previous representations, understandings, negotiations, and agreements, either written or oral, between the Parties or their representatives Exhibit I Annex 2 Page 2 of 3 with respect to the subject matter hereof, and constitutes the entire agreement of the Parties with respect to the subject matter hereof. 4. This Assignment Agreement is made subject to all existing and future applicable federal, state, and local laws and to all existing and future duly promulgated orders or other duly authorized actions of governmental authorities having jurisdiction over the matters set forth in this Assignment Agreement. 5. The interpretation and performance of this Assignment Agreement shall be in accordance with the laws of the State of Ohio, excluding conflicts of law principles that would require the application of the laws of a different jurisdiction. 6. The numbered paragraphs contained in this Assignment Agreement are solely for the convenience of the Parties and should not be used or relied upon in any manner in the construction or interpretation of this Assignment Agreement. 7. If any provision of this Assignment Agreement is found to be invalid, illegal, or unenforceable by reason of any existing or subsequently enacted legislation or by decree of a court of competent jurisdiction, such legislation or decree shall not impair, invalidate, or nullify the remainder of this Assignment Agreement, which shall remain in full force and effect. In such circumstances, the Parties agree to negotiate in good faith to replace such provision and restore the relative allocation of economic risks and benefits between the Parties as reflected herein. 8. This Assignment Agreement may be executed in any number of counterparts, each of which shall be an original, but all of which together shall constitute one and the same instrument. IN WITNESS WHEREOF, the Parties have executed this Assignment Agreement as of the date set forth at the beginning of this Assignment Agreement. THE OHIO POWER COMPANY BY:____________________________ APPALACHIAN POWER COMPANY BY:____________________________ Exhibit I Annex 2 Page 3 of 3 CONSENT BY NCEMC NCEMC is executing this Assignment Agreement to evidence its consent to the assignment, transfer, and delegation from APCo to OPCo of all of APCo's rights, interests, duties, and obligations under the Power Supply Agreement, pursuant to the terms of this Assignment Agreement, effective as of January 1, 2002, and that from and after such date APCo shall be relieved of its obligations under the Power Supply Agreement, which shall be assumed by OPCo. NORTH CAROLINA ELECTRIC MEMBERSHIP CORPORATION BY:______________________________ Exhibit I Annex 3 Page l of 3 ASSIGNMENT OF RIGHT TO POWER AND ENERGY ASSOCIATED THEREWITH FROM THE ROCKPORT PLANT THIS ASSIGNMENT AGREEMENT, is made and entered into as of this ______ day of ____________, 2001, by and between INDIANA MICHIGAN POWER COMPANY ("I&M") and POWER MARKETING AFFILIATE ("PMA"), and acknowledged by AEP GENERATING COMPANY ("AEG"), WITNESSETH WHEREAS, AEG and I&M, are both subsidiaries of American Electric Power Company, Inc., and own equal shares of the Rockport Steam Electric Generating Plant Units No. 1 and 2, which are each 1300 MW steam electric generating units located near the town of Rockport, Indiana (both generating units collectively referred to as the "Rockport Plant"); WHEREAS, I&M entered into a Unit Power Agreement with AEG, dated March 31, 1982, wherein AEG agreed to make available to I&M all of the power (and energy associated therewith) available to AEG at the Rockport Plant; WHEREAS, I&M entered into a Unit Power Agreement with Virginia Electric Power Company ("VEPCO"), which has since terminated, whereby I&M assigned to VEPCO 455 MW, or 70%, from Rockport Unit No. 1 to which I&M was entitled from AEG under the Unit Power Agreement between I&M and AEG dated. March 31, 1982; WHEREAS, AEG, I&M and Kentucky Power Company ("KPCO") entered into an Assignment of Right to Power and Energy Associated Therewith from the Rockport Plant, dated August 1, 1984 and which will terminate on December 31, 2004, wherein I&M agreed to make available to KPCO 30% of its right, title and interest in and to the power (and energy associated therewith) from the Rockport Plant to which I&M was entitled from AEG under the Unit Power Agreement between I&M and AEG dated March 31, 1982; WHEREAS, I&M and KPCO entered into a Unit Power Agreement, dated August 1, 1984 and which will terminate on December 31, 2004, wherein KPCO agreed to pay the power bills that I&M would have paid for that 30% of AEG's share of the capacity of the Rockport Plant; WHEREAS, I&M desires to assign, transfer, and delegate to PMA and PMA is willing to accept assignment, transfer, and delegation from I&M the following assignment, transfer and delegation of I&M's rights, interests, duties, and obligations to the Rockport Plant under the Unit Power Agreements, pursuant to the terms of this Assignment Agreement; Exhibit I Annex 3 Page 2 of 3 NOW, THEREFORE, in consideration of the premises and mutual covenants set forth herein, the Parties agree as follows: 1.1 I&M assigns, transfers, and delegates to PMA and PMA is willing to accept the assignment, transfer and delegation from I&M: 1.1.1 70% of its rights, interests, duties and obligations to the power (and energy associated therewith) from the Rockport Unit No. 1 to which I&M shall be entitled from AEG under the Unit Power Agreement between I&M and AEG dated March 31, 1982; 1.1.2 As of January 1, 2005, 30% of its rights, interests, duties and obligations in and to the power (and energy associated therewith) from the Rockport Plant to which I&M shall be entitled from AEG under the Unit Power Agreement between I&M and AEG dated March 31, 1982; 1.2 PMA agrees to pay to AEG those amounts which I&M would have paid to AEG under the terms of the Unit Power Agreements, for PMA's entitlement in this agreement. 1.3 This agreement shall become effective as of the date this Assignment Agreement is executed by the Parties. 1.4 Subsequent to the effective date of this Assignment Agreement I&M shall be relieved of any responsibility for the obligations and duties under the Unit Power Agreement that are transferred herein to PMA and shall have no rights to the power (and energy associated therewith) available to AEG at Rockport Unit No. 1 that is assigned hereby. 2. The performance of the obligations of I&M and PMA hereunder shall be subject to the receipt and continued effectiveness of all necessary authorizations of governmental regulatory authorities. The parties shall use their best efforts to secure and maintain all such authorizations. 3. This Assignment Agreement is made subject to all existing and applicable federal, state, and local laws and to all existing and future duly promulgated orders or the duly authorized actions of governmental authorities having jurisdiction over the matters set forth in this Assignment Agreement. 4. The interpretation and performance of this Assignment Agreement shall be in accordance with the laws of the State of Michigan, excluding conflicts of law principles that would require the application of the laws of a different jurisdiction. -2- Exhibit I Annex 3 Page 3 of 3 5. If any provision of this Assignment Agreement is found to be invalid, illegal, or unenforceable by reason of any existing or subsequently enacted legislation or by decree of court of competent jurisdiction, such legislation or decree shall not impair, invalidate, or nullify the remainder of this Assignment Agreement, which shall remain in full force and effect. In such circumstances, the Parties agree to negotiate in good faith to replace such provision and restore the relative allocation of economic risks and benefits between the Parties as reflected herein. 6. The agreements herein set forth have been made for the benefit of I&M and PMA and their respective successors and assigns, and no other person shall acquire or have any right under or by virtue of this Agreement. 7. This Assignment Agreement may be executed in any number of counterparts, each of which shall be an original, but all of which together shall constitute one and the same instrument. IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be duly executed as of the day and year first above written. INDIANA MICHIGAN POWER COMPANY By ________________________________ POWER MARKETING AFFILIATE By ________________________________ The undersigned hereby acknowledges the above Assignment. AEP GENERATING COMPANY By ________________________________ -3- Exhibit I Annex 4 Page 1 of 5 ASSIGNMENT OF INTER-COMPANY POWER AGREEMENTS Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, and Ohio Power Company (referred to collectively as the "AEP Operating Companies") hereby assign to Power Marketing Affiliate ("PMA") all of AEP Operating Companies' right, title and interest in and to the Inter-Company Power Agreement among Ohio Valley Electric Corporation ("OVEC"), Appalachian Power Company, The Cincinnati Gas & Electric Company, Columbus Southern Power Company, The Dayton Power and Light Company, Indiana Michigan Power Company, Kentucky Utilities Company, Louisville Gas and Electric Company, Monongahela Power Company, Ohio Edison Company, Pennsylvania Power Company, The Potomac Edison Company, Southern Indiana Gas and Electric Company, The Toledo Edison Company and West Penn, dated July 10, 1953, as amended from time to time (the "Agreement"), which sets forth the terms and conditions under which the Sponsoring Companies, as defined in the Agreement, are obligated to deliver supplemental energy to OVEC, or are entitled to receive surplus energy from OVEC, as the case may be. AEP Operating Companies acknowledge that the Agreement is a rate schedule on file with the Federal Energy Regulatory Commission ("FERC"), and that this Assignment shall be duly filed with FERC. AEP Operating Companies agree to pay PMA ten dollars ($10.00) in consideration for the assignment of the Agreement by AEP Operating Companies to PMA. AEP Operating Companies warrant that the Agreement is valid and enforceable, that it is in full force and effect and has not been breached by AEP Operating Companies and that there Exhibit I Annex 4 Page 2 of 5 are no offsets or counter-claims against AEP Operating Companies by any party to the Agreement. PMA agrees to perform all of the obligations and duties of AEP Operating Companies under the Agreement. AEP Operating Companies, however, shall remain responsible for performance of any obligations that arise under the Agreement in the event PMA is for any reason unable to perform those obligations. Accepted and agreed to this ________ day of _______________, 2001. APPALACHIAN POWER COMPANY _________________________________ Name: Title: COLUMBUS SOUTHERN POWER COMPANY _________________________________ Name: Title: INDIANA MICHIGAN POWER COMPANY _________________________________ Name: Title: -2- Exhibit I Annex 4 Page 3 of 5 OHIO POWER COMPANY _________________________________ Name: Title: POWER MARKETING AFFILIATE _________________________________ Name: Title: -3- Exhibit I Annex 4 Page 4 of 5 CONSENT TO ASSIGNMENT The undersigned on behalf of the indicated principal consents to the attached assignment, in the form attached, from Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company or Ohio Power Company (referred to collectively as the "AEP Operating Companies") to Power Marketing Affiliate, in the form attached, of all AEP Operating Companies' right, title and interest in the inter-company power agreement among Ohio Valley Electric Corporation et al. dated July 10, 1953 as amended from time to time. Appalachian Power Company The Cincinnati Gas and Electric Company By:______________________________ By:____________________________________ Ohio Valley Electric Corporation Columbus Southern Power Company By:______________________________ By:____________________________________ The Dayton Power and Light Company Indiana Michigan Power Company By:______________________________ By:____________________________________ Kentucky Utilities Company Louisville Gas and Electric Company By:______________________________ By:____________________________________ Monongahela Power Company Ohio Edison Company By:______________________________ By:____________________________________ -4- Exhibit I Annex 4 Page 5 of 5 Pennsylvania Power Company The Potomac Edison Company By:______________________________ By:_______________________________ Southern Indiana Gas and Electric Company The Toledo Edison Company By:______________________________ By:_______________________________ West Penn Power Company By:______________________________ -5- Exhibit I Annex 5 Page 1 of 3 ASSIGNMENT OF WHOLESALE SERVICE AGREEMENT THIS ASSIGNMENT AGREEMENT ("Assignment Agreement") is made and entered into as of this __________________ day of _____________ [YEAR] by and between [NAME OF SELLER UNDER SERVICE AGREEMENT TO BE ASSIGNED] ("Seller"), a corporation organized under the laws of the State of ______________ and Power Marketing Affiliate ("PMA"), a corporation organized under the laws of the State of ______________ (hereinafter referred to collectively as the "Parties" and individually as "Party"). [NAME OF WHOLESALE CUSTOMER UNDER SERVICE AGREEMENT TO BE ASSIGNED] ("Customer"), a corporation organized under the laws of the State of _________ also is executing this Assignment Agreement to evidence its consent thereto. WITNESSETH WHEREAS, Seller and Customer have entered into a [NAME OF AGREEMENT] ("ELECTRIC SERVICE AGREEMENT"), dated as of [DATE], as heretofore amended, modified and supplemented, pursuant to which Seller provides to Customer capacity and associated energy; WHEREAS, Seller desires to assign, transfer, and delegate to [ASSIGNEE] and [ASSIGNEE] is willing to accept assignment, transfer, and delegation from Seller of all of Seller's rights, interests, duties, and obligations under the Electric Service Agreement, pursuant to the terms of this Assignment Agreement; WHEREAS, the Electric Service Agreement provides that the Electric Service Agreement may be assigned; and WHEREAS, Customer desires to give its consent to the assignment, transfer, and delegation of Seller's rights, interests, duties, and obligations under the Electric Service Agreement to Assignee; NOW, THEREFORE, in consideration of the premises and mutual covenants set forth herein, the Parties agree as follows: 1. Seller hereby assigns, transfers, and delegates to Assignee all of Seller's rights, interests, duties, and obligations under the Electric Service Agreement. Effective as of January 1, 2002, Assignee agrees to assume all of the rights, interests, duties, and obligations of Seller under the Electric Service Agreement. 2. Each of the Parties warrants and represents that the execution and delivery of this Assignment Agreement has been duly authorized, and upon execution and delivery by such Party, shall be a valid and binding agreement, enforceable according to its terms. 3. This Assignment Agreement supersedes all previous representations, understandings, negotiations, and agreements, either written or oral, between the Parties or their representatives with respect to the subject matter hereof, and constitutes the entire agreement of the Parties with respect to the subject matter hereof. Exhibit I Annex 5 Page 2 of 3 4. This Assignment Agreement is made subject to all existing and future applicable federal, state, and local laws and to all existing and future duly promulgated orders or other duly authorized actions of governmental authorities having jurisdiction over the matters set forth in this Assignment Agreement. 5. The interpretation and performance of this Assignment Agreement shall be in accordance with the laws of the State of _____________ excluding conflicts of law principles that would require the application of the laws of a different jurisdiction. 6. The numbered paragraphs contained in this Assignment Agreement are solely for the convenience of the Parties and should not be used or relied upon in any manner in the construction or interpretation of this Assignment Agreement. 7. If any provision of this Assignment Agreement is found to be invalid, illegal, or unenforceable by reason of any existing or subsequently enacted legislation or by decree of a court of competent jurisdiction, such legislation or decree shall not impair, invalidate, or nullify the remainder of this Assignment Agreement, which shall remain in full force and effect. In such circumstances, the Parties agree to negotiate in good faith to replace such provision and restore the relative allocation of economic risks and benefits between the Parties as reflected herein. 8. This Assignment Agreement may be executed in any number of counterparts, each of which shall be an original, but all of which together shall constitute one and the same instrument. IN WITNESS WHEREOF, the Parties have executed this Assignment Agreement as of the date set forth at the beginning of this Assignment Agreement. [SELLER] By:____________________________ [ASSIGNEE] By:____________________________ Exhibit I Annex 5 Page 3 of 3 CONSENT BY [CUSTOMER] Customer is executing this Assignment Agreement to evidence its consent to the assignment, transfer, and delegation from Seller to Customer of all of Seller's rights, interests, duties, and obligations under the Power Supply Agreement, pursuant to the terms of this Assignment Agreement, effective as of January 1, 2002, and that from and after such date Seller shall be relieved of its obligations under the Electric Service Agreement, which shall be assumed by Assignee. [CUSTOMER] By:___________________________ EXHIBIT J STATEMENT CONCERNING CONSISTENCY OF THE TRANSFERS WITH THE PUBLIC INTEREST; EFFECT OF THE TRANSFERS ON COMPETITION, RATES AND REGULATION The Commission has applied its Merger Policy Statement(14) when evaluating similar asset transfers. The Transfers do not raise any issues under the Merger Policy Statement that should require a trial-type hearing or even lengthy or detailed review. In particular: o The Transfers will not raise any market power issues because they are strictly internal in nature and will not result in any increase in concentration of the markets in which APCo, I&M, CSP, OPCo, KPCO, CPL, WTU or SWEPCO, or any other AEP affiliate, participates, or in the control by the AEP System of transmission facilities. o The Transfers will not have any material adverse effect on the rates paid by the wholesale customers of APCo, I&M, CSP, OPCo, KPCO, CPL, WTU and SWEPCO. o The Transfers will not unreasonably impair effective federal or state regulation of CSP, OPCo, CPL, WTU and SWEPCO, or any of their affiliates that are subject to utility regulation. The proposed Transfers and corporate separation plans of CSP, OPCo, CPL, WTU and SWEPCO are similar to restructurings the Commission has authorized for other public utilities that have reorganized the ownership of their utility assets in order to comply with state restructuring laws. FIRST ENERGY CORP., 94 FERC Paragraph 61,179 (2001); PUBLIC SERVICE COMPANY OF NEW MEXICO, 93 FERC Paragraph 61,213 (2000); COMMONWEALTH EDISON COMPANY, 93 FERC Paragraph 61,020 (2000); CENTRAL ILLINOIS PUBLIC SERVICE COMPANY, ET AL., 89 FERC Paragraph 62,125 (1999); ILLINOIS POWER COMPANY, ET AL., 88 FERC Paragraph 62,229 (1999); NIAGARA MOHAWK POWER CORPORATION, 89 FERC Paragraph 61,124 (1999); and JERSEY CENTRAL POWER & LIGHT COMPANY, 87 FERC Paragraph 61,104 (1999). ---------- (14) INQUIRY CONCERNING THE COMMISSION'S MERGER POLICY UNDER THE FEDERAL POWER ACT: POLICY STATEMENT, ORDER NO. 592, III FERC Stats. & Regs. Paragraph 31,044 (1996) (codified at 18 C.F.R.ss. 2.26) (hereinafter, the "Merger Policy Statement"). A. THE TRANSFERS WILL NOT ADVERSELY AFFECT COMPETITION Neither the Transfers of the generating assets of CPL and WTU to subsidiaries of Domestic Genco nor the assignment to PMA of the interests of APCo, OPCo, CSP and I&M in the OVEC Agreement and the Rockport Agreement will result in any change in ultimate control of such assets. Such generating assets and contract rights to other power supply resources will be controlled by AEP both before and after the Transfers. Accordingly, market concentration data and market shares will remain as they were before the Transfers and will improve when a substantial part of CPL's generating fleet is divested to new owners in 2002. The AEP operating companies are committed to participation in RTOs. CSP EDC and OPCo EDC will participate in the Alliance RTO, which the Commission has approved in most respects, and will thereby carry out the commitments made by AEP in connection with its merger with CSW in Docket No. EC98-40-000 to join a Commission-approved RTO by December 15, 2001. SWEPCO and PSO have been leaders in the development of the SPP RTO, and are committed to the establishment of a Commission-approved RTO. PSO and SWEPCO support the participation of SPP transmission owners in a larger RTO, as the Commission has recommended. CPL EDC and WTU EDC will operate under the supervision of the ERCOT independent transmission organization approved by the PUCT. These RTO commitments of the AEP operating companies will ensure the availability of non-discriminatory access to transmission facilities and related ancillary services in accordance with the access policies enunciated by the Commission in Order No. 2000. B. THE TRANSFERS WILL NOT IMPAIR EFFECTIVE REGULATION The Transfers cannot impair effective regulation because the new affiliates of CSP, OPCo, CPL, WTU and SWEPCO that take title to jurisdictional facilities by means of the Transfers will be subject to regulation by this Commission after the Transfers except with respect 2 to intrastate sales of electricity in ERCOT. The Applicants are already members of a registered public utility holding company system and in connection with the AEP/CSW merger committed to this Commission's review of affiliate dealings. AMERICAN ELECTRIC POWER COMPANY, INC. AND CENTRAL AND SOUTHWEST CORPORATION, 85 FERC Paragraph 61,201 at 61,821-22 (1998). Consequently, the Transfers do not present OHIO POWER concerns. After the corporate separation is completed, OPCo PGC, CSP PGC, CPL PGC and WTU PGC will no longer be subject to rate regulation by state regulatory commissions; however, this is the necessary result of implementing the electric utility regulatory laws of Ohio and Texas. Also, after corporate separation, intrastate sales made by CPL PGC, WTU PGC and PMA to purchasers in ERCOT will not be subject to regulation by the Commission. TXU TRADING COMPANY, 91 FERC Paragraph 61, 242 (2000) ("sales for re-sale within ERCOT are governed by Texas LAW"); DESTEC POWER SERVICES, INC., 72 FERC Paragraph 61,277 (1995). Again, this is the result of a state policy to establish a competitive wholesale power market that is subject to safeguards that are consistent with the standards employed by the Commission in establishing market-based rates. Under Section 39.154 OF S.B. 7, no PGC operating in ERCOT may own or control more than 20 percent of the installed generating capacity located in, or capable of delivering electricity to, ERCOT. In addition, under Section 39.153 OF S.B. 7, at least 60 days before the start of retail choice in Texas, CPL and WTU (as well as SWEPCO) must auction off entitlements to at least 15 percent of their installed generation. Such entitlements must continue in effect for at least five years after the start of retail competition in ERCOT, or in the case of CPL PGC until it completes its planned divestiture of generating units in 2002. Under Sections 39.155, 39.156 and 39.157 of S.B. 7, the PUCT has been given broad authority to monitor and address market power problems that may develop after the start of retail choice. 3 Applicants' EDC affiliates will continue to be subject to regulation of electric delivery and default power supply services by the PUCT and the PUCO and regulation of interstate transmission services by the Commission. Further, the Applicants' corporate separation plans have been reviewed and approved by state utility regulators in Texas and Ohio (see Exhibit L). C. THE TRANSFERS WILL NOT ADVERSELY AFFECT RATES The rates at which the Applicants now provide wholesale requirements services are set forth in the power supply agreements and related tariffs that will be assigned and transferred. The wholesale requirements contracts that AEPSC will assign to PMA are not subject to fuel adjustment clauses and the Transfers will not affect the rates stated in such agreements, which are not subject to unilateral change. OPCo PGC, CSP PGC and SWEPCO will retain their existing wholesale requirements contracts with unaffiliated purchasers. Although such contracts do not entitle the purchasers to have their requirements supplied from particular power supply resources, customers served under such contracts will generally continue to be served from the same power supply resources that are currently used to serve them and, hence, such customers will not be materially adversely affected by the Transfers.(15) The existing wholesale requirements of CPL and WTU will be assigned to CPL PGC and WTU PGC, respectively, resulting in such customers continuing to be served from the same generation that is currently used to ---------- (15) SEE ATLANTIC CITY ELECTRIC CO., 90 FERC Paragraph 61,268 at 61,899 (2000) (holding that a customer had "no contractual right to receive service from specific generating resources ... nor does the contract prevent the acquisition or sale of facilities[.]"); PUBLIC SERVICE ELECTRIC AND GAS CO., 88 FERC Paragraph 61,299 at 61,917 (1999) (rejecting intervenor's arguments that it had a right to service from specific generating resources and therefore the contract should not be assigned to an affiliate power marketer and explaining that the agreement did not specify generating resources or a specific price); NEW YORK STATE ELECTRIC & GAS CORP., ORDER DENYING REH'G., 86 FERC Paragraph 61,284 at 62,023 (1999) (rejecting intervenor's arguments that the sale of a low cost generating unit would impermissibly increase rates and holding that such arguments should be raised in a Section 206 complaint alleging that rates are no longer just and reasonable); JERSEY CENTRAL POWER &.LIGHT CO., 87 FERC Paragraph 61,014 (1999). 4 serve them even though such customers have no rights to be served from particular power supply resources. CPL and WTU make full and partial requirements wholesale power sales to the cooperative and municipal customers listed on Exhibit F. Such sales are generally made at stated base rates, which are subject to adjustment pursuant to a fuel adjustment clause that is consistent with Section 35.14 of the Commission's regulations. The rates applicable to such sales are subject to unilateral rate change filings made pursuant to Section 205 of the Federal Power Act, except in the case of WTU's full requirements sales to customers served under WTU's Wholesale Power Choice Tariff, WTU FERC Electric Tariff No. 9, which are made at stated base rates that are fixed until December 31, 2007, WTU's-full requirements sales to the City of Hearne, Texas, WTU FERC Rate Schedule No. 25, which are made at base customer, demand and energy rates that are fixed until March 31, 2003 and WTU's partial requirements sale to Brazos Electric Power Cooperative, Inc., which is made at base customer, demand and energy rates that are fixed through December 31, 2002, when that sale will end. With the exception of North Carolina Electric Membership Corporation (NCEMC), all wholesale requirements customers of the AEP operating companies listed on Exhibit F are hereby offered an "open season" to contract with other power suppliers for service beginning no later than January 1, 2003, by giving 180 days' prior written notice to terminate their existing contracts. NCEMC's contract with APCo, which continues in effect through 2010, contains fixed demand charges that were back-end loaded. An open season enables customers, if they so choose, to avoid any increased costs incurred by their suppliers as the result of the Transfers.(16) If NCEMC were permitted to abandon the contract now, it would receive a windfall from having paid demand charges from the beginning of the contract term in 1996 until the present that were ---------- (16) NEW YORK STATE ELECTRIC & GAS CORP., 86 FERC Paragraph 61,284 at 62,023 (1999). 5 substantially less than the agreed upon demand-related revenue requirement. Because the demand charges are fixed by contract, they will not be affected by APCo's assigning the NCEMC contract to OPCo. CPL and WTU hereby offer to freeze through the earlier of the termination dates of such contracts, or december 31, 2004, the base rates set forth in those of their existing wholesale requirements contracts listed in Exhibit F that they will assign to CPL PGC or WTU PGC that are subject to unilateral rate change filings. Rates for transmission services and rates for generation-based ancillary services will also be unaffected by the Transfers. CPL EDC and WTU EDC will continue to provide new transmission service in accordance with the transmission pricing and access rules of the PUCT as memorialized in open access transmission tariffs filed with this Commission consistent with PUCT transmission policies and ERCOT Protocols. SWEPCO EDC will provide new transmission service under the open access transmission tariff of the Southwest Power Pool (or its successor in function) and will continue existing transactions under the AEP open access transmission tariff (OATT).(17) CSP EDC and OPCo EDC will provide new transmission service under the open access transmission tariff of the Alliance RTO, and will continue existing transactions under the AEP OATT. Generation-based ancillary services will be available from the ERCOT ISO, the Southwest Power Pool or other RTO in which SWEPCO EDC, SWEPCO and PSO participate, and the Alliance RTO, as the case may be, and the generation controlled by Domestic Genco will be subject to redispatch orders of the Alliance RTO, the SPP RTO (or its ---------- (17) At a time closer to completion of the Transfers, AEPSC will file changes in the AEP OATT to reflect changes in the ownership of the transmission facilities that will occur as the result of the Transfers. 6 successor in function) and the ERCOT ISO, as the case may be, in order to clear transmission constraints. Retail rates in Texas are frozen until January 1, 2002. On and after January 1, 2002, all Texas retail customers now served by CPL, WTU and SWEPCO will have choice in their retail providers, except for certain large retail customers whose contracts have terms that extend beyond January 1, 2002. The rates at which CPL REP, WTU REP and SWEPCO REP may furnish retail electric service to residential and small commercial customers on and after that date will be limited to a "price to beat" set by the PUCT, which will be approximately 6% lower than the frozen retail rates now in effect. The rates Ohio retail residential customers will pay for power supply costs have been reduced by five percent, and retail rates in Ohio will be frozen for all retail customers for the first five years of retail competition, unless the PUCO finds that effective competition for one or more customer classes is in place before the end of the five-year period. 7 EXHIBIT K MAPS Attached hereto are system maps for CPL, WTU, SWEPCO, CSP, and OPCo that show the location of their respective generating stations and high voltage transmission lines. [MAPS OMITTED] EXHIBIT L REGULATORY ORDERS The SEC must approve the Transfers under the 1935 Act. The Nuclear Regulatory Commission must approve the transfer of the operating licenses for CPL's interest in the South Texas Project Nuclear Generating Station. SWEPCO must obtain authority from the Louisiana Public Service Commission to transfer its transmission assets to SWEPCO EDC. The PUCT has already approved the Transfers to be made by CPL, WTU and SWEPCO, and the PUCO has already approved the Transfers to be made by CSP and OPCo. Copies of the orders of the PUCO and the PUCT, together with the stipulations that underlie such orders, are attached. ATTACHMENT 1 RESTATED AND AMENDED AEP-EAST INTERCONNECTION AGREEMENT Original Sheet No. 1 First Revised Appalachian Power Company Rate Schedule No. FPC No. 20 First Revised Kentucky Power Company Rate Schedule No. FPC No. 11 First Revised Indiana Michigan Power Company Rate Schedule No. FPC No. 17 -------------------------------------------------------------------------------- RESTATED AND AMENDED INTERCONNECTION AGREEMENT APPALACHIAN POWER COMPANY, KENTUCKY POWER COMPANY, INDIANA MICHIGAN POWER COMPANY AND AMERICAN ELECTRIC POWER SERVICE CORPORATION AS AGENT EFFECTIVE JANUARY 1, 2002 -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Original Sheet No. 2 First Revised Appalachian Power Company Rate Schedule No. FPC No. 20 First Revised Kentucky Power Company Rate Schedule No. FPC No. 11 First Revised Indiana Michigan Power Company Rate Schedule No. FPC No. 17 -------------------------------------------------------------------------------- RESTATED AND AMENDED INTERCONNECTION AGREEMENT THIS RESTATED AND AMENDED INTERCONNECTION AGREEMENT is made and entered into as of this _ day________________, of 2001, by and among Appalachian Power Company ("APC"), Kentucky Power Company ("KPC"), Indiana Michigan Power Company ("I&M") and American Electric Power Service Corporation (as defined below, "AEPSC") as agent to the other parties (as defined below, "Agent"). Ohio Power Company ("OPC") and Columbus Southern Power Company ("CSP") are executing this Agreement solely for the purposes of Section 13.7. WHEREAS, APC, KPC, I&M, OPC, and CSP (collectively the "Utility Signatories") own and operate interconnected electric generation, transmission and distribution facilities with which they are engaged in the business of generating, transmitting and selling electric power and energy to the general public and to other electric utilities; WHEREAS, the Utility Signatories and the Agent coordinate the planning, construction, operation and maintenance of the Utility Signatories' electric supply facilities on an integrated basis pursuant to an Interconnection Agreement dated July 6, 1951, as subsequently modified and supplemented (the "AEP Interconnection Agreement"); WHEREAS, the Utility Signatories' electric facilities are now and have been for many years interconnected through their respective transmission facilities and transmission facilities of third parties at a number of points (hereby designated and hereinafter called "Interconnection Points"); -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Original Sheet No. 3 First Revised Appalachian Power Company Rate Schedule No. FPC No. 20 First Revised Kentucky Power Company Rate Schedule No. FPC No. 11 First Revised Indiana Michigan Power Company Rate Schedule No. FPC No. 17 -------------------------------------------------------------------------------- WHEREAS, OPC and CSP are required under Ohio law to separate the ownership of their power supply assets and operations from their energy delivery assets and obligations by January 1, 2002; WHEREAS, on and after January 1, 2002, OPC and CSP will no longer have public utility obligations to Ohio retail customers and the power supply assets formerly owned by OPC and CSP will be operated in an unregulated Ohio competitive power supply market while APC, KPC and I&M will continue to have public utility obligations to retail customers in Tennessee, Virginia, West Virginia, Kentucky, Indiana, and Michigan; WHEREAS, APC, KPC, and I&M believe that they can continue to achieve efficiencies and economic benefits through the coordinated planning and operation of their respective power supply resources; WHEREAS, the Utility Signatories and the Agent wish to amend and restate the existing AEP Interconnection Agreement, in accordance with the terms hereof, in order to (a) remove OPC and CSP as parties and (b) provide for the dispatch on an integrated basis of the power supply assets of APC, KPC and I&M and to provide for internal energy transactions among APC, KPC and I&M on a basis that fosters economic operations and can accommodate implementation of future deregulation initiatives; WHEREAS, the achievement of the foregoing will be facilitated by the performance of certain services by an agent; WHEREAS, AEPSC is the service company affiliate of APC, KPC and I&M and as such performs a variety of services on their behalf in accordance with applicable rules and -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Original Sheet No. 4 First Revised Appalachian Power Company Rate Schedule No. FPC No. 20 First Revised Kentucky Power Company Rate Schedule No. FPC No. 11 First Revised Indiana Michigan Power Company Rate Schedule No. FPC No. 17 -------------------------------------------------------------------------------- regulations of the Securities and Exchange Commission promulgated under the Public Utility Holding Company Act of 1935; and WHEREAS, AEPSC is willing to serve as Agent to APC, KPC and I&M under this Agreement with respect to generation-related activities. NOW, THEREFORE, in consideration of the premises and the mutual covenants and agreements herein set forth, the Parties mutually agree as follows: ARTICLE I DEFINITIONS 1.1 AEP INTERCONNECTION AGREEMENT has the meaning set forth in the second recital clause. 1.2 AEPSC means American Electric Power Service Corporation, a wholly- owned subsidiary of American Electric Power Company, Inc. and a service company affiliate of APC, KPC and I&M. 1.3 AGENT means the Parties' designated representative for the purposes specified in Article V and elsewhere in this Agreement. The Agent will be AEPSC. 1.4 AGREEMENT means this Restated and Amended Operating Agreement, including all Service Schedules and attachments hereto, as it may be amended from time to time. 1.5 APC means Appalachian Power Company. 1.6 CSP means Columbus Southern Power Company. 1.7 DECREMENTAL COST means the costs avoided by an Operating Company solely by reason of its purchase of an incremental amount of energy from another Operating Company, including but not limited to costs for fuel, reactive power, labor, operation, maintenance, start-up, fuel handling, taxes, emission allowances, and transmission and ancillary -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Original Sheet No. 5 First Revised Appalachian Power Company Rate Schedule No. FPC No. 20 First Revised Kentucky Power Company Rate Schedule No. FPC No. 11 First Revised Indiana Michigan Power Company Rate Schedule No. FPC No. 17 -------------------------------------------------------------------------------- service charges and losses. Such costs may also include costs that otherwise would have been paid for energy to third parties if such costs would have been less than the Operating Company's own cost of generating the same amount of energy or such purchases would have been required to serve load requirements. 1.8 FERC means the Federal Energy Regulatory Commission or any successor agency having jurisdiction over this Agreement. 1.9 I&M means Indiana Michigan Power Company. 1.10 INCREMENTAL COST means any costs incurred by an Operating Company solely by reason of its provision of an incremental amount of energy to supply to another Operating Company, including but not limited to costs for fuel, reactive power, labor, operation, maintenance, start-up, fuel handling, taxes, emission allowances, and transmission and ancillary service charges and losses, and charges for any power and energy purchased that is reasonably allocated by the Agent to such supply, and other expenses incurred that would not have been incurred if the supply had not been provided to the other Operating Company. 1.11 INDUSTRY STANDARDS means those principles, guides, criteria, standards, and practices referred to in Article XI. 1.12 INTERCONNECTION POINTS shall have the meaning set forth in the fourth recital clause. 1.13 KPC means Kentucky Power Company. 1.14 OFF-SYSTEM SALES means all sales of power and energy to customers of the Operating Companies other than Retail Customers, Wholesale Requirements Customers, and affiliates of American Electric Power Company, Inc. -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Original Sheet No. 6 First Revised Appalachian Power Company Rate Schedule No. FPC No. 20 First Revised Kentucky Power Company Rate Schedule No. FPC No. 11 First Revised Indiana Michigan Power Company Rate Schedule No. FPC No. 17 -------------------------------------------------------------------------------- 1.15 OFF-SYSTEM PURCHASES means purchases from a third party of capacity and/or energy to reduce power supply costs, to provide reliability of supply for the Operating Companies, or to engage in Off-System Sales. 1.16 OPC means Ohio Power Company. 1.17 OPERATING COMMITTEE means the administrative body established pursuant to Article V1 for the purposes therein specified. 1.18 OPERATING COMPANIES means APC, KPC and I&M, collectively. 1.19 OPERATING COMPANY means APC, KPC or I&M, individually. 1.20 PARTY or PARTIES means one or more of the following, individually or collectively, as the context warrants: APC, KPC, I&M, and Agent. 1.21 RETAIL CUSTOMER for purposes of this Agreement means a retail power customer on whose behalf an Operating Company has undertaken an obligation to obtain power supply resources so as to supply electricity to reliably meet the electric need of such customer, either directly or through affiliates having retail load obligations. 1.22 SERVICE SCHEDULES means the Service Schedules attached to this Agreement and those that later may be agreed to by the Parties and accepted for filing by FERC, as they may be amended from time to time. 1.23 SYSTEM EMERGENCY means a condition which, if not promptly corrected, threatens to cause imminent harm to persons or property, including the equipment of a Party or a third party, or threatens the reliability of electric service provided by an Operating Company to Retail Customers or Wholesale Requirements Customers. 1.24 UTILITY SIGNATORIES has the meaning set forth in the first recital clause. -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Original Sheet No. 7 First Revised Appalachian Power Company Rate Schedule No. FPC No. 20 First Revised Kentucky Power Company Rate Schedule No. FPC No. 11 First Revised Indiana Michigan Power Company Rate Schedule No. FPC No. 17 -------------------------------------------------------------------------------- 1.25 WHOLESALE REQUIREMENTS CUSTOMER means a customer whose loads are served from an Operating Company's transmission system and that such Operating Company has undertaken, by contract, to serve with respect to such customer's partial or full requirements at cost-based rates and to acquire power supply resources and other resources necessary to meet such requirements. ARTICLE 11 TERM OF AGREEMENT 2.1 TERM; WITHDRAWAL Subject to FERC approval or acceptance for filing, this Agreement shall take effect on January 1, 2002, and shall continue in full force and effect until terminated: (a) by mutual agreement; (b) upon twelve (12) months' written notice by one Party to each of the other Parties; or (c) if one of the Operating Companies has withdrawn as a Party in accordance with the immediately following sentence, as of the date that either of the remaining Operating Companies no longer has Retail Customers other than default service customers that an Operating Company serves as a provider of last resort in a state whose regulatory policy requires competition in retail power supply. An Operating Company may, upon twelve (12) months' written notice to the other Parties, withdraw as a Party to this Agreement if under state law it will no longer have Retail Customers other than default service customers that such Operating Company serves as a provider of last resort in a state whose regulatory policy requires competition in retail power supply. An Operating Company that serves Retail Customers in more than one state may, upon twelve (12) months' written notice to the other Parties, terminate the applicability of this Agreement to its operations in any such state if under state law it will no longer have Retail Customers in such state, other than default service customers that such -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Original Sheet No. 8 First Revised Appalachian Power Company Rate Schedule No. FPC No. 20 First Revised Kentucky Power Company Rate Schedule No. FPC No. 11 First Revised Indiana Michigan Power Company Rate Schedule No. FPC No. 17 -------------------------------------------------------------------------------- Operating Company serves as the provider of last resort in light of such state's policy requiring competition in retail power supply. 2.2 PERIODIC REVIEW This Agreement will be reviewed periodically by the Operating Committee to determine whether revisions are necessary or appropriate. ARTICLE III OBJECTIVES 3.1 PURPOSE The purpose of this Agreement is to provide a contractual basis for coordinating the planning, operation, and maintenance of the power supply resources of the Operating Companies to achieve economies and efficiencies consistent with the provision of reliable electric service and an equitable sharing of the benefits and costs of such coordinated arrangements. ARTICLE IV SCOPE AND RELATIONSHIP TO OTHER AGREEMENTS AND SERVICES 4.1 SCOPE The transactions governed by this Agreement are subject to, and may be limited from time to time by, applicable state and federal laws, and the regulations, rules, and orders of applicable regulatory agencies regarding the purchase and sale of energy and/or capacity among affiliates. This Agreement is not intended to preclude the Parties from entering into other arrangements between or among themselves or with third parties. -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Original Sheet No. 9 First Revised Appalachian Power Company Rate Schedule No. FPC No. 20 First Revised Kentucky Power Company Rate Schedule No. FPC No. 11 First Revised Indiana Michigan Power Company Rate Schedule No. FPC No. 17 -------------------------------------------------------------------------------- 4.2 TRANSMISSION This Agreement is intended to apply to the coordination of the power supply resources of, and loads served by, the Operating Companies. It is not intended to apply to the coordination of transmission facilities owned or operated by the Operating Companies. ARTICLE V AGENT 5.1 AGENT'S FUNCTIONS Subject to the direction of the Operating Committee, Agent agrees to: (a) evaluate and make recommendations concerning power supply resources additions to be installed or acquired to meet the load requirements of the Operating Companies or to make Off-System Sales; (b) coordinate the operation and maintenance of the Operating Companies' power supply resources; (c) coordinate the economic dispatch of power supply resources for the Operating Companies; (d) conduct Off-System Purchases and Off-System Sales on behalf of the Operating Companies; (e) prepare and deliver to the Parties all bills and billing information relating to transactions pursuant to this Agreement; (f) acquire and coordinate transmission and ancillary services from affiliated and non-affiliated transmission providers for use with respect to transactions between or among Operating Companies under this Agreement, Off-System Purchases and Off-System Sales; -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Original Sheet No. 10 First Revised Appalachian Power Company Rate Schedule No. FPC No. 20 First Revised Kentucky Power Company Rate Schedule No. FPC No. 11 First Revised Indiana Michigan Power Company Rate Schedule No. FPC No. 17 -------------------------------------------------------------------------------- (g) reassign transmission services obtained for wholesale merchant purposes on behalf of any Operating Company; (h) coordinate the Operating Companies' procurement of fuel and transportation services; and (i) perform such other activities and duties as may be assigned from time to time by the Operating Committee. 5.2 APPOINTMENT AND ACCEPTANCE OF AUTHORITY; DELEGATION OF DUTIES 5.2(A) APPOINTMENT OF AGENT As of January 1, 2002, the Operating Companies delegate to AEPSC as the Agent and AEPSC, as the Agent, hereby accepts responsibility and authority for the duties listed in Section 5.1 and elsewhere in this Agreement. Except as herein expressly established otherwise, the Agent shall perform each of those duties in consultation with the Operating Committee. 5.2(B) DELEGATION OF DUTIES With the prior written consent of the other Parties, AEPSC may assign all or a part of its responsibilities under this Agreement to another entity. ARTICLE VI COMPOSITION AND DUTIES OF THE OPERATING COMMITTEE 6.1 OPERATING COMMITTEE The Operating Committee is the administrative body created to administer this Agreement and shall consist of four (4) members. One member shall be a representative of APC, one member shall be a representative of KPC, one member shall be a representative of I&M, and the fourth member shall be a representative of the Agent. With respect to all duties and -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Original Sheet No. 11 First Revised Appalachian Power Company Rate Schedule No. FPC No. 20 First Revised Kentucky Power Company Rate Schedule No. FPC No. 11 First Revised Indiana Michigan Power Company Rate Schedule No. FPC No. 17 -------------------------------------------------------------------------------- decisions, the Operating Committee will take such action as reasonably necessary to permit each of the Operating Companies to fulfill its reliability obligations. 6.2 MEETING DATES The Operating Committee shall hold meetings at such times, means, and places as the members shall determine from time to time. Minutes of each Operating Committee meeting shall be prepared and maintained. 6.3 DECISIONS All decisions of the Operating Committee shall be by a majority vote of the members present or voting by proxy at the meeting at which the vote is taken. As necessary, recommendations will be made to the President of each Operating Company, the Chief Executive Officer of American Electric Power Company, Inc., or such other officer(s) or directors as may be appropriate. 6.4 DUTIES The Operating Committee shall have the following duties, unless such duties are otherwise assigned by a vote of the Operating Committee to the Agent, in which case the Agent shall perform such duties. The Operating Committee will be responsible for: (a) overseeing deployment of the power supply resources of the Operating Companies; (b) reviewing and making recommendations concerning the proportional sharing of costs and benefits under this Agreement among the Operating Companies; (c) administering this Agreement and recommending any amendments hereto, including such amendments that are proposed in response to a change in regulatory requirements applicable to one or more of the Operating Companies; -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Original Sheet No. 12 First Revised Appalachian Power Company Rate Schedule No. FPC No. 20 First Revised Kentucky Power Company Rate Schedule No. FPC No. 11 First Revised Indiana Michigan Power Company Rate Schedule No. FPC No. 17 -------------------------------------------------------------------------------- (d) reviewing and, if necessary, amending the duties and responsibilities of the Agent; and (e) ensuring coordination for other matters not specifically provided for herein that the Operating Committee considers necessary to the reliable and economic use of the Operating Companies' power supply resources. ARTICLE VII COORDINATED PLANNING AND OPERATIONS 7.1 COORDINATED SYSTEM PLANNING The Agent, under the direction of the Operating Committee, will, on an annual basis, or more frequently if circumstances dictate, assess the adequacy of the power supply resources of the Operating Companies from the perspective of each Operating Company and the Operating Companies collectively, taking into account reserve requirements, state integrated resource plans, as applicable, each Operating Company's load forecast, changing regulatory structures and requirements and all other criteria applicable by law or regulation to each Operating Company, and make a recommendation whether to acquire additional power supply resources for the benefit of such Operating Company. In making this evaluation, the Agent will assess whether economies and efficiencies may be achieved by selecting common power supply resources for more than one Operating Company, subject to regulatory, transmission, economic, and operational constraints. The Agent will determine also whether an Operating Company's resource needs could be met by the sale of capacity on a temporary basis pursuant to Section 7.3 or through purchase from a non-affiliated utility. Based on the Agent's evaluation, the Operating Committee will decide whether or not to add power supply resources for the benefit of more than one Operating Company. If it -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Original Sheet No. 13 First Revised Appalachian Power Company Rate Schedule No. FPC No. 20 First Revised Kentucky Power Company Rate Schedule No. FPC No. 11 First Revised Indiana Michigan Power Company Rate Schedule No. FPC No. 17 -------------------------------------------------------------------------------- decides to add such resources, the costs associated with such power supply resources will be allocated to the Operating Companies in proportion to their need for such power supply resources. Similarly, the Agent, under the direction of the Operating Committee, will, on an annual basis, or more frequently if circumstances dictate, assess whether an Operating Company has power supply resources in excess of its needs (short-term or long-term) that should be made available to the other Operating Companies or third parties. Notwithstanding any of the foregoing, the actual addition or disposition of power supply resources will be conditioned on compliance with all applicable state and other regulatory requirements; in no event will the Operating Committee or Agent acquire, assign, reassign, or dispose of power supply resources for an Operating Company in contravention of such requirements. 7.2 COORDINATED SYSTEM DISPATCH It is the intent of the Operating Companies to dispatch their combined power supply resources on a coordinated basis in real time to minimize total power supply costs for the Operating Companies. 7.3 CAPACITY SALES Whenever any Operating Company has surplus capacity and any other Operating Company has insufficient capacity, the Agent shall evaluate the feasibility of a capacity transaction between the Operating Companies. Such evaluation shall take into account the availability of transmission capacity, state resource procurement policies, and alternative opportunities for sales and purchases. The terms of any such transaction shall be set out in separate agreements or Service Schedules, which shall be subject to any necessary FERC approval. Notwithstanding the foregoing, an Operating Company will not enter into an -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Original Sheet No. 14 First Revised Appalachian Power Company Rate Schedule No. FPC No. 20 First Revised Kentucky Power Company Rate Schedule No. FPC No. 11 First Revised Indiana Michigan Power Company Rate Schedule No. FPC No. 17 -------------------------------------------------------------------------------- agreement to purchase capacity from another Operating Company if, at the time of agreement, the purchaser could acquire like amounts of capacity from a third party at lower cost. 7.4 ENERGY SALES An Operating Company will make energy available from its power supply resources to another Operating Company for the purposes and to the extent provided by this Agreement. 7.5 EMERGENCY RESPONSE In the event of a System Emergency, no adverse distinction shall be made between the customers of any of the Operating Companies. Each Operating Company shall, when so instructed by the Agent, make its power supply resources available in response to a System Emergency. Notwithstanding the foregoing, it is understood that transmission constraints may limit the ability of one Operating Company to respond to a System Emergency of another Operating Company. ARTICLE VIII ASSIGNMENT OF COSTS AND BENEFITS OF COORDINATED OPERATIONS 8.1 SERVICE SCHEDULES The costs and revenues associated with coordinated operations as described in Article VII shall be distributed in the manner provided from time to time in the Service Schedules. It is understood and agreed that all such Service Schedules are intended to establish an equitable sharing of costs and/or benefits among the Parties, and that circumstances may, from time to time, require a reassessment of the relative benefits and burdens of this Agreement, or of the methods used to apportion benefits and burdens or of the Service Schedules. Upon a -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Original Sheet No. 15 First Revised Appalachian Power Company Rate Schedule No. FPC No. 20 First Revised Kentucky Power Company Rate Schedule No. FPC No. 11 First Revised Indiana Michigan Power Company Rate Schedule No. FPC No. 17 -------------------------------------------------------------------------------- recommendation of the Operating Committee and agreement among the Parties, any of the Service Schedules may be amended as of any date agreed to by the Parties, subject to receipt of any necessary regulatory authorizations. ARTICLE IX BILLING PROCEDURES 9.1 RECORDS The Agent shall maintain such records as may be necessary to determine the assignment of costs and benefits of coordinated operations pursuant to this Agreement. Such records shall be made available to the Parties upon request. 9.2 MONTHLY STATEMENTS As promptly as practicable after the end of each calendar month, the Agent shall prepare a statement setting forth the monthly summary of costs and revenues allocated or assigned to the Parties in sufficient detail as may be needed for settlements under the provisions of this Agreement. As required, the Agent may provide such statements on an estimated basis and then adjust those statements for actual results. 9.3 BILLINGS AND PAYMENTS The Agent shall handle all billing between the Operating Companies and other entities with which they engage in Off-System Purchases and Off-System Sales pursuant to this Agreement. Payments among the Parties shall be made by remittance of the net amount billed or by making appropriate accounting entries on the books of the Parties. 9.4 TAXES Should any federal, state, or local tax, surcharge or similar assessment, in addition to those that may now exist, be levied upon the electric capacity, energy, or services to be -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Original Sheet No. 16 First Revised Appalachian Power Company Rate Schedule No. FPC No. 20 First Revised Kentucky Power Company Rate Schedule No. FPC No. 11 First Revised Indiana Michigan Power Company Rate Schedule No. FPC No. 17 -------------------------------------------------------------------------------- provided in connection with this Agreement, or upon the provider of service as measured by the electric capacity, energy, or services, or the revenue therefrom, such additional amount shall be included in the net billing described in Section 9.3. ARTICLE X FORCE MAJEURE 10.1 EVENTS EXCUSING PERFORMANCE No Party shall be liable to another Party for or on account of any loss, damage, injury, or expense resulting from or arising out of a delay or failure to perform, either in whole or in part, any of the agreements, covenants, or obligations made by or imposed upon the Parties by this Agreement, by reason of or through strike, work stoppage of labor, failure of contractors or suppliers of materials (including fuel), failure of equipment, environmental restrictions, riot, fire, flood, ice, invasion, civil war, commotion, insurrection, military or usurped power, order of any court or regulatory agency granted in any BONA FIDE legal proceedings or action, or of any civil or military authority either DE FACTO or DE JURE, explosion, Act of God or the public enemies, or any other cause reasonably beyond its control and not attributable to its neglect. A Party experiencing such a delay or failure to perform shall use due diligence to remove the cause or causes thereof; however, no Party shall be required to add to, modify or upgrade any facilities, or to settle a strike or labor dispute except when, according to its own best judgment, such action is advisable. -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Original Sheet No. 17 First Revised Appalachian Power Company Rate Schedule No. FPC No. 20 First Revised Kentucky Power Company Rate Schedule No. FPC No. 11 First Revised Indiana Michigan Power Company Rate Schedule No. FPC No. 17 -------------------------------------------------------------------------------- ARTICLE XI INDUSTRY STANDARDS 11.1 ADHERENCE TO RELIABILITY CRITERIA The Parties agree to conform to all applicable national and regional electric reliability council principles, guides, criteria, and standards and industry standard practices (collectively, "Industry Standards") as they affect the implementation of this Agreement. ARTICLE XII DELIVERY POINTS 12.1 DELIVERY POINTS All electric energy delivered under this Agreement shall be of the character commonly known as three-phase sixty-cycle energy, and shall be delivered at the various Interconnection Points where the transmission systems of the Operating Companies are interconnected, either directly or through transmission facilities of third parties, at the nominal unregulated voltage designated for such points, and at such other points and voltages as may be determined and agreed upon by the Operating Companies. ARTICLE XIII GENERAL 13.1 NO THIRD PARTY BENEFICIARIES This Agreement does not create rights of any character whatsoever in favor of any person, corporation, association, entity or power supplier, other than the Parties, and the obligations herein assumed by the Parties are solely for the use and benefit of the Parties. Nothing in this Agreement shall be construed as permitting or vesting, or attempting to permit or vest, in any person, corporation, association, entity or power supplier, other than the Parties, any -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Original Sheet No. 18 First Revised Appalachian Power Company Rate Schedule No. FPC No. 20 First Revised Kentucky Power Company Rate Schedule No. FPC No. 11 First Revised Indiana Michigan Power Company Rate Schedule No. FPC No. 17 -------------------------------------------------------------------------------- rights hereunder or in any of the resources or facilities owned or controlled by the Parties or the use thereof. 13.2 WAIVERS Any waiver at any time by a Party of its rights with respect to a default under this Agreement, or with respect to any other matter arising in connection with this Agreement, shall not be deemed a waiver with respect to any subsequent default or matter. Any delay, short of the statutory period of limitation, in asserting or enforcing any right under this Agreement, shall not be deemed a waiver of such right. 13.3 SUCCESSORS AND ASSIGNS This Agreement shall inure to the benefit of and be binding upon the Parties only, and their respective successors and assigns, and shall not be assignable by any Party without the written consent of the other Parties except to a successor in the operation of its properties by reason of a reorganization to comply with state or federal restructuring requirements, or a merger, consolidation, sale or foreclosure whereby substantially all such properties are acquired by or merged with those of such a successor. 13.4 LIABILITY AND INDEMNIFICATION Subject to any applicable state or federal law that may specifically restrict limitations on liability, each Party shall release, indemnify, and hold harmless the other Parties, their directors, officers and employees from and against any and all liability for loss, damage or expense alleged to arise from, or be incidental to, injury to persons and/or damage to property in connection with its facilities or the production or transmission of electric energy by or through such facilities, or related to performance or non-performance of this Agreement, including any negligence arising hereunder. In no event shall any Party be liable to another Party for any -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Original Sheet No. 19 First Revised Appalachian Power Company Rate Schedule No. FPC No. 20 First Revised Kentucky Power Company Rate Schedule No. FPC No. 11 First Revised Indiana Michigan Power Company Rate Schedule No. FPC No. 17 -------------------------------------------------------------------------------- indirect, special, incidental, or consequential damages with respect to any claim arising out of this Agreement. 13.5 SECTION HEADINGS The descriptive headings of the Articles and Sections of this Agreement are used for convenience only, and shall not modify or restrict any of the terms and provisions thereof. 13.6 NOTICE Any notice or demand for performance required or permitted under any of the provisions of this Agreement shall be deemed to have been given on the date such notice, in writing, is deposited in the U.S. mail, postage prepaid, certified or registered mail, addressed to the Parties at the addresses specified below: Appalachian Power Company 1 Riverside Plaza Columbus, Ohio 43215 Kentucky Power Company 1 Riverside Plaza Columbus, Ohio 43215 Indiana Michigan Power Company 1 Riverside Plaza Columbus, Ohio 43215 AGENT 1 Riverside Plaza Columbus, Ohio 43215 or in such other form or to such other address as the Parties may stipulate. 13.7 EFFECT ON OTHER AGREEMENTS This Agreement supersedes and replaces the AEP Interconnection Agreement, effective as of the date this Agreement is made effective as set out in Section 2.1. In light of the reorganization of OPC and CSP in accordance with state law, OPC and CSP withdrew as parties to the AEP -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Original Sheet No. 20 First Revised Appalachian Power Company Rate Schedule No. FPC No. 20 First Revised Kentucky Power Company Rate Schedule No. FPC No. 11 First Revised Indiana Michigan Power Company Rate Schedule No. FPC No. 17 -------------------------------------------------------------------------------- Interconnection Agreement as of midnight December 31, 2001 and are not parties to this Agreement. ARTICLE XIV REGULATORY APPROVAL 14.1 REGULATORY AUTHORIZATION This Agreement is subject to and conditioned upon its approval or acceptance for filing without material condition or modification by the FERC. In the event that this Agreement is not so approved or accepted for filing in its entirety without modification, or the FERC subsequently modifies this Agreement upon complaint or upon its own initiative, any Party may, irrespective of the notice provisions in Section 2.1, terminate this Agreement or the AEP Interconnection Agreement by giving thirty (30) days' advance written notice to the other Parties. 14.2 CHANGES It is contemplated by the Parties that it may be appropriate from time to time to change, amend, modify, or supplement this Agreement, including the Service Schedules and any other attachments that may be made a part of this Agreement, to reflect changes in operating practices or costs of operations or for other reasons. Any such changes to this Agreement shall be in writing executed by the Parties and subject to approval or acceptance for filing by the FERC. -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Original Sheet No. 21 First Revised Appalachian Power Company Rate Schedule No. FPC No. 20 First Revised Kentucky Power Company Rate Schedule No. FPC No. 11 First Revised Indiana Michigan Power Company Rate Schedule No. FPC No. 17 -------------------------------------------------------------------------------- IN WITNESS WHEREOF, the Parties have caused this Agreement to be executed and attested by their duly authorized officers on the day and year first above written. APPALACHIAN POWER COMPANY By: ____________________________________ Title: _________________________________ KENTUCKY POWER COMPANY By: ____________________________________ Title: _________________________________ INDIANA MICHIGAN POWER COMPANY By: ____________________________________ Title: _________________________________ AMERICAN ELECTRIC POWER SERVICE CORPORATION By: ____________________________________ Title: _________________________________ The undersigned are executing this Agreement solely for the purpose of Section 13.7 hereof. OHIO POWER COMPANY By: ____________________________________ Title: _________________________________ -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Original Sheet No. 22 First Revised Appalachian Power Company Rate Schedule No. FPC No. 20 First Revised Kentucky Power Company Rate Schedule No. FPC No. 11 First Revised Indiana Michigan Power Company Rate Schedule No. FPC No. 17 -------------------------------------------------------------------------------- COLUMBUS SOUTHERN POWER COMPANY By: ____________________________________ Title: _________________________________ -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Original Sheet No. 23 First Revised Appalachian Power Company Rate Schedule No. FPC No. 20 First Revised Kentucky Power Company Rate Schedule No. FPC No. 11 First Revised Indiana Michigan Power Company Rate Schedule No. FPC No. 17 -------------------------------------------------------------------------------- SERVICE SCHEDULE A ENERGY SALES A1 - DURATION This Service Schedule A shall become effective and binding when the Agreement of which it is a part becomes effective, and shall continue in full force and effect throughout the duration of the Agreement unless terminated or suspended. A2 - AVAILABILITY OF SERVICE This Service Schedule A governs sales of energy made pursuant to Section 7.4 of the Agreement, which are sales of energy not associated with sales of capacity. A3 - ENERGY TRANSFER PRICES A purchasing Operating Company ("Purchaser") shall pay a selling Operating Company ("Seller") the following amount for energy purchased under this Schedule A ("Transfer Price"):_ (1) The Seller's Incremental Costs plus (2) One-half the difference between: (a) the Purchaser's Decremental Costs; and (b) the Seller's Incremental Costs. -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Original Sheet No. 24 First Revised Appalachian Power Company Rate Schedule No. FPC No. 20 First Revised Kentucky Power Company Rate Schedule No. FPC No. 11 First Revised Indiana Michigan Power Company Rate Schedule No. FPC No. 17 -------------------------------------------------------------------------------- SERVICE SCHEDULE B OFF-SYSTEM SALES AND OFF-SYSTEM PURCHASES B1 - DURATION This Service Schedule B shall become effective and binding when the Agreement of which it is a part becomes effective, and shall continue in full force and effect throughout the duration of the Agreement unless terminated or suspended. B2 - APPLICABILITY Agent shall undertake Off-System Sales and Off-System Purchases on behalf of the Operating Companies. Where Agent undertakes these activities, revenues and expenses shall be allocated or arranged in accordance with this Service Schedule B. B3 - ALLOCATION OF SYSTEM PURCHASES AND SALES A. Off-System Purchases. Any expenses for an Off-System Purchase during an hour shall be distributed to the Operating Company(ies) receiving energy from the purchase to cover an energy deficiency during the hour. Any remaining expenses for an Off-System Purchase during such hour shall be distributed to the Operating Companies in proportion to the megawatt-hours of energy that would have been provided from the respective Operating Companies' other power supply resources that were displaced during such hour. B. Off-System Sales. Any revenues from Off-System Sales in an hour shall first be applied to reimburse the Incremental Costs of the Operating Companies that contributed to the sales in such hour. Net revenues remaining after such reimbursement shall be distributed to the Operating Companies in proportion to each Operating Company's generation for sales (including economy energy sales) less the amount of energy such Operating Company purchased from the other Operating Companies in such hour pursuant to Section 7.4 of this Agreement and Schedule A (but not less than zero). -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 ATTACHMENT 2 RESTATED AND AMENDED AEP-WEST OPERATING AGREEMENT Original Sheet No. 1 Public Service Company of Oklahoma, Rate schedule FERC No. 345 Southwestern Electric Power Company, Rate Schedule FERC No. 346 RESTATED AND AMENDED OPERATING AGREEMENT PUBLIC SERVICE COMPANY OF OKLAHOMA, SOUTHWESTERN ELECTRIC POWER COMPANY, AND AMERICAN ELECTRIC POWER SERVICE CORPORATION AS AGENT EFFECTIVE JANUARY 1, 2002 Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Original Sheet No. 2 Public Service Company of Oklahoma, Rate schedule FERC No. 345 Southwestern Electric Power Company, Rate Schedule FERC No. 346 RESTATED AND AMENDED OPERATING AGREEMENT THIS RESTATED AND AMENDED OPERATING AGREEMENT is made and entered into as of this __ day of _______________, 2001, by and among Public Service Company of Oklahoma ("PSO"), Southwestern Electric Power Company ("SWEPCO") and American Electric Power Service Corporation ("AEPSC") as agent to the other parties ("Agent"). WHEREAS, PSO and SWEPCO own and operate interconnected electric generation, transmission, and distribution facilities with which they are engaged in the business of generating, transmitting, and selling electric power and energy to the general public and to other electric utilities; WHEREAS, PSO and SWEPCO are parties to the Restated and Amended Operating Agreement among Central Power and Light Company (CPL), PSO, SWEPCO, West Texas Utilities Company (WTU) and Central and South West Services, Inc. (CSWS) dated January 1, 1997; WHEREAS, CSWS has been merged into AEPSC as of June 15, 2001 and CPL and WTU are required under Texas law to separate the ownership of their power supply assets and operations from their energy delivery assets and operations by January 1, 2002; WHEREAS, on and after January 1, 2002, CPL and WTU will no longer have public utility obligations to Texas retail customers and the power supply assets formerly owned by CPL and WTU will be operated in an unregulated Texas competitive power supply market while PSO and SWEPCO will continue to have public utility obligations to retail customers in Oklahoma, Arkansas and Louisiana; Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Original Sheet No. 3 Public Service Company of Oklahoma, Rate schedule FERC No. 345 Southwestern Electric Power Company, Rate Schedule FERC No. 346 WHEREAS, PSO, and SWEPCO believe that they can continue to achieve efficiencies and economic benefits through the coordinated planning and operation of their respective power supply resources; WHEREAS, the achievement of the foregoing will be facilitated by the performance of certain services by an agent; and WHEREAS, AEPSC is the service company affiliate of PSO and SWEPCO and as such performs a variety of services on their behalf in accordance with applicable rules and regulations of the Securities and Exchange Commission promulgated under the Public Utility Holding Company Act of 1935; and WHEREAS, AEPSC is willing to serve as Agent to PSO and SWEPCO under this Agreement with respect to generation-related activities; and NOW, THEREFORE, in consideration of the premises and the mutual covenants and agreements herein set forth, the Parties mutually agree as follows: ARTICLE I DEFINITIONS 1.1 AEPSC means American Electric Power Service Corporation, a wholly owned subsidiary of American Electric Power Company, Inc. and a service company affiliate of PSO and SWEPCO. 1.2 AGENT means the Parties' designated representative for the purposes specified in Article V and elsewhere in this Agreement. The Agent will be AEPSC. 1.3 AGREEMENT means this Restated and Amended Operating Agreement, including all Service Schedules and attachments hereto, as it may be amended from time to time. 1.4 DECREMENTAL COST means the costs avoided by an Operating Company solely by reason of its purchase of an incremental amount of energy from another Operating Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Original Sheet No. 4 Public Service Company of Oklahoma, Rate schedule FERC No. 345 Southwestern Electric Power Company, Rate Schedule FERC No. 346 Company, including but not limited to costs for fuel, reactive power, labor, operation, maintenance, start-up, fuel handling, taxes, emission allowances, and transmission and ancillary service charges and losses. Such costs may also include costs that otherwise would have been paid for energy to third parties if such costs would have been less than the Operating Company's own cost of generating the same amount of energy or such purchases would have been required to serve load requirements. 1.5 FERC means the Federal Energy Regulatory Commission or any successor agency having jurisdiction over this Agreement. 1.6 INCREMENTAL COST means any costs incurred by an Operating Company solely by reason of its provision of an incremental amount of energy to supply to the other Operating Company, including but not limited to costs for fuel, reactive power, labor, operation, maintenance, start-up, fuel handling, taxes, emission allowances, and transmission and ancillary service charges and losses, and charges for any power and energy purchased that is reasonably allocated by the Agent to such supply, and other expenses incurred that would not have been incurred if the supply had not been provided to the other Operating Company. 1.7 INDUSTRY STANDARDS means those principles, guides, criteria, standards, and practices referred to in Article XI. 1.8 OFF-SYSTEM SALES means all sales of power and energy to customers of the Operating Companies other than Retail Customers, Wholesale Requirements Customers, and affiliates of American Electric Power Company, Inc. 1.9 OFF-SYSTEM PURCHASES means purchases from a third party of capacity and/or energy to reduce power supply costs, to provide reliability of supply for the Operating Companies or to engage in Off-System Sales. Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Original Sheet No. 5 Public Service Company of Oklahoma, Rate schedule FERC No. 345 Southwestern Electric Power Company, Rate Schedule FERC No. 346 1.10 OPERATING COMMITTEE means the administrative body established pursuant to Article VI for the purposes therein specified. 1.11 OPERATING COMPANIES means PSO and SWEPCO. 1.12 OPERATING COMPANY means either PSO or SWEPCO. 1.13 PARTY OR PARTIES means one or more of the following, individually or collectively, as the context warrants: PSO, SWEPCO, and Agent. 1.14 PSO means Public Service Company of Oklahoma. 1.15 RETAIL CUSTOMER for purposes of this Agreement means a retail power customer on whose behalf an Operating Company has undertaken an obligation to obtain power supply resources so as to supply electricity to reliably meet the electric need of such customer, either directly or through affiliates having retail load obligations. 1.16 SERVICE SCHEDULES means the Service Schedules attached to this Agreement and those that later may be agreed to by the Parties and accepted for filing by FERC, as they may be amended from time to time. 1.17 SWEPCO means Southwestern Electric Power Company. 1.18 SYSTEM EMERGENCY means a condition which, if not promptly corrected, threatens to cause imminent harm to persons or property, including the equipment of a Party or a third party, or threatens the reliability of electric service provided by an Operating Company to Retail Customers or Wholesale Requirements Customers. 1.19 WHOLESALE REQUIREMENTS CUSTOMER means a customer whose loads are served from an Operating Company's transmission system and that such Operating Company has undertaken, by contract, to serve with respect to such customer's partial or full requirements at Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Original Sheet No. 6 Public Service Company of Oklahoma, Rate schedule FERC No. 345 Southwestern Electric Power Company, Rate Schedule FERC No. 346 cost-based rates and to acquire power supply resources and other resources necessary to meet such requirements. ARTICLE II TERM OF AGREEMENT 2.1 TERM Subject to FERC approval or acceptance for filing, this Agreement shall take effect on January 1, 2002, and shall continue in full force and effect until terminated: (a) by mutual agreement; (b) as of the date that either Operating Company no longer has Retail Customers other than default service customers that an Operating Company serves as the provider of last resort in a state whose regulatory policy requires competition in retail power supply; or (c) upon twelve (12) months' written notice by one Party to each of the other Parties. An Operating Company that serves Retail Customers in more than one state may, upon written notice to the other Parties, terminate the applicability of this Agreement to its operations in any such state when it no longer has Retail Customers in such state, other than default service customers that such Operating Company serves as the provider of last resort in light of such state's regulatory policy requiring competition in retail power supply. 2.2 PERIODIC REVIEW This Agreement will be reviewed periodically by the Operating Committee to determine whether revisions are necessary or appropriate. Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Original Sheet No. 7 Public Service Company of Oklahoma, Rate schedule FERC No. 345 Southwestern Electric Power Company, Rate Schedule FERC No. 346 ARTICLE III OBJECTIVES 3.1 PURPOSE The purpose of this Agreement is to provide a contractual basis for coordinating the planning, operation, and maintenance of the power supply resources of the Operating Companies to achieve economies and efficiencies consistent with the provision of reliable electric service and an equitable sharing of the benefits and costs of such coordinated arrangements. ARTICLE IV SCOPE AND RELATIONSHIP TO OTHER AGREEMENTS AND SERVICES 4.1 SCOPE The transactions governed by this Agreement are subject to, and may be limited from time to time by, applicable state and federal laws, and the regulations, rules, and orders of applicable regulatory agencies regarding the purchase and sale of energy and/or capacity among affiliates. This Agreement is not intended to preclude the Parties from entering into other arrangements between or among themselves or with third parties. 4.2 TRANSMISSION This Agreement is intended to apply to the coordination of the power supply resources of, and loads served by, the Operating Companies. It is not intended to apply to the coordination of transmission facilities owned or operated by the Operating Companies. Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Original Sheet No. 8 Public Service Company of Oklahoma, Rate schedule FERC No. 345 Southwestern Electric Power Company, Rate Schedule FERC No. 346 ARTICLE V AGENT 5.1 AGENT'S FUNCTIONS Subject to the direction of the Operating Committee, Agent agrees to: (a) evaluate and make recommendations concerning power supply resources additions to be installed or acquired to meet the load requirements of the Operating Companies or to make Off-System Sales; (b) coordinate the operation and maintenance of the Operating Companies' power supply resources; (c) coordinate the economic dispatch of power supply resources for the Operating Companies; (d) conduct Off-System Purchases and Off-System Sales on behalf of the Operating Companies; (e) prepare and deliver to the Parties all bills and billing information relating to transactions pursuant to this Agreement; (f) acquire and coordinate transmission and ancillary services from affiliated and non-affiliated transmission providers for use with respect to transactions between or among Operating Companies under this Agreement, Off-System Purchases and Off-System Sales; (g) reassign transmission services obtained for wholesale merchant purposes on behalf of any Operating Company; (h) coordinate the Operating Companies' procurement of fuel and fuel transportation services; and Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Original Sheet No. 9 Public Service Company of Oklahoma, Rate schedule FERC No. 345 Southwestern Electric Power Company, Rate Schedule FERC No. 346 (i) perform such other activities and duties as may be assigned from time to time by the Operating Committee. 5.2 APPOINTMENT AND ACCEPTANCE OF AUTHORITY; DELEGATION OF DUTIES 5.2(A) APPOINTMENT OF AGENT As of January 1, 2002, the Operating Companies delegate to AEPSC as the Agent and AEPSC, as the Agent, hereby accepts responsibility and authority for the duties listed in Section 5.1 and elsewhere in this Agreement. Except as herein expressly established otherwise, the Agent shall perform each of those duties in consultation with the Operating Committee. 5.2(B) DELEGATION OF DUTIES With the prior written consent of the other Parties, AEPSC may assign all or a part of its responsibilities under this Agreement to another entity. ARTICLE VI COMPOSITION AND DUTIES OF THE OPERATING COMMITTEE 6.1 OPERATING COMMITTEE The Operating Committee is the administrative body created to administer this Agreement and shall consist of three (3) members. One member shall be a representative of PSO, one member shall be a representative of SWEPCO, and the third member shall be a representative of the Agent. With respect to all duties and decisions, the Operating Committee will take such action as reasonably necessary to permit each of the Operating Companies to fulfill its reliability obligations. 6.2 MEETING DATES Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Original Sheet No. 10 Public Service Company of Oklahoma, Rate schedule FERC No. 345 Southwestern Electric Power Company, Rate Schedule FERC No. 346 The Operating Committee shall hold meetings at such times, means, and places as the members shall determine from time to time. Minutes of each Operating Committee meeting shall be prepared and maintained. 6.3 DECISIONS All decisions of the Operating Committee shall be by a majority vote of the members present or voting by proxy at the meeting at which the vote is taken. As necessary, recommendations will be made to the President of each Operating Company, the Chief Executive Officer of American Electric Power Company, Inc., or such other officer(s) or directors as may be appropriate. 6.4 DUTIES The Operating Committee shall have the following duties, unless such duties are otherwise assigned by a vote of the Operating Committee to the Agent, in which case the Agent shall perform such duties. The Operating Committee will be responsible for: (a) overseeing deployment of the power supply resources of the Operating Companies; (b) reviewing and making recommendations concerning the proportional sharing of costs and benefits under this Agreement among the Operating Companies; (c) administering this Agreement and recommending any amendments hereto, including such amendments that are proposed in response to a change in regulatory requirements applicable to one or more of the Operating Companies; (d) reviewing and, if necessary, amending the duties and responsibilities of the Agent; and Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Original Sheet No. 11 Public Service Company of Oklahoma, Rate schedule FERC No. 345 Southwestern Electric Power Company, Rate Schedule FERC No. 346 (e) ensuring coordination for other matters not specifically provided for herein that the Operating Committee considers necessary to the reliable and economic use of the Operating Companies' power supply resources. ARTICLE VII COORDINATED PLANNING AND OPERATIONS 7.1 COORDINATED SYSTEM PLANNING The Agent, under the direction of the Operating Committee will, on an annual basis, or more frequently if circumstances dictate, assess the adequacy of the power supply resources of the Operating Companies from the perspective of each Operating Company and the Operating Companies collectively, taking into account reserve requirements, state integrated resource plans, as applicable, each Operating Company's load forecast, changing regulatory structures and requirements and all other criteria applicable by law, regulation or agreement to each Operating Company, and make a recommendation whether to acquire additional power supply resources for the benefit of such Operating Company. In making this evaluation, the Agent will assess whether economies and efficiencies may be achieved by selecting common power supply resources for more than one Operating Company, subject to regulatory, transmission, economic, and operational constraints. The Agent will determine also whether an Operating Company's resource needs could be met by the sale of capacity on a temporary basis pursuant to Section 7.3 or through purchase from a non-affiliated utility. Based on Agent's evaluation the Operating Committee will decide whether or not to add power supply resources for the benefit of more than one Operating Company. If it decides to add such resources, the costs associated with such power supply resources will be allocated to the Operating Companies in proportion to their need for such power supply resources. Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Original Sheet No. 12 Public Service Company of Oklahoma, Rate schedule FERC No. 345 Southwestern Electric Power Company, Rate Schedule FERC No. 346 Similarly, the Agent, under the direction of the Operating Committee, will, on an annual basis, or more frequently if circumstances dictate, assess whether an Operating Company has power supply resources in excess of its needs (short-term or long-term) that should be made available to the other Operating Company or third parties. Notwithstanding any of the foregoing, the actual addition or disposition of power supply resources will be conditioned on compliance with all applicable state and other regulatory requirements; in no event will the Operating Committee or Agent acquire, assign, reassign, or dispose of power supply resources for an Operating Company in contravention of such requirements. 7.2 COORDINATED SYSTEM DISPATCH It is the intent of the Operating Companies to dispatch their combined power supply resources on a coordinated basis in real time to minimize total power supply costs for the Operating Companies. 7.3 CAPACITY SALES Whenever any Operating Company has surplus capacity and the other Operating Company has insufficient capacity, the Agent shall evaluate the feasibility of a capacity transaction between the Operating Companies. Such evaluation shall take into account the availability of transmission capacity, state resource procurement policies, and alternative opportunities for sales and purchases. The terms of any such transaction shall be set out in separate agreements or Service Schedules, which shall be subject to any necessary FERC approval. Notwithstanding the foregoing, an Operating Company will not enter into an agreement to purchase capacity from the other Operating Company if, at the time of agreement, the purchaser could acquire like amounts of capacity from a third party at lower cost. Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Original Sheet No. 13 Public Service Company of Oklahoma, Rate schedule FERC No. 345 Southwestern Electric Power Company, Rate Schedule FERC No. 346 7.4 ENERGY SALES An Operating Company will make energy available from its power supply resources to the other Operating Company for the purposes and to the extent provided by this Agreement. 7.5 EMERGENCY RESPONSE In the event of a System Emergency, no adverse distinction shall be made between the customers of either Operating Company. Each Operating Company shall, when so instructed by the Agent, make its power supply resources available in response to a System Emergency. Notwithstanding the foregoing, it is understood that transmission constraints may limit the ability of one Operating Company to respond to a System Emergency of the other. ARTICLE VIII ASSIGNMENT OF COSTS AND BENEFITS OF COORDINATED OPERATIONS 8.1 SERVICE SCHEDULES The costs and revenues associated with coordinated operations as described in Article VII shall be distributed in the manner provided from time to time in the Service Schedules. It is understood and agreed that all such Service Schedules are intended to establish an equitable sharing of costs and/or benefits among the Parties, and that circumstances may, from time to time, require a reassessment of the relative benefits and burdens of this Agreement, of the methods used to apportion benefits and burdens or of the Service Schedules. Upon a recommendation of the Operating Committee and agreement among the Parties, any of the Service Schedules may be amended as of any date agreed to by the Parties, subject to receipt of any necessary regulatory authorizations. Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Original Sheet No. 14 Public Service Company of Oklahoma, Rate schedule FERC No. 345 Southwestern Electric Power Company, Rate Schedule FERC No. 346 ARTICLE IX BILLING PROCEDURES 9.1 RECORDS The Agent shall maintain such records as may be necessary to determine the assignment of costs and benefits of coordinated operations pursuant to this Agreement. Such records shall be made available to the Parties upon request. 9.2 MONTHLY STATEMENTS As promptly as practicable after the end of each calendar month, the Agent shall prepare a statement setting forth the monthly summary of costs and revenues allocated or assigned to the Parties in sufficient detail as may be needed for settlements under the provisions of this Agreement. As required, the Agent may provide such statements on an estimated basis and then adjust those statements for actual results. 9.3 BILLINGS AND PAYMENTS The Agent shall handle all billing between the Operating Companies and other entities with which they engage in Off-System Purchases and Off-System Sales pursuant to this Agreement. Payments among the Parties shall be made by remittance of the net amount billed or by making appropriate accounting entries on the books of the Parties. 9.4 TAXES Should any federal, state, or local tax, surcharge or similar assessment, in addition to those that may now exist, be levied upon the electric capacity, energy, or services to be provided in connection with this Agreement, or upon the provider of service as measured by the electric capacity, energy, or services, or the revenue therefrom, such additional amount shall be included in the net billing described in Section 9.3. Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Original Sheet No. 15 Public Service Company of Oklahoma, Rate schedule FERC No. 345 Southwestern Electric Power Company, Rate Schedule FERC No. 346 ARTICLE X FORCE MAJEURE 10.1 EVENTS EXCUSING PERFORMANCE No Party shall be liable to another Party for or on account of any loss, damage, injury, or expense resulting from or arising out of a delay or failure to perform, either in whole or in part, any of the agreements, covenants, or obligations made by or imposed upon the Parties by this Agreement, by reason of or through strike, work stoppage of labor, failure of contractors or suppliers of materials (including fuel), failure of equipment, environmental restrictions, riot, fire, flood, ice, invasion, civil war, commotion, insurrection, military or usurped power, order of any court or regulatory agency granted in any BONA FIDE legal proceedings or action, or of any civil or military authority either DE FACTO or DE JURE, explosion, Act of God or the public enemies, or any other cause reasonably beyond its control and not attributable to its neglect. A Party experiencing such a delay or failure to perform shall use due diligence to remove the cause or causes thereof; however, no Party shall be required to add to, modify or upgrade any facilities, or to settle a strike or labor dispute except when, according to its own best judgment, such action is advisable. ARTICLE XI INDUSTRY STANDARDS 11.1 ADHERENCE TO RELIABILITY CRITERIA The Parties agree to conform to all applicable national and regional electric reliability council principles, guides, criteria, and standards and industry standard practices (collectively, "Industry Standards") as they affect the implementation of this Agreement. Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Original Sheet No. 16 Public Service Company of Oklahoma, Rate schedule FERC No. 345 Southwestern Electric Power Company, Rate Schedule FERC No. 346 ARTICLE XII GENERAL 12.1 NO THIRD PARTY BENEFICIARIES This Agreement does not create rights of any character whatsoever in favor of any person, corporation, association, entity or power supplier, other than the Parties, and the obligations herein assumed by the Parties are solely for the use and benefit of the Parties. Nothing in this Agreement shall be construed as permitting or vesting, or attempting to permit or vest, in any person, corporation, association, entity or power supplier, other than the Parties, any rights hereunder or in any of the resources or facilities owned or controlled by the Parties or the use thereof. 12.2 WAIVERS Any waiver at any time by a Party of its rights with respect to a default under this Agreement, or with respect to any other matter arising in connection with this Agreement, shall not be deemed a waiver with respect to any subsequent default or matter. Any delay, short of the statutory period of limitation, in asserting or enforcing any right under this Agreement, shall not be deemed a waiver of such right. 12.3 SUCCESSORS AND ASSIGNS This Agreement shall inure to the benefit of and be binding upon the Parties only, and their respective successors and assigns, and shall not be assignable by any Party without the written consent of the other Parties except to a successor in the operation of its properties by reason of a reorganization to comply with state or federal restructuring requirements, or a merger, consolidation, sale or foreclosure whereby substantially all such properties are acquired by or merged with those of such a successor. Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Original Sheet No. 17 Public Service Company of Oklahoma, Rate schedule FERC No. 345 Southwestern Electric Power Company, Rate Schedule FERC No. 346 12.4 LIABILITY AND INDEMNIFICATION Subject to any applicable state or federal law that may specifically restrict limitations on liability, each Party shall release, indemnify, and hold harmless the other Parties, their directors, officers and employees from and against any and all liability for loss, damage or expense alleged to arise from, or be incidental to, injury to persons and/or damage to property in connection with its facilities or the production or transmission of electric energy by or through such facilities, or related to performance or non-performance of this Agreement, including any negligence arising hereunder. In no event shall any Party be liable to another Party for any indirect, special, incidental, or consequential damages with respect to any claim arising out of this Agreement. 12.5 SECTION HEADINGS The descriptive headings of the Articles and Sections of this Agreement are used for convenience only, and shall not modify or restrict any of the terms and provisions thereof. 12.6 NOTICE Any notice or demand for performance required or permitted under any of the provisions of this Agreement shall be deemed to have been given on the date such notice, in writing, is deposited in the U.S. mail, postage prepaid, certified or registered mail, addressed to: AGENT PSO SWEPCO 1 Riverside Plaza 212 E. Sixth Street 428 Travis Street Columbus, OH 43215 Tulsa, OK 74119 Shreveport, LA 71156 or in such other form or to such other address as the Parties may stipulate. 12.7 EFFECT ON OTHER AGREEMENTS This Agreement supersedes and replaces the Restated and Amended Operating Agreement among PSO, SWEPCO, West Texas Utilities Company and Central Power and Light Company Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Original Sheet No. 18 Public Service Company of Oklahoma, Rate schedule FERC No. 345 Southwestern Electric Power Company, Rate Schedule FERC No. 346 and Central and South West Services, Inc. dated January 1, 1997, effective as of the date this Agreement is to be made effective as set out in Section 2.1. ARTICLE XIII REGULATORY APPROVAL 13.1 REGULATORY AUTHORIZATION This Agreement is subject to and conditioned upon its approval or acceptance for filing without material condition or modification by the FERC. In the event that this Agreement is not so approved or accepted for filing in its entirety without modification, or the FERC subsequently modifies this Agreement upon complaint or upon its own initiative, any Party may, irrespective of the notice provisions in Section 2.1, terminate this Agreement or the Restated and Amended Operating Agreement referred to in Section 12.7, by giving thirty days' advance written notice to the other Parties. 13.2 CHANGES It is contemplated by the Parties that it may be appropriate from time to time to change, amend, modify, or supplement this Agreement, including the Service Schedules and any other attachments that may be made a part of this Agreement, to reflect changes in operating practices or costs of operations or for other reasons. Any such changes to this Agreement shall be in writing executed by the Parties and subject to approval or acceptance for filing by the FERC. Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Original Sheet No. 19 Public Service Company of Oklahoma, Rate schedule FERC No. 345 Southwestern Electric Power Company, Rate Schedule FERC No. 346 IN WITNESS WHEREOF, the Parties have caused this Agreement to be executed and attested by their duly authorized officers on the day and year first above written. PUBLIC SERVICE COMPANY OF OKLAHOMA By: ------------------------------------- Title: ------------------------------------- SOUTHWESTERN ELECTRIC POWER COMPANY By: ------------------------------------- Title: ------------------------------------- By: Title: AMERICAN ELECTRIC POWER SERVICE CORPORATION By: ------------------------------------- Title: ------------------------------------- Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Original Sheet No. 20 Public Service Company of Oklahoma, Rate schedule FERC No. 345 Southwestern Electric Power Company, Rate Schedule FERC No. 346 SERVICE SCHEDULE A ENERGY SALES A1 - DURATION This Service Schedule A shall become effective and binding when the Agreement of which it is a part becomes effective, and shall continue in full force and effect throughout the duration of the Agreement unless terminated or suspended. A2 - AVAILABILITY OF SERVICE This Service Schedule A governs sales of energy made pursuant to Section 7.4 of the Agreement, which are sales of energy not associated with sales of capacity. A3 - ENERGY TRANSFER PRICES, A purchasing Operating Company ("Purchaser") shall pay a selling Operating Company ("Seller") the following amount for energy purchased under this Schedule A ("Transfer Price"): (1) The Seller's Incremental Costs plus (2) One-half the difference between: (a) the Purchaser's Decremental Costs; and (b) the Seller's Incremental Costs. Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Original Sheet No. 21 Public Service Company of Oklahoma, Rate schedule FERC No. 345 Southwestern Electric Power Company, Rate Schedule FERC No. 346 SERVICE SCHEDULE B OFF-SYSTEM SALES AND OFF-SYSTEM PURCHASES B1 - DURATION This Service Schedule B shall become effective and binding when the Agreement of which it is a part becomes effective, and shall continue in full force and effect throughout the duration of the Agreement unless terminated or suspended. B2 - APPLICABILITY Agent shall undertake Off-System Sales and Off-System Purchases on behalf of the Operating Companies. Where Agent undertakes these activities, revenues and expenses shall be allocated or arranged in accordance with this Service Schedule B. B3 - ALLOCATION OF OFF-SYSTEM PURCHASES AND SALES A. Off-System Purchases. Any expenses for an Off-System Purchase during an hour shall be distributed to the Operating Company(ies) receiving energy from the purchase to cover an energy deficiency during the hour. Any remaining expenses for an Off-System Purchase during such hour shall be distributed to the Operating Companies in proportion to the megawatt-hours of energy that would have been provided from the respective Operating Companies' other power supply resources that were displaced during such hour. B. Off-System Sales. Any revenues from Off-System Sales in an hour shall first be applied to reimburse the Incremental Costs of the Operating Companies that contributed to the sales in such hour. Net revenues remaining after such reimbursement shall be distributed to the Operating Companies in proportion to each Operating Company's generation for sales (including economy energy sales) less the amount of energy such Operating Company purchased from the other Operating Company in such hour pursuant to Section 7.4 of this Agreement and Schedule A (but not less than zero). Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 ATTACHMENT 3 SYSTEM INTEGRATION AGREEMENT American Electric Power Service Corporation Original Sheet No. 1 Second Substitute Rate Schedule FERC No. 20 RESTATED AND AMENDED SYSTEM INTEGRATION AGREEMENT AMONG APPALACHIAN POWER COMPANY KENTUCKY POWER COMPANY INDIANA MICHIGAN POWER COMPANY PUBLIC SERVICE COMPANY OF OKLAHOMA SOUTHWESTERN ELECTRIC POWER COMPANY AND AMERICAN ELECTRIC POWER SERVICE CORPORATION, AS AGENT Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 American Electric Power Service Corporation Original Sheet No. 2 Second Substitute Rate Schedule FERC No. 20 RESTATED AND AMENDED SYSTEM INTEGRATION AGREEMENT THIS RESTATED AND AMENDED SYSTEM INTEGRATION AGREEMENT ("Agreement") is made and entered into as of the __ day of _____________, 2001 by and among Appalachian Power Company ("APC"), Kentucky Power Company ("KPC"), Indiana Michigan Power Company ("I&M"), Public Service Company of Oklahoma ("PSO"), and Southwestern Electric Power Company ("SWEPCO"); and their agent American Electric Power Service Corporation ("AEPSC"). The foregoing companies are referred to herein collectively as the Parties and individually as a Party. WHEREAS, APC, KPC, and I&M (collectively, the "AEP East Operating Companies") own and operate interconnected electric generation, transmission and distribution facilities with which they are engaged in the business of generating, transmitting and selling electric power and energy to the general public and to other electric utilities; and WHEREAS, the AEP East Operating Companies coordinate the planning, construction, operation and maintenance of their electric supply facilities on an integrated basis pursuant to an Interconnection Agreement, restated and amended on 2001; and WHEREAS, PSO and SWEPCO (collectively, the "AEP West Operating Companies") own and operate interconnected electric generation, transmission and distribution facilities with which they are engaged in the business of generating, transmitting and selling electric power and energy to the general public and to other electric utilities; and WHEREAS, the AEP West Operating Companies coordinate the planning, construction, operation and maintenance of their electric supply facilities on an Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 American Electric Power Service Corporation Original Sheet No. 3 Second Substitute Rate Schedule FERC No. 20 integrated basis pursuant to an Operating Agreement, restated and amended on _____________, 2001; and WHEREAS, following the consummation of a merger between their parent companies on June 15, 2000, the AEP East Operating Companies and the AEP West Operating Companies are electrically and operationally integrated to the extent practicable while preserving the basic terms and conditions of the AEP East Interconnection Agreement and the AEP West Operating Agreement; and WHEREAS, the Parties desire to maintain a framework under which the power supply resources of the AEP East Operating Companies and the AEP West Operating Companies will to the extent practicable be planned, operated, maintained and dispatched on a coordinated basis; NOW, THEREFORE, in consideration of the premises and the mutual covenants and agreements herein set forth, the Parties mutually agree as follows: ARTICLE I DEFINITIONS 1.1 AEP EAST INTERCONNECTION AGREEMENT means the Restated and Amended Interconnection Agreement among AEPSC and the AEP East Operating Companies dated _____________, 2001, as the same may be subsequently modified and supplemented. 1.2 AEP EAST OPERATING COMPANIES for purposes of this Agreement means the following operating companies of American Electric Power Company, Inc. which, together with AEPSC, are parties to the AEP East Interconnection Agreement: APC, KPC, and I&M, collectively. 1.3 AEP EAST ZONE means the electric generation, transmission and distribution facilities of the AEP East Operating Companies. Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 American Electric Power Service Corporation Original Sheet No. 4 Second Substitute Rate Schedule FERC No. 20 1.4 AEPSC means American Electric Power Service Corporation. 1.5 AEP WEST OPERATING AGREEMENT means the Restated and Amended Operating Agreement among AEPSC and the AEP West Operating Companies dated _____________, 2001, as the same may be subsequently modified or supplemented. 1.6 AEP WEST OPERATING COMPANIES means PSO and SWEPCO, collectively. 1.7 AEP WEST ZONE means the electric generation, transmission and distribution facilities of the AEP West Operating Companies. 1.8 AGENT means the Parties' designated representative for the purposes specified in Section 5.1 and elsewhere in this Agreement. 1.9 AGREEMENT means this Restated and Amended System Integration Agreement, including all Service Schedules and attachments hereto. 1.10 APC means Appalachian Power Company. 1.11 COMBINED SYSTEM means the AEP East Zone and the AEP West Zone. 1.12 DECREMENTAL CAPACITY COST in the recipient zone means the lower of the recipient's cost of capacity installation or capacity purchase price in its own zonal market, i.e., Market Price. The determination of Market Price shall be based on actual purchases of similar characteristics from unaffiliated third parties. In the event that no such purchases are available, documentable offers from unaffiliated third parties shall determine the Market Price. In the event that no such offers are available, a published index of capacity market price shall determine the Market Price. 1.13 ERCOT means the Electric Reliability Council of Texas. Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 American Electric Power Service Corporation Original Sheet No. 5 Second Substitute Rate Schedule FERC No. 20 1.14 FERC means the Federal Energy Regulatory Commission or a successor agency having jurisdiction over this Agreement. 1.15 FOREGONE OPPORTUNITY COST as it relates to capacity exchanges means what the supplier could have sold the capacity for in its own zonal market if the capacity exchange did not take place, i.e., Market Price. The determination of Market Price shall be based on actual sales of similar characteristics to unaffiliated third parties. In the event that no such sales are available, documentable offers from unaffiliated third parties shall determine the Market Price. In the event that no such offers are available, a published index of capacity market price shall determine the Market Price. 1.16 GENERATING RESOURCE means the electric power generating facilities or capacity owned by or under contract to a Party or Parties to meet the capacity and energy needs of the Party or Parties. 1.17 I&M means Indiana Michigan Power Company. 1.18 INCREMENTAL TRANSMISSION COSTS means any costs for transmission service to effect system energy exchange other than the 250 MW of firm transmission service purchased from Ameren Corporation prior to the Merger. 1.19 INDUSTRY STANDARDS means those principles, guides, criteria, standards and practices referred to in Section 12.1. 1.20 INTERCONNECTION CONSTRAINTS has the meaning ascribed to that term in Section 7.2. 1.21 KPC means Kentucky Power Company. 1.22 MERGER means the merger of Central and South West Corporation into a merger subsidiary of American Electric Power Company, Inc., effective June 15, 2000. Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 American Electric Power Service Corporation Original Sheet No. 6 Second Substitute Rate Schedule FERC No. 20 1.23 NATIVE LOAD CUSTOMER for purposes of this Agreement means a wholesale or retail power customer on whose behalf a Party, by statute, franchise, regulatory requirement, or firm power supply contract, has undertaken an obligation to supply electricity at cost-of-service rates to reliably meet the electric needs of such customer. The term "Native Load Customer" for purposes of this Agreement excludes customers and that portion of a customer's load served pursuant to contracts that do not obligate the supplier to install capacity to meet the customer's load requirements. 1.24 OFF-SYSTEM PURCHASES means purchases from a third party of energy and/or capacity to reduce costs or to provide reliability for the Combined System or to engage in Off-System Sales. 1.25 OFF-SYSTEM SALES means all sales of power and energy to non-Native Load Customers of the Parties to this Agreement. 1.26 OPERATING COMMITTEE means the administrative body established pursuant to Article VI for the purposes therein specified. 1.27 OPERATING COMPANY means APC, KPC, I&M, PSO, or SWEPCO, individually. 1.28 OUT-OF-POCKET COST, unless otherwise specified, means all expenses incurred that would not otherwise have been incurred if the corresponding service had not been arranged. Such expenses will include, but are not limited to, fuel, reactant, operation, maintenance, tax, S02 and other atmospheric emission allowances, transmission losses, margins associated with foregone sales opportunities and charges for any power and energy purchased which is reasonably allocated by the Agent to such service, and other expenses incurred which would not have been incurred if the service had not been arranged. In such cases where foregone sales opportunities are included, the Agent will be responsible for Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 American Electric Power Service Corporation Original Sheet No. 7 Second Substitute Rate Schedule FERC No. 20 maintaining adequate documentation of these opportunities. This support may include but is not limited to actual sales during that period, regional market indices and/or logs of offers received. 1.29 OWNED GENERATING CAPACITY is the aggregate capacity of the electric power sources of the zone, in Kilowatts, that is normally expected to be available to carry load. Such capacity shall include (i) the capacity installed at the generating stations owned by the operating companies in the zone and (ii) the capacity available to the operating companies of the zone through arrangements with affiliated companies or unaffiliated companies, if so designated by the Operating Committee with the approval of the operating companies. 1.30 PARTY OR PARTIES means one or more of the following individually or collectively, as the context warrants: APC, KPC, I&M, AEPSC, PSO, and SWEPCO. 1.31 PSO means Public Service Company of Oklahoma. 1.32 SERVICE SCHEDULES means the Service Schedules attached to this Agreement and those that later may be agreed to by the Parties and accepted for filing by the FERC. 1.33 SPP means the Southwest Power Pool reliability council. 1.34 SWEPCO means Southwestern Electric Power Company. 1.35 SYSTEM EMERGENCY means a condition which, if not promptly corrected, threatens to cause imminent harm to persons or property, including the equipment of a Party or a third party, or threatens the reliability of electric service provided by a Party to Native Load Customers. 1.36 SYSTEM SALES REALIZATION means the difference between (i) revenues collected from Off-System Sales and (ii) the Out-of-Pocket Cost of such Off-System Sales and any transmission cost related to such activities. Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 American Electric Power Service Corporation Original Sheet No. 8 Second Substitute Rate Schedule FERC No. 20 ARTICLE II TERM OF AGREEMENT 2.1 TERM Subject to FERC approval or acceptance for filing, this Agreement shall take effect on January 1, 2002, and shall continue in full force and effect until terminated: (a) by mutual agreement; (b) as of the date that any Operating Company no longer has retail Native Load Customers other than default service customers that an Operating Company serves as the provider of last resort in a state whose regulatory policy requires competition in retail power supply; or (c) upon twelve (12) months' written notice by one Party to each of the other Parties. 2.2 PERIODIC REVIEW This Agreement will be reviewed periodically by the Operating Committee to determine whether revisions are necessary or appropriate. Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 American Electric Power Service Corporation Original Sheet No. 9 Second Substitute Rate Schedule FERC No. 20 ARTICLE III OBJECTIVES 3.1 PURPOSE The purpose of this Agreement is to provide the contractual basis for coordinated planning, operation and maintenance of the power supply resources of the Combined System to achieve economies consistent with the provision of reliable electric service and an equitable sharing of the benefits and costs of such coordinated arrangements. Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 American Electric Power Service Corporation Original Sheet No. 10 Second Substitute Rate Schedule FERC No. 20 ARTICLE IV RELATIONSHIP TO OTHER AGREEMENTS AND SERVICES 4.1 GOVERNING PROVISIONS This Agreement is intended to apply in addition to and not in lieu of the AEP East Interconnection Agreement and the AEP West Operating Agreement. The provisions of this Agreement shall, to the extent practicable, be construed and applied in a manner that is consistent with the AEP East Interconnection Agreement and the AEP West Operating Agreement. In the event of any inconsistency, however, the provisions of this Agreement shall control. This Agreement is further intended to apply to the power supply resources and loads served by the Combined System. It does not apply to the transmission facilities owned or operated by the AEP East Operating Companies and the AEP West Operating Companies. Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 American Electric Power Service Corporation Original Sheet No. 11 Second Substitute Rate Schedule FERC No. 20 ARTICLE V AGENT 5.1 AGENT'S FUNCTIONS The Parties hereby designate AEPSC as their Agent for the purposes of: (a) coordinating the planning and design of generation to be installed for the Combined System and the acquisition of power supply resources; (b) coordinating the operation and maintenance of the Combined System power supply resources; (c) coordinating the economic dispatch for the power supply resources of the Combined System; (d) conducting the Combined System's Off-System Purchases and Sales; (e) providing and or acquiring any additional power supply services for the loads served and sales made on behalf of the Combined System; (f) developing all bills and billing information among the Parties pursuant to this Agreement; and (g) such other activities and duties as may be assigned from time to time by the Operating Committee. 5.2 DELEGATION AND ACCEPTANCE OF AUTHORITY The Parties hereby delegate to the Agent and the Agent hereby accepts responsibility and authority for the duties listed in Section 5.1 and elsewhere in this Agreement. Except as herein expressly established otherwise, the Agent shall perform each of those duties in consultation with the Operating Committee. Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 American Electric Power Service Corporation Original Sheet No. 12 Second Substitute Rate Schedule FERC No. 20 ARTICLE VI COMPOSITION AND DUTIES OF THE OPERATING COMMITTEE 6.1 OPERATING COMMITTEE The Operating Committee is the administrative body created to administer this Agreement and shall consist of three (3) members. One member shall be a representative of the AEP East Operating Companies, one member shall be a representative of the AEP West Operating Companies and the third member shall be a representative of AEPSC. 6.2 MEETING DATES The Operating Committee shall hold meetings at such times, means and places as the members shall determine from time to time. Minutes of each Operating Committee meeting shall be prepared and maintained. 6.3 DECISIONS A11 decisions of the Operating Committee shall be by a majority vote of the members present or voting by proxy at the meeting at which the vote is taken. As necessary, recommendations will be made to the Chief Executive Officer or his designee. Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 American Electric Power Service Corporation Original Sheet No. 13 Second Substitute Rate Schedule FERC No. 20 6.4 DUTIES The Operating Committee shall have the following duties, unless such duties are otherwise assigned by a vote of the Operating Committee to the Agent, in which case the Agent shall perform such duties. The Operating Committee will be responsible for: (a) administering this Agreement and recommending any amendments hereto including such amendments which could result from any deregulation of any of the power supply resources of the Combined System; (b) overseeing operation of the power supply resources of the Combined System; (c) reviewing and making recommendations concerning the proportional sharing of costs and benefits under this Agreement; (d) reviewing and, if necessary, amending the duties and responsibilities of the Agent; (e) evaluating and making recommendations concerning power supply additions to meet the requirements of Native Load Customers; and (f) ensuring coordination for other matters not specifically provided for herein that the Operating Committee considers necessary to operate the Combined System reliably and economically. Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 American Electric Power Service Corporation Original Sheet No. 14 Second Substitute Rate Schedule FERC No. 20 ARTICLE VII COORDINATED PLANNING AND OPERATION 7.1 COORDINATED SYSTEM PLANNING New capacity will be planned to meet the Combined System's requirements, subject to regulatory, transmission, economic and operational constraints and the existing interconnection and operating agreements of the Parties. To the extent practicable, the power supply resources of the AEP East Zone and the AEP West Zone shall be planned and developed on the basis that the Combined System constitutes an integrated electric system and that the objective of such planning and development shall be to maximize efficiency, reliability and cost effectiveness of the Combined System. The Agent shall coordinate the power supply development for the Combined System. 7.2 COMBINED SYSTEM DISPATCH It is the intent of the Parties, when and as practicable, that the Combined System dispatch be conducted on a least-cost basis subject to availability of transmission entitlements linking the two zones (such availability limitations being referred to hereinafter as the "Interconnection Constraints"). In determining the Combined System's appropriate dispatch priorities, the AEP East Zone's most economic power supply resources will be used to serve the Native Load Customers of the AEP East Operating Companies and the AEP West Zone's most economic power supply resources will be used to serve the Native Load Customers of the AEP West Operating Companies. The zones will be centrally dispatched in real time to minimize total generation costs for the Combined System, subject to the Interconnection Constraints. Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 American Electric Power Service Corporation Original Sheet No. 15 Second Substitute Rate Schedule FERC No. 20 Similarly, subject to the Interconnection Constraints, unit commitment will be performed to meet the Combined System's obligations, taking into account the specific obligations within each zone. 7.3 CAPACITY EXCHANGE Whenever either the AEP East Zone or the AEP West Zone has surplus capacity relative to its capacity planning reserve requirements or otherwise has capacity available for sale, and the other zone has insufficient capacity relative to its capacity planning reserve requirements, the surplus zone, acting through the Agent, shall make its surplus capacity available to the other zone for periods of one (1) year or less, subject to the Interconnection Constraints. Such capacity exchanges shall only be made when the selling region's foregone opportunity cost to sell capacity is lower than the buying region's decremental capacity purchase cost. 7.4 ENERGY EXCHANGE The AEP East Zone and the AEP West Zone each shall make energy available from its Generating Resources to the other zone for the purposes and to the extent required by this Agreement. 7.5 EMERGENCY RESPONSE In the event of a System Emergency, no adverse distinction shall be made between the Native Load Customers of the AEP East Zone and those of the AEP West Zone. Each zone shall, when so instructed by the Agent, make its Generating Resources available in response to a System Emergency. Notwithstanding the foregoing, it is understood that the Interconnection Constraints may limit the ability of one zone to respond to a System Emergency in the other. Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 American Electric Power Service Corporation Original Sheet No. 16 Second Substitute Rate Schedule FERC No. 20 ARTICLE VIII OFF-SYSTEM PURCHASES AND OFF-SYSTEM SALES 8.1 CENTRALIZED OFF-SYSTEM PURCHASES AND OFF-SYSTEM SALES All Off-System Purchases and Off-System Sales shall be conducted centrally under the direction of the Agent. 8.2 COORDINATION WITH AGENT Subject to compliance with applicable codes of conduct, the Parties shall promptly communicate any potential Off-System Purchases and Off-System Sales to the Agent and shall cooperate in evaluating and facilitating such transactions as are determined by the Agent to be in the interest of the Combined System. Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 American Electric Power Service Corporation Original Sheet No. 17 Second Substitute Rate Schedule FERC No. 20 ARTICLE IX ASSIGNMENT OF COSTS AND BENEFITS OF COORDINATED OPERATIONS 9.1 SERVICE SCHEDULES The costs and revenues associated with coordinated operations as described in Articles VII and VIII shall be distributed in the manner provided from time to time in the Service Schedules attached to and incorporated by reference into this Agreement. It is understood and agreed that all such Service Schedules are intended to establish an equitable sharing of costs and/or benefits among the Parties, and that circumstances may, from time to time, require a reassessment of relative benefits and burdens or of the methods used in the Service Schedules to apportion the benefits and burdens. Upon a recommendation of the Operating Committee and agreement among the Parties, any of the Service Schedules may be amended as of any date agreed to by the Parties, subject to receipt of necessary regulatory authorization. The initial Service Schedules incorporated into this Agreement are as follows: SCHEDULE A: Allocation of Capacity Costs and Purchased Power Costs; SCHEDULE B: Pricing for System Capacity Exchanges; SCHEDULE C: Pricing for System Energy Exchanges; and SCHEDULE D: Allocation of Off-System Sales Realizations. Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 American Electric Power Service Corporation Original Sheet No. 18 Second Substitute Rate Schedule FERC No. 20 ARTICLE X BILLING PROCEDURES 10.1 RECORDS The Agent shall maintain such records as may be necessary to determine the assignment of costs and benefits of coordinated operations pursuant to this Agreement. Such records shall be made available to the Parties upon request. 10.2 MONTHLY STATEMENTS As promptly as practicable after the end of each calendar month, the Agent shall prepare a statement setting forth the monthly summary of costs and revenues allocated or assigned to the Parties in sufficient detail as may be needed for settlements under the provisions of this Agreement. As required, the Agent may provide such statements on an estimated basis and then adjust those statements for actual results. 10.3 BILLINGS AND PAYMENTS The Agent shall handle all billing between the Parties and other entities with which the Combined System engages in Off-System Sales pursuant to this Agreement. Payment among the Parties shall be by making remittance of the net amount billed or by making appropriate accounting entries on the books of the Parties. 10.4 TAXES Should any federal, state, or local tax, surcharge or similar assessment, in addition to those that may now exist, be levied upon the electric power, energy or service to be provided in connection with this Agreement, or upon the provider of service as measured by the power, energy or service, or the revenue therefrom, such additional amount shall be included in the net billing as described in Section 10.3. Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 American Electric Power Service Corporation Original Sheet No. 19 Second Substitute Rate Schedule FERC No. 20 ARTICLE XI FORCE MAJEURE 11.1 EVENTS EXCUSING PERFORMANCE No Party shall be liable to another Party for or on account of any loss, damage, injury, or expense resulting from or arising out of a delay or failure to perform, either in whole or in part, any of the agreements, covenants or obligations made by or imposed upon the Parties by this Agreement, by reason of or through strike, work stoppage of labor, failure of contractors or suppliers of materials (including fuel), failure of equipment, environmental restrictions, riot, fire, flood, ice, invasion, civil war, commotion, insurrection, military or usurped power, order of any court granted in any bona fide adverse legal proceedings or action, or of any civil or military authority either de facto or de jure, explosion, Act of God or the public enemies, or any other cause reasonably beyond its control and not attributable to its neglect. A Party experiencing such a delay or failure to perform shall use due diligence to remove the cause or causes thereof; however, no Party shall be required to add to, modify or upgrade any facilities, or to settle a strike or labor dispute except when, according to its own best judgment, such action is advisable. Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 American Electric Power Service Corporation Original Sheet No. 20 Second Substitute Rate Schedule FERC No. 20 ARTICLE XII INDUSTRY STANDARDS 12.1 ADHERENCE TO RELIABILITY CRITERIA The Parties agree to conform to all applicable national and regional electric reliability council principles, guides, criteria, and standards and industry standard practices (collectively, "Industry Standards") as they affect the implementation of this Agreement. Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 American Electric Power Service Corporation Original Sheet No. 21 Second Substitute Rate Schedule FERC No. 20 ARTICLE XIII GENERAL 13.1 NO THIRD PARTY BENEFICIARIES This Agreement does not create rights of any character whatsoever in favor of any person, corporation, association, entity or power supplier, other than the Parties, and the obligations herein assumed by the Parties are solely for the use and benefit of said Parties. Nothing in this Agreement shall be construed as permitting or vesting, or attempting to permit or vest, in any person, corporation, association, entity or power supplier, other than the Parties, any rights hereunder or in any of the resources or facilities owned or controlled by the Parties or the use thereof. 13.2 WAIVERS Any waiver at any time by a Party of its rights with respect to a default under this Agreement, or with respect to any other matter arising in connection with this Agreement, shall not be deemed a waiver with respect to any subsequent default or matter. Any delay, short of the statutory period of limitation, in asserting or enforcing any right under this Agreement, shall not be deemed a waiver of such right. 13.3 SUCCESSORS AND ASSIGNS This Agreement shall inure to the benefit of and be binding upon the Parties only, and their respective successors and assigns, and shall not be assignable by any Party without the written consent of the other Parties except to a successor in the operation of its properties by reason of a merger, consolidation, sale or foreclosure whereby substantially all such properties are acquired by or merged with those of such a successor. 13.4 LIABILITY AND INDEMNIFICATION Subject to any applicable state or federal law which may specifically restrict limitations on liability, each Party shall release, indemnify, and hold harmless the Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 American Electric Power Service Corporation Original Sheet No. 22 Second Substitute Rate Schedule FERC No. 20 other Parties, their directors, officers and employees from and against any and all liability for loss, damage or expense alleged to arise from, or incidental to, injury to persons and/or damage to property in connection with its facilities or the production or transmission of electric energy by or through such facilities, or related to performance or non-performance of this Agreement, including any negligence arising hereunder. In no event shall any Party be liable to another Party for any indirect, special, incidental or consequential damages with respect to any claim arising out of this Agreement. 13.5 SECTION HEADINGS The descriptive headings of the Articles and Sections of this Agreement are used for convenience only, and shall not modify or restrict any of the terms and provisions thereof. 13.6 NOTICE Any notice or demand for performance required or permitted under any of the provisions of this Agreement shall be deemed to have been given on the date such notice, in writing, is deposited in the U.S. mail, postage prepaid, certified or registered mail, addressed to: AGENT - AEP Service Corporation 1 Riverside Plaza Columbus, Ohio 43215-2373 or in such other form or to such other address as the Parties may stipulate. Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 American Electric Power Service Corporation Original Sheet No. 23 Second Substitute Rate Schedule FERC No. 20 13.7 EFFECT ON OTHER AGREEMENTS This Agreement supersedes and replaces the June 15, 2000 System Integration Agreement among APC, KPC, Ohio Power Company, Columbus Southern Power Company, and I&M and AEPSC; and Central Power and Light Company, PSO, SWEPCO, and West Texas Utilities Company and Central and South West Services, Inc., effective as of the date this Agreement is to be made effective as set out in Section 2.1. Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 American Electric Power Service Corporation Original Sheet No. 24 Second Substitute Rate Schedule FERC No. 20 ARTICLE XIV REGULATORY APPROVAL 14.1 REGULATORY AUTHORIZATION This Agreement is subject to and conditioned upon acceptance for filing without material condition or modification by the FERC. In the event that this Agreement is not so accepted for filing in its entirety, any Party may terminate this Agreement or the System Integration Agreement referred to in Section 13.7 immediately. 14.2 CHANGES It is contemplated by the Parties that it may be appropriate from time to time to change, amend, modify or supplement this Agreement, including the Schedules and attachments which are a part of this Agreement, to reflect changes in operating practices or costs of operations or for other reasons. Any such changes to this Agreement shall be in writing executed by the Parties, subject to necessary regulatory authorizations. IN WITNESS WHEREOF, the Parties have caused this Agreement to be executed and attested by their duly authorized officers on the day and year first above written. Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 American Electric Power Service Corporation Original Sheet No. 25 Second Substitute Rate Schedule FERC No. 20 APPALACHIAN POWER COMPANY By: ------------------------------------- Title: ------------------------------------- KENTUCKY POWER COMPANY By: ------------------------------------- Title: ------------------------------------- INDIANA MICHIGAN POWER COMPANY By: ------------------------------------- Title: ------------------------------------- PUBLIC SERVICE COMPANY OF OKLAHOMA By: ------------------------------------- Title: ------------------------------------- SOUTHWESTERN ELECTRIC POWER COMPANY By: ------------------------------------- Title: ------------------------------------- AMERICAN ELECTRIC POWER SERVICE CORPORATION By: ------------------------------------- Title: ------------------------------------- Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 American Electric Power Service Corporation Original Sheet No. 26 Second Substitute Rate Schedule FERC No. 20 SERVICE SCHEDULE A ALLOCATION OF CAPACITY COSTS AND PURCHASED POWER COSTS A1 - DURATION This Service Schedule A shall continue in full force and effect throughout the duration of this Agreement, except as provided in Sections 9.1 and 14.2 of the Agreement. This Service Schedule A is a part of the Agreement and, as such, the use of terms in this Service Schedule A that are defined in the Agreement shall have the same meanings as set forth in the Agreement. A2 - CAPACITY COSTS The AEP East Operating Companies on one hand and the AEP West Operating Companies on the other hand each shall continue to have full responsibility for all fixed costs relating to its respective power supply resources that were in commercial operation prior to June 15, 2000. For new power supply resources acquired or installed after June 15, 2000 to meet the Combined System's capacity requirements, an allocation of the associated fixed capacity costs (including associated transmission costs) shall be made based on the decision to acquire or install the power supply resources, between the AEP East Zone and the AEP West Zone in proportion to the amount of new capacity required in each zone, as determined by the Agent. Once such allocation is made between the AEP East Zone and the AEP West Zone, the treatment of costs, as applicable, within these zones shall be governed respectively by the AEP East Interconnection Agreement and the AEP West Operating Agreement. At such time as the Agent determines an allocation among the operating companies of new capacity that AEP has constructed or purchased, AEP will convey its decision respecting such allocation to its wholesale customers buying at a cost-of-service rate and each state regulatory commission with jurisdiction over the operating companies. Each such customer Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 American Electric Power Service Corporation Original Sheet No. 27 Second Substitute Rate Schedule FERC No. 20 buying at a cost-of-service rate and each state regulatory commission shall retain any right provided them under the Federal Power Act to challenge AEP's decision. A3 - PURCHASED POWER COSTS Except in the case of (i) an Off-System Purchase which is allocated by the Agent to an Off-System Sale and (ii) the capacity costs allocated pursuant to Section A2 above, the cost of purchased power will be assigned to the zone (the AEP East Zone or the AEP West Zone) which takes physical delivery of the energy. Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 American Electric Power Service Corporation Original Sheet No. 28 Second Substitute Rate Schedule FERC No. 20 SERVICE SCHEDULE B PRICING FOR SYSTEM CAPACITY EXCHANGES B1 - DURATION This Service Schedule B shall continue in full force and effect throughout the duration of this Agreement, except as provided in Sections 9.1 and 14.2 of the Agreement. This Service Schedule B is a part of the Agreement and, as such, the use of terms in this Service Schedule B that are defined in the Agreement shall have the same meanings as set forth in the Agreement. B2 - CAPACITY TRANSFER PRICE Capacity made available by either the AEP East Zone or the AEP West Zone to the other pursuant to Section 7.3 of the Agreement shall be priced at one-half the sum of (i) the foregone opportunity cost to sell capacity in the supplier zone and (ii) the decremental capacity purchase cost in the recipient zone, as determined by the Agent. If such capacity transfers require additional transmission-related costs, such transmission-related costs will be added to the foregone opportunity costs in determining the sharing of capacity-related savings. Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 American Electric Power Service Corporation Original Sheet No. 29 Second Substitute Rate Schedule FERC No. 20 SERVICE SCHEDULE C PRICING FOR SYSTEM ENERGY EXCHANGES C1 - DURATION This Service Schedule C shall continue in full force and effect throughout the duration of this Agreement, except as provided in Sections 9.1 and 14.2 of the Agreement. This Service Schedule C is a part of the Agreement and, as such, the use of terms in this Service Schedule C that are defined in the Agreement shall have the same meanings as set forth in the Agreement. C2 - ENERGY TRANSFER PRICES (a) Economic transfers of energy between the AEP East Zone and the AEP West Zone shall be priced at the lower of (i) the recipient zone's decremental costs or (ii) one-half of the sum of the supplier zone's Out-of-Pocket cost including Incremental Transmission Costs and the recipient zone's decremental cost. (b) The Agent shall make any determinations necessary to implement the foregoing pricing provisions. Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 American Electric Power Service Corporation Original Sheet No. 30 Second Substitute Rate Schedule FERC No. 20 SERVICE SCHEDULE D ALLOCATION OF OFF-SYSTEM SALES REALIZATIONS DI - DURATION This Service Schedule D shall continue in full force and effect throughout the duration of this Agreement, except as provided in Sections 9.1 and 14.2 of the Agreement. This Service Schedule D is a part of the Agreement and, as such, the use of terms in this Service Schedule D that are defined in the Agreement shall have the same meanings as set forth in the Agreement. D2 - ALLOCATION OF OFF-SYSTEM SALES COSTS The AEP East Zone and the AEP West Zone each shall be reimbursed, before determining the Off-System Sales Realizations, for its respective Out-of-Pocket Costs and any transmission-related expenses incurred to supply energy for Off-System Sales. Costs attributable to long-term (defined for purposes of this Service Schedule D as having a term of one year or longer entered into prior to the Merger) Off-System Sales shall be assigned to the zone in which such sales were initiated. All additional overhead costs associated with Off-System Sales shall be allocated between the AEP East Zone and the AEP West Zone in accordance with the following Allocation of Off-System Sales Realizations. D3 - ALLOCATION OF OFF-SYSTEM SALES REALIZATIONS The Agent shall determine the Off-System Sales Realizations on an hourly basis. The sum of the hourly amounts for each billing period (adjusted to remove realizations associated with long-term Off-System Sales) shall be allocated between the AEP East Zone and the AEP West Zone according to the ratio of owned generating capacity in the two zones. Realizations associated with the long-term Off-System Sales shall be assigned to the zone in which such sales were initiated. Issued by: J. Craig Baker Effective: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 ATTACHMENT 4 UNIT POWER SALES AGREEMENT BETWEEN SWEPCO AND POWER MARKETING AFFILIATE Southwestern Electric Power Company Original Sheet No. 1 Rate Schedule FERC No. 340 UNIT POWER SALES AGREEMENT AMONG SOUTHWESTERN ELECTRIC POWER COMPANY, POWER MARKETING AFFILIATE, AND AMERICAN ELECTRIC POWER SERVICE CORPORATION Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 2 Rate Schedule FERC No. 340 TABLE OF CONTENTS SHEET ARTICLE I DEFINITIONS .................................................. 11 ARTICLE II SALE AND PURCHASE OF UNIT POWER .............................. 18 Section 2.1 Obligations of SWEPCO and PMA ................................ 18 Section 2.2 Delivery ..................................................... 18 Section 2.3 Obligations of AEPSC ......................................... 18 ARTICLE III TERM OF AGREEMENT ............................................ 19 Section 3.1 Effective Date ............................................... 19 Section 3.2 Termination Date ............................................. 19 3.2.1 First Renewal Tenn .................................... 19 3.2.2. Second Renewal Term ................................... 20 ARTICLE IV ALLOCATION OF CAPACITY ....................................... 21 Section 4.1 Assigned Capacity ............................................ 21 4.1.1 PMA's Assigned Capacity ............................... 21 4.1.2 SWEPCO's Assigned Capacity ............................ 22 Section 4.2 Effect of Capacity Auction in Texas Mandated By Statute ...... 22 Section 4.3 Effect of Required Divestiture, Assignment, or Other Disposition of SWEPCO Generation Serving Arkansas or Louisiana Native Load or Wholesale Loads ..................... 23 Section 4.4 Effect of Disagreement as to Unit Retirement ................. 23 4.4.1 Assignment by SWEPCO to PMA ........................... 23 4.4.2 Contracts Pertaining to Retired Unit .................. 24 a. Retiring Party's Contracts ......................... 24 Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 3 Rate Schedule FERC No. 340 b. Joint Contracts .................................... 24 c. Contracts Concerning Infrastructure ................ 24 4.4.3 Effect on Residual Obligations ........................ 24 ARTICLE V SCHEDULING AND OPERATIONS .................................... 25 Section 5.1 Dispatch ..................................................... 25 Section 5.2 Forecasts .................................................... 26 Section 5.3 Operations, Management, and Maintenance ...................... 26 5.3.1 Replacement of AEPSC .................................. 27 Section 5.4 Operating Committee .......................................... 28 5.4.1 Operating Committee Responsibilities .................. 28 5.4.2 Operating Committee Meetings .......................... 30 5.4.3 Information for Use of the Operating Committee ........ 31 Section 5.5 Unit Commitment .............................................. 31 Section 5.6 Dispatch of Units; Call on Uncommitted Capacity .............. 31 5.6.1 Units to be Dispatched ................................ 31 5.6.2 Call on Uncommitted Units ............................. 31 5.6.3 Recall of Called Capacity ............................. 32 5.6.4 Undispatched Capacity from Committed Units ............ 32 ARTICLE VI COST COMPONENTS AND PAYMENT TERMS ............................ 33 Section 6.1 Cost Components .............................................. 33 6.1.1 Amounts Paid by SWEPCO for Third-Party Services ....... 33 Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 4 Rate Schedule FERC No. 340 Section 6.2 Capacity Charge .............................................. 33 Section 6.3 Non-Fuel Variable Operating Costs ............................ 34 Section 6.4 Fuel Costs ................................................... 34 6.4.1 Option to Supply Fuel ................................. 34 a. Use of Delivery and Storage Facilities ............. 35 b. Effect of Existing Fuel Supply and Transportation Contracts .......................................... 35 c. Effect of Non-Delivery ............................. 36 6.4.2 Operating Committee Oversight .......................... 36 6.4.3 Fuel Inventory ......................................... 37 Section 6.5 FERC Fees .................................................... 37 Section 6.6 Emission Allowances .......................................... 37 Section 6.7 Capital Repairs and Improvements ............................. 39 Section 6.8 Annual Budgeting Process ..................................... 39 Section 6.9 Costs Upon Retirement or Decommissioning of Units ............ 40 ARTICLE VII BILLING AND PAYMENT .......................................... 40 Section 7.1 Billing Procedure ............................................ 40 Section 7.2 Payment ...................................................... 41 Section 7.3 Billing Disputes ............................................. 41 Section 7.4 Billing Adjustments .......................................... 42 Section 7.5 Applicable Interest Rate ..................................... 42 ARTICLE VIII TRANSMISSION SERVICES ........................................ 42 Section 8.1 Responsibilities ............................................. 42 Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 5 Rate Schedule FERC No. 340 ARTICLE IX INTERRUPTION AND CURTAILMENTS ............................... 42 Section 9.1 Scheduled Outages ........................................... 42 Section 9.2 Notification of Unscheduled Outages ......................... 43 Section 9.3 Effect of Curtailment ....................................... 43 ARTICLE X FORCE MAJEURE ............................................... 43 Section 10.1 Definition .................................................. 43 Section 10.2 Performance Excused ......................................... 44 Section 10.3 Strike Issues ............................................... 44 Section 10.4 Payments Not Excused ........................................ 44 ARTICLE XI DEFAULTS .................................................... 44 Section 11.1 Events of Default ........................................... 45 11.1.1 Bankruptcy .......................................... 45 11.1.2 Violation or Noncompliance with Governmental Requirement ......................................... 45 11.1.3 Failure to Perform ................................. 45 Section 11.2 Notice of Default and Opportunity to Cure ................... 45 Section 11.3 No Waiver ................................................... 46 Section 11.4 Dispute Resolution .......................................... 46 ARTICLE XII DISPUTE RESOLUTION .......................................... 46 Section 12.1 Presentation of Dispute ..................................... 47 Section 12.2 Inability of Operating Committee to Reach Agreement ......... 47 Section 12.3 Arbitration ................................................. 47 12.3.1 Commencement of Arbitration Proceeding .............. 47 Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 6 Rate Schedule FERC No. 340 12.3.2 Appointment of Arbitrator ........................... 48 12.3.3 Arbitration Proceedings ............................. 48 12.3.4 Authority of Arbitrator ............................. 49 12.3.5 Expenses and Costs .................................. 49 12.3.6 Location of Arbitration Proceedings ................. 49 12.3.7 Confidentiality ..................................... 50 12.3.8 FERC Jurisdiction Over Certain Disputes ............. 50 Section 12.4 Exclusive Means of Dispute Resolution ....................... 51 ARTICLE XIII INDEMNIFICATION; LIMITATION OF LIABILITY .................... 51 Section 13.1 Responsibilities ............................................ 51 Section 13.2 Limitation of Liability ..................................... 52 Section 13.3 Limitation of Actions ....................................... 52 ARTICLE XIV REGULATORY REQUIREMENTS ..................................... 52 Section 14.1 Required Regulatory Approvals and Actions ................... 52 Section 14.2 Regulatory Review ........................................... 53 ARTICLE XV BOOKS AND RECORDS ........................................... 53 Section 15.1 Books and Records ........................................... 53 Section 15.2 Audits ...................................................... 54 Section 15.3 Cooperation in Connection with Regulatory and Judicial Proceedings ................................................. 54 ARTICLE XVI. MISCELLANEOUS ............................................... 54 Section 16.1 Interpretation .............................................. 54 Section 16.2 Partial Invalidity .......................................... 55 Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 7 Rate Schedule FERC No. 340 Section 16.3 Assignment ................................................. 55 Section 16.4 Successors Included ........................................ 56 Section 16.5 Applicable Laws, Regulations, Orders, Approvals, and Permits .................................................... 56 Section 16.6 Choice of Law and Jurisdiction ............................. 56 Section 16.7 Entire Agreement ........................................... 56 Section 16.8 Counterparts to this Agreement ............................. 56 Section 16.9 Amendments ................................................. 56 Section 16.10 Notices .................................................... 57 Section 16.11 Waivers .................................................... 58 Section 16.12 Independent Contractors .................................... 58 Section 16.13 No Third Party Beneficiaries ............................... 58 Section 16.14 Further Assurances ......................................... 59 Section 16.15 Confidentiality ............................................ 59 Section 16.16 Joint Preparation .......................................... 60 Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 8 Rate Schedule FERC No. 340 UNIT POWER SALES AGREEMENT THIS UNIT POWER SALES AGREEMENT ("AGREEMENT") is made and entered into as of this __________________ day of ______________________, 2001, by and among Southwestern Electric Power Company ("SWEPCO"), Power Marketing Affiliate ("PMA"), and American Electric Power Service Corporation ("AEPSC"). SWEPCO, PMA, and AEPSC are wholly owned subsidiaries of American Electric Power Company, Inc. ("AEP"). W I T N E S S E T H WHEREAS, SWEPCO is a vertically integrated public utility company engaged in the provision of retail electric service to franchised service areas in the states of Arkansas, Louisiana, and Texas; WHEREAS, SWEPCO serves retail customers in Arkansas, Louisiana, and Texas from its own generation, as well as from the resources provided through the AEP System and through purchases from non-affiliates; WHEREAS, SWEPCO is part of the AEP System, and has participated with affiliated regulated electric utility operating companies in the AEP-West Operating Agreement and the System Integration Agreement in order to share in the benefits of the coordinated dispatch of the combined power supply resources of the AEP System; Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 9 Rate Schedule FERC No. 340 WHEREAS, PMA is a subsidiary of AEP, and will dispatch and market AEP power supply resources not subject to state cost-of-service regulation; WHEREAS, AEPSC is a subsidiary of AEP that provides certain operation, management, maintenance, and fuel procurement services to SWEPCO with respect to SWEPCO's generating units, as well as other services, including but not limited to engineering, technical, financial, human resources, and information technology services; WHEREAS, the electric utility industry is currently undergoing, and is expected to continue to undergo, significant regulatory, structural, and economic changes; WHEREAS, Texas has enacted a statute that requires the restructuring of the electric utility industry in that state by separating ownership and management of generation assets and related businesses from ownership and management of transmission and distribution assets and related businesses by January 1, 2002, in order to foster the development of competitive electricity markets; WHEREAS, Arkansas has enacted legislation that also requires the restructuring of regulated electric utility companies operating in that state, but the effective date of restructuring in that state has been postponed to at least October 1, 2003; WHEREAS, Louisiana has not yet enacted legislation requiring the restructuring of regulated electric utility companies operating in that state; WHEREAS, under Texas law, after January 1, 2002, SWEPCO may no longer make direct sales to retail customers, while SWEPCO will continue to be operated on a Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 10 Rate Schedule FERC No. 340 regulated, vertically integrated basis and continue to serve retail customers in Arkansas and Louisiana; WHEREAS, SWEPCO intends to adopt a solution to the issues posed by restructuring in Texas that enables SWEPCO to operate its generation attributable to restructured and non-restructured states on a consistent basis, to use its generation attributable to restructured states to comply with the intent of restructuring legislation by competing for generation sales, and to continue to provide vertically integrated retail electric service in regulated jurisdictions; WHEREAS, SWEPCO is willing to sell, and PMA is willing to purchase, Available Assigned Capacity and Energy from SWEPCO's generation resources as provided in this Agreement; WHEREAS, SWEPCO and PMA desire that AEPSC continue to provide the services with respect to SWEPCO's generating units that it has been providing, but in the event AEPSC is unwilling or no longer able to provide such services to SWEPCO, or the Operating Committee elects to terminate the provision of services by AEPSC, that the same services be provided by a service provider selected by the Operating Committee on an efficient and cost-effective basis, so as to maximize the availability of SWEPCO's generating units while minimizing the cost of operating, managing, maintaining, and providing fuel for those units; Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 11 Rate Schedule FERC No. 340 NOW, THEREFORE, in consideration of the premises and mutual covenants set forth herein, the Parties agree as follows: ARTICLE I DEFINITIONS For purposes of this Agreement, the following terms shall have the following meanings: 1.1. "AEP-WEST OPERATING AGREEMENT" means that agreement dated January 1, 1997 by and among Central Power and Light Company, Public Service Company of Oklahoma, SWEPCO, West Texas Utilities Company, and Central and South West Services, Inc., entitled "Restated and Amended Operating Agreement," and any amendment thereto now or hereafter executed by the parties to that agreement. 1.2. "AGREEMENT" means this Unit Power Sales Agreement, including attachments, and any amendments thereto now or hereafter executed by the Parties. 1.3. "ARKANSAS COMMISSION" means the Arkansas Public Service Commission, or any successor organization thereto. 1.4. "ANNUAL BUDGET" means the budget established for each Operating Year in accordance with Section 6.8. 1.5. "ANNUAL OPERATING PLAN" means the operating plan established for each Operating Year in accordance with Section 6.8. 1.6. "APPLICABLE OATT" means the Open Access Transmission Tariff filed with FERC by AEPSC on behalf of SWEPCO and certain of its affiliates in accordance with FERC's Order No. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 12 Rate Schedule FERC No. 340 888 or the Open Access Transmission Tariff filed with FERC by the Southwest Power Pool, as either may be applicable to particular transmission service, or any successor transmission service tariff to either, including any such successor tariff of a Regional Transmission Organization to which SWEPCO transfers operating control or authority over its transmission facilities. 1.7. "ASSIGNED CAPACITY" means that part of the SWEPCO Generating Capacity as defined in Section 4.1 that is allocated, from each generating unit listed in Schedule A or agreement listed in Schedule B, to PMA or to SWEPCO, respectively, under this Agreement. 1.8. "AVAILABLE,", when used to refer to capacity, means that such capacity is currently capable of being dispatched. 1.9. "AVAILABLE ASSIGNED CAPACITY", means that portion of a Party's Assigned Capacity that is currently Available for dispatch. "AVAILABLE CAPACITY" means Available Assigned Capacity and any Called Capacity. 1.10. "BANKRUPTCY" means a situation in which: (i) a Party files a voluntary petition in bankruptcy or is adjudicated as bankrupt or insolvent, or files any petition, answer or consent seeking any reorganization, arrangement, composition, readjustment, liquidation, dissolution or similar relief for itself under the present or future applicable federal, state or other statute or law relating to bankruptcy, insolvency or other relief for debtors, or seeks or consents to, or acquiesces in the appointment of, any trustee, receiver, conservator or liquidator of such Party or of all or any substantial part of such Party's properties (the term "acquiesces" as used in this definition, includes, without limitation, the failure to file a petition or motion to vacate or Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 13 Rate Schedule FERC No. 340 discharge any order, judgment or decree within fifteen Days after entry of such order, judgment or decree); (ii) a court of competent jurisdiction enters an order, judgment or decree approving a petition filed against a Party seeking a reorganization, arrangement, composition, readjustment, liquidation, dissolution or similar relief under any present or future federal bankruptcy law or any other present or future applicable federal, state or other statute or law relating to bankruptcy, insolvency or other relief for debtors, and such Party acquiesces in the entry of such order, judgment or decree or such order, judgment or decree remains unvacated and unstayed for an aggregate of sixty Days, whether or not consecutive, after the date of entry thereof, or any trustee, receiver, conservator or liquidator of such Party or of all or any substantial part of its property is appointed without the consent or acquiescence of such Party and such appointment remains unvacated and unstayed for an aggregate of sixty Days, whether or not consecutive; (iii) a Party admits in writing its inability to pay its debts as they mature; (iv) a Party gives notice to any federal or state governmental authority of insolvency or pending insolvency, or suspension or pending suspension of operations; or (v) a Party makes an assignment for the benefit of creditors or take any other similar action for the protection or benefit of creditors. 1.11. "BUSINESS DAY" means any Day on which Federal Reserve member banks are open for business. A Business Day shall commence at 8:00 a.m. and close at 5:00 p.m., prevailing local time, at the location of the relevant Party's principal place of business, or at such other location as the context may require. In the event that the location cannot be determined from context, SWEPCO's principal place of business shall govern for purposes of application of the definition of "Business Day." Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 14 Rate Schedule FERC No. 340 1.12. "CALLED CAPACITY" means that share of the other Party's Available Assigned Capacity and associated Energy that either PMA or SWEPCO may call under Section 5.6 of this Agreement in the event that the other Party does not designate such Available Assigned Capacity to be dispatched. 1.12.1. "PMA'S CALLED CAPACITY" refers to Available Assigned Capacity and associated Energy not designated to be dispatched by SWEPCO and called by PMA. 1.12.2. "SWEPCO'S CALLED CAPACITY", refers to Available Assigned Capacity and associated Energy not designated to be dispatched by PMA and called by SWEPCO. 1.13. "DAY" means a period of twenty-four (24) consecutive hours, beginning at 12:01 a.m., local time, at the Delivery Point(s); provided, however, that on the Day on which Central Daylight Savings Time becomes effective, the period shall be twenty-three (23) consecutive hours, and on the Day on which Central Standard Time becomes effective, the period shall be twenty-five (25) consecutive hours. 1.14. "DELIVERY POINTS" means the points at which SWEPCO's generating units are connected to SWEPCO's transmission facilities. 1.15. "EMERGENCY", means (i) any abnormal system condition that requires immediate manual or automatic action to prevent loss of firm load, equipment damage, or tripping of system elements that could adversely affect the reliability of SWEPCO's electric system, and (ii) any existing or potential system condition on SWEPCO's electric system that SWEPCO determines, Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 15 Rate Schedule FERC No. 340 in the exercise of reasonable discretion, is not or will not be in conformance with applicable criteria. 1.16. "EMISSION ALLOWANCE" means an emission allowance as defined by any state or federal statute for the control of air pollution, or any amendment thereto and any regulation promulgated thereunder. 1.17. "ENERGY", means the electric energy supplied under this Agreement, which shall be in the form of three-phase, alternating current at a frequency of 60 Hertz, with reasonable variations of frequency and voltage allowed consistent with Good Utility Practice. 1.18. "FERC" means the Federal Energy Regulatory Commission or any successor federal agency having regulatory jurisdiction over this Agreement. 1.19. "FIRST RENEWAL TERM" shall have the meaning provided in Section 3.2.1 of this Agreement. 1.20. "GOOD UTILITY PRACTICE" MEANS any of the practices, methods, and acts required, approved, or engaged in by a significant portion of the electric utility industry in the region where SWEPCO's generating units listed in Schedule A operate during the relevant time period, or any of the practices, methods, and acts which, in the exercise of reasonable judgment in light of the facts known at the time the decision was made, could have been expected to accomplish the desired result at the lowest reasonable cost consistent with good business practices, reliability, safety, and expedition. Good Utility Practice is not intended to be limited to the Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 16 Rate Schedule FERC No. 340 optimum practice, method, or act; rather, it is intended to be a spectrum of acceptable practices, methods, and acts. 1.21. "GOVERNMENTAL REQUIREMENT" means any statute, law, regulation, ordinance, rule, exemption, or order of any federal, state, county, municipal or other governmental authority, any political subdivision of any of the foregoing, or any governmental, quasi-governmental, judicial, public or statutory instrumentality, authority, body or entity, including, without limitation, the final, non-appealable judicial or administrative interpretation of any such statute, law, regulation, ordinance, rule, exemption, or order by any such authority, instrumentality, body, or entity. 1.22. "INITIAL TERM" shall have the meaning provided in Section 3.2 of this Agreement. 1.23. "LOUISIANA COMMISSION" means the Louisiana Public Service Commission, or any successor organization thereto. 1.24. "MONTH" means the period beginning at 12:01 a.m., local time, on the first Day of each calendar month and ending at midnight of the last Day of such calendar month. 1.25. "OPERATING YEAR" means (i) with respect to the year 2002, that period of time beginning the Effective Date and ending on December 31, 2002; and (ii) with respect to subsequent years during the term of this Agreement, the calendar year commencing on January 1 and ending December 31 or such earlier date in such calendar year on which this Agreement expires or is terminated. 1.26. "PARTIES" means SWEPCO, PMA, AEPSC, or the assignee or successor of any of their rights and obligations under this Agreement; provided, however, in Section 5.6 and Article XI Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 17 Rate Schedule FERC No. 340 (including all sections and subsections of each such Section or Article), "PARTIES" refers only to SWEPCO and PMA, or either of them, as the case may be. "PARTY" means one of the Parties. 1.27. "SECOND RENEWAL TERM" shall have the meaning provided in Section 3.2.2 of this Agreement. 1.28. "SWEPCO GENERATING CAPACITY" shall have the meaning set forth in Section 4.1 of this Agreement. 1.29. "SYSTEM INTEGRATION AGREEMENT" means that agreement among Appalachian Power Company, Kentucky Power Company, Ohio Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, and AEPSC, as Agent; and Central Power and Light Company, Public Service Company of Oklahoma, SWEPCO, West Texas Utilities Company, and Central and South West Services, Inc., as Agent, issued May 19, 2000 and effective June 15, 2000, and any amendment thereto now or hereafter executed by the parties to that agreement. 1.30. "PUCT" means the Public Utility Commission of Texas, or any successor organization thereto. 1.31. "UNCOMMITTED CAPACITY" means Available Assigned Capacity that SWEPCO or PMA does not schedule in the initial unit commitment described in Section 5.5. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 18 Rate Schedule FERC No. 340 ARTICLE II SALE AND PURCHASE OF UNIT POWER 2.1. OBLIGATIONS OF SWEPCO AND PMA. SWEPCO shall sell, and PMA shall purchase, Available Capacity and associated dispatched Energy from that portion of the SWEPCO's Generating Capacity that constitutes PMA's Assigned Capacity, and from any portion of SWEPCO's Uncommitted Capacity that is scheduled by PMA pursuant to Section 5.6.2. Each Party shall have the right to designate a portion of its Available Capacity and associated dispatched Energy for ancillary services. 2.2. DELIVERY. SWEPCO shall deliver Energy purchased by PMA at the Delivery Point associated with the generating unit from which the Energy is produced, or in the case of Energy delivered under a third-party agreement listed in Schedule B, at the delivery point specified in the third-party agreement. 2.3. OBLIGATIONS OF AEPSC. AEPSC shall continue to provide those operations, management, maintenance, fuel procurement, and other services enumerated in Section 5.1 of the Restated and Amended AEP West Operating Agreement with respect to the generating units listed on Schedule A. AEPSC shall also provide such additional services as the Operating Committee may, from time to time request, or shall cease providing particular services if so requested by the Operating Committee. In providing such services, subject to the overriding direction of the Operating Committee, AEPSC shall adhere to Good Utility Practice and shall provide such services at the lowest cost consistent with maximizing the availability of such generating units. If AEPSC ceases to provide operations, management, maintenance and fuel Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 19 Rate Schedule FERC No. 340 procurement services with respect to SWEPC0's generating units listed in Schedule A, it shall cease to be a Party to this Agreement on the date it ceases to provide all such services. ARTICLE III TERM OF AGREEMENT 3.1. EFFECTIVE DATE. This Agreement shall be effective upon execution by SWEPCO, PMA, and AEPSC. PMA shall begin to purchase Available Capacity and Energy under this Agreement, and shall begin to dispatch its Assigned Capacity, on January 1, 2002, or on such later date as all required regulatory authorizations have been received. PMA shall have no obligation to purchase or to pay for any Available Capacity or Energy before January 1, 2002 or such later date as all required regulatory authorizations have been received, or to reimburse SWEPCO for any costs that SWEPCO has expensed before that date. 3.2. TERMINATION DATE. Except for (a) termination following an Event of Default as provided in Section 11.2; (b) termination because of regulatory disapproval or regulatory changes as provided in Article XV; or (c) termination pursuant to mutual agreement of SWEPC0 and PMA, this Agreement shall continue in effect with respect to each generating unit listed on Schedule A and each capacity purchase agreement listed on Schedule B for an Initial Term ending on the date shown on Schedule A or Schedule B respectively. 3.2.1. FIRST RENEWAL TERM. Not less than one year before the end of the Initial Term with respect to each unit listed in Schedule A and each agreement listed in Schedule B, PMA shall provide notice to SWEPCO if it wishes to extend this Agreement as to that unit or agreement for a First Renewal Term. In the event Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 20 Rate Schedule FERC No. 340 that PMA elects to enter into a First Renewal Term, the Operating Committee shall retain a consultant, at PMA's expense, to provide an estimate of the remaining useful life of the subject unit or agreement as of the first day of the First Renewal Term. The length of the First Renewal Tenn shall be less than 75 percent of the estimated remaining useful life of the subject unit or agreement as of the first day of the First Renewal Term, expressed in months, and rounded down to the last full month before reaching 75 percent of that estimated remaining useful life. The date by which PMA must provide notice if it wishes to enter into the First Renewal Tenn with respect to each unit or agreement is listed on Schedule A or B respectively. 3.2.2. SECOND RENEWAL TERM. If PMA elects to extend the Agreement for the First Renewal Term with respect to any unit or agreement, then not less than one year before the end of the First Renewal Term as to that unit or agreement, PMA shall provide notice to SWEPCO if it wishes to extend this Agreement for a Second Renewal Term as to that unit or agreement. In the event that PMA elects to enter into a Second Renewal Term, the Operating Committee shall retain a consultant, at PMA's expense, to provide an estimate of the remaining useful life of the subject unit or agreement as of the first day of the Second Renewal Term. The length of the Second Renewal Term shall be less than 75 percent of the estimated remaining useful life of the subject unit or agreement as of the first day of the Second Renewal Term, expressed in months, and rounded down to the last full month before reaching 75 percent of that estimated remaining useful life. This Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 21 Rate Schedule FERC No. 340 Agreement shall terminate as to each such unit or agreement at the conclusion of the Second Renewal Term. ARTICLE IV ALLOCATION OF CAPACITY 4.1. ASSIGNED CAPACITY. SWEPCO and PMA shall each have the right to Available Capacity and associated Energy from its respective Assigned Capacity. Assigned Capacity will be Available to SWEPCO and PMA individually in the same proportion (a) from each of the generating units listed in Schedule A to this Agreement or, in the case of jointly owned units, from SWEPCO's share of such units as reflected on Schedule A, with respect to the capability of each such unit as that capability may change over time as determined by the Operating Committee and (b) from certain capacity purchase agreements made by SWEPCO, listed in Schedule B. For purposes of this Agreement, the capacity of the generating units listed in Schedule A, or in the case of jointly owned units, SWEPCO's share of capacity in such units, and the capacity purchases listed in Schedule B shall be collectively referred to as the "SWEPCO Generating Capacity." 4.1.1. PMA'S ASSIGNED CAPACITY. PMA's Assigned Capacity percentage at each unit listed on Schedule A or from each purchase agreement listed on Schedule B shall be that percentage of the total capability of the SWEPCO Generating Capacity determined using a ratio of the sum of the demands of the SWEPCO-Texas retail native load and the SWEPCO wholesale contract native load for the SWEPCO Wholesale contracts listed on Schedule C at the time of the four Year 2000 coincident Monthly summer (June, July, August, and September) SWEPCO peak Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 22 Rate Schedule FERC No. 340 demands to the sum of the same four coincident peak demands of the total SWEPCO native load. For purposes of this Agreement, the Parties have determined and agree that PMA's initial Assigned Capacity percentage will be 54.46 percent. 4.1.2. SWEPCO'S ASSIGNED CAPACITY. SWEPCO's Assigned Capacity percentage at each unit listed on Schedule A or from each purchase agreement listed on Schedule B shall be that percentage determined by subtracting PMA's Assigned Capacity percentage from 100 percent. For purposes of this Agreement, the Parties have determined and agree that SWEPCO's initial Assigned Capacity percentage will be 45.54 percent. In the event that, after the Effective Date of this Agreement, SWEPCO constructs any new generating unit(s) or enters into an agreement to acquire capacity from a third party, the capacity acquired by such new construction or through such new contract will be SWEPCO's. 4.2. EFFECT OF CAPACITY AUCTION IN TEXAS MANDATED BY STATUTE. Texas has mandated by statute that a portion of SWEPCO's generation previously serving its Texas retail load be offered to third parties for a specified period of time by auction sale. During any part of the term of this Agreement that this requirement is in effect, all such generation required to be auctioned pursuant to Texas statute will the responsibility of PMA, which shall furnish the capacity entitlements to the third parties and shall be entitled to any payments made by such third parties with respect to their acquisition of such capacity entitlements during any part of the term of this Agreement. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 23 Rate Schedule FERC No. 340 4.3. EFFECT OF REQUIRED DIVESTITURE, ASSIGNMENT, OR OTHER DISPOSITION OF SWEPCO GENERATION SERVING ARKANSAS OR LOUISIANA NATIVE LOAD. If SWEPCO divests, assigns or otherwise disposes of generation serving Arkansas or Louisiana native load voluntarily or in compliance with an Arkansas or Louisiana statute, or an Order or Settlement issued or approved by the Arkansas Commission or the Louisiana Commission, any such disposition shall be satisfied from SWEPCO's Assigned Capacity and the percentages set forth in Sections 4.1.1 and 4.1.2 shall be deemed to be changed accordingly. SWEPCO shall be entitled to receive the proceeds from any such disposition. 4.4. EFFECT OF DISAGREEMENT AS TO UNIT RETIREMENT. If SWEPCO and PMA are unable to agree on whether a unit should be retired or kept in service, the Party wishing to retire the unit (referred to in this Section as the "Retiring Party") may provide notice pursuant to Section 16.10 to the other Party (referred to in this Section as the "Non-Retiring Party) and to AEPSC requiring that the unit be removed from the list of units in Schedule A within one year from the date of the notice. 4.4.1. ASSIGNMENT BY SWEPCO TO PMA. In the event that SWEPCO wishes to retire a unit and PMA wishes that it continue to operate, and SWEPCO provides notice to remove the unit from Schedule A, then at PMA's request, and subject to any necessary regulatory review and approval and third-party consents, SWEPCO will transfer to PMA at depreciated book value title to the unit and SWEPCO's title, ownership, or other interests in such real estate, equipment, operational and Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 24 Rate Schedule FERC No. 340 landfill rights, permits, and other property, interests, and rights reasonably required for the operation of the unit. 4.4.2. CONTRACTS PERTAINING TO RETIRED UNIT. After a unit has been removed from Schedule A pursuant to the terms of this Section: a. RETIRING PARTY'S CONTRACTS. The Retiring Party shall bear all of the costs of those contracts pertaining to that unit into which it has entered without the participation of the Non-Retiring Party. b. JOINT CONTRACTS. To the extent such contracts pertain to that unit, SWEPCO and PMA will each bear its Assigned Capacity percentage share of the benefits and obligations of contracts into which SWEPCO and PMA have entered jointly, or into which AEPSC has entered on behalf of both SWEPCO and PMA with the approval of the Operating Committee. c. CONTRACTS CONCERNING INFRASTRUCTURE. In the event that the Retiring Party has contracts concerning infrastructure that solely relates to the retiring plant, the Non-Retiring Party shall have right of first refusal if the Retiring Party sells or otherwise disposes of all or a part of its interest in such a contract. 4.4.3. EFFECT ON RESIDUAL OBLIGATIONS. In the event that SWEPCO or PMA provides notice to remove a unit from Schedule A, and the other Party determines that it Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 25 Rate Schedule FERC No. 340 will continue to operate the unit after it is removed from Schedule A, the Operating Committee shall cause an independent engineering assessment to be made of the costs of decommissioning that unit as of the date of its projected removal from Schedule A. If either SWEPCO or PMA disagrees with the projection of costs in the independent engineering assessment, it may pursue the dispute resolution procedures provided in Article XII to determine the correct assessment. Once the correct assessment is determined, whether through the independent engineering assessment or through dispute resolution, the Retiring Party shall establish an interest-bearing escrow account in the full amount of its Assigned Capacity percentage share of the assessment amount. The Non-Retiring Party shall have the right to draw upon the escrow account, including accrued interest, at the time that the unit is decommissioned, but not before. In return for the Retiring Party's establishment and funding of the escrow account, the Non-Retiring Party shall release the Retiring Party for all liability for the costs of decommissioning the unit. ARTICLE V SCHEDULING AND OPERATIONS 5.1. DISPATCH. PMA shall have the exclusive right to dispatch Energy and ancillary services from its Available Assigned Capacity, as well as from PMA's Called Capacity. Subject to operational requirements established by the Operating Committee and the operation of the units consistent with Good Utility Practice by AEPSC or another third party, SWEPCO shall make PMA's Available Assigned Capacity and PMA's Called Capacity Available for PMA to dispatch Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 26 Rate Schedule FERC No. 340 at all times. SWEPCO shall have the exclusive right to dispatch Energy and ancillary services from its Available Assigned Capacity, as well as from SWEPCO's Called Capacity. 5.2. FORECASTS. AEPSC shall notify SWEPCO and PMA on or before the fifteenth Day of each Month of the amount of Available Capacity and Energy expected to have Available from each of the generating units and each of the purchase agreements included in the SWEPCO Generating Capacity in each of the next thirty-six (36) Months. AEPSC shall provide SWEPCO and PMA with any forecasts of unit outages with respect to the units listed on Schedule A that it either develops or produces. In the event that the amount of Available Capacity or Energy forecast to be Available from any such generating unit(s) or purchase agreement(s) changes, AEPSC will notify SWEPCO and PMA as soon as it is feasible to do so. 5.3. OPERATIONS, MANAGEMENT, AND MAINTENANCE. AEPSC, at the direction of the Operating Committee, shall continue to operate, manage, and maintain the SWEPCO-owned or -operated power plants listed on Schedule A in accordance with Good Utility Practice in order to make Available the dependable capacity of each generating unit at all times that the unit is in operation and to minimize unit downtime. The Operating Committee shall direct AEPSC, and any other service provider that the Operating Committee selects, to operate, manage, and maintain the SWEPCO-owned or -operated power plants listed on Schedule A, to follow PMA's dispatch instructions as well as SWEPCO's, and otherwise to coordinate with PMA and with SWEPCO to the maximum extent possible to achieve the purposes of this Agreement. No agreement with AEPSC or any other third party shall remove or reduce any of SWEPCO's obligations under this Agreement. With respect to those power plants listed on Schedule A that are not owned or Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 27 Rate Schedule FERC No. 340 operated by SWEPCO, AEPSC shall carry out its contract administration responsibilities with respect to those plants in order to assure that SWEPCO's contract rights are exercised in order to benefit both SWEPCO and PMA. 5.3.1. REPLACEMENT OF AEPSC. In the event that AEPSC (a) is unable to provide any or all of the services with respect to the generating units listed on Schedule A that it was providing on January 1, 2001; (b) is precluded by law from providing any or all of such services; (c) furnishes not less than twelve Months' notice to the other Parties that it is no longer willing to provide any or all of such services; or (d) is removed as a service provider with respect to any or all such services by decision of the Operating Committee, SWEPCO shall enter into an agreement with another service provider to obtain the services formerly provided by AEPSC; provided, however, that the selection of such service provider and the new agreement with such provider will both be subject to review and approval by the Operating Committee. The new agreement will require the new service provider to adhere to Good Utility Practice in providing services to SWEPCO and to provide such services at the lowest cost consistent with maximizing the availability of the generating units listed in Schedule A. The new service provider shall become a Party to this Agreement, and shall appoint an Operating Representative to participate in the activities of the Operating Committee as set forth in Section 5.4. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 28 Rate Schedule FERC No. 340 5.4. OPERATING COMMITTEE. By written notice to the other Parties, each Party shall name one representative ("Operating Representative") and one alternate to act for it in matters pertaining to operating arrangements under this Agreement. A Party may change its Operating Representative or alternate at any time by written notice to the other Parties. The three Operating Representatives for the respective Parties, or their alternates, shall comprise the Operating Committee. All decisions, directives, or other actions by the Operating Committee must be by unanimous agreement of the Operating Representatives of SWEPCO and PMA. The Operating Representative of AEPSC, or of any third party that provides services in replacement of AEPSC pursuant to Section 5.3.1 above, shall be free to express the views of AEPSC or such third party on any matter, but shall not have a vote on the Operating Committee except as specifically provided in Section 12. 1. If the Operating Representatives of the Parties are unable to agree on any matter, the matter will be resolved through the dispute resolution procedures provided in Article XII; provided, however, that AEPSC may seek resolution of any matter through the dispute resolution procedures provided in Article XII notwithstanding the unanimous agreement of the Operating Representatives of SWEPCO and PMA with respect to such matter. 5.4.1. OPERATING COMMITTEE RESPONSIBILITIES. The Operating Committee shall have the following responsibilities: a. Review and approval of the Annual Budget and Annual Operating Plan described in Section 6.8, including determination of the Emission Allowances required to be acquired by SWEPCO and PMA. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 29 Rate Schedule FERC No. 340 b. Establishment and review of procedures and systems for dispatch, notification of dispatch, and unit commitment under this Agreement, including any commitment of Called Capacity pursuant to Section 5.6.2. c. Establishment and monitoring of procedures for communication and coordination with respect to unit capacity availability, fuel firing options, and scheduling of the SWEPCO Generating Capacity, including scheduling of outages for maintenance, repairs, equipment replacements, scheduled inspections, and other foreseeable cause of outages at any generating unit, as well as the return of any unit to availability following an unplanned outage. d. Decisions on capital expenditures, including unit upgrades and repowering. e. Determinations as to changes in the unit capability of the units listed on Schedule A and decisions on unit retirement. f. Establishment and modification of billing procedures under this Agreement. 9. Establishment of projected capacity costs for use in planning by the Parties. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 30 Rate Schedule FERC No. 340 h. Specification of fuels, oversight of fuel inspection and certification procedures, and management of fuel inventories. i. Establishment of, termination of, and approval of any change or amendment to, operating arrangements between SWEPCO and AEPSC or any replacement third party with respect to any of the generating units listed in Schedule A, as well as any change to operating arrangements under any of the contracts listed in Schedule B; provided, however, that AEPSC or any replacement third party shall participate in discussions pursuant to this subsection 5.4.1.i only if and to the extent requested to do so by both SWEPCO and PMA. j. Dispute resolution as provided in Section 12. 1. k. Review and approval of plans and procedures designed to insure compliance with any environmental law, regulation, ordinance or permit, including procedures for allocating and using Emission Allowances or for any programs that permit averaging at more than one unit for compliance. 1. Other duties as assigned by agreement of SWEPCO and PMA. 5.4.2. OPERATING COMMITTEE MEETINGS. The Operating Committee shall meet at least quarterly, and at such other times as any Party may reasonably request. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 31 Rate Schedule FERC No. 340 5.4.3. INFORMATION FOR USE OF THE OPERATING COMMITTEE. The Parties shall cooperate in providing to the Operating Committee the information it reasonably needs to carry out its duties, and to supplement or correct such information on a timely basis. 5.5. UNIT COMMITMENT. SWEPCO and PMA will each make an initial unit commitment one Business Day ahead of real-time dispatch. 5.6. DISPATCH OF UNITS; CALL ON UNCOMMITTED CAPACITY. For purposes of this Section 5.6 and all subsections of this Section, the terms "Party" or "Parties" refers only to SWEPCO, PMA, or both of them, as the case may be, and does not refer to AEPSC. 5.6.1. UNITS TO BE DISPATCHED. Any unit designated to be committed by both Parties will be brought on line or kept on line and any unit that neither Party designates to be committed will remain off line or be taken off line. 5.6.2. CALL ON UNCOMMITTED UNITS. Any unit designated to be committed by one Party, but designated not to be committed by the other Party, will be brought on line or kept on line only if the Party designating the unit for commitment undertakes to pay any applicable start-up costs for the unit, as well as any applicable minimum running costs for the unit thereafter, in which event the unit shall be brought on line or kept on line, as the case may be. The Party so designating the unit shall have the right to schedule and dispatch up to all of the Available Capacity of the unit. The Party exercising this right shall be referred to as the "Calling Party," Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 32 Rate Schedule FERC No. 340 and the capacity called by that Party in excess of its Assigned Capacity percentage of the Available Capacity of that unit shall be referred to as its "Called Capacity." The other Party shall be referred to as the "Non-Calling" Party. The Calling Party shall provide reasonable notice to the Non-Calling Party of its call, including any start-up or shut-down time for each unit subject to its call. 5.6.3. RECALL OF CALLED CAPACITY. The Non-Calling Party can reclaim any Called Capacity attributable to its Assigned Capacity share from any unit by giving the Calling Party notice equal to the normal start-up time for the unit in question or one hour, whichever is longer. At the end of the notice period, the Non-Calling Party shall have the right to schedule and dispatch the recalled capacity. At that point, the Non-Calling Party shall resume its responsibility for its share of any applicable start up costs for unit, and prospectively shall bear its responsibility for the costs associated with its Assigned Capacity from the unit. 5.6.4. UNDISPATCHED CAPACITY FROM COMMITTED UNITS. If any capacity remains Available but is not dispatched from a Party's Available Assigned Capacity with respect to a unit committed as a result of the initial unit commitment, the other Party may only schedule and dispatch such capacity pursuant to agreement with the non-dispatching Party. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 33 Rate Schedule FERC No. 340 ARTICLE VI COST COMPONENTS AND PAYMENT TERMS 6.1. COST COMPONENTS. In return for SWEPCO's sale to PMA of Assigned Capacity and Energy under this Agreement, PMA will pay SWEPCO a Capacity Charge as provided in Section 6.2, PMA's share of Non-Fuel Variable Operating Costs as provided in Section 6.3, and Fuel Costs attributable to PMA as provided in Section 6.4. In addition, PMA will pay SWEPCO its share of any other costs approved by the Operating Committee and initially incurred by SWEPCO. Pursuant to Article VII, SWEPCO will bill PMA for those costs with respect to those items and services provided by or through SWEPCO. 6.1.1. AMOUNTS PAID BY SWEPCO FOR THIRD-PARTY SERVICES. SWEPCO shall be responsible in the first instance to make all payments due to AEPSC, or to any replacement service provider furnishing services to SWEPCO, at the units identified on Schedule A, even though such payments will be reflected in the share of Monthly charges payable by PMA to SWEPCO. PMA assumes no liability to AEPSC, or to any service provider furnishing replacement services, by reason of its execution of this Agreement. 6.2. CAPACITY CHARGE. In the case of the generating units listed in Schedule A, PMA will pay a monthly Capacity Charge for its Assigned Capacity calculated pursuant to the formulas and procedures set forth in Schedule D to this Agreement. In the case of the agreements listed in Schedule B, PMA shall pay a Capacity Charge each Month calculated by multiplying its Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 34 Rate Schedule FERC No. 340 Assigned Capacity percentage by the amount of the Capacity Charge that SWEPCO is required to pay under each such agreement for that Month. 6.3. NON-FUEL VARIABLE OPERATING COSTS. In the case of the generating units listed in Schedule A, PMA will pay the Non-Fuel Variable Operating Costs associated with the amount of Energy that it dispatches from Called Capacity in each Month. The formulas, components, and procedures for calculating the Monthly Non-Fuel Variable Operating Costs are listed in Schedule E to this Agreement. 6.4. FUEL COSTS. AEPSC, at the direction of the Operating Committee, shall continue to procure and deliver fuel to each of the generating units listed in Schedule A. Except for any unit listed in Schedule A for which PMA has exercised the option described in Section 6.4.1, for each unit listed in Schedule A, PMA will pay for the Fuel Costs associated with the Energy that it schedules from its Assigned Capacity and from any Called Capacity that it takes pursuant to a call of Uncommitted Capacity as described in Section 5.6 above. Fuel Costs will include the cost of the fuel itself, the cost of fuel transportation, and any carrying charges associated with fuel, and will be calculated by the procedures set forth in Schedule D. 6.4.1. OPTION TO SUPPLY FUEL. With respect to each unit listed in Schedule A, PMA shall have the option, on six (6) Months' notice, to supply the fuel necessary to operate its Assigned Capacity and its Called Capacity, if any, at that unit. This option must be noticed at the same time as to all generating units at a single facility served from the same physical fuel inventory. The option, once noticed, may not be revoked without SWEPCO's consent. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 35 Rate Schedule FERC No. 340 a. USE OF DELIVERY AND STORAGE FACILITIES. If it exercises the option described in this Section 6.4.1, PMA shall have the right to use delivery and storage facilities, including rights of access, owned by SWEPCO or under contract to SWEPCO for the delivery to or storage of such fuel at the station, in proportion to its Assigned Capacity percentage. PMA shall pay to SWEPCO a Monthly charge reflecting the proportional cost of its use of fuel delivery and storage facilities in each Month. b. EFFECT OF EXISTING FUEL SUPPLY AND TRANSPORTATION CONTRACTS. In the event that PMA exercises the option described in this Section 6.4.1 with respect to a unit as to which fuel is supplied under one or more of the long-term fuel supply contracts listed in Schedule E to this Agreement, SWEPCO shall assign to PMA, and PMA shall accept assignment of, a percentage interest of SWEPCO's rights and obligations under the applicable contract(s), and any associated transportation contract(s), determined by multiplying PMA's Assigned Capacity percentage by SWEPCO's entitlement to receive fuel under the contract(s) for the unit(s) as to which the option is exercised. c. Effect of Non-Delivery. If PMA exercises the option provided in this subsection, but for any reason the fuel supply that is PMA's Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 36 Rate Schedule FERC No. 340 responsibility is not timely delivered to the subject generating unit(s), PMA shall not have the right to commit or dispatch the units affected. 6.4.2. OPERATING COMMITTEE OVERSIGHT. In the event that PMA exercises the option to supply fuel described in Section 6.4.1 with respect to any unit, the specifications for the fuel(s) supplied for that unit will be established and, when appropriate, modified, by the Operating Committee. Fuel will be subject to inspection and certification procedures as the Operating Committee may decide. Fuel inventories at each unit that is the subject of the option, or at the generating facility containing such units, may be physically commingled, but separate accounts will be maintained to reflect the fuel credited to each Party and used by each Party at each unit. The Operating Committee will develop procedures to avoid imbalances between the amount of fuel SWEPCO and PMA each delivers and the amount of fuel SWEPCO and PMA each uses, and shall take any steps necessary for the correction of any imbalance by settlement or payment as soon as feasible, but in no event shall imbalances be permitted to exist for more than six months without settlement or payment. The Fuel Costs of SWEPCO and PMA with respect to an individual unit will be equal to the sum of minimum load and hourly average Fuel Costs (based on average heat rates at the unit's level of capacity utilization) associated with the Energy that each schedules from that unit from its Assigned Capacity or Called Capacity. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 37 Rate Schedule FERC No. 340 6.4.3. FUEL INVENTORY. In the event that PMA exercises the option to supply fuel described in Section 6.4.1 with respect to any unit, SWEPCO will assign to PMA a fraction of the fuel inventory as of the date of the option takes effect at the generating units affected by the exercise of the option. The fraction shall be determined by multiplying PMA's Assigned Capacity percentage by the total fuel inventory of that unit on the date of assignment. The assignment shall be at the book value of the total inventory of that unit as of the date of assignment, less book value of the same fraction of the same inventory on the Effective Date of this Agreement. 6.5. FERC FEES. SWEPCO and PMA shall be individually responsible for any fees charged by FERC on the basis of the sales or transmission by each of capacity or energy at wholesale in interstate commerce. 6.6. EMISSION ALLOWANCES. On or before the Effective Date of this Agreement, SWEPCO will assign to PMA the fraction, equal to PMA's Assigned Capacity percentage, of each vintage year of Emission Allowances, issued by the U.S. Environmental Protection Agency ("USEPA") pursuant to Title IV of the Clean Air Act Amendments of 1990 and any regulations thereunder ("Title IV Emission Allowances"), that it has received from the Administrator of USEPA with respect to SWEPCO's generating units listed in Schedule A in the past and has not expended as of the date of assignment. In addition, SWEPCO will assign to PMA a fraction of such Title IV Emission Allowances which were purchased by SWEPCO and held in any account for use at those SWEPCO units. The fraction of such Title IV Emission Allowances to be assigned by Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 38 Rate Schedule FERC No. 340 SWEPCO to PMA will be determined by multiplying PMA's Assigned Capacity percentage by the total of such Title IV Emission Allowances that it has received or purchased and has not expended as of the date of assignment. Thereafter, Title IV Emission Allowances received by SWEPCO with respect to those generating units will be shared by the SWEPCO and PMA in accordance with the Assigned Capacity percentage of each of them. To the extent that additional Title IV Emission Allowances are required, SWEPCO and PMA will each be responsible for acquiring sufficient Title IV Emission Allowances to satisfy the Emission Allowances required because of its dispatch of Energy from each unit. AEPSC will also determine the number and allocation of Emission Allowances to be supplied to any third-party unit operator under applicable designated representative agreements. On or before January 10 of each year, AEPSC shall determine and notify SWEPCO and PMA of the number of additional Emission Allowances consumed by each of them through December 31 of the previous year, and SWEPCO and PMA shall each transfer into the appropriate generating unit U.S. EPA Allowance Transfer System account that number of Emission Allowances with a small compliance margin by January 31 of that year. In the event that SWEPCO or PMA fails to surrender the required number of Emission Allowances by January 3 1, AEPSC shall purchase the required number of Emission Allowances, and SWEPCO or PMA, as the case may be, shall reimburse AEPSC for such purchases, with interest running from the date of the purchases to the date of payment. The Operating Committee will develop procedures to be implemented after the end of each calendar year to account for the Title IV Emission Allowances required by the use of each unit by SWEPCO and PMA and to correct any imbalance between Emission Allowances supplied and Emission Allowances used through the end of the preceding year by settlement or payment. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 39 Rate Schedule FERC No. 340 6.7. CAPITAL REPAIRS AND IMPROVEMENTS. Capital repairs and improvements will be determined by the Operating Committee pursuant to the annual budgeting process set forth in Section 6.8. Expenditures for such capital repairs and improvements will initially be paid by SWEPCO, which shall include the costs of such capital repairs and improvements in calculating the Capacity Charge pursuant to Section 6.2; provided, however, that expenditures that the Operating Committee determines have been or will be incurred exclusively for one Party shall be assigned exclusively to that Party. 6.8. ANNUAL BUDGETING PROCESS. At least 90 days before the start of each Operating Year, SWEPCO shall submit to the Operating Committee a proposed Annual Budget with respect to its generating units listed in Schedule A, a proposed Annual Operating Plan with respect to those generating units, and an estimate and schedule of costs to be incurred for major maintenance or replacement items with respect to those generating units during the next six-year period. At that time, or as soon thereafter as is feasible, it shall also provide corresponding information provided by the seller under each of the agreements listed in Schedule B. The Annual Budget shall be presented on a month-by-month basis for each Month during the next Operating Year, and shall include an operating budget, a capital budget, an estimate of the cost of any major repairs that SWEPCO anticipates will occur during such Operating Year with respect to the generating units listed in Schedule A, and an itemized estimate of all projected non-fuel variable operating expenses relating to SWEPCO's operation of those generating units during that Operating Year. The members of the Operating Committee will meet and work in good faith to agree upon the final Annual Budget and final Annual Operating Plan, and will also meet to discuss the information provided with respect to the agreements listed in Schedule B, including whether Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 40 Rate Schedule FERC No. 340 SWEPCO should seek a modification in the seller's budget or operating plans with respect to the capacity that is the subject of each of those contracts. Once approved, the Annual Budget and Annual Operating Plan shall remain in effect throughout the applicable Operating Year, subject to such changes, revisions, amendments, and updating as the Operating Committee may determine. 6.9. COSTS UPON RETIREMENT OR DECOMMISSIONING OF UNITS. Upon the retirement or decommissioning of any SWEPCO generating unit listed in Schedule A, PMA will be responsible to pay a percentage equal to its Assigned Capacity percentage of the net amount by which the costs of all decommissioning, closure, restoration, and environmental protection measures taken by SWEPCO with respect to the retirement or decommissioning of the unit exceed the proceeds of sale or salvage of the unit, including all facilities and equipment. To the extent such proceeds exceed the costs of all decommissioning, closure, restoration, and environmental protection measures taken by SWEPCO with respect to the retirement or decommissioning of the unit, PMA shall be entitled to receive a percentage of such proceeds equal to its Assigned Capacity percentage. Any dispute between SWEPCO and PMA concerning the application of this section will be resolved through the dispute resolution procedures provided in Article XII. ARTICLE VII BILLING AND PAYMENT 7.1. BILLING PROCEDURE. SWEPCO shall track and bill PMA Monthly for the Capacity Charge attributable to PMA's Assigned Capacity, any Non-Fuel Variable Operating Costs attributable to Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 41 Rate Schedule FERC No. 340 PMA, fuel costs as provided in Section 6.4, and for PMA's share of any other costs approved by the Operating Committee and initially incurred by SWEPCO. 7.2. PAYMENT. Payment of the amounts set forth on the invoice is due from PMA within ten Days after receipt of the invoice, unless otherwise agreed to by SWEPCO and PMA in writing; provided, however, that if the tenth Day after receipt of an invoice is not a Business Day, payment of the amounts set forth in that invoice will be due on the first Business Day after that tenth Day. 7.3. BILLING DISPUTES. PMA may, in good faith, challenge the correctness of any bill rendered under this Agreement no later than twelve (12) Months after the date the bill was rendered. In the event that a bill or portion thereof is challenged, PMA shall nevertheless pay the undisputed amount of the bill when due. Any challenge to a bill shall be in writing and shall state the specific basis for the challenge. If it is subsequently determined or agreed that an adjustment to the bill is appropriate, SWEPCO shall prepare a revised bill and submit such revised bill to PMA. If a refund is due, SWEPCO shall make such refund at the time it submits the revised bill, together with interest on such refund from the date of PMA's original overpayment to the date of SWEPCO's refund payment. If an additional amount is due as a result of the resolution of the billing dispute, PMA shall pay such additional amount within ten Days after receipt of the revised bill, together with interest on such additional amount from the date of PMA's original underpayment to the date of PMA's additional payment. If SWEPCO and PMA cannot agree as to the resolution of a billing dispute within thirty days after the challenge is presented, the dispute will be resolved pursuant to the disputes resolution procedures provided in Article XII. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 42 Rate Schedule FERC No. 340 7.4. BILLING ADJUSTMENTS. SWEPCO shall have the right to adjust any bill rendered under this Agreement for any arithmetic, computational, estimation, meter reading, billing, or other errors no later than twelve (12) Months after the date that the bill was rendered. Any billing adjustment shall be in writing and shall state the specific basis for the adjustment. PMA shall not pay interest on any additional amount due as a result of such adjustment, nor shall SWEPCO shall pay interest on any refund due because of such adjustment. 7.5. APPLICABLE INTEREST RATE. All interest calculations under this Agreement shall use a rate per annum equal to the Federal Funds Rate (as published by the Board of Governors of the Federal Reserve System as from time to time in effect). Such interest shall be calculated on the basis of the actual number of Days elapsed over a year of 360 Days. ARTICLE VIII TRANSMISSION SERVICES 8.1. RESPONSIBILITIES. SWEPCO and PMA shall each be responsible for arranging for transmission service and ancillary services for energy dispatched from its Available Assigned Capacity and Called Capacity, as provided in the Applicable OATT or other applicable tariffs. ARTICLE IX INTERRUPTION AND CURTAILMENTS 9.1. SCHEDULED OUTAGES. SWEPCO and PMA shall jointly agree on the scheduling of outages for maintenance, repairs, equipment replacements, scheduled inspections, and other foreseeable cause of -outages at any SWEPCO generating unit listed in Schedule A. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 43 Rate Schedule FERC No. 340 9.2. NOTIFICATION OF UNSCHEDULED OUTAGES. AEPSC and SWEPCO shall notify PMA as soon as is feasible of any unscheduled outage at any of SWEPCO's generating units listed in Schedule A, or any unscheduled outage affecting deliveries under any of the agreements listed in Schedule B, including the anticipated duration of such unscheduled outage as soon as such duration can reasonably be estimated, and shall update such reports as new information becomes available, until all affected units have been restored to full service. 9.3. EFFECT OF CURTAILMENT. In the event of a curtailment of capacity in any generating unit subject to this Agreement, whether by reason of a scheduled or unscheduled outage, PMA's Assigned Capacity and SWEPCO's Assigned Capacity in such unit shall be decreased in proportion to the respective Assigned Capacity percentages of SWEPCO and PMA under this Agreement, in amount equal to the total amount of such capacity curtailed until the end of the curtailment. ARTICLE X FORCE MAJEURE 10.1. DEFINITION. As used in this Agreement, the term "Force Majeure" means any cause that is beyond the reasonable control of, and without the fault or negligence of, the Party claiming Force Majeure. Force Majeure includes sabotage, strikes or other labor difficulties, riots, civil disturbances, acts of God, acts of public enemies, drought, earthquake, flood, explosion, fire, lightning, landslides, or similar cataclysmic event, or appropriation, diversion, or interruption of service under this Agreement by any court or governmental authority having jurisdiction thereof, or any other cause, whether of the kind enumerated herein or otherwise, not within the control of Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 44 Rate Schedule FERC No. 340 the Party claiming Force Majeure. Economic hardship of any Party shall not constitute a Force Majeure event under this Agreement, including the loss of any market or the inability of either SWEPCO or PMA to economically use or resell energy generated from its Assigned Capacity or from any Called Capacity. 10.2. PERFORMANCE EXCUSED. If any Party is rendered wholly or partially unable to perform under this Agreement because of a Force Majeure event, that Party shall be excused from such obligations to the extent that the occurrence of the Force Majeure event prevents such Party's performance, provided that: (a) the non-performing Party promptly, but in no case longer than three (3) Business Days after the occurrence of the Force Majeure event, gives the other Parties written notice describing in reasonable detail the nature of the Force Majeure event; (b) the suspension of performance shall be of no greater scope and of no longer duration than is reasonably required by the Force Majeure event; and (c) the non-performing Party used Good Utility Practice to remedy its inability to perform. 10.3. STRIKE ISSUES. NO Party to this Agreement shall be required to settle a strike affecting it, except when, in its best judgment, such a settlement appears advisable. 10.4. PAYMENTS NOT EXCUSED. Nothing in this Article X shall excuse either SWEPCO or PMA from making payments when due for its share of the cost components set forth in Article VI or for any other amounts due under any provision of this Agreement. ARTICLE XI DEFAULTS Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 45 Rate Schedule FERC No. 340 11.1. EVENTS OF DEFAULT. For purposes of this Article XI and all sections and subsections of this Article, the terms "Party" or "Parties" refer only to SWEPCO, PMA, or both of them, as the case may be, and do not refer to AEPSC. The following constitute Events of Default by a Party under this Agreement: 11.1.1. BANKRUPTCY. The Bankruptcy of either Party shall be an Event of Default by that Party. 11.1.2. VIOLATION OR NONCOMPLIANCE WITH GOVERNMENTAL REQUIREMENT. Violation or noncompliance with a Governmental Requirement by a Party or its agent shall be an Event of Default by that Party, if the violation or noncompliance has or may have a Material Adverse Effect on the non-defaulting Party with respect to its rights or obligations under this Agreement. For purposes of this Agreement, a "Material Adverse Effect" is any impact or effect that deprives a Party of all or a substantial portion of its reasonably expected benefits under this Agreement, whether directly or by increasing that Party's burdens or costs under this Agreement. 11.1.3. FAILURE TO PERFORM. The failure of a Party to perform a material obligation under this Agreement shall be an Event of Default by that Party. 11.2. NOTICE OF DEFAULT AND OPPORTUNITY TO CURE. Upon the occurrence of an Event of Default, the non-defaulting Party may deliver a written Notice of Default to the defaulting Party. Except for the event set forth in Section 11.1.1, for which the non-defaulting Party may terminate Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 46 Rate Schedule FERC No. 340 this Agreement immediately, the Default Notice shall begin the running of a cure period of thirty (30) Days, at the end of which the non-defaulting Party may terminate this Agreement if the default has not been cured; provided, however, that if the default cannot reasonably be cured within said thirty-day period and the defaulting Party shall have commenced to cure such failure within said period and shall thereafter proceed with reasonable diligence and good faith to cure such failure, then the cure period shall be extended for such longer period of time (but not more than ninety (90) days total, including the original thirty-day period) as shall be necessary to accomplish such cure with all reasonable diligence (so long as such extended period will not cause an immediate Material Adverse Effect on the non-defaulting Party and provided further that the occurrence of any such immediate Material Adverse Effect shall terminate the extended period). 11.3. NO WAIVER. If a non-defaulting Party does not give the Notice of Default provided in Section 11.2, or does not terminate this Agreement after the running of the cure period, notwithstanding the failure of the defaulting Party to cure, in whole or in part, the default, the non-defaulting Party shall not waive any rights it has under this Agreement, including the right to give a new Notice of Default as to the uncured default. 11.4. DISPUTE RESOLUTION. Any dispute as to the application of this Article shall be resolved through the dispute resolution procedures provided in Article XII. ARTICLE XII DISPUTE RESOLUTION Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 47 Rate Schedule FERC No. 340 12.1. PRESENTATION OF DISPUTE. If any Party believes that a dispute has arisen as to the meaning or application of this Agreement, it shall present that matter to the Operating Committee in writing, and shall provide a copy of that writing to the other Parties pursuant to the notice provisions of Section 16.10 of this Agreement. The Operating Representative of any Party not involved in the dispute may participate in discussion of the dispute, but shall not have a vote on the resolution of the dispute. For purposes of resolving a dispute presented to the Operating Committee, if AEPSC (or any third party that provides services in replacement of AEPSC pursuant to section 5.3.1) is one of the Parties involved in the dispute, its Operating Representative shall have a vote on the resolution of the dispute, and any decision of the Operating Committee resolving the dispute must be unanimous. 12.2. INABILITY OF OPERATING COMMITTEE TO REACH AGREEMENT. If the Operating Committee is unable to reach agreement on any dispute within thirty days after the dispute is presented to it, the matter shall be referred to the Chief Operating Officers of the Parties involved in the dispute for resolution in the manner that such individuals shall agree is appropriate; provided, however, that any Party involved in a dispute may invoke the arbitration provisions set forth in Section 12.3 at any time after the end of the thirty-day period provided for the Operating Committee to reach agreement. 12.3. ARBITRATION. 12.3.1. COMMENCEMENT OF ARBITRATION PROCEEDING. If the Parties involved in a dispute arising under this Agreement are unable to resolve that dispute through the Operating Committee within thirty days after the dispute is presented to the Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 48 Rate Schedule FERC No. 340 Operating Committee pursuant to Section 12.1, or through reference of the matter to the Chief Operating Officers of the Parties involved in the dispute pursuant to section 12.2, any Party involved in the dispute may commence arbitration proceedings by providing written notice to the other Parties, detailing the nature of the dispute, designating the issue(s) to be arbitrated, identifying the provisions of this Agreement under which the dispute arose, and setting forth such Party's proposed resolution of such dispute. 12.3.2. APPOINTMENT OF ARBITRATOR. Within 10 days of the date of the notice of arbitration, a representative of each Party involved in the dispute shall meet for the purpose of selecting an arbitrator. If the Parties' representatives are unable to agree on an arbitrator within 15 days of the date of the notice of arbitration, then an arbitrator shall be selected in accordance with the procedures of the American Arbitration Association ("AAA"). Whether the arbitrator is selected by the Parties' representatives or in accordance with the procedures of the AAA, the arbitrator shall have the qualifications and experience in the occupation, profession, or discipline relevant to the subject matter of the dispute. 12.3.3. ARBITRATION PROCEEDINGS. Any arbitration proceeding shall be subject to the Federal Arbitration Act, 9 U.S.C. ss. ss. 1 ET SEQ. (1994), as it may be amended, or any successor enactment thereto, and shall be conducted in accordance with the commercial arbitration rules of the AAA in effect on the date of the notice to the extent not inconsistent with the provisions of this Article XII. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 49 Rate Schedule FERC No. 340 12.3.4. AUTHORITY OF ARBITRATOR. The arbitrator shall be bound by the provisions of this Agreement where applicable, and shall have no authority to modify any terms and conditions of this Agreement in any manner. The arbitrator shall render a decision resolving the dispute in an equitable manner, and may determine that monetary damages are due to a Party or may issue a directive that a Party take certain actions or refrain from taking certain actions, but shall not be authorized to order any other form of relief, provided, however, that nothing in this Article shall preclude the arbitrator from rendering a decision that adopts the resolution of the dispute proposed by a Party. Unless otherwise agreed to by the Parties involved in the dispute, the arbitrator shall render a decision within 120 days of appointment, and shall notify the Parties to this Agreement in writing of such decision and the reasons supporting such decision. The decision of the arbitrator shall be final and binding upon the Parties involved in the dispute, and any award may be enforced in any court of competent jurisdiction. 12.3.5. EXPENSES AND COSTS. The fees and expenses of the arbitrator shall be shared equally by the Parties involved in the dispute, unless the arbitrator specifies a different allocation. All other expenses and costs of the arbitration proceeding shall be the responsibility of the Party incurring such expenses and costs. 12.3.6. LOCATION OF ARBITRATION PROCEEDINGS. Unless otherwise agreed by the Parties involved in the dispute, any arbitration proceedings shall be conducted in Columbus, Ohio. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 50 Rate Schedule FERC No. 340 12.3.7. CONFIDENTIALITY. Except as provided in this Article, the existence, contents, or results of any arbitration proceeding under this Article may not be disclosed without the prior written consent of the Parties involved in the dispute; provided, however, that any Party may make disclosures as may be required to fulfill regulatory obligations to any agencies having jurisdiction, and may inform its lenders, affiliates, auditors, and insurers, as necessary, under pledge of confidentiality, and may consult with expert consultants as required in connection with an arbitration proceeding under pledge of confidentiality. 12.3.8. FERC JURISDICTION OVER CERTAIN DISPUTES. Nothing in this Agreement shall be construed to preclude any Party from filing a petition or complaint with FERC with respect to any claim over which FERC has jurisdiction. In such case, any other Party may request that FERC reject the petition or complaint or otherwise decline to exercise its jurisdiction. If FERC declines to act with respect to all or part of a claim, the portion of the claim not so accepted by FERC may be resolved through arbitration, as provided in this Article. To the extent that FERC asserts or accepts jurisdiction over all or part of a claim, the decisions, findings of fact, or orders of FERC shall be final and binding, subject to judicial review under the Federal Power Act, and any arbitration proceedings that may have commenced prior to the assertion or acceptance of jurisdiction by FERC shall be stayed, pending the outcome of the FERC proceedings. The arbitrator shall have no authority to modify, and shall be conclusively bound by, any decisions, findings of fact, or orders of FERC; provided, however, that to the extent that any Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 51 Rate Schedule FERC No. 340 decisions, findings of fact, or orders of FERC do not provide a final or complete remedy to a Party seeking relief, such Party may proceed to arbitration under this Article to secure such a remedy, subject to any FERC decisions, findings, or orders. 12.4. EXCLUSIVE MEANS OF DISPUTE RESOLUTION. The procedures set forth in this Article XII shall be the exclusive means for resolving disputes arising under this Agreement and shall survive this Agreement to the extent necessary to resolve any disputes pertaining to this Agreement. Except as provided in Sections 12.3.1 and 12.3.8, no Party shall have the right to bring any dispute for resolution by a court, agency, or other entity having jurisdiction over this Agreement, unless both Parties agree in writing to such procedure. ARTICLE XIII INDEMNIFICATION; LIMITATION OF LIABILITY 13.1. RESPONSIBILITIES. Subject to Section 13.2, each Party shall indemnify and hold harmless each other Party and its owners, officers, directors, employers, represent atives, and agents for, against, and from any claim, liability, damage, loss, or expenses of any kind or nature (including reasonable attorneys' fees) for any claims, suits, judgments, demands, actions, or liabilities, in each such instance to the extent determined to be attributed to the negligence, gross negligence, willful misconduct, or strict liability in tort or breach of this Agreement by the indemnitor or its owners, officers, directors, employers, representatives, and agents (it being the intention of the Parties that each Party is entitled to reciprocal and comparative indemnity). The provisions of this Section 13.1 shall survive the expiration or termination of this Agreement. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 2 Southwestern Electric Power Company Original Sheet No. 52 Rate Schedule FERC No. 340 13.2. LIMITATION OF LIABILITY. FOR BREACH OF ANY PROVISION OF THIS AGREEMENT, A PARTY'S LIABILITY SHALL BE LIMITED TO DIRECT ACTUAL DAMAGES ONLY. SUCH DIRECT ACTUAL DAMAGES SHALL BE THE SOLE AND EXCLUSIVE REMEDY, AND ALL OTHER REMEDIES OR DAMAGES AT LAW OR IN EQUITY ARE WAIVED. UNLESS EXPRESSLY HEREIN PROVIDED, NO PARTY SHALL BE LIABLE FOR CONSEQUENTIAL, INCIDENTAL, PUNITIVE, EXEMPLARY, OR INDIRECT DAMAGES, LOST PROFITS OR OTHER BUSINESS INTERRUPTION DAMAGES, BY STATUTE, IN TORT OR CONTRACT, UNDER ANY INDEMNITY PROVISION OR OTHERWISE. IT IS THE INTENT OF THE PARTIES THAT THE LIMITATIONS HEREIN IMPOSED ON REMEDIES AND THE MEASURE OF DAMAGES BE WITHOUT REGARD TO THE CAUSE OR CAUSES RELATED THERETO, INCLUDING THE NEGLIGENCE OF ANY PARTY, WHETHER SUCH NEGLIGENCE BE SOLE, JOINT OR CONCURRENT, OR ACTIVE OR PASSIVE. 13.3. LIMITATION OF ACTIONS. No Party shall present a claim under this Agreement for damages or other relief with respect to any action or omission of another Party that occurred more than twenty-four (24) Months before the claim is asserted. With respect to billing disputes, any claim for reduction or increase must be presented within twelve (12) Months after the bill was rendered. ARTICLE XIV REGULATORY REQUIREMENTS 14.1. REQUIRED REGULATORY APPROVALS AND ACTIONS. In the event that any regulatory agency with jurisdiction to approve or disapprove this Agreement finally disapproves this Agreement, Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 53 Rate Schedule FERC No. 340 then the Agreement shall terminate on December 31, 2001 or the date of disapproval, whichever is later. No regulatory disapproval shall be final for purposes of this terminating this Agreement until all motions for reconsideration or appeals of the disapproval letter have been decided and the time for any further appeal shall have elapsed without such further appeal having been noticed. 14.2. REGULATORY REVIEW. If, during review of this Agreement, any regulatory agency with jurisdiction and authority to do so orders the modification of any term or condition, or orders the alteration of any charge(s), or in any way conditions its approval of this Agreement, and either SWEPCO or PMA determines that such order, action, or decision has or will have a Material Adverse Effect on it (as that term is defined in Section 11.1.2), SWEPCO and PMA shall negotiate in good faith to agree on modified terms and conditions mutually agreeable to them that are consistent with such regulatory order, action, or decision and that preserve, to the maximum extent possible, the balance of economic benefits and burdens previously created by this Agreement before the issuance of such regulatory order, action, or decision. ARTICLE XV BOOKS AND RECORDS 15.1. BOOKS AND RECORDS. SWEPCO shall keep such books and records with respect to the costs of owning, operating, and maintaining or improving its generating units and such other pertinent information under this Agreement as shall be required (1) to allow PMA to verify the accuracy of SWEPCO's billing statements, and (2) to comply with FERC and other regulatory authority requirements. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 54 Rate Schedule FERC No. 340 15.2. AUDITS. PMA shall have the right, at its sole expense, upon reasonable notice and during normal Business Day hours, to examine SWEPCO's books and records to the extent reasonably necessary to verify the accuracy of any statement, charge, or computation made pursuant to this Agreement, for a period of up to one year after such statement, charge or computation has been supplied to PMA. 15.3. COOPERATION IN CONNECTION WITH REGULATORY AND JUDICIAL PROCEEDINGS. To the extent that any Party requires relevant information in the possession of another Party for regulatory or judicial purposes, the Party possessing such information shall cooperate with the other Party to provide the information required to satisfy the inquiry; provided, however, that a Party may deem any information in its possession to be privileged or confidential, and to this extent, the Party seeking such information for regulatory or judicial purposes shall put forth its best efforts to protect the privileged or confidential status of such information, including promptly notifying the other Party that the information has been requested, and petitioning the applicable regulatory or judicial body for a protective order protecting the privileged or confidential status of the information. ARTICLE XVI MISCELLANEOUS 16.1. INTERPRETATION. In this Agreement: (i) unless otherwise specified, references to any Article, Section, Schedule or Exhibit are references to such Article, Section, Schedule or Exhibit of this Agreement; (ii) the singular includes the plural and the plural includes the singular; (iii) unless otherwise specified, each reference to a Governmental Requirement includes all provisions amending, modifying, supplementing or replacing such Governmental Requirement Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 55 Rate Schedule FERC No. 340 from time to time; (iv) the words "including," "includes" and "include" shall be deemed to be followed by the words "without limitation"; (v) unless otherwise specified, each reference to any agreement includes all amendments, modifications, supplements, and restatements made to such agreement from time to time which are not prohibited by this Agreement; (vi) the descriptive headings of the various Articles and Sections of this Agreement have been inserted for convenience of reference only and shall in no way modify or restrict the terms and provisions thereof, and (vii) "herein," "hereof," "hereto" and "hereunder" and similar terms refer to this Agreement as a whole. 16.2. PARTIAL INVALIDITY. Wherever possible, each provision of this Agreement shall be interpreted in a manner as to be effective and valid under applicable law, but if any provision contained herein shall be found to be invalid, illegal, or unenforceable in any respect and for any reason, such provision shall be ineffective to the extent, but only to the extent, of such invalidity, illegality, or unenforceability without invalidating the remainder of the provision or any provision of this Agreement, unless such a construction would be unreasonable. If such a construction would be unreasonable or would deprive a Party of a material benefit under this Agreement, the Parties shall seek to amend this Agreement to remove the invalid portion and otherwise provide the benefit, unless prohibited by law. 16.3. ASSIGNMENT. Any transfer or assignment by any Party of any or all rights, benefits or responsibilities under this Agreement shall not relieve the transferring Party of any responsibility under this Agreement unless the other Parties so consent; provided, however, that consent to a release of an assigning Party's responsibilities shall not be unreasonably withheld. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 56 Rate Schedule FERC No. 340 16.4. SUCCESSORS INCLUDED. Reference to any individual, corporation, or other entity shall be deemed a reference to such individual, corporation, or other entity together with its successors and permitted assigns from time to time. 16.5. APPLICABLE LAWS, REGULATIONS, ORDERS, APPROVALS, AND PERMITS. This Agreement is made subject to all existing and future applicable Governmental Requirements, including federal, state, and local laws and to all existing and future duly promulgated orders or other duly authorized actions of governmental authorities having jurisdiction over the matters set forth in this Agreement. 16.6. CHOICE OF LAW AND JURISDICTION. The interpretation and performance of this Agreement shall be in accordance with the laws of the State of Texas, excluding conflicts of law principles that would require the application of the laws of a different jurisdiction. 16.7. ENTIRE AGREEMENT. This Agreement supersedes all previous representations, understandings, negotiations, and agreements either written or oral between the Parties or their representatives with respect to the subject matter hereof, and constitutes the entire agreement of the Parties with respect to the subject matter hereof. 16.8. COUNTERPARTS TO THIS AGREEMENT. This Agreement may be executed in any number of counterparts, each of which shall be an original, but all of which together shall constitute one and the same instrument. 16.9. AMENDMENTS. It is contemplated by the Parties that it may be appropriate from time to time to change, amend, modify, or supplement this Agreement, including the Service Schedules Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 57 Rate Schedule FERC No. 340 and any other attachments that may be made a part of this Agreement, to reflect changes in operating practices or costs of operations or for other reasons. Any such changes to this Agreement shall be in writing executed by the Parties and, if appropriate, subject to approval or acceptance for filing by the FERC. 16.10. NOTICES. Unless otherwise provided in this Agreement, any notice, consent, or other communication required to be made under this Agreement shall be in writing and shall be delivered in person, by certified mail (postage prepaid, return receipt requested), or by nationally recognized overnight courier (charges prepaid), in each case properly addressed to such Party as shown below, or sent by facsimile transmission to the facsimile number indicated below. Any Party may from time to time change its address for the purposes of notices, consents, or other communications to that Party by a similar notice specifying a new address, but no such change shall become effective until it is actually received by the Parties sought to be charged with its contents. All notices, consents, or other communications required or permitted under this Agreement that are addressed as provided in this Section 16.10 shall be deemed to have been given (a) upon delivery, if delivered in person or by overnight courier or certified mail, or (b) upon automatically generated confirmation if given by facsimile. SWEPCO: 1 Riverside Plaza Columbus, OH 43215 facsimile: 614-223-2352 PMA: 1 Riverside Plaza Columbus, OH 43215 facsimile: 614-324-5096 Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 58 Rate Schedule FERC No. 340 AEPSC: 1 Riverside Plaza Columbus, OH 43215 facsimile: 614-223-2352 16.11. WAIVERS. The failure of any Party to enforce at anytime any provision of this Agreement shall not be construed as a waiver of such provision. No such failure to enforce a provision shall affect in any way the validity of this Agreement or any portion thereof or the right of that Party thereafter to enforce each and every provision of this Agreement. To be effective, a waiver under this Agreement must be in writing and specifically state that it is a waiver. No waiver of any breach of this Agreement shall be held to constitute a waiver of any other or subsequent breach. 16.12. INDEPENDENT CONTRACTORS. SWEPCO and PMA are independent contractors. Nothing contained herein shall be deemed to create an association, joint venture, partnership or principal/agent relationship between SWEPCO and PMA or impose any partnership obligation or liability on either of them. Neither SWEPCO nor PMA shall have any right, power or authority to enter into any agreement or commitment, act on behalf of or otherwise bind the other Party in any way. 16.13. NO THIRD-PARTY BENEFICIARIES. Nothing in this Agreement, whether express or implied, is intended to confer any rights or remedies under or by reason of this Agreement on any persons other than the Parties and their respective successors and permitted assigns. Nor is anything in this Agreement intended to relieve or discharge the obligation or liability of any third persons to any Party or give any third person any right of subrogation or action against any Party. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 59 Rate Schedule FERC No. 340 16.14. FURTHER ASSURANCES. If any Party determines in its reasonable discretion that any further instruments, assurances, or other things are necessary or desirable to carry out the terms of this Agreement, the other Parties shall execute and deliver all such instruments or assurances, and do all things reasonably necessary or desirable to carry out the terms of this Agreement. 16.15. CONFIDENTIALITY. Each Party agrees that it will maintain in strictest confidence all documents, materials and other information marked "Confidential" or "Proprietary" by the disclosing Party ("Confidential Information") which it shall have obtained regarding another Party during the course of the negotiations leading to, and its performance of, this Agreement (whether obtained before or after the date of this Agreement). Each Party also agrees that it will maintain in strictest confidence, and treat as Confidential Information (whether marked "Confidential" or "Proprietary" or not) all nonpublic information regarding the condition or operation of any generating unit or plant that is the subject of this Agreement. Confidential Information shall not be communicated to any third person by a Party (other than to its affiliates, counsel, accountants, financial or tax advisors, or insurance consultants or in connection with its financing); PROVIDED that in the event the receiving Party is required by law, regulation or court order to disclose any Confidential Information, the receiving Party will promptly notify the disclosing Party in writing prior to making any such disclosure in order to facilitate the disclosing Party's seeking a protective order or other appropriate remedy from the proper authority and further PROVIDED that the receiving Party further agrees that if the disclosing Party ultimately discloses such Confidential Information to the requesting legal or regulatory body, it will furnish only that portion of the Confidential Information which is legally required and will exercise all reasonable efforts to obtain reliable assurances that confidential treatment will be Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 60 Rate Schedule FERC No. 340 accorded the Confidential Information. The obligations of nondisclosure and restricted use of Confidential Information shall survive the expiration or other termination of this Agreement until such obligations expire in accordance with their respective terms. 16.16 JOINT PREPARATION. This Agreement shall be deemed to have been jointly prepared by all Parties, and no ambiguity herein shall be construed for or against any Party based upon the identity of the author of this Agreement or any portion thereof. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 61 Rate Schedule FERC No. 340 IN WITNESS WHEREOF, the Parties have executed this Agreement as of the date set forth at the beginning of this Agreement. SOUTHWESTERN ELECTRIC POWER COMPANY By: ---------------------------------------- POWER MARKETING AFFILIATE By: ---------------------------------------- AMERICAN ELECTRIC POWER SERVICE CORPORATION By: ---------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 62 Rate Schedule FERC No. 340 SCHEDULE A SWEPCO GENERATING UNITS SUBJECT TO THIS AGREEMENT ------------------------------------------------- UNIT MAXIMUM DEPENDABLE END OF RENEWAL kW NET OUTPUT INITIAL TERM NOTICE DATE ---- ------------------ ------------ ----------- Arsenal Hill Unit 5 110,000 Dolet Hills Unit 1* 261,521 Flint Creek Unit 1* 264,000 Knox Lee Unit 2 25,000 Knox Lee Unit 3 25,000 Knox Lee Unit 4 77,000 Knox Lee Unit 5 344,000 Lieberman Unit 1 25,000 Lieberman Unit 2 26,000 Lieberman Unit 3 112,000 Lieberman Unit 4 110,000 Lone Star Unit 1 50,000 Pirkey Unit 1* 580,068 Welsh Unit 1 528,000 Welsh Unit 2 528,000 Welsh Unit 3 528,000 Wilkes Unit 1 175,000 Wilkes Unit 2 357,000 Wilkes Unit 3 348,000 * indicates SWEPCO share of jointly owned unit Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 63 Rate Schedule FERC No. 340 SCHEDULE B SWEPCO CAPACITY PURCHASE CONTACTS SUBJECT TO THIS AGREEMENT ----------------------------------------------------------- CONTRACT INITIAL TERM -------- ------------ Purchase from Southwest Mesa Wind Project Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 64 Rate Schedule FERC No. 340 SCHEDULE C SWEPCO WHOLESALE CONTRACTS -------------------------- Northeast Texas Electric Cooperative East Texas Electric Cooperative Tex-La Electric Cooperative (Two contracts) Rayburn Country Electric Cooperative City of Bentonville, Arkansas City of Hope, Arkansas City of Minden, Louisiana Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 65 Rate Schedule FERC No. 340 SCHEDULE D FORMULAS, COMPONENTS, AND PROCEDURES FOR CALCULATING MONTHLY CAPACITY CHARGES ----------------------------------------------------------------------------- D-1 Schedule D DETERMINATION OF CHARGES APPLICABLE TO Page 1 PRODUCTION REVENUE REQUIREMENTS AND FUEL 12 MONTHS ENDED 12/31/00 1. Monthly Capacity Charge = (Annual Production Cost * PMA's Assigned Capacity Percentage (Note A)) ---------------------------------------------------------------------- 12 2. Monthly Fuel Charge = Monthly Fuel Cost * (PMA's Monthly MWH Scheduled / Total Monthly MWH Scheduled) Where: Annual Production Cost, P. D-2 Monthly Fuel Cost, P. D-17 MWH scheduled from generating units listed in Schedule A except for those units for which PMA has exercised the option described in Section 6.4.1. Note A: PMA's Assigned Capacity Percentage as stated in Section 4.1.1. Note B: The charges determined by this Schedule shall be based on the costs associated with the generating units listed in Schedule A. Note C: Refer to P. D-18 for estimated billing and true-up procedures to be followed in the determination of charges pursuant to this Schedule. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 66 Rate Schedule FERC No. 340 D-2 Schedule D ANNUAL PRODUCTION COST Page 2 12 MONTHS ENDED 12/31/00 PRODUCTION Reference Amount -------------------------------------------------------------------------------- 1. Return on Investment P. D-3, L.19, Col.(1) -------------------------------------------------------------------------------- 2. Operation & Maintenance Expense P. D-12, L.9, Col.(1) -------------------------------------------------------------------------------- 3. Depreciation Expense P. D-13, L.8, Col.(1) -------------------------------------------------------------------------------- 4. Taxes Other Than Income Taxes P. D-14, L.5, Col.(2) -------------------------------------------------------------------------------- 5. Income Tax P. D-15, L.5, Col.(1) -------------------------------------------------------------------------------- 6. Annual Production Cost L.1 to L.5 -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 67 Rate Schedule FERC No. 340 D-3 Schedule D RETURN ON PRODUCTION-RELATED INVESTMENT Page 3 12 MONTHS ENDED 12/31/00 -------------------------------------------------------------------------------- Reference Amount -------------------------------------------------------------------------------- 1. ELECTRIC PLANT (1) -------------------------------------------------------------------------------- 2. Gross Plant in Service P. D-4, L.4, Col. (2) -------------------------------------------------------------------------------- 3. Less: Accumulated Depreciation P. D-4, L.11, Col. (2) -------------------------------------------------------------------------------- 4. Less: Accumulated Deferred Taxes P. D-4, L.12, Col. (2) -------------------------------------------------------------------------------- 5. Net Plant in Service L.2 - (L.3 + L.4) -------------------------------------------------------------------------------- 6. Plant Held for Future Use (Note A) FERC-1, P.200, L.10 -------------------------------------------------------------------------------- 7. Pollution Control CWIP Note B -------------------------------------------------------------------------------- 8. Fuel Conversion CWIP Note B -------------------------------------------------------------------------------- 9. Subtotal - Electric Plant L.5+L.6+L.7+L.8 -------------------------------------------------------------------------------- 10. WORKING CAPITAL -------------------------------------------------------------------------------- 11. Materials & Supplies -------------------------------------------------------------------------------- 12. Fuel P. D-7, L.2, Col. (2) -------------------------------------------------------------------------------- 13. Nonfuel P. D-7, L.8, Col. (2) -------------------------------------------------------------------------------- 14. Total M & S L.12 + L.13 -------------------------------------------------------------------------------- 15. Prepayments (Note A) FERC-1, P. 110, L.46 -------------------------------------------------------------------------------- 16. Cash Requirements P. D-6, L.17 -------------------------------------------------------------------------------- 17. Total Investment L.9+L.14+L.15+L.16 -------------------------------------------------------------------------------- 18. Composite Cost of Capital P.D-9, L.4, Col. (4) -------------------------------------------------------------------------------- 19. Return on Investment L.17 x L.18 -------------------------------------------------------------------------------- Note A: Production amount only. To be determined by AEPSC. Note B: To be determined by AEPSC. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 68 Rate Schedule FERC No. 340 D-4 Schedule D PRODUCTION-RELATED ELECTRIC PLANT IN SERVICE Page 4 12 MONTHS ENDED 12/31/00
SYSTEM PRODUCTION ---------------------------------------------------------------------------------------------------------- Reference Amount Reference Amount (1) (2) ---------------------------------------------------------------------------------------------------------- 1. GROSS PLANT IN SERVICE (Note A) ---------------------------------------------------------------------------------------------------------- 2. Plant in Service (Note D) FERC-1, P. 207 L.42 ---------------------------------------------------------------------------------------------------------- 3. Allocated General Plant P. D-5, Col. (3), L.26 ---------------------------------------------------------------------------------------------------------- 4. Total L.2 + L.3 ---------------------------------------------------------------------------------------------------------- 5. Col. (2), L.4 ---------------------------------------------------------------------------------------------------------- 6. Col. (1), L.4 ---------------------------------------------------------------------------------------------------------- 7. Col. (2), L.5/Col. (2), L.6 ---------------------------------------------------------------------------------------------------------- 8. ACCUMULATED PROVISION FOR DEPRECIATION (Note A) ---------------------------------------------------------------------------------------------------------- 9. Plant in Service FERC-1, P. 219, L.18-22 (Note E) ---------------------------------------------------------------------------------------------------------- 10. Allocated General Plant Note B ---------------------------------------------------------------------------------------------------------- 11. Total L.9 + L.10 ---------------------------------------------------------------------------------------------------------- 12. ACCUMULATED FERC-1, P. 274-278, DEFERRED TAXES 232 & 234 Accts. 282, (Note A) 283, 254, 182.3 & 190 Note C ----------------------------------------------------------------------------------------------------------
Note A: Thirteen Months Average Note B: (% From P. D-5, Col. (2), L.27) X (13 Months Average General Plant Accumulated Depreciation FERC-1, P. 219, Col.(c), L.25) Note C: (% From Col. (2), L.7 above) X (Col. (1), L.12) Note D Includes Generator Step-Up Transformers and Other Generation related investments previously included in the transmission plant accounts, but not included in the establishment of rates for AEP Open Access Transmission Tariff. Note E: Includes Accumulated Depreciation associated with the Generator Step-Up Transformers and Other Generation investments (See Note D). Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 69 Rate Schedule FERC No. 340 D-5 Schedule D PRODUCTION-RELATED GENERAL PLANT ALLOCATION Page 5 12 MONTHS ENDED 12/31/00 General Plant Accounts 101 and 106 -------------------------------------------------------------------------------- Total Related to System Allocation Production (Note A) Factor (1) x (2) (1) (2) (3) -------------------------------------------------------------------------------- 1. General Plant -------------------------------------------------------------------------------- 2. Land -------------------------------------------------------------------------------- 3. District Offices -------------------------------------------------------------------------------- 4. General Offices Note B -------------------------------------------------------------------------------- 5. Total Land -------------------------------------------------------------------------------- 6. Structures -------------------------------------------------------------------------------- 7. District Offices -------------------------------------------------------------------------------- 8. General Offices Note B -------------------------------------------------------------------------------- 9. Total Structures -------------------------------------------------------------------------------- 10. Office Equipment -------------------------------------------------------------------------------- 11. District Offices -------------------------------------------------------------------------------- 12. General Offices Note B -------------------------------------------------------------------------------- 13. Total Office Equipment -------------------------------------------------------------------------------- 14. Transportation Equipment Note B -------------------------------------------------------------------------------- 15. Stores Equipment Note B -------------------------------------------------------------------------------- 16. Tools, Shop & Garage Equipment Note B -------------------------------------------------------------------------------- 17. Lab Equipment Note B -------------------------------------------------------------------------------- 18. Communications Equipment Note B -------------------------------------------------------------------------------- 19. Miscellaneous Equipment Note B -------------------------------------------------------------------------------- 20. Subtotal -------------------------------------------------------------------------------- 21. PERCENT Note C -------------------------------------------------------------------------------- 22. Other Tangible Property -------------------------------------------------------------------------------- 23. Fuel Exploration Note D -------------------------------------------------------------------------------- 24. Rail Car Facility Note D -------------------------------------------------------------------------------- 25. Total Other Tangible Property -------------------------------------------------------------------------------- 26. TOTAL GENERAL PLANT -------------------------------------------------------------------------------- 27. PERCENT Note E -------------------------------------------------------------------------------- NOTE A: Thirteen months average data from SWEPCO Books. NOTE B: Allocation factors based on wages and salaries in electric operations and maintenance expenses excluding administrative and general expenses: a. Total wages and salaries in electric operation and maintenance expenses excluding administrative and general expense, FERC-1, P.354, Col. (b), L. 25 minus L. 24. b. Production wages and salaries in electric operation and maintenance expense, FERC-1, P.354, Col. (b), L.18. c. Ratio (b/a) To the extent separate functional accounting ledgers are developed in the future, the directly assigned production function General Plant amounts shall be utilized. NOTE C: L.20, Col. (3)/L.20, Col. (1) NOTE D: Directly assigned to Production NOTE E: L.26, Col. (3)/L.26, Col. (1) Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 70 Rate Schedule FERC No. 340 D-6 Schedule D PRODUCTION-RELATED CASH REQUIREMENT Page 6 12 MONTHS ENDED 12/31/00 -------------------------------------------------------------------------------- Reference Amount -------------------------------------------------------------------------------- 1. Revenue Days (All Customers) (Note A) -------------------------------------------------------------------------------- 2. Weighted Days for payment for fuel (Note A) -------------------------------------------------------------------------------- 3. Weighted Days for payment of purchased power (Note A) -------------------------------------------------------------------------------- 4. Fuel Expense -------------------------------------------------------------------------------- 5. Steam FERC-1, P. 320, L.5 -------------------------------------------------------------------------------- 6. Nuclear FERC-1, P. 320, L.25 -------------------------------------------------------------------------------- 7. Other FERC-1, P. 321, L.63 -------------------------------------------------------------------------------- 8. Total L.5 + L.6 + L.7 -------------------------------------------------------------------------------- 9. Fuel Cash Requirements (L.1-L.2)/360 X L.8 -------------------------------------------------------------------------------- 10. Purchased Power FERC-1, P. 321, L.76 -------------------------------------------------------------------------------- 11. Purchased Power Cash Requirements (L.1-L.3)/360 X L.10 -------------------------------------------------------------------------------- 12. Other Operation & Maintenance Exp. -------------------------------------------------------------------------------- 13. Other Production FERC-1, P. 321, L.80 - (L.8 + L.10) -------------------------------------------------------------------------------- 14. Allocated A&G Expenses P. D-8, L.17, Col. (b) -------------------------------------------------------------------------------- 15. Total L.13 + L.14 -------------------------------------------------------------------------------- 16. Other O&M Cash Requirements 45/360 X L.15 -------------------------------------------------------------------------------- 17. Total Cash Requirements L.9 + L.11 + L.16 -------------------------------------------------------------------------------- Note A: Total company revenue and expense lag days to be determined by AEPSC. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 71 Rate Schedule FERC No. 340 D-7 Schedule D PRODUCTION-RELATED MATERIALS & SUPPLIES Page 7 12 MONTHS ENDED 12/31/00 -------------------------------------------------------------------------------- SYSTEM PRODUCTION -------------------------------------------------------------------------------- Reference Amount Reference Amount (1) (2) -------------------------------------------------------------------------------- 1. Materials & Supplies (Note A) -------------------------------------------------------------------------------- 2. Fuel (Note C) FERC-1, P.227 100% Col. (1) -------------------------------------------------------------------------------- 3. Non-Fuel FERC-1, P.227 -------------------------------------------------------------------------------- 4. Production Note D 100% Col. (1) -------------------------------------------------------------------------------- 5. Transmission Note D 090 -------------------------------------------------------------------------------- 6. Distribution Note D 090 -------------------------------------------------------------------------------- 7. General Note D Note B -------------------------------------------------------------------------------- 8. Total L.4+L.5+L.6+L.7 L.4+L.5+L.6+L.7 -------------------------------------------------------------------------------- Note A: Thirteen months average. Note B: Column (1) times % from P. D-5, Col. (3), L. 27. Note C: Booked amounts will be adjusted for inventory carried on behalf of others in respect to which the Company received carrying charge compensation from others. Note D: Functional breakdown furnished from SWEPCO's books by AEPSC. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 72 Rate Schedule FERC No. 340 D-8 Schedule D PRODUCTION-RELATED Page 8 ADMINISTRATIVE & GENERAL EXPENSE ALLOCATION 12 MONTHS ENDED 12/31/00
------------------------------------------------------------------------------------------------------------------------------ SYSTEM FUNCTION PRODUCTION ------------------------------------------------------------------------------------------------------------------------------ Reference Amount Amount ------------------------------------------------------------------------------------------------------------------------------ Account (1) (2) (3) ------------------------------------------------------------------------------------------------------------------------------ 1. ADMINISTRATIVE & GENERAL EXPENSE ------------------------------------------------------------------------------------------------------------------------------ 2. RELATED TO WAGES AND SALARIES ------------------------------------------------------------------------------------------------------------------------------ 3. A&G Salaries 920 FERC-1, P.322 ------------------------------------------------------------------------------------------------------------------------------ 4. Outside Services 923 FERC-1, P.323 ------------------------------------------------------------------------------------------------------------------------------ 5. Employee Pensions & Benefits 926 FERC-1, P.323 ------------------------------------------------------------------------------------------------------------------------------ 6. Office Supplies 921 FERC-1, P.322 ------------------------------------------------------------------------------------------------------------------------------ 7. Injuries & Damages 925 FERC-1, P.323 ------------------------------------------------------------------------------------------------------------------------------ 8. Franchise Requirements 927 FERC-1, P.323 ------------------------------------------------------------------------------------------------------------------------------ 9. Duplicate Charges - Cr. 929 FERC-1, P.323 ------------------------------------------------------------------------------------------------------------------------------ 10. Total Ls. 3 through 9 Note A ------------------------------------------------------------------------------------------------------------------------------ 11. MISCELLANEOUS GENERAL EXPENSES 930 FERC-1, P.323 Note A & D ------------------------------------------------------------------------------------------------------------------------------ 12. ADM. EXPENSE TRANSFER - CR. 922 FERC-1, P.322 Note B ------------------------------------------------------------------------------------------------------------------------------ 13. PROPERTY INSURANCE 924 FERC-1, P.323 Note E ------------------------------------------------------------------------------------------------------------------------------ 14. REGULATORY COMM. EXPENSES 928 FERC-1, P.323 Note D & E ------------------------------------------------------------------------------------------------------------------------------ 15. RENTS 931 FERC-1, P.323 Note B ------------------------------------------------------------------------------------------------------------------------------ 16. MAINTENANCE OF GENERAL PLANT 935 FERC-1, P.323 Note C ------------------------------------------------------------------------------------------------------------------------------ 17. TOTAL A & G EXPENSE Ls. 10 through 16 ------------------------------------------------------------------------------------------------------------------------------
Note A: % from Note B, P. D-5. Note B: % Plant from P. D-4, Col. (2), L.7. Note C: General Plant from P. D-5, Col. (3), L.27 Note D: Excluding all items not related to wholesale service. Note E: Analysis by company accounting department. Note F: To the extent separate functional accounting ledgers are developed in the future, the directly assigned production function Administrative and General amounts shall be utilized. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 73 Rate Schedule FERC No. 340 D-9 Schedule D COMPOSITE COST OF CAPITAL Page 9 12 MONTHS ENDED 12/31/00 -------------------------------------------------------------------------------- Total Company Cost of Composite Average Capitalization Capital Cost of Capital -------------------------------------------------------------------------------- Reference $ % % (2 x 3) (1) (2) (3) (4) -------------------------------------------------------------------------------- 1. Long Term Debt Note A -------------------------------------------------------------------------------- 2. Preferred Stock Note B -------------------------------------------------------------------------------- 3. Common Stock Note C 11.1% -------------------------------------------------------------------------------- 4. Total -------------------------------------------------------------------------------- Note A: Line 1, Columns (1) and (3) from P. D-10. Note B: Line 2, Columns (1) and (3) from P. D-11. Note C: Line 3, Column (1), FERC-1, P. 112, Line 14 less P. D-11, Line 1(d). Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 74 Rate Schedule FERC No. 340 D-10 Schedule D AVERAGE LONG TERM DEBT Page 10 12 MONTHS ENDED 12/31/00 -------------------------------------------------------------------------------- Average Debt Interest Balance Booked (1) (2) -------------------------------------------------------------------------------- 1. Total (Col. 1, FERC-1, P. 112, L.22, P. 111, Ls.54 & 65, P. 113, L.52) (Col. 2, FERC-1, P. 117, L.56) -------------------------------------------------------------------------------- 2. Amortization of Debt Discount, Debt Expense, and Gain/Loss on Reacquired Debt (Col. 2, FERC-1, P. 117, Ls. 56 through 58) -------------------------------------------------------------------------------- 3. Amortization of Premium on Debt (Col. 2, FERC-1, P. 117, L.59) -------------------------------------------------------------------------------- 4. Total (L.1 + L.2 + L.3) -------------------------------------------------------------------------------- 5. Embedded Costs (L.4, Col. 2/L.4, Col. 1) -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 75 Rate Schedule FERC No. 340 D-11 Schedule D AVERAGE PREFERRED STOCK Page 11 12 MONTHS ENDED 12/31/00 -------------------------------------------------------------------------------- Reference Amount -------------------------------------------------------------------------------- 1. (a) Preferred Stock Dividends FERC-1, P. 118, L.29 -------------------------------------------------------------------------------- (b) Preferred Stock Issued Note A FERC-1, P.1 12, L.3 -------------------------------------------------------------------------------- (c) Premium on Preferred Stock Note A FERC- 1, P. 112, L. 6 -------------------------------------------------------------------------------- (d) Total Preferred Stock L.1 (b) + L.1 (c) -------------------------------------------------------------------------------- 2. Average Cost Rate L.1 (a)/L.1 (d) -------------------------------------------------------------------------------- Note A: 13-Month Average. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 76 Rate Schedule FERC No. 340 D-12 Schedule D ANNUAL PRODUCTION O & M EXPENSE Page 12 EXCLUDING FUEL USED IN ELECTRIC GENERATION 12 MONTHS ENDED 12/31/00 -------------------------------------------------------------------------------- Account No. Production (1) -------------------------------------------------------------------------------- 1. Total Production O&M Expense FERC-1, P. 321, Col. (b), L.80 -------------------------------------------------------------------------------- 2. Fuel Used in Electric Generation FERC-1, P. 320-321, Col. (b) Ls. 5, 25 & 63 -------------------------------------------------------------------------------- 3. Coal Handling 501.xx, Note A -------------------------------------------------------------------------------- 4. Lignite Handling 501.xx, Note A -------------------------------------------------------------------------------- 5. Sale of Fly Ash (Revenue & Expense) 501.xx, Note A -------------------------------------------------------------------------------- 6. Purchased Power FERC-1, P. 321, Col. (b), L. 76, Note B -------------------------------------------------------------------------------- 7. Total Production O&M Expense L1-L2+L3+L4+L5 -L6 Excluding Fuel Used in Electric Generation Above -------------------------------------------------------------------------------- 8. A & G Expense P. D-8, L.17, Col.(3) -------------------------------------------------------------------------------- 9. Total O & M L7 + L8 -------------------------------------------------------------------------------- Note A: Fuel handling O&M expenses not recoverable under FERC fuel adjustment clause. See page D-17. Note B: Purchased power charges for contracts other than those shown on Schedule B. Note C: Unit start-up and minimum running costs as described in Sections 5.6 and 6.3 and billed under Schedule E shall be excluded from appropriate FERC production O&M accounts. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 77 Rate Schedule FERC No. 340 D-13 Schedule D PRODUCTION-RELATED DEPRECIATION EXPENSE Page 13 12 MONTHS ENDED 12/31/00 -------------------------------------------------------------------------------- Depreciation Expense (1) -------------------------------------------------------------------------------- PRODUCTION PLANT -------------------------------------------------------------------------------- 1. Steam -------------------------------------------------------------------------------- 2. Nuclear -------------------------------------------------------------------------------- 3. Hydraulic Conventional -------------------------------------------------------------------------------- 4. Hydraulic Pump Storage -------------------------------------------------------------------------------- 5. Other Production -------------------------------------------------------------------------------- 6. Production Related General Plant (Note B) -------------------------------------------------------------------------------- 7. Generator Step Up Related Depreciation (Note C) -------------------------------------------------------------------------------- 8. Total Production -------------------------------------------------------------------------------- Note A: Lines 1 through 5 will be Depreciation Expense reported on page 336 of the FERC Form No. 1 adjusted for amortization of acquisition adjustments. Note B: General Plant Depreciation Expense (from page 336 of the FERC Form No. 1, adjusted for amortization adjustments) times ratio of Production Related General Plant to total General Plant computed on page D-5, Line 21, Col. (3). To the extent separate functional accounting ledgers are developed in the future, the directly assigned production function General Plant Depreciation Expense shall be utilized. Note C: FERC-1, P.336, L. 7 times ratio of Generator Step Up Investment and Other Generation Related Investments (See Note D, P. D-4) to total Transmission Investment. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 78 Rate Schedule FERC No. 340 D-14 Schedule D PRODUCTION RELATED Page 14 TAXES OTHER THAN INCOME TAXES 12 MONTHS ENDED 12/31/00 -------------------------------------------------------------------------------- REFERENCE TOTAL COMPANY % PRODUCTION AMOUNT AMOUNT (1) (2) -------------------------------------------------------------------------------- TAXES RELATED TO PRODUCTION WAGES AND SALARIES -------------------------------------------------------------------------------- 1. State Unemployment Note A -------------------------------------------------------------------------------- 2. Federal Social Security & Note A Unemployment -------------------------------------------------------------------------------- 3. Total Note B -------------------------------------------------------------------------------- 4. PROPERTY & OTHER TAXES Note A & C RELATED TO PLANT INVESTMENT -------------------------------------------------------------------------------- 5. TOTAL TAXES OTHER L. 3 + L. 4 THAN INCOME TAXES -------------------------------------------------------------------------------- Note A: Taxes other than Income Taxes will be those reported in FERC-1, P. 262 & 263 as listed above. Note B: Total (Col. (1), L.4) allocated on the basis of wages & salaries in Electric O & M Expenses (excl. A & G), FERC-1, P. 354, Col. (b). Amount (1) Total W & S (excl. A & G) (2) Production W & S To the extent separate functional accounting ledgers are developed in the future, the directly assigned production function wages and salary taxes shall be utilized. Note C: Production plant related property taxes included in Property Taxes (FERC-1, P. 262 & 263) and in the Franchise Tax (FERC-1, P.262 & 263) and other production related taxes. To the extent separate functional accounting ledgers are developed in the future, the directly assigned production functional property taxes shall be utilized. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 79 Rate Schedule FERC No. 340 D-15 Schedule D PRODUCTION-RELATED INCOME TAX Page 15 12 MONTHS ENDED 12/31/00 Reference Amount (1) -------------------------------------------------------------------------------- 1. Return on Investment P. D-3, L.19 -------------------------------------------------------------------------------- 2. Interest P. D-3, L.17 x P. D-9, L.1, Col.(4) -------------------------------------------------------------------------------- 3. Balance for Equity Earnings L. 1 - L.2 -------------------------------------------------------------------------------- 4. Combined Income Tax Factor P. D-16, L. 11 -------------------------------------------------------------------------------- 5. Income Tax L. 4 x L.3 -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 80 Rate Schedule FERC No. 340 D-16 Schedule D COMPUTATION OF EFFECTIVE INCOME TAX RATE Page 16 12 MONTHS ENDED 12/31/00 -------------------------------------------------------------------------------- REFERENCE AMOUNT -------------------------------------------------------------------------------- 1. Net Income FERC-1, P. 117, L.72 LESS FERC-1, P. 117, L.36 Add: Income Taxes -------------------------------------------------------------------------------- 2. Federal FERC- 1, P. 114, L.14 -------------------------------------------------------------------------------- 3. Other FERC- 1, P. 114, L.15 -------------------------------------------------------------------------------- 4. Provision for Deferred Inc. Taxes FERC- 1, P. 114, L.16 -------------------------------------------------------------------------------- 5. Provision for Def Inc. Taxes-Cr. FERC- 1, P. 114, L.17 -------------------------------------------------------------------------------- 6. Investment Tax Cr. Adjustment Net FERC- 1, P. 114, L.18 -------------------------------------------------------------------------------- Taxes applicable to Other Income and Deductions: -------------------------------------------------------------------------------- 7. Income Taxes - Federal & Other FERC- 1, P. 117, Ls. 47 and 48 -------------------------------------------------------------------------------- 8. Total Income Taxes Ls. 2 through 7 -------------------------------------------------------------------------------- 9. Pretax Earnings Base L.1 + L.8 -------------------------------------------------------------------------------- 10. Effective Income Tax Rate L.8/L.9 -------------------------------------------------------------------------------- 11. Combined Tax Factor L10/(10-L.100) -------------------------------------------------------------------------------- Note A: To the extent separate functional accounting ledgers are developed in the future, the production function effective income tax information shall be utilized. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 81 Rate Schedule FERC No. 340 D-17 Schedule D MONTHLY FUEL COST Page 17 -------------------------------------------------------------------------------- MONTHLY FUEL EXPENSE Account Reference Amount -------------------------------------------------------------------------------- 1. Steam Power Generation 501 Note A -------------------------------------------------------------------------------- 2. Nuclear Power Generation 518 Note A -------------------------------------------------------------------------------- 3. Other Power Generation 547 Note A -------------------------------------------------------------------------------- 4. Coal Handling 501.xx Note B -------------------------------------------------------------------------------- 5. Lignite Handling 501.xx Note B -------------------------------------------------------------------------------- 6. Sale of Fly Ash (Revenue & 501.xx Note B Expense) -------------------------------------------------------------------------------- 7. Total Monthly Fuel Expense Ls. 1 through 3 less Ls. 4 through 6 -------------------------------------------------------------------------------- Note A: Monthly fuel costs associated with units listed in Schedule A except for those units for which PMA has exercised the option described in Section 6.4.1. Note B: Fuel handling O&M expenses not recoverable under FERC fuel adjustment clause. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 82 Rate Schedule FERC No. 340 D-18 Schedule D ESTIMATED BILLING AND TRUE-UP PROCEDURE Page 18 MONTHLY CAPACITY CHARGES ------------------------ Prior to November 1 of the year preceding each contract year, estimated Monthly Capacity Charges shall be determined by AEPSC on behalf of SWEPCO and made available to the PMA pursuant to the cost of service formulas set forth in this Schedule. The estimated Monthly Capacity Charges to be billed during each contract year shall be based on the most recent FERC Form No. 1 data available and shall be made effective January 1 and billed each successive Month of the contract year. No later than June 30 of the year following each contract year, actual Monthly Capacity Charges shall be determined by AEPSC on behalf of SWEPCO and made available to the PMA pursuant to the cost of service formulas set forth in this Schedule. The actual Monthly Capacity Charges for the contract year shall be based on the FERC Form No. 1 data for the contract year. Any difference between the sums due SWEPCO for the contract year and sums billed to the PMA during the contract year shall be billed to the PMA or refunded to the PMA, as appropriate. MONTHLY FUEL CHARGES -------------------- Actual Monthly Fuel Charges shall be determined by AEPSC on behalf of SWEPCO and billed each Month to the PMA pursuant to the formulas set forth in this Schedule. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 83 Rate Schedule FERC No. 340 SCHEDULE E FORMULAS, COMPONENTS, AND PROCEDURES FOR CALCULATING MONTHLY NON-FUEL VARIABLE OPERATING COSTS Actual start-up costs and applicable minimum running costs for each unit designated to be committed and brought on line for the benefit of only one Party subject to the terms of Section 5.6.2 shall be determined by AEPSC and directly billed each month to the appropriate Calling Party pursuant to the formulas set forth in this Schedule. All amounts directly billed under this Schedule shall be excluded from the Total Production O&M Expense calculated on page D-12 of Schedule D. Start-up Costs = (MWH * COST) + O&M Where: MWH = Energy in MWH required to run necessary equipment to start unit as determined by AEPSC COST = Cost per MWH including cost of power and transmission costs if applicable O&M = Approximate O&M costs associated with each unit start as determined by AEPSC And, Minimum Non-fuel Running Costs = VNFO&M * MWHP Where: VNFO&M = Variable Non-fuel O&M costs per MWH for each unit as determined by AEPSC MWHP = MWH produced as a result of calls on uncommitted capacity pursuant to Section 5.6.2 Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Southwestern Electric Power Company Original Sheet No. 84 Rate Schedule FERC No. 340 SCHEDULE F SWEPCO LONG-TERM FIRM FUEL SUPPLY CONTRACTS ------------------------------------------ SUPPLIER NAME TYPE OF CONTRACT -------------------------------------------------------------------------------- RAG American Coal Company Coal Supply Fka: Amax Coal West, Inc. Burlington Northern Santa Fe Railroad Company Rail Transportation Fka: Burlington Northern Railroad Company Kansas City Southern Railroad Burlington Northern Santa Fe Railroad Company Rail Transportation Fka: Burlington Northern Railroad Company Kansas City Southern Railroad Kansas City Southern Railroad Rail Transportation Union Pacific Railroad Company Rail Transportation Dolet Hills Lignite Company, LLC Lignite Mining Red River Mining Company Lignite Supply and Transportation The Sabine Mining Company Lignite Mining El Paso Field Services Gas Transportation Fka: Gulf States Pipeline Corporation Reliant Energy Gas Transmission Company Gas Transportation Fka: NorAm Gas Transmission Company Transok, LLC Gas Transportation Fka: Transok, Inc. Transok Gas Company Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 ATTACHMENT 5 SECOND UNIT POWER SALES AGREEMENT BETWEEN POWER MARKETING AFFILIATE AND SWEPCO Power Marketing Affiliate Original Sheet No. 1 Rate Schedule FERC No. 344 -------------------------------------------------------------------------------- SECOND UNIT POWER SALES AGREEMENT AMONG POWER MARKETING AFFILIATE, SOUTHWESTERN ELECTRIC POWER COMPANY, AND AMERICAN ELECTRIC POWER SERVICE CORPORATION -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Power Marketing Affiliate Original Sheet No. 1 Rate Schedule FERC No. 344 -------------------------------------------------------------------------------- TABLE OF CONTENTS SHEET ARTICLE I DEFINITIONS ...................................................7 ARTICLE II PURPOSE OF SECOND AGREEMENT; RELATION TO FIRST AGREEMENT ..............................................11 Section 2.1 Purpose of Second Agreement ..................................11 Section 2.2 SWEPCO Wholesale Percentage ..................................12 Section 2.3 SWEPCO Additional Percentage .................................12 Section 2.4 SWEPCO Retail Percentage .....................................13 Section 2.5 Relation of Second Agreement to First Agreement ..............13 2.5.1. Effect of Assignment on Operations Under First Agreement................................14 2.5.2 Incorporation of Certain Provisions By Reference ....14 ARTICLE III ASSIGNMENT OF CAPACITY RIGHTS ................................15 Section 3.1 Obligations of PMA and SWEPCO ................................15 Section 3.2 Delivery .....................................................15 Section 3.3 Obligations of AEPSC .........................................15 ARTICLE IV TERM OF SECOND AGREEMENT .....................................15 Section 4.1 Effective Date ...............................................15 Section 4.2 Termination Date .............................................16 ARTICLE V ALLOCATION OF CAPACITY .......................................17 Section 5.1 Purchased Capacity ...........................................17 Section 5.2 Effect of Termination or Expiration of Wholesale Contracts ...17 Section 5.3 Effect of Decrease in Obligations, Under Section 39.202(m) of PURA ......................................................18 -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Power Marketing Affiliate Original Sheet No. 3 Rate Schedule FERC No. 344 -------------------------------------------------------------------------------- Section 5.4 Effect of Decrease or Elimination of Obligation to Serve Retail Customers By Reason of PUCT Decision to Delay Retail Choice...18 ARTICLE VI SCHEDULING AND OPERATIONS ....................................19 Section 6.1 Dispatch .....................................................19 Section 6.2 Operating Committee ..........................................19 ARTICLE VII COST COMPONENTS AND PAYMENT TERMS ............................19 Section 7.1 Cost Components ..............................................19 Section 7.2 Capacity Charge ..............................................20 Section 7.3 Fuel Costs ...................................................20 7.3.1 Effect of PMA's Exercise of Fuel Supply Option ........21 7.3.2 Fuel Inventory ........................................22 Section 7.4 Emission Allowances ..........................................22 Section 7.5 Capital Repairs and Improvements .............................23 Section 7.6 Costs Upon Retirement or Decommissioning of Units ............23 ARTICLE VIII BILLING AND PAYMENT ..........................................23 Section 8.1 Billing, Payment, and Adjustment Procedures ..................23 ARTICLE IX TRANSMISSION SERVICES ........................................24 Section 9.1 Responsibilities .............................................24 ARTICLE X INTERRUPTION AND CURTAILMENTS ................................24 Section 10.1 Outages and Curtailment Procedures ...........................24 Section 10.2 Effect of Curtailment ........................................24 ARTICLE XI REGULATORY REQUIREMENTS ......................................25 Section 11.1 Required Regulatory Approvals and Actions ....................25 Section 11.2 Regulatory Review ............................................25 -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Power Marketing Affiliate Original Sheet No. 4 Rate Schedule FERC No. 344 -------------------------------------------------------------------------------- ARTICLE XII MISCELLANEOUS ................................................25 Section 12.1 Interpretation ...............................................25 Section 12.2 Partial Invalidity ...........................................26 Section 12.3 Assignment ...................................................26 Section 12.4 Successors Included ..........................................27 Section 12.5 Applicable Laws, Regulations, Orders, Approvals, and Permits ......................................................27 Section 12.6 Choice of Law and Jurisdiction ...............................27 Section 12.7 Entire Agreement .............................................27 Section 12.8 Counterparts to this Agreement ...............................28 Section 12.9 Amendments ...................................................28 Section 12.10 Notices ......................................................28 Section 12.11 Waivers ......................................................29 Section 12.12 Independent Contractors ......................................29 Section 12.13 No Third-Party Beneficiaries .................................29 Section 12.14 Further Assurances ...........................................30 Section 12.15 Confidentiality ..............................................30 Section 12.16 Joint Preparation ............................................31 -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Power Marketing Affiliate Original Sheet No. 5 Rate Schedule FERC No. 344 -------------------------------------------------------------------------------- SECOND UNIT POWER SALES AGREEMENT THIS SECOND UNIT POWER SALES AGREEMENT ("SECOND AGREEMENT") is made and entered into as of this _______________ day of ______________________, 2001, by and among Power Marketing Affiliate ("PMA"), Southwestern Electric Power Company ("SWEPCO"), and American Electric Power Service Corporation ("AEPSC"). PMA, SWEPCO, and AEPSC are wholly-owned subsidiaries of American Electric Power Company, Inc. ("AEP"). WITNESSETH WHEREAS, SWEPCO, PMA, and AEPSC have entered into a Unit Power Sales Agreement dated as of _______________, 2001 ("First Agreement"), by which SWEPCO will sell, and PMA will purchase, Available Capacity and Energy, and AEPSC will provide certain services with respect to SWEPCO's generating units, so as to maximize the availability of SWEPCO's generating units while minimizing the cost of operating, managing, maintaining, and providing fuel for those units; WHEREAS, SWEPCO has previously entered into the wholesale power supply contracts listed on Schedule A to this Second Agreement and desires to ensure the continued fulfillment of its obligations under the wholesale power supply contracts listed on Schedule A to this Second Agreement; -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Power Marketing Affiliate Original Sheet No. 6 Rate Schedule FERC No. 344 -------------------------------------------------------------------------------- WHEREAS, if the power region in which SWEPCO is located is not a "qualifying power region" pursuant to the terms of section 39.152(a) of the Texas Public Utilities Regulatory Act ("PURA"), after the introduction of customer choice under Texas law the SWEPCO-affiliated Retail Electric Provider ("SWEPCO REP") may have a continuing obligation under section 39.202(m) of PURA to serve certain retail 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; WHEREAS, section 39.103 of PURA provides that if the Public Utility Commission of Texas ("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; WHEREAS, PMA is willing to assign to SWEPCO, and SWEPCO is willing to accept assignment of PMA's rights and obligations under the First Agreement with respect to (1) a defined SWEPCO Wholesale Percentage of PMA's Assigned Capacity under that agreement in order to provide SWEPCO with part of the resources needed to continue to fulfill its obligations under the wholesale power supply contracts listed on Schedule A to this Second Agreement; (2) an Additional Percentage of PMA's Assigned Capacity under that agreement, if necessary, in order that SWEPCO may provide the SWEPCO REP with part of the resources needed for the SWEPCO REP to fulfill its continuing obligations, if any, to serve certain retail customers under section 39.202(m) of PURA; and (3) a SWEPCO Retail Percentage of PMA's Assigned Capacity under that -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Power Marketing Affiliate Original Sheet No. 7 Rate Schedule FERC No. 344 -------------------------------------------------------------------------------- agreement, if necessary, in order to provide SWEPCO with part of the resources needed to fulfill its continuing obligation, if any, to serve retail customers in the event that the PUCT decides to delay retail customer choice in SWEPCO's territory until after January 1, 2002; NOW, THEREFORE, in consideration of the premises and mutual covenants set forth herein, the Parties agree as follows: ARTICLE I DEFINITIONS For purposes of this Second Agreement, the following terms shall have the following meanings: 1.1. "APPLICABLE OATT" means the Open Access Transmission Tariff filed with FERC by AEPSC on behalf of SWEPCO and certain of its affiliates in accordance with FERC's Order No. 888 or the Open Access Transmission Tariff filed with FERC by the Southwest Power Pool, as either may be applicable to particular transmission service, or any successor transmission service tariff to either, including any such successor tariff of a Regional Transmission Organization to which SWEPCO transfers operating control or authority over its transmission facilities. 1.2. "ASSIGNED CAPACITY" means that part of the "SWEPCO Generating Capacity" as defined in Section 4.1 of the First Agreement that is allocated to PMA or to SWEPCO, respectively, under the First Agreement. 1.3. "AVAILABLE," when used to refer to capacity, means that such capacity is currently capable of being dispatched. -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Power Marketing Affiliate Original Sheet No. 8 Rate Schedule FERC No. 344 -------------------------------------------------------------------------------- 1.4. "AVAILABLE ASSIGNED CAPACITY" means that portion of a Party's Assigned Capacity or Purchased Capacity that is currently Available for dispatch. 1.5. "BUSINESS DAY" means any Day on which Federal Reserve member banks are open for business. A Business Day shall commence at 8:00 a.m. and close at 5:00 p.m., prevailing local time, at the location of the relevant Party's principal place of business, or at such other location as the context may require. In the event that the location cannot be determined from context, SWEPCO's principal place of business shall govern for purposes of application of the definition of "Business Day." 1.6. "DAY", means a period of twenty-four (24) consecutive hours, beginning at 12:01 a.m., local time, at the Delivery Point(s); provided, however, that on the Day on which Central Daylight Savings Time becomes effective, the period shall be twenty-three (23) consecutive hours, and on the Day on which Central Standard Time becomes effective, the period shall be twenty-five (25) consecutive hours. 1.7. "DELIVERY POINTS" means the points at which SWEPCO's generating units are connected to SWEPCO's transmission facilities. 1.8. "EFFECTIVE DATE" shall have the meaning set forth in Section 4.1 of this Second Agreement. 1.9. "EMERGENCY" means (i) any abnormal system condition that requires immediate manual or automatic action to prevent loss of firm load, equipment damage, or tripping of system elements that could adversely affect the reliability of SWEPCO's electric system, and (ii) any existing or potential system condition on SWEPCO's electric system that SWEPCO determines, -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Power Marketing Affiliate Original Sheet No. 9 Rate Schedule FERC No. 344 -------------------------------------------------------------------------------- in the exercise of reasonable discretion, is not or will not be in conformance with applicable criteria. 1.10. "EMISSION ALLOWANCE" means an emission allowance as defined by any state or federal statute for the control of air pollution, or any amendment thereto and any regulation promulgated thereunder. 1.11. "Energy", means the electric energy supplied under this Second Agreement, which shall be in the form of three-phase, alternating current at a frequency of 60 Hertz, with reasonable variations of frequency and voltage allowed consistent with Good Utility Practice. 1.12. "FERC" means the Federal Energy Regulatory Commission or any successor federal agency having regulatory jurisdiction over this Second Agreement. 1.13. "FIRST AGREEMENT" means that Unit Power Sales Agreement executed by SWEPCO, PMA, and AEPSC and dated as of ______________ 2001, including attachments, and any amendments thereto now or hereafter executed by the parties to that agreement._ 1.14. "GOOD UTILITY PRACTICE" means any of the practices, methods, and acts required, approved, or engaged in by a significant portion of the electric utility industry in the region where SWEPCO's generating units listed in Schedule A of the First Agreement operate during the relevant time period, or any of the practices, methods, and acts which, in the exercise of reasonable judgment in light of the facts known at the time the decision was made, could have been expected to accomplish the desired result at the lowest reasonable cost consistent with good business practices, reliability, safety, and expedition. Good Utility Practice is not intended to be -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Power Marketing Affiliate Original Sheet No. 10 Rate Schedule FERC No. 344 -------------------------------------------------------------------------------- limited to the optimum practice, method, or act; rather, it is intended to be a spectrum of acceptable practices, methods, and acts. 1.15. "GOVERNMENTAL REQUIREMENT" means any statute, law, regulation, ordinance, rule, exemption, or order of any federal, state, county, municipal or other governmental authority, any political subdivision of any of the foregoing, or any governmental, quasi-govemmental, judicial, public or statutory instrumentality, authority, body or entity, including, without limitation, the final, non-appealable judicial or administrative interpretation of any such statute, law, regulation, ordinance, rule, exemption, or order by any such authority, instrumentality, body, or entity. 1.16. "MONTH" means the period beginning at 12:01 a.m., local time, on the first Day of each calendar month and ending at midnight of the last Day of such calendar month. 1.17. "PARTIES" means SWEPCO, PMA, AEPSC, or the assignee or successor of any of their rights and obligations under this Second Agreement. "PARTY", means one of the Parties. 1.18. "PURCHASED CAPACITY" AND "SWEPCO PURCHASED CAPACITY" mean that portion of PMA's Assigned Capacity that PMA assigns to SWEPCO under the terms of this Second Agreement. 1.19. "PUCT" means the Public Utility Commission of Texas, or any successor organization thereto. 1.20. "PURA" means the Texas Public Utility Regulatory Act, Chapter 39 of Title 2 of the Texas Utilities Code. -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Power Marketing Affiliate Original Sheet No. 11 Rate Schedule FERC No. 344 -------------------------------------------------------------------------------- 1.21. "SECOND AGREEMENT" means this Second Unit Power Sales Agreement, including attachments, and any amendments thereto now or hereafter executed by the Parties. 1.22. "SWEPCO ADDITIONAL PERCENTAGE" shall have the meaning set forth in Section 2.3 of this Second Agreement. 1.23. "SWEPCO REP" shall refer to the SWEPCO-affiliated Retail Electric Provider. 1.24. "SWEPCO RETAIL PERCENTAGE" shall have the meaning set forth in Section 2.4 of this Second Agreement. 1.25. "SWEPCO WHOLESALE PERCENTAGE" shall have the meaning set forth in Section 2.2 of this Second Agreement. ARTICLE II PURPOSE OF SECOND AGREEMENT; RELATION TO FIRST AGREEMENT 2.1. PURPOSE OF SECOND AGREEMENT. THE purpose of this Second Agreement is to provide SWEPCO with access to the SWEPCO Wholesale Percentage of PMA's Assigned Capacity under the First Agreement for such time as SWEPCO has an obligation to supply power under the power supply contracts listed in Schedule A to this Second Agreement; with access to the SWEPCO Additional Percentage for such time, if any, as SWEPCO may provide the SWEPCO REP with part of the resources needed to continue to serve certain customers under section 39.202(m) of PURA; and with access to the SWEPCO Retail Percentage for such time, if any, as the PUCT may delay retail customer choice in SWEPCO's territory after January 1, 2002. -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Power Marketing Affiliate Original Sheet No. 12 Rate Schedule FERC No. 344 -------------------------------------------------------------------------------- 2.2. SWEPCO WHOLESALE PERCENTAGE. Schedule A sets forth the SWEPCO wholesale supply contracts that are the subject of this Second Agreement, together with the termination or expiration date of each. For each such contract, the Parties have calculated a percentage determined using a ratio of the sum of the demands of the native load for that contract at the time of the four Year 2000 coincident Monthly summer (June, July, August, and September) SWEPCO peak demands to the sum of the same four coincident peak demands of the total SWEPCO native load. The sum of the percentages calculated for all the agreements listed in Schedule A as to which SWEPCO has a supply obligation at a given time constitutes the SWEPCO Wholesale Percentage as of that time. Because the contracts listed in Schedule A have a variety of termination or expiration dates, the SWEPCO Wholesale Percentage will diminish over time as provided in Section 5.2. The Parties agree that the SWEPCO Wholesale Percentage as of the Effective Date of this Second Agreement is 17.78 percent. 2.3. SWEPCO ADDITIONAL PERCENTAGE. In the event that the power region in which SWEPCO is located is not a "qualifying power region" pursuant to the terms of section 39.152(a) of PURA by January 1, 2002, or such later date as SWEPCO shall begin to purchase Available Capacity and Energy under this Second Agreement, and by reason of that fact (1) the SWEPCO REP has a continuing obligation to serve certain customers under section 39.202(m) of PURA 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, and (2) SWEPCO provides the SWEPCO REP with part of the resources necessary to continue to serve such customers, the Parties shall determine the SWEPCO Additional Percentage by using a ratio of: (a) the sum of the demands of the native loads for all those customers as to whom the SWEPCO REP shall have a continuing obligation -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Power Marketing Affiliate Original Sheet No. 13 Rate Schedule FERC No. 344 -------------------------------------------------------------------------------- to serve under section 39.202(m) of PURA, such demands to be measured at the time of the four Year 2000 coincident Monthly summer (June, July, August, and September) SWEPCO peak demands, to: (b) the sum of the same four coincident peak demands of the total SWEPCO native load. The SWEPCO Additional Percentage shall diminish from time to time to reflect the removal of any customer from the group as to which the SWEPCO REP has a continuing obligation to serve under section 39.202(m) of PURA. 2.4. SWEPCO RETAIL PERCENTAGE. In the event that the PUCT determines, pursuant to section 39.103 of PURA, to delay retail customer choice in SWEPCO's territory after January 1, 2002, the Parties shall determine the SWEPCO Retail Percentage by using a ratio of: (a) the sum of the demands of the native loads for all those customers as to whom SWEPCO shall have a continuing obligation to serve under section pursuant to the PUCT's delay of retail customer choice in SWEPCO's territory (excluding native loads included in the determination of the SWEPCO Additional Percentage), such demands to be measured at the time of the four Year 2000 coincident Monthly summer (June, July, August, and September) SWEPCO peak demands, to: (b) the sum of the same four coincident peak demands of the total SWEPCO native load. The SWEPCO Retail Percentage shall be reduced or eliminated on the date(s) that retail customer choice is permitted to proceed in SWEPCO's territory with respect to all retail customers, or with respect to particular customers or classes of retail customers. 2.5. RELATION OF SECOND AGREEMENT TO FIRST AGREEMENT. This Second Agreement supplements and modifies the First Agreement. The Parties intend that the First Agreement and -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Power Marketing Affiliate Original Sheet No. 14 Rate Schedule FERC No. 344 -------------------------------------------------------------------------------- the Second Agreement be interpreted consistently and in harmony with each other; however, where there is an actual or perceived conflict between the provisions of the two agreements, the provisions of the Second Agreement shall control. 2.5.1. EFFECT OF ASSIGNMENT ON OPERATIONS UNDER FIRST AGREEMENT. In carrying out its duties under the First Agreement, the Operating Committee shall take account of the assignment by PMA of its rights and obligations with respect to that portion of PMA's Assigned Capacity percentage equal to the sum of the SWEPCO Wholesale Percentage, the SWEPCO Additional Percentage, and the SWEPCO Retail Percentage and shall adjust the respective rights, duties, and obligations of PMA and SWEPCO accordingly. When complying with any Governmental Requirement or other obligation imposed by a third party, the respective rights, duties, and obligations of PMA and SWEPCO shall be allocated so as to take account of the assignment by PMA of its rights and obligations with respect to that portion of PMA's Assigned Capacity percentage equal to the sum of the SWEPCO Wholesale Percentage, the SWEPCO Additional Percentage, and the SWEPCO Retail Percentage. 2.5.2. INCORPORATION OF CERTAIN PROVISIONS BY REFERENCE. The provisions of Articles X (Force Majeure), XI (Defaults), XII (Dispute Resolution), XIII (Indemnification; Limitation of Liability), and XV (Books and Records) of the First Agreement, as they may be amended from time to time, apply to this Second Agreement and are hereby incorporated by reference as if set forth herein. -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Power Marketing Affiliate Original Sheet No. 15 Rate Schedule FERC No. 344 -------------------------------------------------------------------------------- ARTICLE III ASSIGNMENT OF CAPACITY RIGHTS 3.1. OBLIGATIONS OF PMA AND SWEPCO. PMA shall assign to SWEPCO all rights and obligations of PMA under the First Agreement with respect to that part of PMA's Assigned Capacity percentage equal to the sum of the SWEPCO Wholesale Percentage, the SWEPCO Additional Percentage, and the SWEPCO Retail Percentage as the SWEPCO Wholesale Percentage, the SWEPCO Additional Percentage, and the SWEPCO Retail Percentage change from time to time. 3.2. DELIVERY. PMA, shall deliver Energy purchased by SWEPCO at the Delivery Point associated with the generating unit from which the Energy is produced, or in the case of Energy delivered under a third-party agreement listed in Schedule B of the First Agreement, at the delivery point specified in the third-party agreement. 3.3. OBLIGATIONS OF AEPSC. Except as expressly provided herein, AEPSC's obligations under the First Agreement shall not be affected by this Second Agreement. ARTICLE IV TERM OF SECOND AGREEMENT 4.1. EFFECTIVE DATE. This Second Agreement shall be effective upon execution by SWEPCO, PMA, and AEPSC. SWEPCO shall begin to purchase Available Capacity and Energy under this Second Agreement, and shall begin to dispatch its Purchased Capacity, on the same day that PMA begins to purchase Available Capacity and Energy under the First Agreement, or on such later date as all required regulatory authorizations have been received. -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Power Marketing Affiliate Original Sheet No. 16 Rate Schedule FERC No. 344 -------------------------------------------------------------------------------- 4.2. TERMINATION DATE. Except for (a) termination following an Event of Default as provided in Section 11.2 of the First Agreement; (b) termination because of regulatory disapproval or regulatory changes as provided in Article XV; or (c) termination pursuant to mutual agreement of PMA and SWEPCO, this Second Agreement shall continue in effect so long as (1) SWEPCO has a supply obligation under any of the wholesale power supply contracts listed in Schedule A under the terms of each such contract as currently in effect; or (2) SWEPCO provides part of the resources needed for the SWEPCO REP to fulfill its obligation to continue to serve certain customers under section 39.202(m) of PURA; or (3) SWEPCO has an obligation to serve certain retail classes of customers by reason of a decision by the PUCT to delay retail customer choice in SWEPCO's territory; PROVIDED, HOWEVER, that in no event shall the term of this Second Agreement exceed the Initial Term of the First Agreement; AND PROVIDED FURTHER, that in the event that PMA elects, with respect to any units listed in Schedule A of the First Agreement and/or any contract listed in Schedule B of the First Agreement, to renew the First Agreement pursuant to the terms of Sections 3.2.1 and/or 3.2.2 of that First Agreement, this Second Agreement shall be renewed for that unit or agreement for a term equal to the corresponding renewal term of the First Agreement for that unit or agreement. However, no extension, renewal, or amendment of any contract listed in Schedule A shall have the effect of extending this Second Agreement. -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Power Marketing Affiliate Original Sheet No. 17 Rate Schedule FERC No. 344 -------------------------------------------------------------------------------- ARTICLE V ALLOCATION OF CAPACITY 5.1. PURCHASED CAPACITY. PMA's assignment of its rights and obligations with respect to a portion of its Assigned Capacity percentage under the First Agreement is on a unit-by-unit basis (a) from each of the generating units listed in Schedule A to the First Agreement (or, in the case of jointly-owned units, SWEPCO's share of such units) with respect to the capability of each such unit as that capability may change over time and (b) from certain capacity purchase agreements, listed in Schedule B to the First Agreement. To the extent that any of the generation and supply resources listed in Schedules A and B of the First Agreement is unavailable in whole or in part, whether by reason of unit outages, curtailments, or otherwise, PMA shall have no obligation to adjust its assignment of rights and obligations to SWEPCO from any other resource. 5.2. EFFECT OF TERMINATION OR EXPIRATION OF WHOLESALE CONTRACTS. As each wholesale power supply contract listed in Schedule A to this Second Agreement is terminated or expires, the SWEPCO Wholesale Percentage will be reduced by the percentage listed for that contract in Schedule A, and PMA's obligation to make Purchased Capacity and Energy Available to SWEPCO will be reduced by the same amount. The amendment or extension of any contract listed in Schedule A shall not have the effect of changing the termination or expiration date listed for that contract in Schedule A. The SWEPCO Wholesale Percentage will be reduced by the amount listed for each contract on the termination or expiration date listed for that contract in Schedule A, notwithstanding any extension of such contract, unless the termination or expiration -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Power Marketing Affiliate Original Sheet No. 18 Rate Schedule FERC No. 344 -------------------------------------------------------------------------------- of the contract shall occur before the date listed for that contract in Schedule A, in which case the SWEPCO Wholesale Percentage shall be reduced by the amount listed for that contract on such earlier termination or expiration date. Notwithstanding any other provision of this Second Agreement, if a Governmental Requirement extends all or part of SWEPCO's supply obligations under any of the contracts listed on Schedule A of this Second Agreement beyond the termination or expiration date listed on Schedule A, or beyond a termination or expiration date earlier than that listed on Schedule A that would otherwise be applicable, then the termination or expiration date listed on Schedule A, or such earlier termination or expiration date, shall be treated as extended, but only to the extent necessary to comply with the Governmental Requirement. 5.3. EFFECT OF DECREASE IN OBLIGATIONS UNDER SECTION 39.202(m) OF PURA. To the extent that the SWEPCO REP's obligation to serve any or all customers that it may be required to continue to serve under the terms of section 39.202(m) of PURA decreases, whether by reason of the power region in which SWEPCO is located becoming a "qualifying power region" pursuant to the terms of section 39.152(a) of the PURA or for any other reason, the SWEPCO Additional Percentage will be reduced so that it reflects only the SWEPCO REP's remaining obligation, if any, under section 39.202(m) of PURA. 5.4. EFFECT OF DECREASE OR ELIMINATION OF OBLIGATION TO SERVE RETAIL CUSTOMERS BY REASON OF PUCT DECISION TO DELAY RETAIL CHOICE. To the extent that SWEPCO's obligations to serve any or all retail customers or classes of such customers by reason of a determination of the PUCT under section 39.103 of PURA to delay retail customer choice in SWEPCO's territory are decreased or eliminated because customer choice is permitted to proceed in SWEPCO's -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Power Marketing Affiliate Original Sheet No. 19 Rate Schedule FERC No. 344 -------------------------------------------------------------------------------- territory with respect to all retail customers, or particular customers or classes of retail customers, or for any other reason, the SWEPCO Retail Percentage will be reduced so that it reflects only SWEPCO's remaining obligation, if any, to serve such retail customers. ARTICLE VI SCHEDULING AND OPERATIONS 6.1. DISPATCH. Notwithstanding any provision in the First Agreement, SWEPCO shall have the exclusive right to dispatch Energy and ancillary services from its Available Purchased Capacity. Unit commitment and dispatch procedures shall be conducted as provided in the First Agreement. 6.2. OPERATING COMMITTEE. Except as expressly provided in this Second Agreement, the duties and obligations of the Operating Committee established in Section 5.4 of the First Agreement shall not be altered or diminished by reason of this Second Agreement. ARTICLE VII COST COMPONENTS AND PAYMENT TERMS 7.1. COST COMPONENTS. In return for PMA's sale to SWEPCO of Purchased Capacity and associated Energy under this Second Agreement, SWEPCO will pay PMA a share of the Capacity Charge paid by PMA to SWEPCO pursuant to Section 6.2 of the First Agreement and a share of the Fuel Costs paid by PMA to SWEPCO under Section 6.4 of the First Agreement. In addition, to the extent that amounts paid by PMA to SWEPCO for PMA's share of any other costs approved by the Operating Committee and initially incurred by SWEPCO do not reflect the -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Power Marketing Affiliate Original Sheet No. 20 Rate Schedule FERC No. 344 -------------------------------------------------------------------------------- effects of the SWEPCO Additional Percentage or the SWEPCO Retail Percentage, SWEPCO shall pay PMA the share of such costs attributable to the SWEPCO Additional Percentage or the SWEPCO Retail Percentage as the case may be. Pursuant to Article VIII, AEPSC will provide SWEPCO with a statement of the amounts due to PMA from SWEPCO under this Second Agreement, and the statement will show the effect of netting those amounts against the amounts due from PMA to SWEPCO for the corresponding Month. 7.2. CAPACITY CHARGE. SWEPCO will pay a capacity charge to PMA under this Second Agreement each Month calculated by multiplying the Capacity Charge due from PMA to SWEPCO for that Month under Section 7.2 of the First Agreement by a fraction, the numerator of which is the sum of the SWEPCO Wholesale Percentage, the SWEPCO Additional Percentage, and the SWEPCO Retail Percentage, as each may be in effect on the 15th Day of that Month, and the denominator of which is PMA's Assigned Capacity Percentage in effect on the 15th Day of that Month. 7.3. FUEL COSTS. SWEPCO will pay fuel costs to PMA under this Second Agreement each Month calculated by multiplying the Fuel Costs due from PMA to SWEPCO for that Month under Section 7.2 of the First Agreement by a fraction, the numerator of which is the sum of the energy SWEPCO schedules from the SWEPCO Wholesale Percentage, the SWEPCO Additional Percentage, and the SWEPCO Retail Percentage, as each may be in effect on the 15th Day of that Month, and the denominator of which is the total energy scheduled from PMA's Assigned Capacity Percentage in effect on the 15th Day of that Month. -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Power Marketing Affiliate Original Sheet No. 21 Rate Schedule FERC No. 344 -------------------------------------------------------------------------------- 7.3.1. EFFECT OF PMA'S EXERCISE OF FUEL SUPPLY OPTION. If PMA exercises the fuel supply option described in Section 6.4.1 of the First Agreement, PMA shall not supply fuel necessary to operate SWEPCO's Purchased Capacity. Further, PMA's proportionate right to use delivery and storage facilities, including rights of access, owned or controlled by SWEPCO for the delivery to or storage of such fuel to each station with respect to which PMA exercises the option, shall not include any proportion attributable to the SWEPCO Wholesale Percentage, the SWEPCO Additional Percentage, or the SWEPCO Retail Percentage, as each may be in effect as of the date of use; nor shall the charge by SWEPCO for such use reflect any proportion attributable to the SWEPCO Wholesale Percentage, the SWEPCO Additional Percentage, or the SWEPCO Retail Percentage, as each may be in effect during the period for which the charge is assessed. In the event that PMA exercises the option described in this paragraph with respect to a unit as to which fuel is supplied under one or more of the long-term fuel supply contracts listed in Schedule F of the First Agreement, for purposes of determining the percentage interest of SWEPCO's rights and obligations under the applicable contract(s), and any associated transportation contract(s) that may be assigned to PMA pursuant to the terms of Section 6.3.1 of the First Agreement, PMA's Assigned Capacity percentage shall not include the SWEPCO Wholesale Percentage, the SWEPCO Additional Percentage, or the SWEPCO Retail Percentage, as each may be in effect on the date with respect to which the calculation is performed. -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Power Marketing Affiliate Original Sheet No. 22 Rate Schedule FERC No. 344 -------------------------------------------------------------------------------- 7.3.2. FUEL INVENTORY. In the event that PMA exercises the option to supply fuel described in Section 6.4.1 of the First Agreement with respect to any unit, the fraction of the fuel inventory to be assigned by SWEPCO to PMA pursuant to Section 6.4.2 of the First Agreement shall be determined with SWEPCO's Wholesale Percentage, the SWEPCO Additional Percentage, and the SWEPCO Retail Percentage, as each may be in effect on the date of assignment, excluded from PMA's Assigned Capacity percentage. 7.4. EMISSION ALLOWANCES. For the purpose of determining the fraction of the Emission Allowances issued by the U.S. Environmental Protection Agency ("USEPA") pursuant to Title IV of the Clean Air Act Amendments of 1990 and any regulations thereunder ("Title IV Emission Allowances") to be assigned by SWEPCO to PMA on or before the Effective Date of the First Agreement pursuant to Section 6.6 of the First Agreement, the SWEPCO Wholesale Percentage, the SWEPCO Additional Percentage, and the SWEPCO Retail Percentage, as each may be in effect as of the Effective Date of this Second Agreement, shall be treated as excluded from PMA's Assigned Capacity Percentage. Thereafter, for purposes of allocating Title IV Emission Allowances received by SWEPCO in accordance with Section 6.6 of the First Agreement, PMA's Assigned Capacity percentage for the period as to which allocation is made will be treated as excluding the SWEPCO Wholesale Percentage, the SWEPCO Additional Percentage, and the SWEPCO Retail Percentage, and SWEPCO's Assigned Capacity percentage for the same period will be treated as including the SWEPCO Wholesale Percentage, the SWEPCO Additional Percentage, and the SWEPCO Retail Percentage. In determining procedures for allocating and using Emission Allowances or for any programs that permit -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Power Marketing Affiliate Original Sheet No. 23 Rate Schedule FERC No. 344 -------------------------------------------------------------------------------- averaging at more than one unit for compliance, the Operating Committee shall adjust PMA's and SWEPCO's respective rights and obligations to take account of the SWEPCO Wholesale Percentage, the SWEPCO Additional Percentage, and the SWEPCO Retail Percentage. 7.5. CAPITAL REPAIRS AND IMPROVEMENTS. For purposes of determining responsibility for paying the costs of such capital repairs and improvements, PMA's Assigned Capacity Percentage will be decreased by the sum of the SWEPCO Wholesale Percentage, the SWEPCO Additional Percentage, and the SWEPCO Retail Percentage, as each may be in effect as of the date of measurement, and SWEPCO's Assigned Capacity percentage will be increased by the same sum. 7.6. COSTS UPON RETIREMENT OR DECOMMISSIONING OF UNITS. Upon the retirement or decommissioning of any SWEPCO generating unit listed in Schedule A of the First Agreement, PMA's responsibility to pay or receive a percentage of the net amount by which the costs of all decommissioning, closure, restoration, and environmental protection measures taken by SWEPCO with respect to the retirement or decommissioning of the unit exceed or fall short of the proceeds of sale or salvage of the unit, including all facilities and equipment, will be determined by subtracting the sum of the SWEPCO Wholesale Percentage, the SWEPCO Additional Percentage, and the SWEPCO Retail Percentage, as each may be in effect on the date of retirement from PMA's Assigned Capacity Percentage as of that date. ARTICLE VIII BILLING AND PAYMENT 8.1. BILLING, PAYMENT, AND ADJUSTMENT PROCEDURES. AEPSC will act as Agent for PMA and SWEPCO for the purpose of preparing and tendering statements under this Second Agreement and will notify both Parties of the amount, if any, to be netted against amounts due from PMA to -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Power Marketing Affiliate Original Sheet No. 24 Rate Schedule FERC No. 344 -------------------------------------------------------------------------------- SWEPCO under the terms of the First Agreement for SWEPCO's purchases from PMA in the same billing period. Subject to the netting procedures described in this Article and in Article VII of this Second Agreement, the provisions of Article VII of the First Agreement shall apply with respect to all billing, payment, adjustment procedures, and billing dispute resolution under this Second Agreement. ARTICLE IX TRANSMISSION SERVICES 9.1. RESPONSIBILITIES. SWEPCO shall be responsible for arranging for transmission service and ancillary services for energy dispatched from its Purchased Capacity, as provided in the Applicable OATT or other applicable tariffs. ARTICLE X INTERRUPTION AND CURTAILMENTS 10.1. OUTAGES AND CURTAILMENT PROCEDURES. The outage and curtailment procedures set forth in Article IX of the First Agreement shall apply to this Second Agreement, as modified herein. 10.2. EFFECT OF CURTAILMENT. When a curtailment of capacity gives rise to the need to decrease PMA's Assigned Capacity and SWEPCO's Assigned Capacity as provided in Section 9.3 of the First Agreement, the decrease in PMA's Assigned Capacity shall be shared between PMA and SWEPCO so that the percentage reduction in SWEPCO's Purchased Capacity by reason of the curtailment shall be equal to the percentage reduction in PMA's Assigned Capacity by reason of the curtailment as provided in Section 9.3 of the First Agreement. -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Power Marketing Affiliate Original Sheet No. 25 Rate Schedule FERC No. 344 -------------------------------------------------------------------------------- ARTICLE XI REGULATORY REQUIREMENTS 11.1. REQUIRED REGULATORY APPROVALS AND ACTIONS. In the event that any regulatory agency with jurisdiction to approve or disapprove this Second Agreement finally disapproves this Second Agreement, then the Second Agreement shall terminate on December 31, 2001 or the date of disapproval, whichever is later. No regulatory disapproval shall be final for purposes of this terminating this Second Agreement until all motions for reconsideration or appeals of the disapproval letter have been decided and the time for any further appeal shall have elapsed without such further appeal having been noticed. 11.2. REGULATORY REVIEW. If, during review of this Second Agreement, any regulatory agency with jurisdiction and authority to do so orders the modification of any term or condition, or orders the alteration of any charge(s), or in any way conditions its approval of this Second Agreement, and either SWEPCO or PMA determines that such order, action, or decision has or will have a Material Adverse Effect on it (as that term is defined in Section 11.1.2 of the First Agreement), SWEPCO and PMA shall negotiate in good faith to agree on modified terms and conditions mutually agreeable to them that are consistent with such regulatory order, action, or decision and that preserve, to the maximum extent possible, the balance of economic benefits and burdens previously created by this Second Agreement before the issuance of such regulatory order, action, or decision. ARTICLE XII MISCELLANEOUS 12.1. INTERPRETATION. In this Second Agreement: (i) unless otherwise specified, references to any Article, Section, Schedule or Exhibit are references to such Article, Section, Schedule or -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Power Marketing Affiliate Original Sheet No. 26 Rate Schedule FERC No. 344 -------------------------------------------------------------------------------- Exhibit of this Second Agreement; (ii) the singular includes the plural and the plural includes the singular; (iii) unless otherwise specified, each reference to a Governmental Requirement includes all provisions amending, modifying, supplementing or replacing such Governmental Requirement from time to time; (iv) the words "including," "includes" and "include" shall be deemed to be followed by the words "without limitation"; (v) unless otherwise specified, each reference to any agreement includes all amendments, modifications, supplements, and restatements made to such agreement from time to time which are not prohibited by this Second Agreement; (vi) the descriptive headings of the various Articles and Sections of this Second Agreement have been inserted for convenience of reference only and shall in no way modify or restrict the terms and provisions thereof; and (vii) "herein," "hereof," "hereto" and "hereunder" and similar terms refer to this Second Agreement as a whole. 12.2. PARTIAL INVALIDITY. Wherever possible, each provision of this Second Agreement shall be interpreted in a manner as to be effective and valid under applicable law, but if any provision contained herein shall be found to be invalid, illegal, or unenforceable in any respect and for any reason, such provision shall be ineffective to the extent, but only to the extent, of such invalidity, illegality, or unenforceability without invalidating the remainder of the provision or any provision of this Second Agreement, unless such a construction would be unreasonable. If such a construction would be unreasonable or would deprive a Party of a material benefit under this Second Agreement, the Parties shall seek to amend this Second Agreement to remove the invalid portion and otherwise provide the benefit, unless prohibited by law. 12.3. ASSIGNMENT. Any transfer or assignment by any Party of any or all rights, benefits or responsibilities under this Second Agreement shall not relieve the transferring Party of any -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Power Marketing Affiliate Original Sheet No. 27 Rate Schedule FERC No. 344 -------------------------------------------------------------------------------- responsibility under this Second Agreement unless the other Parties so consent; provided, however, that consent to a release of an assigning Party's responsibilities shall not be unreasonably withheld. 12.4. SUCCESSORS INCLUDED. Reference to any individual, corporation, or other entity shall be deemed a reference to such individual, corporation, or other entity together with its successors and permitted assigns from time to time. 12.5. APPLICABLE LAWS, REGULATIONS, ORDERS, APPROVALS, AND PERMITS. This Second Agreement is made subject to all existing and future applicable Governmental Requirements, including federal, state, and local laws and to all existing and future duly promulgated orders or other duly authorized actions of governmental authorities having jurisdiction over the matters set forth in this Second Agreement. 12.6. CHOICE OF LAW AND JURISDICTION. The interpretation and performance of this Second Agreement shall be in accordance with the laws of the State of Texas, excluding conflicts of law principles that would require the application of the laws of a different jurisdiction. 12.7. ENTIRE AGREEMENT. Subject to the incorporation by reference of portions of the First Agreement pursuant to Section 2.5.2 of this Second Agreement, this Second Agreement supersedes all previous representations, understandings, negotiations, and agreements either written or I oral between the Parties or their representatives with respect to the subject matter hereof, and constitutes the entire agreement of the Parties with respect to the subject matter hereof. -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Power Marketing Affiliate Original Sheet No. 28 Rate Schedule FERC No. 344 -------------------------------------------------------------------------------- 12.8. COUNTERPARTS TO THIS AGREEMENT. This Second Agreement may be executed in any number of counterparts, each of which shall be an original, but all of which together shall constitute one and the same instrument. 12.9. AMENDMENTS. It is contemplated by the Parties that it may be appropriate from time to time to change, amend, modify, or supplement this Agreement, including the Service Schedules and any other attachments that may be made a part of this Agreement, to reflect changes in operating practices or costs of operations or for other reasons. Any such changes to this Agreement shall be in writing executed by the Parties and, if appropriate, subject to approval or acceptance for filing by the FERC. 12.10. NOTICES. Unless otherwise provided in this Second Agreement, any notice, consent, or other communication required to be made under this Second Agreement shall be in writing and shall be delivered in person, by certified mail (postage prepaid, return receipt requested), or by nationally recognized overnight courier (charges prepaid), in each case properly addressed to such Party as shown below, or sent by facsimile transmission to the facsimile number indicated below. Any Party may from time to time change its address for the purposes of notices, consents, or other communications to that Party by a similar notice specifying a new address, but no such change shall become effective until it is actually received by the Parties sought to be charged with its contents. All notices, consents, or other communications required or permitted under this Second Agreement that are addressed as provided in this Section 16.10 shall be deemed to have been given (a) upon delivery, if delivered in person, by overnight courier, or by certified mail; or (b) upon automatically generated confirmation, if given by facsimile. -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Power Marketing Affiliate Original Sheet No. 29 Rate Schedule FERC No. 344 -------------------------------------------------------------------------------- SWEPCO: 1 Riverside Plaza Columbus, OH 43215 614-223-2352 PMA: 1 Riverside Plaza Columbus, OH 43215 614-324-5096 AEPSC: 1 Riverside Plaza Columbus, OH 43215 614-223-2352 12.11. WAIVERS. The failure of any Party to enforce at any time any provision of this Second Agreement shall not be construed as a waiver of such provision. No such failure to enforce a provision shall affect in any way the validity of this Second Agreement or any portion thereof or the right of that Party thereafter to enforce each and every provision of this Second Agreement. To be effective, a waiver under this Second Agreement must be in writing and specifically state that it is a waiver. No waiver of any breach of this Second Agreement shall be held to constitute a waiver of any other or subsequent breach. 12.12. INDEPENDENT CONTRACTORS. PMA and SWEPCO are independent contractors. Nothing contained herein shall be deemed to create an association, joint venture, partnership or principal/agent relationship between PMA and SWEPCO or impose any partnership obligation or liability on either of them. Neither PMA nor SWEPCO shall have any right, power or authority to enter into any agreement or commitment, act on behalf of or otherwise bind the other Party in any way. 12.13. NO THIRD-PARTY BENEFICIARIES. Nothing in this Second Agreement, whether express or implied, is intended to confer any rights or remedies under or by reason of this Second -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Power Marketing Affiliate Original Sheet No. 30 Rate Schedule FERC No. 344 -------------------------------------------------------------------------------- Agreement on any persons other than the Parties and their respective permitted successors and assigns. Nor is anything in this Second Agreement intended to relieve or discharge the obligation or liability of any third persons to any Party or give any third person any right of subrogation or action against any Party. 12.14. FURTHER ASSURANCES. If any Party determines in its reasonable discretion that any further instruments, assurances, or other things are necessary or desirable to carry out the terms of this Second Agreement, the other Parties shall execute and deliver all such instruments or assurances, and do all things reasonably necessary or desirable to carry out the terms of this Second Agreement. 12.15. CONFIDENTIALITY. Each Party agrees that it will maintain in strictest confidence all documents, materials and other information marked "Confidential" or "Proprietary" by the disclosing Party ("Confidential Information") which it shall have obtained regarding another Party during the course of the negotiations leading to, and its performance of, this Second Agreement (whether obtained before or after the date of this Second Agreement). Each Party also agrees that it will maintain in strictest confidence, and treat as Confidential Information (whether marked "Confidential" or "Proprietary" or not) all nonpublic information regarding the condition or operation of any generating unit or plant that is the subject of this Second Agreement. Confidential Information shall not be communicated to any third person by a Party (other than to its affiliates, counsel, accountants, financial or tax advisors, or insurance consultants or in connection with its financing); PROVIDED that in the event the receiving Party is required by law, regulation or court order to disclose any Confidential Information, the receiving Party will promptly notify the disclosing Party in writing prior to making any such disclosure in -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Power Marketing Affiliate Original Sheet No. 31 Rate Schedule FERC No. 344 -------------------------------------------------------------------------------- order to facilitate the disclosing Party's seeking a protective order or other appropriate remedy from the proper authority and further PROVIDED that the receiving Party further agrees that if the disclosing Party ultimately discloses such Confidential Information to the requesting legal or regulatory body, it will furnish only that portion of the Confidential Information which is legally required and will exercise all reasonable efforts to obtain reliable assurances that confidential treatment will be accorded the Confidential Information. The obligations of nondisclosure and restricted use of Confidential Information shall survive the expiration or other termination of this Second Agreement until such obligations expire in accordance with their respective terms. 12.16. JOINT PREPARATION. This Second Agreement shall be deemed to have been jointly prepared by all Parties, and no ambiguity herein shall be construed for or against any Party based upon the identity of the author of this Second Agreement or any portion thereof. -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Power Marketing Affiliate Original Sheet No. 32 Rate Schedule FERC No. 344 -------------------------------------------------------------------------------- IN WITNESS WHEREOF, the Parties have executed this Second Agreement as of the date set forth at the beginning of this Second Agreement. POWER MARKETING AFFILIATE By:__________________________________________ SOUTHWESTERN ELECTRIC POWER COMPANY By:__________________________________________ AMERICAN ELECTRIC POWER SERVICE CORPORATION By:__________________________________________ -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Power Marketing Affiliate Original Sheet No. 33 Rate Schedule FERC No. 344 -------------------------------------------------------------------------------- SCHEDULE A SWEPCO WHOLESALE CONTRACTS -------------------------------------------------------------------------------- CONTRACT PERCENTAGE EXPIRATION DATE -------------------------------------------------------------------------------- Northeast Texas Electric Cooperative 7.06 -------------------------------------------------------------------------------- East Texas Electric Cooperative 1.47 -------------------------------------------------------------------------------- Tex-La Electric Cooperative (SPP) 2.11 -------------------------------------------------------------------------------- Tex-La Electric Cooperative (ERCOT) 1.01 -------------------------------------------------------------------------------- Rayburn Country Electric Cooperative 2.38 -------------------------------------------------------------------------------- City of Bentonville, Arkansas 1.45 -------------------------------------------------------------------------------- City of Hope, Arkansas 1.45 -------------------------------------------------------------------------------- City of Minden, Louisiana 0.85 -------------------------------------------------------------------------------- TOTAL 17.78 -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 ATTACHMENT 6 UNIT POWER SALES AGREEMENT BETWEEN OHIO POWER COMPANY AND POWER MARKETING AFFILIATE Ohio Power Company Original Sheet No. 1 Rate Schedule FERC No. 343 UNIT POWER SALES AGREEMENT AMONG OHIO POWER COMPANY AND POWER MARKETING AFFILIATE Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Ohio Power Company Original Sheet No. 2 Rate Schedule FERC No. 343 TABLE OF CONTENTS
PAGE ARTICLE I DEFINITIONS .......................................................8 ARTICLE II SALE AND PURCHASE OF UNIT POWER ..................................14 Section 2.1 Obligations of OPCO and PMA ......................................14 Section 2.2 Delivery .........................................................14 Section 2.3 OPCO's Obligations Subject to Buckeye Agreements .................15 Section 2.4 Obligations Subject to Other Agreements ..........................15 ARTICLE III TERM OF AGREEMENT ................................................16 Section 3.1 Effective Date ...................................................16 Section 3.2 Termination Date .................................................16 3.2.1 First Renewal Term .......................................16 3.2.2 Second Renewal Term ......................................17 ARTICLE IV CAPACITY .........................................................17 Section 4.1 Capacity .........................................................17 ARTICLE V SCHEDULING AND OPERATIONS ........................................18 Section 5.1 Dispatch .........................................................18 Section 5.2 Forecasts ........................................................18 Section 5.3 Operating Committee ..............................................18 5.3.1 Operating Committee Responsibilities .....................19 5.3.2 Operating Committee Meetings .............................21 5.3.3 Information for Use of the Operating Committee ...........21
Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Ohio Power Company Original Sheet No. 3 Rate Schedule FERC No. 343 Section 5.4 Unit Commitment ..................................................21 Section 5.5 Dispatch of Units ................................................21 ARTICLE VI COST COMPONENTS AND PAYMENT TERMS ................................21 Section 6.1 Cost Components ..................................................22 Section 6.2 Monthly Demand Charge ............................................22 Section 6.3 Monthly Operating Expenses .......................................22 6.3.1 Amounts Paid by OPCO for Third-party Services ............22 Section 6.4 Federal Income Tax ...............................................23 Section 6.5 FERC Fees ........................................................23 Section 6.6 Capital Repairs and Improvements .................................23 Section 6.7 Annual Budgeting Process .........................................23 ARTICLE VII - BILLING AND PAYMENT ..............................................24 Section 7.1 Billing Procedure ................................................24 Section 7.2 Timeliness of Payment ............................................24 Section 7.3 Disputes and Adjustments of Invoices .............................25 Section 7.4 Applicable Interest Rate .........................................25 ARTICLE VIII- TRANSMISSION SERVICES ............................................26 Section 8.1 Responsibilities .................................................26 ARTICLE IX - INTERRUPTION AND CURTAILMENTS ....................................26 Section 9.1 Scheduled Outages ................................................26 Section 9.2 Notification of Unscheduled Outages ..............................26 ARTICLE X - FORCE MAJEURE ....................................................26 Section 10.1 Definition .......................................................27
Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Ohio Power Company Original Sheet No. 4 Rate Schedule FERC No. 343 Section 10.2 Performance Excused ..............................................27 Section 10.3 Strike Issues ....................................................28 Section 10.4 Payments Not Excused .............................................28 ARTICLE XI - DEFAULTS .........................................................28 Section 11.1 Events of Default ................................................28 11.1.1 Bankruptcy ..............................................28 11.1.2 Violation or Noncompliance with Governmental Requirement .............................................28 11.1.3 Failure to Perform ......................................29 Section 11.2 Notice of Default and Opportunity to Cure ........................29 Section 11.3 No Waiver ........................................................29 Section 11.4 Dispute Resolution ...............................................30 ARTICLE XII - DISPUTE RESOLUTION ...............................................30 Section 12.1 Presentation of Dispute ..........................................30 Section 12.2 Inability of Operating Committee to Reach Agreement ..............30 Section 12.3 Arbitration ......................................................30 12.3.1 Commencement of Arbitration Proceeding ..................30 12.3.2 Appointment of Arbitrator ...............................31 12.3.3 Arbitration Proceedings .................................31 12.3.4 Authority of Arbitrator .................................32 12.3.5 Expenses and Costs ......................................32 12.3.6 Location of Arbitration Proceedings .....................32 12.3.7 Confidentiality .........................................33 12.3.8 FERC Jurisdiction Over Certain Disputes .................33
Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Ohio Power Company Original Sheet No. 5 Rate Schedule FERC No. 343 Section 12.4 Exclusive Means of Dispute Resolution ............................34 ARTICLE XIII - INDEMNIFICATION; LIMITATION OF LIABILITY .........................34 Section 13.1 Responsibilities .................................................34 Section 13.2 Limitation of Liability ..........................................35 Section 13.3 Limitation of Actions ............................................35 ARTICLE XIV - REGULATORY REQUIREMENTS ..........................................35 Section 14.1 Required Regulatory Approvals and Actions ........................35 Section 14.2 Regulatory Review ................................................36 ARTICLE XV - BOOKS AND RECORDS ................................................36 Section 15.1 Books and Records ................................................36 Section 15.2 Audits ...........................................................37 Section 15.3 Cooperation in Connection with Regulatory and Judicial Proceedings ......................................................37 ARTICLE XVI - MISCELLANEOUS ....................................................37 Section 16.1 Interpretation ...................................................37 Section 16.2 Partial Invalidity ...............................................38 Section 16.3 Assignment .......................................................38 Section 16.4 Successors Included ..............................................39 Section 16.5 Applicable Laws, Regulations, Orders, Approvals, and Permits ..........................................................39 Section 16.6 Choice of Law and Jurisdiction ...................................39 Section 16.7 Entire Agreement .................................................39 Section 16.8 Counterparts to this Agreement ...................................39 Section 16.9 Amendments .......................................................40
Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Ohio Power Company Original Sheet No. 6 Rate Schedule FERC No. 343 Section 16.10 Notices ..........................................................40 Section 16.11 Waivers ..........................................................41 Section 16.12 Independent Contractors ..........................................41 Section 16.13 No Third Party Beneficiaries .....................................41 Section 16.14 Further Assurances ...............................................42 Section 16.15 Confidentiality ..................................................42 Section 16.16 Joint Preparation ................................................43 Schedule A OPCO Generating Units Subject to This Agreement ........................44 Schedule B Calculation of Monthly Power Bill ......................................45
Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Ohio Power Company Original Sheet No. 7 Rate Schedule FERC No. 343 UNIT POWER SALES AGREEMENT THIS UNIT POWER SALES AGREEMENT ("AGREEMENT") is made and entered into as of this __________________ day of __________________, 2001, by and among Ohio Power Company ("OPCO") and Power Marketing Affiliate ("PMA"). OPCO and PMA are wholly-owned subsidiaries of American Electric Power Company, Inc. ("AEP"). WITNESSETH WHEREAS, OPCO is currently a vertically-integrated electric utility company providing electric service to retail customers located in its franchised service area in Ohio; WHEREAS, on July 6, 1999, Amended Substitute Senate Bill No. 3 ("Restructuring Act") became law in Ohio, mandating that OPCO reorganize its corporate structure to separate its generation and power supply functions from its transmission and distribution functions; WHEREAS, in accordance with the Restructuring Act, OPCO will become a generating and power supply company; WHEREAS, PMA is a subsidiary of AEP, and will dispatch and market AEP power supply resources not subject to cost-of-service regulation; Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Ohio Power Company Original Sheet No. 8 Rate Schedule FERC No. 343 WHEREAS, OPCO is willing to sell, and PMA is willing to purchase, OPCO Generating Capacity and associated dispatched Energy, pursuant to the rates, terms and conditions set forth herein. NOW, THEREFORE, in consideration of the premises and mutual covenants set forth herein, the Parties agree as follows: ARTICLE I DEFINITIONS For purposes of this Agreement, the following terms shall have the following meanings. 1.1. "AGREEMENT" means this Unit Power Sales Agreement, including attachments, and any amendments thereto now or hereafter executed by the Parties. 1.2. "ALLIANCE RTO" means the Alliance Regional Transmission Organization. 1.3. "ANCILLARY SERVICES" means one or more of those services that are defined in the Applicable OATT as ancillary services. 1.4. "ANNUAL BUDGET" means the budget established for each Operating Year in accordance with Section 6.7. 1.5. "ANNUAL OPERATING PLAN" means the operating plan established for each Operating Year in accordance with Section 6.7. 1.6. "APPLICABLE OATT" means the Open Access Transmission Tariff filed with FERC by American Electric Power Service Corporation on behalf of OPCO and certain of its affiliates in Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Ohio Power Company Original Sheet No. 9 Rate Schedule FERC No. 343 accordance with FERC's Order No. 888 or the Open Access Transmission Tariff filed with FERC by the Alliance RTO, as either may be applicable to particular transmission service, or any successor transmission service tariff to either, including any such successor tariff of a regional transmission organization to which OPCO transfers operating control or authority over its transmission facilities. 1.7. "AVAILABLE," when used to refer to capacity, means that such capacity is currently capable of being dispatched. 1.8. "AVAILABLE CAPACITY" means that portion of the OPCO Generating Capacity that is currently Available. 1.9. "BANKRUPTCY" means a situation in which: (i) a Party files a voluntary petition in bankruptcy or is adjudicated as bankrupt or insolvent, or files any petition, answer or consent seeking any reorganization, arrangement, composition, readjustment, liquidation, dissolution or similar relief for itself under the present or future applicable federal, state or other statute or law relating to bankruptcy, insolvency or other relief for debtors, or seeks or consents to, or acquiesces in the appointment of, any trustee, receiver, conservator or liquidator of such Party or of all or any substantial part of such Party's properties (the term "acquiesces" as used in this definition, includes the failure to file a petition or motion to vacate or discharge any order, judgment or decree within fifteen (15) Days after entry of such order, judgment or decree); (ii) a court of competent jurisdiction enters an order, judgment or decree approving a petition filed against a Party seeking a reorganization, arrangement, composition, readjustment, liquidation, dissolution or similar relief under any present or future federal bankruptcy law or any other Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Ohio Power Company Original Sheet No. 10 Rate Schedule FERC No. 343 present or future applicable federal, state or other statute or law relating to bankruptcy, insolvency or other relief for debtors, and such Party acquiesces in the entry of such order, judgment or decree or such order, judgment or decree remains unvacated and unstayed for an aggregate of sixty (60) Days, whether or not consecutive, after the date of entry thereof, or any trustee, receiver, conservator or liquidator of such Party or of all or any substantial part of its property is appointed without the consent or acquiescence of such Party and such appointment remains unvacated and unstayed for an aggregate of sixty (60) Days, whether or not consecutive; (iii) a Party admits in writing its inability to pay its debts as they mature; (iv) a Party gives notice to any federal or state governmental authority of insolvency or pending insolvency, or suspension or pending suspension of operations; or (v) a Party makes an assignment for the benefit of creditors or takes any other similar action for the protection or benefit of creditors. 1.10. "BUCKEYE" means Buckeye Power, Inc., an Ohio corporation not for profit. 1.11. "BUCKEYE AGREEMENTS" means (a) the Buckeye Station Agreement; (b) the Power Delivery Agreement, dated as of January 1, 1968, among Buckeye Power, Inc., the Cincinnati Gas & Electric Company, Columbus and Southern Ohio Electric Company, the Dayton Power and Light Company, Monongahela Power Company, Ohio Power Company, and the Toledo Edison Company; (c) the Deed, dated as of June 27, 1968, from Ohio Power Company to Buckeye Power, Inc.; (d) the Facilities Agreement, dated as of January 1, 1968, by and between Ohio Power Company and Buckeye Power, Inc.; (e) the Agreement dated as of June 20, 1968, between Ohio Power Company and Ohio Edison Company; and (f) the NPC Agreement. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Ohio Power Company Original Sheet No. 11 Rate Schedule FERC No. 343 1.12. "BUCKEYE STATION AGREEMENT" means the Station Agreement, dated as of January 1, 1968, among Ohio Power Company, Buckeye Power, Inc., and Cardinal Operating Company. 1.13. "BUSINESS DAY" means any Day on which the Federal Reserve member banks are open for business. A Business Day shall commence at 8:00 a.m. and close at 5:00 p.m., local time, at the location of the relevant Party's principal place of business, or at such other location as the context may require. In the event that the location cannot be determined from context, OPCO's principal place of business shall govern for purposes of application of the definition of "Business Day. 1.14. "CARDINAL STATION" means the steam electric generating station, and all associated facilities, located near Brilliant, Ohio, which, as of the date of this Agreement, consists of three (3) steam electric generating units, each nominally rated at 615,000 kw, one of which is owned by OPCO, and the remaining two of which are owned by Buckeye, and associated land and facilities, some of which are owned jointly by OPCO and Buckeye, and others of which are owned individually by OPCO or Buckeye. 1.15. "DAY" means a period of twenty-four (24) consecutive hours, beginning at 12:00:01 a.m., local time, at the Delivery Points; provided, however, that on the Day on which Eastern Daylight Savings Time becomes effective, the period shall be twenty-three (23) consecutive hours, and on the Day on which Eastern Standard Time becomes effective, the period shall be twenty-five (25) consecutive hours. 1.16. "DELIVERY POINTS" means (i) in the case of each of the generating units listed in Schedule A, other than the jointly-owned generating units, the points at which such generating unit is Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Ohio Power Company Original Sheet No. 12 Rate Schedule FERC No. 343 connected to OPCO's transmission facilities owned by an AEP affiliate, and (ii) in the case of each of the jointly-owned generating units listed in Schedule A, the delivery point identified for such unit in the agreements among the joint owners applicable to such unit. 1.17. "EFFECTIVE DATE" shall be the date set forth in the first paragraph of this Agreement. 1.18. "EMERGENCY" means (i) any abnormal system condition that requires immediate manual or automatic action to prevent loss of firm load, equipment damage, or tripping of system elements that could adversely affect the reliability of OPCO's electric system, and (ii) any existing or potential system condition on OPCO's electric system that OPCO determines, in the exercise of reasonable discretion, is not or will not be in conformance with applicable criteria. 1.19. "ENERGY" means the electric energy supplied under this Agreement, which shall be in the form of three-phase, alternating current at a frequency of 60 Hertz, with reasonable variations of frequency and voltage allowed consistent with Good Utility Practice. 1.20. "FERC" means the Federal Energy Regulatory Commission or any successor federal agency having regulatory jurisdiction over this Agreement. 1.21. "FIRST RENEWAL TERM" shall have the meaning set forth in Section 3.2.1 of this Agreement. 1.22. "GOOD UTILITY PRACTICE" means any of the practices, methods, and acts required, approved, or engaged in by a significant portion of the electric utility industry in the region where the generating units listed in Schedule A operate during the relevant time period, or any of the practices, methods, and acts which, in the exercise of reasonable judgment in light of the Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Ohio Power Company Original Sheet No. 13 Rate Schedule FERC No. 343 facts known at the time the decision was made, could have been expected to accomplish the desired result at the lowest reasonable cost consistent with good business practices, reliability, safety, and expedition. Good Utility Practice is not intended to be limited to the optimum practice, method, or act; rather, it is intended to be a spectrum of acceptable practices, methods, and acts. 1.23. "GOVERNMENTAL REQUIREMENT" means any statute, law, regulation, ordinance, rule, exemption, or order of any federal, state, county, municipal or other governmental authority, any political subdivision of any of the foregoing, or any governmental, quasi-governmental, judicial, public or statutory instrumentality, authority, body or entity, including the final, non-appealable judicial or administrative interpretation of any such statute, law, regulation, ordinance, rule, exemption or order by any such authority, instrumentality, body, or entity. 1.24. "INITIAL TERM" shall have the meaning set forth in Section 3.2 of this Agreement. 1.25. "MONTH" means the period beginning at 12:00:01 a.m., local time, on the first Day of each calendar month and ending at midnight of the last Day of such calendar month. 1.26. "NPC AGREEMENT" means the Station Agreement, dated as of January 31, 2000, by and between Ohio Power Company and National Power Cooperative, Inc., an affiliate of Buckeye. 1.27. "OHIO COMMISSION" means the Public Utilities Commission of Ohio, or any successor organization thereto. 1.28. "OPCO GENERATING CAPACITY" means all of the capacity of the generating units listed in Schedule A, or in the case of the jointly-owned generating units, OPCO's full share of Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Ohio Power Company Original Sheet No. 14 Rate Schedule FERC No. 343 capacity in such units, less the portion of the capacity of such units that is required by OPCO to serve its wholesale customers. 1.29. "OPERATING YEAR" means (i) with respect to the year 2002, that period of time beginning on the later of January 1, 2002 and the date on which all required regulatory authorizations have been received, and ending on December 31, 2002; and (ii) with respect to subsequent years during the term of this Agreement, the calendar year commencing on January 1 and ending on December 31 or such earlier date in such calendar year on which this Agreement expires or is terminated. 1.30. "PARTIES" means OPCO, PMA, and or the assignee or successor of any of their rights and obligations under this Agreement. "PARTY" means one of the Parties. 1.31. "SECOND RENEWAL TERM" shall have the meaning set forth in Section 3.2.2 of this Agreement. ARTICLE II SALE AND PURCHASE OF UNIT POWER 2.1. OBLIGATIONS OF OPCO AND PMA. OPCO shall sell, and PMA shall purchase, the OPCO Generating Capacity and all associated dispatched Energy. PMA shall have the right to designate a portion of the OPCO Generating Capacity and associated dispatched Energy for ancillary services. 2.2. DELIVERY. OPCO shall deliver Energy purchased by PMA from any of the generating units listed in Schedule A at the Delivery Point(s) for such generating unit. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Ohio Power Company Original Sheet No. 15 Rate Schedule FERC No. 343 2.3. OPCO'S OBLIGATIONS SUBJECT TO BUCKEYE AGREEMENTS. Notwithstanding any other provision of this Agreement, OPCO's obligations and PMA's rights under this Agreement (including OPCO's obligation to sell, and PMA's right to purchase, the OPCO Generating Capacity and all associated dispatched Energy) are conditioned upon, and subject to, OPCO's rights, and the performance of OPCO's obligations, under the Buckeye Agreements, including (a) the Entitlement of OPCO and Buckeye in and to the use of the Total Net Capability of the Cardinal Station under the Buckeye Station Agreement, (b) OPCO's obligation to deliver Back-up Power and Back-up Energy to Buckeye under the Buckeye Station Agreement, (c) the provisions of the Buckeye Station Agreement applicable to Excess, Surplus and Supplementary Capacity, (d) the provisions of the Buckeye Station Agreement applicable to operation and maintenance of the Cardinal Station, and (e) Buckeye's obligation to sell power under the NPC Agreement. Capitalized terms used in this Section 2.3 that are not otherwise defined in this Agreement, shall have the meanings specified in the Buckeye Station Agreement. 2.4. OBLIGATIONS SUBJECT TO OTHER AGREEMENTS. Notwithstanding any other provision of this Agreement, OPCO's obligations and PMAs' rights under this Agreement with respect to the portion of the OPCO Generating Capacity and associated Energy attributable to any of the jointly-owned generating units listed in Schedule A (including OPCO's obligation to sell and otherwise make Available, and PMA's right to purchase, such portion of the OPCO Generating Capacity and associated Energy), are conditioned upon, and subject to, the provisions of the agreements among the joint owners applicable to such unit. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Ohio Power Company Original Sheet No. 16 Rate Schedule FERC No. 343 ARTICLE III TERM OF AGREEMENT 3.1. EFFECTIVE DATE. This Agreement shall be effective upon the Effective Date. PMA shall begin to purchase OPCO Generating Capacity and associated Energy under this Agreement, and shall begin to dispatch its Available Capacity, on January 1, 2002, or on such later date as all required regulatory authorizations have been received. PMA shall have no obligation to purchase or to pay for any OPCO Generating Capacity or associated Energy before January 1, 2002 or such later date as all required regulatory authorizations have been received, or to reimburse OPCO for any costs that OPCO has expensed before that date. 3.2. TERMINATION DATE. Except for (a) termination following an Event of Default as provided in Section 11.1; (b) termination because of regulatory disapproval or regulatory changes as provided in Article XIV; or (c) termination pursuant to mutual agreement of OPCO and PMA, this Agreement shall continue in effect with respect to each generating unit listed in Schedule A for an Initial Term ending on the date shown in Schedule A. 3.2.1. FIRST RENEWAL TERM. Not less than one (1) year before the end of the Initial Term with respect to each unit listed in Schedule A, PMA shall provide notice to OPCO if it wishes to extend this Agreement as to that unit for a First Renewal Term. In the event that PMA elects to enter into a First Renewal Term, the Operating Committee shall retain a consultant, at PMA's expense, to provide an estimate of the remaining useful life of the subject unit as of the first day of the First Renewal Term. The length of the First Renewal Term shall be less than seventy-five percent (75%) of the estimated remaining useful life of the subject Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Ohio Power Company Original Sheet No. 17 Rate Schedule FERC No. 343 unit as of the first day of the First Renewal Term, expressed in months, and rounded down to the last full month before reaching seventy-five percent (75%) of that estimated remaining useful life. The date by which PMA must provide notice if it wishes to enter into the First Renewal Term with respect to each unit is listed in Schedule A. 3.2.2. SECOND RENEWAL TERM. If PMA elects to extend the Agreement for the First Renewal Term with respect to any unit, then not less than one (1) year before the end of the First Renewal Term as to that unit, PMA shall provide notice to OPCO if it wishes to extend this Agreement for a Second Renewal Term as to that unit. In the event that PMA elects to enter into a Second Renewal Term, the Operating Committee shall retain a consultant, at PMA's expense, to provide an estimate of the remaining useful life of the subject unit as of the first day of the Second Renewal Term. The length of the Second Renewal Term shall be less than seventy-five percent (75%) of the estimated remaining useful life of the subject unit as of the first day of the Second Renewal Term, expressed in months, and rounded down to the last full month before reaching seventy-five percent (75%) of that estimated remaining useful life. This Agreement shall terminate as to each such unit at the conclusion of the Second Renewal Term. ARTICLE IV CAPACITY 4.1. CAPACITY. PMA shall have the right to Available Capacity and associated Energy from the OPCO Generating Capacity in accordance with the terms of this Agreement. Subject to the Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Ohio Power Company Original Sheet No. 18 Rate Schedule FERC No. 343 terms of this Agreement, OPCO Generating Capacity will be Available to PMA (a) from each of the generating units listed in Schedule A to this Agreement or, in the case of the jointly-owned generating units, from OPCO's share of such units as reflected in Schedule A, with respect to the capability of each such unit as that capability may change over time as determined by the Operating Committee. ARTICLE V SCHEDULING AND OPERATIONS 5.1. DISPATCH. PMA shall have the exclusive right to dispatch Energy and ancillary services from the Available Capacity. Subject to operational requirements established by the Operating Committee, OPCO shall make the Available Capacity Available for PMA to dispatch at all times. 5.2. FORECASTS. OPCO or its agent shall notify PMA on or before the fifteenth (15th) Day of each Month of the amount of Available Capacity and Energy expected to be Available from each of the generating units included in the OPCO Generating Capacity in each of the next thirty-six (36) Months. In the event that the amount of Available Capacity or Energy forecast to be Available from any such generating unit(s) changes, OPCO or its agent shall notify PMA as soon as it is feasible to do so. 5.3. OPERATING COMMITTEE. By written notice to the other Party, each Party shall name one representative ("Operating Representative") and one alternate to act for it in matters pertaining to operating arrangements under this Agreement. A Party may change its Operating Representative or alternate at any time by written notice to the other Party. The Operating Representatives for Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Ohio Power Company Original Sheet No. 19 Rate Schedule FERC No. 343 the respective Parties, or their alternates, shall comprise the Operating Committee. All decisions, directives, or other actions by the Operating Committee must be by unanimous agreement of the Operating Representatives of OPCO and PMA. 5.3.1. OPERATING COMMITTEE RESPONSIBILITIES. The Operating Committee shall have the following responsibilities: a. Review and approval of the Annual Budget and Annual Operating Plan described in Section 6.7. b. Establishment and review of procedures and systems for dispatch, notification of dispatch, and unit commitment under this Agreement, including assurance that the units listed in Schedule A are dispatched at a sufficient level to provide OPCO with such energy as it may require to serve its wholesale customers' requirements. c. Establishment and monitoring of procedures for communication and coordination with respect to unit capacity availability, fuel-firing options, and scheduling of the OPCO Generating Capacity, including, subject to Section 9.1, scheduling of outages for maintenance, repairs, equipment replacements, scheduled inspections, and other foreseeable causes of outages at any generating unit, as well as the return of any unit to availability following an unplanned outage. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Ohio Power Company Original Sheet No. 20 Rate Schedule FERC No. 343 d. Decisions on capital expenditures, including unit upgrades and repowering. e. Determinations as to changes in the unit capability of the generating units listed in Schedule A and decisions on unit retirement. f. Establishment and modification of billing procedures under this Agreement. g. Establishment of projected capacity costs for use in planning by the Parties. h. Specification of fuels, oversight of fuel inspection and certification procedures, procurement and delivery of fuel to each of the generating units listed in Schedule A, and management of fuel inventories. i. Establishment of, termination of, and approval of any change or amendment to operating arrangements with respect to any of the generating units listed in Schedule A. j. Dispute resolution as provided in Section 12.1. k. Review and approval of plans and procedures designed to insure compliance with any environmental law, regulation, ordinance or permit, including procedures for allocating and using emission Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Ohio Power Company Original Sheet No. 21 Rate Schedule FERC No. 343 allowances or for any programs that permit averaging at more than one unit for compliance. 1. Other duties as assigned by agreement of OPCO and PMA. 5.3.2. OPERATING COMMITTEE MEETINGS. The Operating Committee shall meet at least quarterly, and at such other times as either Party may reasonably request. 5.3.3. INFORMATION FOR USE OF THE OPERATING COMMITTEE. The Parties shall cooperate in providing to the Operating Committee the information it reasonably needs to carry out its duties, and to supplement or correct such information on a timely basis. 5.4. UNIT COMMITMENT. PMA will make an initial unit commitment for each of the generating units listed in Schedule A one (1) Business Day ahead of real-time dispatch, or, in the case of any of the jointly-owned generating units listed in Schedule A at such earlier time as required to comply with the provisions of any of the agreements among the joint owners applicable to such generating unit or the scheduling procedures established thereunder. 5.5. DISPATCH OF UNITS. Subject to operational requirements established by the Operating Committee and the operation of the generating units consistent with Good Utility Practice, any unit designated to be committed by PMA will be brought on line or kept on line. ARTICLE VI COST COMPONENTS AND PAYMENT TERMS Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Ohio Power Company Original Sheet No. 22 Rate Schedule FERC No. 343 6.1. COST COMPONENTS. In return for OPCO's sale to PMA of the OPCO Generating Capacity and associated dispatched Energy under this Agreement, PMA will pay OPCO a Demand Charge as provided in Section 6.2, PMA's share of Monthly Operating Expenses as provided in Section 6.3, and Federal Income Taxes attributable to PMA as provided in Section 6.4 In addition, PMA will pay OPCO its share of any other costs approved by the Operating Committee and initially incurred by OPCO. Pursuant to Article VII, OPCO will bill PMA for those costs with respect to those items and services provided by or through OPCO. 6.2. MONTHLY DEMAND CHARGE. In the case of the generating units listed in Schedule A, PMA will pay a monthly Demand Charge for the OPCO Generating Capacity equal to the sum of the Monthly Return on Common Equity and Monthly Return on Other Capital calculated in accordance with pages 2 and 3 of Schedule B to this Agreement. 6.3. MONTHLY OPERATING EXPENSES. In the case of the generating units listed in Schedule A, PMA will pay the Monthly Operating Expenses associated with the amount of Energy that it dispatches from each such generating unit in each Month calculated in accordance with page 4 of Schedule B. 6.3.1. AMOUNTS PAID BY OPCO FOR THIRD-PARTY SERVICES. OPCO shall be responsible to make all payments due to any service provider furnishing services to OPCO at the generating units identified in Schedule A, even though the cost of such payments will be reflected in the share of Monthly Operating Expenses payable by PMA to OPCO. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Ohio Power Company Original Sheet No. 23 Rate Schedule FERC No. 343 6.4. FEDERAL INCOME TAX. PMA will pay OPCO a provision for Federal Income Tax each Month calculated in accordance with page 5 of Schedule B. 6.5. FERC FEES. PMA shall be responsible for any fees charged by FERC on the basis of the sales or transmission of capacity or energy at wholesale in interstate commerce. 6.6. CAPITAL REPAIRS AND IMPROVEMENTS. Capital repairs and improvements will be determined by the Operating Committee pursuant to the annual budgeting process set forth in Section 6.7. Expenditures for such capital repairs and improvements will initially be paid by OPCO, which shall include the costs of such capital repairs and improvements in calculating the Demand Charge pursuant to Section 6.2. 6.7. ANNUAL BUDGETING PROCESS. At least ninety (90) days before the start of each Operating Year, OPCO shall submit to the Operating Committee a proposed Annual Budget with respect to its generating units listed in Schedule A, a proposed Annual Operating Plan with respect to those generating units, and an estimate and schedule of costs to be incurred for major maintenance or replacement items with respect to those generating units during the next six (6)-year period. The Annual Budget shall be presented on a Month-by-Month basis for each Month during the next Operating Year, and shall include an operating budget, a capital budget, an estimate of the cost of any major repairs that OPCO anticipates will occur during such Operating Year with respect to the generating units listed in Schedule A, and an itemized estimate of all projected Monthly Operating Expenses relating to OPCO's operation of those generating units during that Operating Year. The members of the Operating Committee will meet and work in good faith to agree upon the final Annual Budget and final Annual Operating Plan, and will also meet to discuss the Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Ohio Power Company Original Sheet No. 24 Rate Schedule FERC No. 343 information provided with respect to any agreements among the owners of the jointly-owned units listed in Schedule A, including whether OPCO should seek a modification in the budget or operating plans with respect to the capacity that is the subject of each of those agreements. Once approved, the Annual Budget and Annual Operating Plan shall remain in effect throughout the applicable Operating Year, subject to such changes, revisions, amendments, and updating as the Operating Committee may determine. ARTICLE VII BILLING AND PAYMENT 7.1. BILLING PROCEDURE. Unless otherwise specifically agreed upon by the Parties, the calendar month shall be the standard period for all payments under this Agreement. As soon as practicable after the end of each Month, OPCO will render to PMA an invoice for the payment obligations, if any, incurred hereunder during the preceding month. 7.2. TIMELINESS OF PAYMENT. Unless otherwise agreed by the Parties, all invoices under this Agreement shall be due and payable in accordance with OPCO's invoice instructions on or before the later of the twentieth (20th) day of each Month, or tenth (10th) day after receipt of the invoice or, if such day is not a Business Day, then on the next Business Day. PMA will make payments by electronic funds transfer, or by other mutually agreeable method(s), to the account designated by OPCO. Any amounts not paid by the due date will be deemed delinquent and will accrue interest at the interest rate specified in Section 7.4, such interest to be calculated from and including the due date to but excluding the date the delinquent amount is paid in full. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Ohio Power Company Original Sheet No. 25 Rate Schedule FERC No. 343 7.3. DISPUTES AND ADJUSTMENTS OF INVOICES. PMA may, in good faith, dispute the correctness of any invoice or any adjustment to an invoice, rendered under this Agreement, and OPCO may adjust any invoice for any arithmetic or computational error, within twelve (12) months of the date the invoice, or adjustment to an invoice, was rendered. In the event an invoice or portion thereof, or any other claim or adjustment arising hereunder, is disputed, PMA shall be required to make payment of the undisputed portion of the invoice when due, with notice of the objection given to OPCO. Any invoice dispute or invoice adjustment shall be in writing and shall state the basis for the dispute or adjustment. Payment of the disputed amount shall not be required until the dispute is resolved. Upon resolution of the dispute, any required payment shall be made within two (2) Business Days of such resolution along with interest accrued at the interest rate specified in Section 7.4 from and including the due date to but excluding the date paid. Inadvertent overpayments shall be returned upon request or deducted by OPCO from subsequent payments, with interest accrued at the interest rate specified in Section 7.4 from and including the date of such overpayment to but excluding the date repaid or deducted by OPCO. Any dispute with respect to an invoice is waived unless PMA notifies OPCO in accordance with this Section 7.3 within twelve (12) months after the invoice is rendered or any specific adjustment to the invoice is made. If an invoice is not rendered within twelve (12) months after the close of the Month during which performance under this Agreement occurred, the right to payment for such performance is waived. 7.4. APPLICABLE INTEREST RATE. All interest calculations under this Agreement (other than interest included in calculating the monthly bill pursuant to Schedule B) shall use a rate per annum equal to the Federal Funds Rate (as published by the Board of Governors of the Federal Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Ohio Power Company Original Sheet No. 26 Rate Schedule FERC No. 343 Reserve System as from time to time in effect). Such interest shall be calculated on the basis of the actual number of Days elapsed over a year of three hundred sixty (360) Days. ARTICLE VIII TRANSMISSION SERVICES 8.1. RESPONSIBILITIES. PMA shall be responsible for arranging for transmission service and ancillary services for Energy dispatched from the Available Capacity from the Delivery Points, as provided in the Applicable OATT or other applicable tariffs. ARTICLE IX INTERRUPTION AND CURTAILMENTS 9.1. SCHEDULED OUTAGES. OPCO and PMA shall jointly agree on the scheduling of outages for maintenance, repairs, equipment replacements, scheduled inspections, and other foreseeable cause of outages at any OPCO generating unit listed in Schedule A, provided however, that in the case of the jointly-owned generating units, such scheduling shall be subject to the provisions of the agreements among the joint owners applicable to such unit. 9.2. NOTIFICATION OF UNSCHEDULED OUTAGES. OPCO shall notify PMA as soon as is feasible of any unscheduled outage at any of OPCO's generating units listed in Schedule A, including the anticipated duration of such unscheduled outage as soon as such duration can reasonably be estimated, and shall update such reports as new information becomes available, until all affected units have been restored to full service. ARTICLE X FORCE MAJEURE Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Ohio Power Company Original Sheet No. 27 Rate Schedule FERC No. 343 10.1. DEFINITION. Force Majeure includes sabotage, strikes or other labor difficulties, riots, civil disturbances, acts of God, acts of public enemies, drought, earthquake, flood, explosion, fire, lightning, landslides, or similar cataclysmic event, or appropriation, diversion, or interruption of service under this Agreement by any court or governmental authority having jurisdiction thereof, or any other cause, whether of the kind enumerated herein or otherwise, that is beyond the reasonable control of, and without the fault or negligence of, the Party claiming Force Majeure. Economic hardship of any Party shall not constitute a Force Majeure event under this Agreement, including the loss of any market or the inability of PMA to economically use or resell the OPCO Generating Capacity or associated Energy. An event constituting force majeure, or otherwise excusing performance, under the Buckeye Agreements or any of the agreements among the joint owners of any of the jointly-owned units listed in Schedule A, shall constitute a Force Majeure event under this Agreement with respect to the Parties' rights and obligations to the portion of the OPCO Generating Capacity and associated Energy attributable to any of the jointly-owned units to which such agreement is applicable. 10.2. PERFORMANCE EXCUSED. If any Party is rendered wholly or partially unable to perform under this Agreement because of a Force Majeure event, that Party shall be excused from such obligations to the extent that the occurrence of the Force Majeure event prevents such Party's performance, provided that: (a) the non-performing Party promptly, but in no case longer than three (3) Business Days after the occurrence of the Force Majeure event, gives the other Party written notice describing in reasonable detail the nature of the Force Majeure event; (b) the suspension of performance shall be of no greater scope and of no longer duration than is Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Ohio Power Company Original Sheet No. 28 Rate Schedule FERC No. 343 reasonably required by the Force Majeure event; and (c) the non-performing Party used Good Utility Practice to remedy its inability to perform. 10.3. STRIKE ISSUES. No Party to this Agreement shall be required to settle a strike affecting it, except when, in its best judgment, such a settlement appears advisable. 10.4. PAYMENTS NOT EXCUSED. Nothing in this Article X shall excuse either OPCO or PMA from making payment when due of the cost components set forth in Article VI or for any other amounts due under any provision of this Agreement. ARTICLE XI DEFAULTS 11.1. EVENTS OF DEFAULT. The following constitute Events of Default by a Party under this Agreement: 11.1.1. BANKRUPTCY. The Bankruptcy of either Party shall be an Event of Default by that Party. 11.1.2. VIOLATION OR NONCOMPLIANCE WITH GOVERNMENTAL REQUIREMENT. Violation or noncompliance with a Governmental Requirement by a Party or its agent shall be an Event of Default by that Party, if the violation or noncompliance has or may have a Material Adverse Effect on the non-defaulting Party with respect to its rights or obligations under this Agreement. For purposes of this Agreement, a "Material Adverse Effect" is any impact or effect that deprives a Party of all or a substantial portion of its reasonably expected benefits under this Agreement, Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Ohio Power Company Original Sheet No. 29 Rate Schedule FERC No. 343 whether directly or by increasing that Party's burdens or costs under this Agreement. 11.1.3. FAILURE TO PERFORM. The failure of a Party to perform a material obligation under this Agreement shall be an Event of Default by that Party. 11.2. NOTICE OF DEFAULT AND OPPORTUNITY TO CURE. Upon the occurrence of an Event of Default, the non-defaulting Party may deliver a written Notice of Default to the defaulting Party. Except for the event set forth in Section 11.1.1, for which the non-defaulting Party may terminate this Agreement immediately, the Notice of Default shall begin the running of a cure period of thirty (30) Days, at the end of which the non-defaulting Party may terminate this Agreement if the default has not been cured; provided, however, that if the default cannot reasonably be cured within said thirty (30)-day period and the defaulting Party shall have commenced to cure such failure within said period and shall thereafter proceed with reasonable diligence and good faith to cure such failure, then the cure period shall be extended for such longer period of time (but not more than ninety (90) days total, including the original thirty (30)-day period) as shall be necessary to accomplish such cure with all reasonable diligence (so long as such extended period will not cause an immediate Material Adverse Effect on the non-defaulting Party and provided further that the occurrence of any such immediate Material Adverse Effect shall terminate the extended period). 11.3. NO WAIVER. If a non-defaulting Party does not give the Notice of Default provided in Section 11.2, or does not terminate this Agreement after the running of the cure period, notwithstanding the failure of the defaulting Party to cure, in whole or in part, the default, the Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Ohio Power Company Original Sheet No. 30 Rate Schedule FERC No. 343 non-defaulting Party shall not waive any rights it has under this Agreement, including the right to give a new Notice of Default as to the uncured default. 11.4. DISPUTE RESOLUTION. Any dispute as to the application of this Article shall be resolved through the dispute resolution procedures provided in Article XII. ARTICLE XII DISPUTE RESOLUTION 12.1. PRESENTATION OF DISPUTE. If either Party believes that a dispute has arisen as to the meaning or application of this Agreement, it shall present that matter to the Operating Committee in writing, and shall provide a copy of that writing to the other Party pursuant to the notice provisions of Section 16.10 of this Agreement. 12.2. INABILITY OF OPERATING COMMITTEE TO REACH AGREEMENT. If the Operating Committee is unable to reach agreement on any dispute within thirty (30) days after the dispute is presented to it, the matter shall be referred to the chief operating officers of the Parties for resolution in the manner that such individuals shall agree is appropriate; provided, however, that any Party involved in a dispute may invoke the arbitration provisions set forth in Section 12.3 at any time after the end of the thirty (30)-day period provided for the Operating Committee to reach agreement if the Operating Committee has not reached agreement. 12.3. ARBITRATION. 12.3.1. COMMENCEMENT OF ARBITRATION PROCEEDING. If the Parties are unable to resolve a dispute through the Operating Committee within thirty (30) days after the dispute is presented to the Operating Committee pursuant to Section 12.1, or Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Ohio Power Company Original Sheet No. 31 Rate Schedule FERC No. 343 through reference of the matter to the chief operating officers of the Parties pursuant to Section 12.2, either Party may commence arbitration proceedings by providing written notice to the other Party, detailing the nature of the dispute, designating the issue(s) to be arbitrated, identifying the provisions of this Agreement under which the dispute arose, and setting forth such Party's proposed resolution of such dispute. 12.3.2. APPOINTMENT OF ARBITRATOR. Within ten (10) days of the date of the notice of arbitration, a representative of each Party shall meet for the purpose of selecting an arbitrator. If the Parties' representatives are unable to agree on an arbitrator within fifteen (15) days of the date of the notice of arbitration, then an arbitrator shall be selected in accordance with the procedures of the American Arbitration Association ("AAA"). Whether the arbitrator is selected by the Parties' representatives or in accordance with the procedures of the AAA, the arbitrator shall have the qualifications and experience in the occupation, profession, or discipline relevant to the subject matter of the dispute. 12.3.3. ARBITRATION PROCEEDINGS. Any arbitration proceeding shall be subject to the Federal Arbitration Act, 9 U.S.C.ss.ss.1 ET SEQ. (1994), as it may be amended, or any successor enactment thereto, and shall be conducted in accordance with the commercial arbitration rules of the AAA in effect on the date of the notice to the extent not inconsistent with the provisions of this Article XII. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Ohio Power Company Original Sheet No. 32 Rate Schedule FERC No. 343 12.3.4. AUTHORITY OF ARBITRATOR. The arbitrator shall be bound by the provisions of this Agreement where applicable, and shall have no authority to modify any terms and conditions of this Agreement in any manner. The arbitrator shall render a decision resolving the dispute in an equitable manner, and may determine that monetary damages are due to a Party or may issue a directive that a Party take certain actions or refrain from taking certain actions, but shall not be authorized to order any other form of relief; provided, however, that nothing in this Article shall preclude the arbitrator from rendering a decision that adopts the resolution of the dispute proposed by a Party. Unless otherwise agreed to by the Parties, the arbitrator shall render a decision within one hundred twenty (120) days of appointment, and shall notify the Parties to this Agreement in writing of such decision and the reasons supporting such decision. The decision of the arbitrator shall be final and binding upon the Parties, and any award may be enforced in any court of competent jurisdiction. 12.3.5. EXPENSES AND COSTS. The fees and expenses of the arbitrator shall be shared equally by the Parties, unless the arbitrator specifies a different allocation. All other expenses and costs of the arbitration proceeding shall be the responsibility of the Party incurring such expenses and costs. 12.3.6. LOCATION OF ARBITRATION PROCEEDINGS. Unless otherwise agreed by the Parties, any arbitration proceedings shall be conducted in Columbus, Ohio. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Ohio Power Company Original Sheet No. 33 Rate Schedule FERC No. 343 12.3.7. CONFIDENTIALITY. Except as provided in this Article, the existence, contents, or results of any arbitration proceeding under this Article may not be disclosed without the prior written consent of the Parties, provided, however, that any Party may make disclosures as may be required to fulfill regulatory obligations to any agencies having jurisdiction, and may inform its lenders, affiliates, auditors, and insurers, as necessary, under pledge of confidentiality, and may consult with expert consultants as required in connection with an arbitration proceeding under pledge of confidentiality. 12.3.8. FERC JURISDICTION OVER CERTAIN DISPUTES. Nothing in this Agreement shall be construed to preclude any Party from filing a petition or complaint with FERC with respect to any claim over which FERC has jurisdiction. In such case, the other Party may request that FERC reject the petition or complaint or otherwise decline to exercise its jurisdiction. If FERC declines to act with respect to all or part of a claim, the portion of the claim not so accepted by FERC may be resolved through arbitration, as provided in this Article. To the extent that FERC asserts or accepts jurisdiction over all or part of a claim, the decisions, findings of fact, or orders of FERC shall be final and binding, subject to judicial review under the Federal Power Act, and any arbitration proceedings that may have commenced prior to the assertion or acceptance of jurisdiction by FERC shall be stayed, pending the outcome of the FERC proceedings. The arbitrator shall have no authority to modify, and shall be conclusively bound by, any decisions, findings of fact, or orders of FERC; provided, however, that to the extent that any Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Ohio Power Company Original Sheet No. 34 Rate Schedule FERC No. 343 decisions, findings of fact, or orders of FERC do not provide a final or complete remedy to a Party seeking relief, such Party may proceed to arbitration under this Article to secure such a remedy, subject to any FERC decisions, findings, or orders. 12.4. EXCLUSIVE MEANS OF DISPUTE RESOLUTION. The procedures set forth in this Article XII shall be the exclusive means for resolving disputes arising under this Agreement and shall survive this Agreement to the extent necessary to resolve any disputes pertaining to this Agreement. Except as provided in Sections 12.3.1 and 12.3.8, neither Party shall have the right to bring any dispute for resolution by a court, agency, or other entity having jurisdiction over this Agreement, unless both Parties agree in writing to such procedure. ARTICLE XIII INDEMNIFICATION; LIMITATION OF LIABILITY 13.1. RESPONSIBILITIES. Subject to Section 13.2, each Party shall indemnify and hold harmless the other Party and its owners, officers, directors, employers, representatives, and agents for, against, and from any claim, liability, damage, loss, or expenses of any kind or nature (including reasonable attorneys' fees) for any claims, suits, judgments, demands, actions, or liabilities, in each such instance to the extent determined to be attributed to the negligence, gross negligence, willful misconduct, or strict liability in tort or breach of this Agreement by the indemnitor or its owners, officers, directors, employers, representatives, and agents (it being the intention of the Parties that each Party is entitled to reciprocal and comparative indemnity). The provisions of this Section 13.1 shall survive the expiration or termination of this Agreement. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Ohio Power Company Original Sheet No. 35 Rate Schedule FERC No. 343 13.2. LIMITATION OF LIABILITY. FOR BREACH OF ANY PROVISION OF THIS AGREEMENT, A PARTY'S LIABILITY SHALL BE LIMITED TO DIRECT ACTUAL DAMAGES ONLY. SUCH DIRECT ACTUAL DAMAGES SHALL BE THE SOLE AND EXCLUSIVE REMEDY, AND ALL OTHER REMEDIES OR DAMAGES AT LAW OR IN EQUITY ARE WAIVED. UNLESS EXPRESSLY HEREIN PROVIDED, NO PARTY SHALL BE LIABLE FOR CONSEQUENTIAL, INCIDENTAL, PUNITIVE, EXEMPLARY, OR INDIRECT DAMAGES, LOST PROFITS OR OTHER BUSINESS INTERRUPTION DAMAGES, BY STATUTE, IN TORT OR CONTRACT, UNDER ANY INDEMNITY PROVISION OR OTHERWISE. IT IS THE INTENT OF THE PARTIES THAT THE LIMITATIONS HEREIN IMPOSED ON REMEDIES AND THE MEASURE OF DAMAGES BE WITHOUT REGARD TO THE CAUSE OR CAUSES RELATED THERETO, INCLUDING THE NEGLIGENCE OF ANY PARTY, WHETHER SUCH NEGLIGENCE BE SOLE, JOINT OR CONCURRENT, OR ACTIVE OR PASSIVE. 13.3. LIMITATION OF ACTIONS. No Party shall present a claim under this Agreement for damages or other relief with respect to any action or omission of the other Party that occurred more than twenty-four (24) Months before the claim is asserted. With respect to billing disputes, any claim for reduction or increase must be presented within twelve (12) Months after the bill was rendered. ARTICLE XIV REGULATORY REQUIREMENTS 14. 1. REQUIRED REGULATORY APPROVALS AND ACTIONS. In the event that any regulatory agency with jurisdiction to approve or disapprove this Agreement finally disapproves this Agreement, Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Ohio Power Company Original Sheet No. 36 Rate Schedule FERC No. 343 then the Agreement shall terminate on December 31, 2001 or the date of disapproval, whichever is later. No regulatory disapproval shall be final for purposes of terminating this Agreement until all motions for reconsideration or appeals of the disapproval letter have been decided and the time for any further appeal shall have elapsed without such further appeal having been noticed. 14.2. REGULATORY REVIEW. If, during review of this Agreement, any regulatory agency with jurisdiction and authority to do so orders the modification of any term or condition, or orders the alteration of any charge(s), or in any way conditions its approval of this Agreement, and either OPCO or PMA determines that such order, action, or decision has or will have a Material Adverse Effect on it (as that term is defined in Section 11.1.2), OPCO and PMA shall negotiate in good faith to agree on modified terms and conditions mutually agreeable to them that are consistent with such regulatory order, action, or decision and that preserve, to the maximum extent possible, the balance of economic benefits and burdens previously created by this Agreement before the issuance of such regulatory order, action, or decision. ARTICLE XV BOOKS AND RECORDS 15.1. BOOKS AND RECORDS. OPCO shall keep such books and records with respect to the costs of owning, operating, and maintaining or improving the generating units listed in Schedule A of which it is the sole owner and such other pertinent information under this Agreement as shall be required (a) to allow PMA to verify the accuracy of OPCO's billing statements, and (b) to comply with FERC and other regulatory authority requirements. OPCO shall endeavor in good faith to make available to PMA such similar information to which OPCO has access under the Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Ohio Power Company Original Sheet No. 37 Rate Schedule FERC No. 343 agreements for jointly-owned units listed in Schedule A, to the extent permitted under such agreements. 15.2. AUDITS. PMA shall have the right, at its sole expense, upon reasonable notice and during normal Business Day hours, to examine OPCO's books and records to the extent reasonably necessary to verify the accuracy of any statement, charge, or computation made pursuant to this Agreement, for a period of up to one (1) year after such statement, charge or computation has been supplied to PMA. 15.3. COOPERATION IN CONNECTION WITH REGULATORY AND JUDICIAL PROCEEDINGS. To the extent that any Party requires relevant information in the possession of another Party for regulatory or judicial purposes, the Party possessing such information shall cooperate with the other Party to provide the information required to satisfy the inquiry; provided, however, that a Party may deem any information in its possession to be privileged or confidential, and to this extent, the Party seeking such information for regulatory or judicial purposes shall put forth its best efforts to protect the privileged or confidential status of such information, including promptly notifying the other Party that the information has been requested, and petitioning the applicable regulatory or judicial body for a protective order protecting the privileged or confidential status of the information. ARTICLE XVI MISCELLANEOUS 16.1. INTERPRETATION. In this Agreement: (a) unless otherwise specified, references to any Article, Section, Schedule or Exhibit are references to such Article, Section, Schedule or Exhibit of this Agreement; (b) the singular includes the plural and the plural includes the singular; (c) Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Ohio Power Company Original Sheet No. 38 Rate Schedule FERC No. 343 unless otherwise specified, each reference to a Governmental Requirement includes all provisions amending, modifying, supplementing or replacing such Governmental Requirement from time to time; (d) the words "including," "includes" and "include" shall be deemed to be followed by the words "without limitation"; (e) unless otherwise specified, each reference to any agreement includes all amendments, modifications, supplements, and restatements made to such agreement from time to time which are not prohibited by this Agreement; (f) the descriptive headings of the various Articles and Sections of this Agreement have been inserted for convenience of reference only and shall in no way modify or restrict the terms and provisions thereof; and (g) "herein," "hereof," "hereto" and "hereunder" and similar terms refer to this Agreement as a whole. 16.2. PARTIAL INVALIDITY. Wherever possible, each provision of this Agreement shall be interpreted in a manner as to be effective and valid under applicable law, but if any provision contained herein shall be found to be invalid, illegal, or unenforceable in any respect and for any reason, such provision shall be ineffective to the extent, but only to the extent, of such invalidity, illegality, or unenforceability without invalidating the remainder of the provision or any other provision of this Agreement, unless such a construction would be unreasonable. If such a construction would be unreasonable or would deprive a Party of a material benefit under this Agreement, the Parties shall seek to amend this Agreement to remove the invalid portion and otherwise provide the benefit, unless prohibited by law. 16.3. ASSIGNMENT. Any transfer or assignment by either Party of any or all rights, benefits or responsibilities under this Agreement shall not relieve the transferring Party of any responsibility Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Ohio Power Company Original Sheet No. 39 Rate Schedule FERC No. 343 under this Agreement unless the other Party so consents; provided, however, that consent to a release of an assigning Party's responsibilities shall not be unreasonably withheld. 16.4. SUCCESSORS INCLUDED. Reference to any individual, corporation, or other entity shall be deemed a reference to such individual, corporation, or other entity together with its successors and permitted assigns from time to time. 16.5. APPLICABLE LAWS, REGULATIONS, ORDERS, APPROVALS, AND PERMITS. This Agreement is made subject to all existing and future applicable Governmental Requirements, including federal, state, and local laws and to all existing and future duly promulgated orders or other duly authorized actions of governmental authorities having jurisdiction over the matters set forth in this Agreement. 16.6. CHOICE OF LAW AND JURISDICTION. The interpretation and performance of this Agreement shall be in accordance with the laws of the State of Ohio, excluding conflicts of law principles that would require the application of the laws of a different jurisdiction. 16.7. ENTIRE AGREEMENT. This Agreement supersedes all previous representations, understandings, negotiations, and agreements either written or oral between the Parties or their representatives with respect to the subject matter hereof, and constitutes the entire agreement of the Parties with respect to the subject matter hereof. 16.8. COUNTERPARTS TO THIS AGREEMENT. This Agreement may be executed in any number of counterparts, each of which shall be an original, but all of which together shall constitute one and the same instrument. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Ohio Power Company Original Sheet No. 40 Rate Schedule FERC No. 343 16.9. AMENDMENTS. It is contemplated by the Parties that it may be appropriate from time to time to change, amend, modify, or supplement this Agreement, including the Schedules and any other attachments that may be made a part of this Agreement, to reflect changes in operating practices or costs of operations or for other reasons. Any such changes to this Agreement shall be in writing executed by the Parties and, if appropriate, subject to approval or acceptance for filing by the FERC. 16.10. NOTICES. Unless otherwise provided in this Agreement, any notice, consent, or other communication required to be made under this Agreement shall be in writing and shall be delivered in person, by certified mail (postage prepaid, return receipt requested), or by nationally recognized overnight courier (charges prepaid), in each case properly addressed to such Party as shown below, or sent by facsimile transmission to the facsimile number indicated below. Any Party may from time to time change its address for the purposes of notices, consents, or other communications to that Party by a similar notice specifying a new address, but no such change shall become effective until it is actually received by the Party sought to be charged with its contents. All notices, consents, or other communications required or permitted under this Agreement that are addressed as provided in this Section 16.10 shall be deemed to have been given (a) upon delivery if delivered in person, given by overnight courier or certified mail, or (b) upon automatically generated confirmation if given by facsimile. OPCO: 1 Riverside Plaza Columbus, OH 43215 Telefacsimile Number: 614-223-2352 Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Ohio Power Company Original Sheet No. 41 Rate Schedule FERC No. 343 PMA: 1 Riverside Plaza Columbus, OH 43215 Telefacsimile Number: 614-324-5096 16.11. WAIVERS. The failure of either Party to enforce at any time any provision of this Agreement shall not be construed as a waiver of such provision. No such failure to enforce a provision shall affect in any way the validity of this Agreement or any portion thereof or the right of that Party thereafter to enforce each and every provision of this Agreement. To be effective, a waiver under this Agreement must be in writing and specifically state that it is a waiver. No waiver of any breach of this Agreement shall be held to constitute a waiver of any other or subsequent breach. 16.12. INDEPENDENT CONTRACTORS. OPCO and PMA are independent contractors. Nothing contained herein shall be deemed to create an association, joint venture, partnership or principal/agent relationship between OPCO and PMA hereto or impose any partnership obligation or liability on either of them. Neither OPCO nor PMA shall have any right, power or authority to enter into any agreement or commitment, act on behalf of or otherwise bind the other Party in any way. 16.13. NO THIRD PARTY BENEFICIARIES. Nothing in this Agreement, whether express or implied, is intended to confer any rights or remedies under or by reason of this Agreement on any persons other than the Parties and their respective permitted successors and permitted assigns. Nor is anything in this Agreement intended to relieve or discharge the obligation or liability of any third Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Ohio Power Company Original Sheet No. 42 Rate Schedule FERC No. 343 persons to either Party or give any third person any right of subrogation or action against either Party. 16.14. FURTHER ASSURANCES. If either Party determines in its reasonable discretion that any further instruments, assurances, or other things are necessary or desirable to carry out the terms of this Agreement, the other Party shall execute and deliver all such instruments or assurances, and do all things reasonably necessary or desirable to carry out the terms of this Agreement. 16.15. CONFIDENTIALITY. Each Party agrees that it will maintain in strictest confidence all documents, materials and other information marked "Confidential" or "Proprietary" by the disclosing Party ("Confidential Information") which it shall have obtained regarding another Party during the course of the negotiations leading to, and its performance of, this Agreement (whether obtained before or after the date of this Agreement). Each Party also agrees that it will maintain in strictest confidence, and treat as Confidential Information (whether marked "Confidential" or "Proprietary" or not) all non-public information regarding the condition or operation of any generating unit or plant that is the subject of this Agreement. Confidential Information shall not be communicated to any third person by a Party (other than to its affiliates, counsel, accountants, financial or tax advisors, or insurance consultants or in connection with its financing); PROVIDED that in the event the receiving Party is required by law, regulation or court order to disclose any Confidential Information, the receiving Party will promptly notify the disclosing Party in writing prior to making any such disclosure in order to facilitate the disclosing Party's seeking a protective order or other appropriate remedy from the proper authority and further PROVIDED that the receiving Party further agrees that if the disclosing Party ultimately discloses such Confidential Information to the requesting legal or regulatory body, it Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Ohio Power Company Original Sheet No. 43 Rate Schedule FERC No. 343 will furnish only that portion of the Confidential Information which is legally required and will exercise all reasonable efforts to obtain reliable assurances that confidential treatment will be accorded the Confidential Information. The obligations of nondisclosure and restricted use of Confidential Information shall survive the expiration or other termination of this Agreement until such obligations expire in accordance with their respective terms. 16.16 JOINT PREPARATION. This Agreement shall be deemed to have been jointly prepared by both Parties, and no ambiguity herein shall be construed for or against either Party based upon the identity of the author of this Agreement or any portion thereof. IN WITNESS WHEREOF, the Parties have executed this Agreement as of the date set forth at the beginning of this Agreement. OHIO POWER COMPANY By: -------------------------------------- POWER MARKETING AFFILIATE By: -------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Ohio Power Company Original Sheet No. 44 Rate Schedule FERC No. 343 SCHEDULE A OPCO GENERATING UNITS SUBJECT TO THIS AGREEMENT MAXIMUM DEPENDABLE END OF INITIAL RENEWAL NOTICE UNIT kW NET OUTPUT TERM DATE ---- ------------------ -------------- -------------- Amos 3* (2/3) 867 Cardinal 1 600 Gavin 1 1,300 Gavin 2 1,300 Kammer 1 210 Kammer 2 210 Kammer 3 210 Mitchell 1 800 Mitchell 2 800 Muskingum River 1 205 Muskingum River 2 205 Muskingum River 3 215 Muskingum River 4 215 Muskingum River 5 585 Sporn* 750 Conventional Hydro 48 Total 8,520 * indicates OPCO share of jointly-owned unit Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Ohio Power Company Original Sheet No. 45 Rate Schedule FERC No. 343 SCHEDULE B ------------------------------------------------------------------------------- Schedule B ------------------------------------------------------------------------------- Page 1 of 5 ------------------------------------------------------------------------------- UNIT POWER SALES AGREEMENT ------------------------------------------------------------------------------- CALCULATION OF MONTHLY POWER BILL ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- Line Component Reference Amount ------------------------------------------------------------------------------- 1. Return on Common Equity P.2, L.14 0 ------------------------------------------------------------------------------- 2. Return on Other Capital P.3, L.5 0 ------------------------------------------------------------------------------- 3. Net Operating Expenses P.4, L.8 0 ------------------------------------------------------------------------------- 4. Provision for Federal Income P.5, L.13 0 Taxes ------------------------------------------------------------------------------- 5. LESS: Revenue from sales to Wholesale Customers 0 ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- 6. Power Bill Amount (Current L.1 + L.2 + L.3 + L.4 - 0 Month) L.5 ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- 7. Prior Billing Adjustment ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- 8. Total Power Bill L.6 + L.7 ------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Ohio Power Company Original Sheet No. 46 Rate Schedule FERC No. 343 SCHEDULE B ------------------------------------------------------------------------------- Schedule B ------------------------------------------------------------------------------- Page 2 of 5 ------------------------------------------------------------------------------- UNIT POWER SALES AGREEMENT ------------------------------------------------------------------------------- CALCULATION OF MONTHLY RETURN ON COMMON EQUITY ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- Line Description Reference Prior Month Balance ------------------------------------------------------------------------------- 1. Long Term Debt FERC 221 - 226 0 ------------------------------------------------------------------------------- 2. Short Term Debt FERC 231, 233 0 ------------------------------------------------------------------------------- 3. Preferred Stock FERC 204-206 0 ------------------------------------------------------------------------------- 4. Common Equity FERC 201-203, 207- 0 218 ------------------------------------------------------------------------------- 5. LESS: Temporary Cash Investments FERC 124,134-136, 0 145 ------------------------------------------------------------------------------- 6. Total Capitalization L.1 + L.2 + L.3 + L.4 - 0 L.5 ------------------------------------------------------------------------------- 7. 40% of Capitalization L.6 X 40% 0 ------------------------------------------------------------------------------- 8. Lesser of CE or 40% of Cap Lesser of L.4 or L.7 0 ------------------------------------------------------------------------------- 9. X Monthly Equity Return Rate Annual Rate of 0.92500% 11.1%/12 ------------------------------------------------------------------------------- 10. Sub-Total L.8 X L.9 0 ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- PLUS: ------------------------------------------------------------------------------- 11. Common Equity exceeding 40% of cap L.4 - L.7 0 ------------------------------------------------------------------------------- 12. X Weighted Cost of Long and Short-Term Debt Outstanding ------------------------------------------------------------------------------- 13. Sub-Total L.11 X L.12 0 ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- 14. Common Equity Return L.10 + L.13 0 --------------------------------------------------------------------=========== Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Ohio Power Company Original Sheet No. 47 Rate Schedule FERC No. 343 SCHEDULE B ------------------------------------------------------------------------------- Schedule B ------------------------------------------------------------------------------- Page 3 of 5 ------------------------------------------------------------------------------- UNIT POWER SALES AGREEMENT ------------------------------------------------------------------------------- CALCULATION OF MONTHLY RETURN ON OTHER CAPITAL ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- Line Description Reference Prior Month Balance ------------------------------------------------------------------------------- 1. Interest Expense on Long Term Debt L. 8 0 ------------------------------------------------------------------------------- 2. PLUS: Interest Expense on Short Term Debt L. 11 0 ------------------------------------------------------------------------------- 3. Net Interest Expense L.1 + L.2 0 ------------------------------------------------------------------------------- 4. PLUS: Preferred Stock Dividend Requirement FERC 437 0 ------------------------------------------------------------------------------- 5. Return on Other Capital L.3 + L.4 0 -------------------------------------------------------------------============ ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- Net Interest Expense Calculation ------------------------------------------------------------------------------- 6. Long Term Debt Outstanding FERC 221-226 0 ------------------------------------------------------------------------------- 7. MULTIPLIED BY: Weighted Cost of Long Term Annual Rate/12 0 Debt ------------------------------------------------------------------------------- 8. Interest Expense on Long Term Debt L.6 X L.7 0 ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- 9. Short Term Debt Outstanding FERC 231, 233 0 ------------------------------------------------------------------------------- 10. MULTIPLIED BY: Weighted Cost of Short Term Annual Rate / 12 0 Debt ------------------------------------------------------------------------------- 11. Interest Expense on Short Term Debt L.9 X L.10 0 ------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Ohio Power Company Original Sheet No. 48 Rate Schedule FERC No. 343 SCHEDULE B ------------------------------------------------------------------------------- Schedule B ------------------------------------------------------------------------------- Page 4 of 5 ------------------------------------------------------------------------------- UNIT POWER SALES AGREEMENT ------------------------------------------------------------------------------- CALCULATION OF MONTHLY OPERATING EXPENSES ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- Line Description Reference Prior Month Charges ------------------------------------------------------------------------------- 1. Provision for Depreciation FERC 403 0 ------------------------------------------------------------------------------- 2. Provision for Amortization FERC 404-407 0 ------------------------------------------------------------------------------- 3. Operating and Maintenance FERC 500-935 0 Expense ------------------------------------------------------------------------------- 4. Taxes, other than FIT FERC 408, 409 0 ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- 5. Operating Expense L.1 + L.2 + L.3 + L.4 0 ------------------------------------------------------------------------------- 6. LESS: Operating Revenue FERC 440-456 (Note) ------------------------------------------------------------------------------- 7. PLUS: Other Income and FERC 412-426 0 Deductions ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- 8. Net Operating Expense L.5 - L.6 + L.7 0 ----------------------------------------------------------------------========= ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- Note: Does not include Revenue from PMA in a/c 454. ------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Ohio Power Company Original Sheet No. 49 Rate Schedule FERC No. 343 SCHEDULE B ------------------------------------------------------------------------------- Schedule B ------------------------------------------------------------------------------- Page 5 of 5 ------------------------------------------------------------------------------- UNIT POWER SALES AGREEMENT ------------------------------------------------------------------------------- CALCULATION OF FEDERAL INCOME TAXES ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- Line Description Reference Amount ------------------------------------------------------------------------------- 1. Return on Common Equity P.1, L.1 0 ------------------------------------------------------------------------------- 2. Return on Other Capital P.1, L.2 0 ------------------------------------------------------------------------------- 3. Total Return L.1 + L.2 0 ------------------------------------------------------------------------------- 4. PLUS: Deferred Federal Income Tax FERC 410-411 0 ------------------------------------------------------------------------------- 5. LESS: Interest Expense P.3, L.3 0 ------------------------------------------------------------------------------- 6. PLUS: Schedule M 0 ------------------------------------------------------------------------------- 7. Sub-Total L.3 + L.4 - L.5 + 0 L.6 ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- 8. MULTIPLIED BY: Gross-up FIT / (1 - FIT) ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- 9. Current Federal Income Tax L.7 X L.8 0 ------------------------------------------------------------------------------- 10. PLUS: Deferred Federal and State L.4 0 Income Tax ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- 11. Total Federal Income Tax - Current L.9 + L.10 0 Month ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- 12. True-up on Federal Income Tax from Prior Month ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- 13. Total Federal Income Tax L.11 + L.12 0 ------------------------------------------------------------------============= Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 ATTACHMENT 7 UNIT POWER SALES AGREEMENT BETWEEN COLUMBUS SOUTHERN POWER COMPANY AND POWER MARKETING AFFILIATE Columbus Southern Power Company Original Sheet No. 1 Rate Schedule FERC No. 342 UNIT POWER SALES AGREEMENT AMONG COLUMBUS SOUTHERN POWER COMPANY AND POWER MARKETING AFFILIATE Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Columbus Southern Power Company Original Sheet No. 2 Rate Schedule FERC No. 342 TABLE OF CONTENTS PAGE ARTICLE I DEFINITIONS ................................................8 ARTICLE II SALE AND PURCHASE OF UNIT POWER ...........................14 Section 2.1 Obligations of CSP and PMA ................................14 Section 2.2 Delivery ..................................................14 Section 2.3 Obligations Subject to Other Agreements ...................14 ARTICLE III TERM OF AGREEMENT .........................................14 Section 3.1 Effective Date ..........................................14 Section 3.2 Termination Date ........................................15 3.2.1 First Renewal Term .................................15 3.2.2 Second Renewal Term ................................16 ARTICLE IV CAPACITY ..................................................16 Section 4.1 Capacity ..................................................16 ARTICLE V SCHEDULING AND OPERATIONS .................................17 Section 5.1 Dispatch ..................................................17 Section 5.2 Forecasts .................................................17 Section 5.3 Operating Committee .......................................17 5.3.1 Operating Committee Responsibilities ................17 5.3.2 Operating Committee Meetings ........................19 5.3.3 Information for Use of the Operating Committee ......20 Section 5.4 Unit Commitment ...........................................20 Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Columbus Southern Power Company Original Sheet No. 3 Rate Schedule FERC No. 342 Section 5.5 Dispatch of Units ............................................20 ARTICLE VI COST COMPONENTS AND PAYMENT TERMS ............................20 Section 6.1 Cost Components ..............................................20 Section 6.2 Monthly Demand Charge ........................................21 Section 6.3 Monthly Operating Expense ....................................21 6.3.1 Amounts Paid by CSP for Third-Party Services ...........21 Section 6.4 Federal Income Tax ...........................................21 Section 6.5 FERC Fees ....................................................21 Section 6.6 Capital Repairs and Improvements .............................21 Section 6.7 Annual Budgeting Process .....................................22 ARTICLE VII BILLING AND PAYMENT ..........................................23 Section 7.1 Billing Procedure ............................................23 Section 7.2 Timeliness of Payment ........................................23 Section 7.3 Disputes and Adjustments of Invoices .........................23 Section 7.4 Applicable Interest Rate .....................................24 ARTICLE VIII TRANSMISSION SERVICES ........................................24 Section 8.1 Responsibilities .............................................24 ARTICLE IX INTERRUPTION AND CURTAILMENTS ................................25 Section 9.1 Scheduled Outages ............................................25 Section 9.2 Notification of Unscheduled Outages ..........................25 ARTICLE X FORCE MAJEURE ................................................25 Section 10.1 Definition ...................................................25 Section 10.2 Performance Excused ..........................................26 Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Columbus Southern Power Company Original Sheet No. 4 Rate Schedule FERC No. 342 Section 10.3 Strike Issues ............................................... 26 Section 10.4 Payments Not Excused ........................................ 26 ARTICLE XI DEFAULTS .................................................... 27 Section 11.1 Events of Default ........................................... 27 11.1.1 Bankruptcy ........................................... 27 11.1.2 Violation or Noncompliance with Governmental Requirement .......................................... 27 11.1.3 Failure to Perform ................................... 27 Section 11.2 Notice of Default and Opportunity to Cure ................... 27 Section 11.3 No Waiver ................................................... 28 Section 11.4 Dispute Resolution .......................................... 28 ARTICLE XII DISPUTE RESOLUTION .......................................... 28 Section 12.1 Presentation of Dispute ..................................... 28 Section 12.2 Inability of Operating Committee to Reach Agreement ......... 29 Section 12.3 Arbitration ................................................. 29 12.3.1 Commencement of Arbitration Proceeding ............... 29 12.3.2 Appointment of Arbitrator ............................ 29 12.3.3 Arbitration Proceedings .............................. 30 12.3.4 Authority of Arbitrator .............................. 30 12.3.5 Expenses and Costs ................................... 31 12.3.6 Location of Arbitration Proceedings .................. 31 12.3.7 Confidentiality ...................................... 31 12.3.8 FERC Jurisdiction Over Certain Disputes .............. 31 Section 12.4 Exclusive Means of Dispute Resolution ....................... 32 Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Columbus Southern Power Company Original Sheet No. 5 Rate Schedule FERC No. 342 ARTICLE XIII INDEMNIFICATION; LIMITATION OF LIABILITY .................... 33 Section 13.1 Responsibilities ............................................ 33 Section 13.2 Limitation of Liability ..................................... 33 Section 13.3 Limitation of Actions ....................................... 34 ARTICLE XIV REGULATORY REQUIREMENTS ..................................... 34 Section 14.1 Required Regulatory Approvals and Actions ................... 34 Section 14.2 Regulatory Review ........................................... 34 ARTICLE XV BOOKS AND RECORDS ........................................... 35 Section 15.1 Books and Records ........................................... 35 Section 15.2 Audits ...................................................... 35 Section 15.3 Cooperation in Connection with Regulatory and Judicial Proceedings ................................................. 35 ARTICLE XVI MISCELLANEOUS ............................................... 36 Section 16.1 Interpretation .............................................. 36 Section 16.2 Partial Invalidity .......................................... 36 Section 16.3 Assignment .................................................. 37 Section 16.4 Successors Included ......................................... 37 Section 16.5 Applicable Laws, Regulations, Orders, Approvals, and Permits ..................................................... 37 Section 16.6 Choice of Law and Jurisdiction .............................. 37 Section 16.7 Entire Agreement ............................................ 38 Section 16.8 Counterparts to this Agreement .............................. 38 Section 16.9 Amendments .................................................. 38 Section 16.10 Notices ..................................................... 38 Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Columbus Southern Power Company Original Sheet No. 6 Rate Schedule FERC No. 342 Section 16.11 Waivers .................................................... 39 Section 16.12 Independent Contractors .................................... 39 Section 16.13 No Third-Party Beneficiaries ............................... 40 Section 16.14 Further Assurances ......................................... 40 Section 16.15 Confidentiality ............................................ 40 Section 16.16 Joint Preparation .......................................... 41 SCHEDULE A CSP Generating Units Subject to This Agreement ............... 43 SCHEDULE B Calculation of Monthly Power Bill ............................ 44 SCHEDULE C CCD Agreements ............................................... 49 Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Columbus Southern Power Company Original Sheet No. 7 Rate Schedule FERC No. 342 UNIT POWER Sales AGREEMENT THIS UNIT POWER SALES AGREEMENT ("AGREEMENT") is made and entered into as of this __________________ day of __________________________________, 2001, by and among Columbus Southern Power Company ("CSP") and Power Marketing Affiliate ("PMA"). CSP and PMA are wholly-owned subsidiaries of American Electric Power Company, Inc. ("AEP"). W I T N E S S E T H WHEREAS, CSP is currently a vertically-integrated electric utility company providing electric service to retail customers located in its franchised service area in Ohio; WHEREAS, on July 6, 1999, Amended Substitute Senate Bill No. 3 ("Restructuring Act") became law in Ohio, mandating that CSP reorganize its corporate structure to separate its generation and power supply functions from its transmission and distribution functions; WHEREAS, in accordance with the Restructuring Act, CSP will become a generating and power supply company; WHEREAS, PMA is a subsidiary of AEP, and will dispatch and market AEP power supply resources not subject to cost-of-service regulation; Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Columbus Southern Power Company Original Sheet No. 8 Rate Schedule FERC No. 342 WHEREAS, CSP is willing to sell, and PMA is willing to purchase, CSP Generating Capacity and associated dispatched Energy, pursuant to the rates, terms and conditions set forth herein. NOW, THEREFORE, in consideration of the premises and mutual covenants set forth herein, the Parties agree as follows: ARTICLE I DEFINITIONS For purposes of this Agreement, the following terms shall have the following meanings. 1.1. "AGREEMENT" means this Unit Power Sales Agreement, including attachments, and any amendments thereto now or hereafter executed by the Parties. 1.2. "ALLIANCE RTO" means the Alliance Regional Transmission Organization. 1.3. "ANCILLARY SERVICES" means one or more of those services that are defined in the Applicable OATT as ancillary services. 1.4. "ANNUAL BUDGET" means the budget established for each Operating Year in accordance with Section 6.7. 1.5. "ANNUAL OPERATING PLAN" means the operating plan established for each Operating Year in accordance with Section 6.7. 1.6. "APPLICABLE OATT" means the Open Access Transmission Tariff filed with FERC by American Electric Power Service Corporation on behalf of CSP and certain of its affiliates in Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Columbus Southern Power Company Original Sheet No. 9 Rate Schedule FERC No. 342 accordance with FERC's Order No. 888 or the Open Access Transmission Tariff filed with FERC by the Alliance RTO, as either may be applicable to particular transmission service, or any successor transmission service tariff to either, including any such successor tariff of a regional transmission organization to which CSP transfers operating control or authority over its transmission facilities. 1.7. "AVAILABLE," when used to refer to capacity, means that such capacity is currently capable of being dispatched. 1.8. "AVAILABLE CAPACITY" means that portion of the CSP Generating Capacity that is currently Available. 1.9. "BANKRUPTCY" means a situation in which: (i) a Party files a voluntary petition in bankruptcy or is adjudicated as bankrupt or insolvent, or files any petition, answer or consent seeking any reorganization, arrangement, composition, readjustment, liquidation, dissolution or similar relief for itself under the present or future applicable federal, state or other statute or law relating to bankruptcy, insolvency or other relief for debtors, or seeks or consents to, or acquiesces in the appointment of, any trustee, receiver, conservator or liquidator of such Party or of all or any substantial part of such Party's properties (the term "acquiesces" as used in this definition, includes the failure to file a petition or motion to vacate or discharge any order, judgment or decree within fifteen (15) Days after entry of such order, judgment or decree); (ii) a court of competent jurisdiction enters an order, judgment or decree approving a petition filed against a Party seeking a reorganization, arrangement, composition, readjustment, liquidation, dissolution or similar relief under any present or future federal bankruptcy law or any other Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Columbus Southern Power Company Original Sheet No. 10 Rate Schedule FERC No. 342 present or future applicable federal, state or other statute or law relating to bankruptcy, insolvency or other relief for debtors, and such Party acquiesces in the entry of such order, judgment or decree or such order, judgment or decree remains unvacated and unstayed for an aggregate of sixty (60) Days, whether or not consecutive, after the date of entry thereof, or any trustee, receiver, conservator or liquidator of such Party or of all or any substantial part of its property is appointed without the consent or acquiescence of such Party and such appointment remains unvacated and unstayed for an aggregate of sixty (60) Days, whether or not consecutive; (iii) a Party admits in writing its inability to pay its debts as they mature; (iv) a Party gives notice to any federal or state governmental authority of insolvency or pending insolvency, or suspension or pending suspension of operations; or (v) a Party makes an assignment for the benefit of creditors or takes any other similar action for the protection or benefit of creditors. 1.10. "BUSINESS DAY" means any Day on which the Federal Reserve member banks are open for business. A Business Day shall commence at 8:00 a.m. and close at 5:00 p.m., local time, at the location of the relevant Party's principal place of business, or at such other location as the context may require. In the event that the location cannot be determined from context, CSP's principal place of business shall govern for purposes of application of the definition of "Business Day." 1.11. "CCD AGREEMENTS" means the agreements with respect to the CCD Units listed in Schedule C attached to this Agreement. 1.12. "CCD UNIT" means any one of the CCD Units. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Columbus Southern Power Company Original Sheet No. 11 Rate Schedule FERC No. 342 1.13. "CCD UNITS" means Beckjord Unit 6, Conesville Unit 4, Stuart Units 1 through 4 and the Zimmer Units. 1.14. "CSP GENERATING CAPACITY" means all of the capacity of the generating units listed in Schedule A, or in the case of the CCD Units, CSP's full share of capacity in such units, less the portion of the capacity of such units that is required by CSP to serve its wholesale customers, if any. As of the Effective Date of this Agreement, CSP's wholesale customers are the City of Glouster, Ohio, the City of Jackson, Ohio, and the City of Westerville, Ohio. 1.15. "DAY" means a period of twenty-four (24) consecutive hours, beginning at 12:00:01 a.m., local time, at the Delivery Points; provided, however, that on the Day on which Eastern Daylight Savings Time becomes effective, the period shall be twenty-three (23) consecutive hours, and on the Day on which Eastern Standard Time becomes effective, the period shall be twenty-five (25) consecutive hours. 1.16. "DELIVERY POINTS" means (i) in the case of each of the generating units listed in Schedule A, other than the CCD Units, the points at which such generating unit is connected to CSP's transmission facilities owned by an AEP affiliate, and (ii) in the case of each of the CCD Units listed in Schedule A, the delivery point identified for such unit in the CCD Agreements applicable to such unit. 1.17. "EFFECTIVE DATE" shall be the date set forth in the first paragraph of this Agreement. 1.18. "EMERGENCY" means (i) any abnormal system condition that requires immediate manual or automatic action to prevent loss of firm load, equipment damage, or tripping of system Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Columbus Southern Power Company Original Sheet No. 12 Rate Schedule FERC No. 342 elements that could adversely affect the reliability of CSP's electric system, and (ii) any existing or potential system condition on CSP's electric system that CSP determines, in the exercise of reasonable discretion, is not or will not be in conformance with applicable criteria. 1.19. "ENERGY" means the electric energy supplied under this Agreement, which shall be in the form of three-phase, alternating current at a frequency of 60 Hertz, with reasonable variations of frequency and voltage allowed consistent with Good Utility Practice. 1.20. "FERC" means the Federal Energy Regulatory Commission or any successor federal agency having regulatory jurisdiction over this Agreement. 1.21. "FIRST RENEWAL TERM" shall have the meaning set forth in Section 3.2.1 of this Agreement. 1.22. "GOOD UTILITY PRACTICE" means any of the practices, methods, and acts required, approved, or engaged in by a significant portion of the electric utility industry in the region where the generating units listed in Schedule A operate during the relevant time period, or any of the practices, methods, and acts which, in the exercise of reasonable judgment in light of the facts known at the time the decision was made, could have been expected to accomplish the desired result at the lowest reasonable cost consistent with good business practices, reliability, safety, and expedition. Good Utility Practice is not intended to be limited to the optimum practice, method, or act; rather, it is intended to be a spectrum of acceptable practices, methods, and acts. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Columbus Southern Power Company Original Sheet No. 13 Rate Schedule FERC No. 342 1.23. "GOVERNMENTAL REQUIREMENT" means any statute, law, regulation, ordinance, rule, exemption, or order of any federal, state, county, municipal or other governmental authority, any political subdivision of any of the foregoing, or any governmental, quasi-govermental, judicial, public or statutory instrumentality, authority, body or entity, including the final, non-appealable judicial or administrative interpretation of any such statute, law, regulation, ordinance, rule, exemption or order by any such authority, instrumentality, body, or entity. 1.24. "INITIAL TERM" shall have the meaning set forth in Section 3.2 of this Agreement. 1.25. "MONTH" means the period beginning at 12:00:01 a.m., local time, on the first Day of each calendar month and ending at midnight of the last Day of such calendar month. 1.26. "OHIO COMMISSION" means the Public Utilities Commission of Ohio, or any successor organization thereto. 1.27. "OPERATING YEAR" means (i) with respect to the year 2002, that period of time beginning on the later of January 1, 2002 and the date on which all required regulatory authorizations have been received, and ending on December 31, 2002; and (ii) with respect to subsequent years during the term of this Agreement, the calendar year commencing on January 1 and ending on December 31 or such earlier date in such calendar year on which this Agreement expires or is terminated. 1.28. "PARTIES" means CSP, PMA, and or the assignee or successor of any of their rights and obligations under this Agreement. "PARTY" means one of the Parties. 1.29. "SECOND RENEWAL TERM" shall have the meaning set forth in Section 3.2.2. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Columbus Southern Power Company Original Sheet No. 14 Rate Schedule FERC No. 342 ARTICLE II SALE AND PURCHASE OF UNIT POWER 2.1. OBLIGATIONS OF CSP AND PMA. CSP shall sell, and PMA shall purchase, the CSP Generating Capacity and all associated dispatched Energy. PMA shall have the right to designate a portion of the CSP Generating Capacity and associated dispatched Energy for ancillary services. 2.2. DELIVERY. CSP shall deliver Energy purchased by PMA from any of the generating units listed in Schedule A at the Delivery Point(s) for such generating unit. 2.3. OBLIGATIONS SUBJECT TO OTHER AGREEMENTS. Notwithstanding any other provision of this Agreement, CSP's obligations and PMA's rights under this Agreement with respect to the portion of the CSP Generating Capacity and associated Energy attributable to any of the CCD Units (including CSP's obligation to sell and otherwise make Available, and PMA's right to purchase, such portion of the CSP Generating Capacity and associated Energy) are conditioned upon, and subject to, the provisions of the CCD Agreements applicable to such unit. ARTICLE III TERM OF AGREEMENT 3.1. EFFECTIVE DATE. This Agreement shall be effective upon the Effective Date. PMA shall begin to purchase CSP Generating Capacity and Energy under this Agreement, and shall begin to dispatch its Available Capacity, on January 1, 2002, or on such later date as all required regulatory authorizations have been received. PMA shall have no obligation to purchase or to pay for any CSP Generating Capacity or Energy before January 1, 2002 or such later date as all Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Columbus Southern Power Company Original Sheet No. 15 Rate Schedule FERC No. 342 required regulatory authorizations have been received, or to reimburse CSP for any costs that CSP has expensed before that date. 3.2. TERMINATION DATE. Except for (a) termination following an Event of Default as provided in Section 11.1; (b) termination because of regulatory disapproval or regulatory changes as provided in Article XIV; or (c) termination pursuant to mutual agreement of CSP and PMA, this Agreement shall continue in effect with respect to each generating unit listed in Schedule A for an Initial Term ending on the date shown in Schedule A. 3.2.1. FIRST RENEWAL TERM. Not less than one (1) year before the end of the Initial Term with respect to each unit listed in Schedule A, PMA shall provide notice to CSP if it wishes to extend this Agreement as to that unit for a First Renewal Term. In the event that PMA elects to enter into a First Renewal Term, the Operating Committee shall retain a consultant, at PMA's expense, to provide an estimate of the remaining useful life of the subject unit as of the first day of the First Renewal Term. The length of the First Renewal Term shall be less than seventy-five percent (75%) of the estimated remaining useful life of the subject unit as of the first day of the First Renewal Term, expressed in months, and rounded down to the last full month before reaching seventy-five percent (75%) of that estimated remaining useful life. The date by which PMA must provide notice if it wishes to enter into the First Renewal Term with respect to each unit is listed in Schedule A. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Columbus Southern Power Company Original Sheet No. 16 Rate Schedule FERC No. 342 3.2.2. SECOND RENEWAL TERM. If PMA elects to extend the Agreement for the First Renewal Term with respect to any unit, then not less than one (1) year before the end of the First Renewal Term as to that unit, PNIA shall provide notice to CSP if it wishes to extend this Agreement for a Second Renewal Term as to that unit. In the event that PMA elects to enter into a Second Renewal Term, the Operating Committee shall retain a consultant, at PMA's expense, to provide an estimate of the remaining useful life of the subject unit as of the first day of the Second Renewal Term. The length of the Second Renewal Term shall be less than seventy-five percent (75%) of the estimated remaining useful life of the subject unit as of the first day of the Second Renewal Term, expressed in months, and rounded down to the last full month before reaching seventy-five percent (75%) of that estimated remaining useful life. This Agreement shall terminate as to each such unit at the conclusion of the Second Renewal Term. ARTICLE IV CAPACITY 4.1. CAPACITY. PMA shall have the right to Available Capacity and associated Energy from the CSP Generating Capacity in accordance with the terms of this Agreement. Subject to the terms of this Agreement, CSP Generating Capacity will be Available to PMA from each of the generating units listed in Schedule A to this Agreement or, in the case of the CCD Units, from CSP's share of such units as reflected in Schedule A, with respect to the capability of each such unit as that capability may change over time as determined by the Operating Committee. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Columbus Southern Power Company Original Sheet No. 17 Rate Schedule FERC No. 342 ARTICLE V SCHEDULING AND OPERATIONS 5.1. DISPATCH. PMA shall have the exclusive right to dispatch Energy and ancillary services from the Available Capacity. Subject to operational requirements established by the Operating Committee, CSP shall make the Available Capacity Available for PMA to dispatch at all times. 5.2. FORECASTS. CSP or its agent shall notify PMA on or before the fifteenth (15th) Day of each Month of the amount of Available Capacity and Energy expected to be Available from each of the generating units included in the CSP Generating Capacity in each of the next thirty-six (36) Months. In the event that the amount of Available Capacity or Energy forecast to be Available from any such generating unit(s) changes, CSP or its agent shall notify PMA as soon as it is feasible to do so. 5.3. OPERATING COMMITTEE. By written notice to the other Party, each Party shall name one representative ("Operating Representative") and one alternate to act for it in matters pertaining to operating arrangements under this Agreement. A Party may change its Operating Representative or alternate at any time by written notice to the other Party. The Operating Representatives for the respective Parties, or their alternates, shall comprise the Operating Committee. All decisions, directives, or other actions by the Operating Committee must be by unanimous agreement of the Operating Representatives of CSP and PMA. 5.3.1. OPERATING COMMITTEE RESPONSIBILITIES. The Operating Committee shall have the following responsibilities: Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Columbus Southern Power Company Original Sheet No. 18 Rate Schedule FERC No. 342 a. Review and approval of the Annual Budget and Annual Operating Plan described in Section 6.7. b. Establishment and review of procedures and systems for dispatch, notification of dispatch, and unit commitment under this agreement, including assurance that the units listed in Schedule A are dispatched at a sufficient level to provide CSP with such energy as it may require to serve its wholesale customers' requirements. c. Establishment and monitoring of procedures for communication and coordination with respect to unit capacity availability, fuel-firing options, and scheduling of the CSP Generating Capacity, including, subject to Section 9.1, scheduling of outages for maintenance, repairs, equipment replacements, scheduled inspections, and other foreseeable causes of outages at any generating unit, as well as the return of any unit to availability following an unplanned outage. d. Decisions on capital expenditures, including unit upgrades and repowering. e. Determinations as to changes in the unit capability of the generating units listed in Schedule A and decisions on unit retirement. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Columbus Southern Power Company Original Sheet No. 19 Rate Schedule FERC No. 342 f. Establishment and modification of billing procedures under this Agreement. g. Establishment of projected capacity costs for use in planning by the Parties. h. Specification of fuels, oversight of fuel inspection and certification procedures, procurement and delivery of fuel to each of the generating units listed in Schedule A, and management of fuel inventories. i. Establishment of, termination of, and approval of any change or amendment to operating arrangements with respect to any of the generating units listed in Schedule A. j. Dispute resolution as provided in Section 12.1. k. Review and approval of plans and procedures designed to insure compliance with any environmental law, regulation, ordinance or permit, including procedures for allocating and using emission allowances or for any programs that permit averaging at more than one unit for compliance. 1. Other duties as assigned by agreement of CSP and PMA. 5.3.2. OPERATING COMMITTEE MEETINGS. The Operating Committee shall meet at least quarterly, and at such other times as either Party may reasonably request. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Columbus Southern Power Company Original Sheet No. 20 Rate Schedule FERC No. 342 5.3.3. INFORMATION FOR USE OF THE OPERATING COMMITTEE. The Parties shall cooperate in providing to the Operating Committee the information it reasonably needs to carry out its duties, and to supplement or correct such information on a timely basis. 5.4. UNIT COMMITMENT. PMA will make an initial unit commitment for each of the generating units listed in Schedule A one (1) Business Day ahead of real-time dispatch, or, in the case of any of the CCD Units at such earlier time as required to comply with the provisions of any of the CCD Agreements applicable to such generating unit or the scheduling procedures established thereunder. 5.5. DISPATCH OF UNITS. Subject to operational requirements established by the Operating Committee and the operation of the generating units consistent with Good Utility Practice, any unit designated to be committed by PMA will be brought on line or kept on line. ARTICLE VI COST COMPONENTS AND PAYMENT TERMS 6.1. COST COMPONENTS. In return for CSP's sale to PMA of the CSP Generating Capacity and associated dispatched Energy under this Agreement, PMA will pay CSP a Demand Charge as provided in Section 6.2, PMA's share of Monthly Operating Expenses as provided in Section 6.3, and Federal Income Taxes attributable to PMA as provided in Section 6.4. In addition, PMA will pay CSP its share of any other costs approved by the Operating Committee and initially incurred by CSP. Pursuant to Article VII, CSP will bill PMA for those costs with respect to those items and services provided by or through CSP. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Columbus Southern Power Company Original Sheet No. 21 Rate Schedule FERC No. 342 6.2. MONTHLY DEMAND CHARGE. In the case of the generating units listed in Schedule A, PMA will pay a monthly Demand Charge for the CSP Generating Capacity equal to the sum of the Monthly Return on Common Equity and Monthly Return on Other Capital calculated in accordance with pages 2 and 3 of Schedule B to this Agreement. 6.3. MONTHLY OPERATING EXPENSES. In the case of the generating units listed in Schedule A, PMA will pay the Monthly Operating Expenses associated with the amount of Energy that it dispatches from each such generating unit in each Month calculated in accordance with page 4 of Schedule B. 6.3.1. AMOUNTS PAID BV CSP FOR THIRD-PARTY SERVICES. CSP shall be responsible to make all payments due to any service provider furnishing services to CSP at the generating units identified in Schedule A, even though the cost of such payments will be reflected in the share of Monthly Operating Expenses payable by PMA to CSP. 6.4. FEDERAL INCOME TAX. PMA will pay CSP a provision for Federal Income Tax each Month calculated in accordance with page 5 of Schedule B. 6.5. FERC FEES. PMA shall be responsible for any fees charged by FERC on the basis of the sales or transmission of capacity or energy at wholesale in interstate commerce. 6.6. CAPITAL REPAIRS AND IMPROVEMENTS. Capital repairs and improvements will be determined by the Operating Committee pursuant to the annual budgeting process set forth in Section 6.7. Expenditures for such capital repairs and improvements will initially be paid by Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Columbus Southern Power Company Original Sheet No. 22 Rate Schedule FERC No. 342 CSP, which shall include the costs of such capital repairs and improvements in calculating the Demand Charge pursuant to Section 6.2. 6.7. ANNUAL BUDGETING PROCESS. At least ninety (90) days before the start of each Operating Year, CSP shall submit to the Operating Committee a proposed Annual Budget with respect to its generating units listed in Schedule A, a proposed Annual Operating Plan with respect to those generating units, and an estimate and schedule of costs to be incurred for major maintenance or replacement items with respect to those generating units during the next six (6)-year period. The Annual Budget shall be presented on a Month-by-Month basis for each Month during the next Operating Year, and shall include an operating budget, a capital budget, an estimate of the cost of any major repairs that CSP anticipates will occur during such Operating Year with respect to the generating units listed in Schedule A, and an itemized estimate of all projected Monthly Operating Expenses relating to CSP's operation of those generating units during that Operating Year. The members of the Operating Committee will meet and work in good faith to agree upon the final Annual Budget and final Annual Operating Plan, and will also meet to discuss the information provided with respect to the CCD Agreements, including whether CSP should seek a modification in the budget or operating plans with respect to the capacity that is the subject of each of those agreements. Once approved, the Annual Budget and Annual Operating Plan shall remain in effect throughout the applicable Operating Year, subject to such changes, revisions, amendments, and updating as the Operating Committee may determine. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Columbus Southern Power Company Original Sheet No. 23 Rate Schedule FERC No. 342 ARTICLE VII BILLING AND PAYMENT 7.1. BILLING PROCEDURE. Unless otherwise specifically agreed upon by the Parties, the calendar month shall be the standard period for all payments under this Agreement. As soon as practicable after the end of each Month, CSP will render to PMA an invoice for the payment obligations, if any, incurred hereunder during the preceding Month. 7.2. TIMELINESS OF PAYMENT. Unless otherwise agreed by the Parties, all invoices under this Agreement shall be due and payable in accordance with CSP's invoice instructions on or before the later of the twentieth (20th) day of each Month, or tenth (10th) day after receipt of the invoice or, if such day is not a Business Day, then on the next Business Day. PMA will make payments by electronic funds transfer, or by other mutually agreeable method(s), to the account designated by CSP. Any amounts not paid by the due date will be deemed delinquent and will accrue interest at the interest rate specified in Section 7.4, such interest to be calculated from and including the due date to but excluding the date the delinquent amount is paid in full. 7.3. DISPUTES AND ADJUSTMENTS OF INVOICES. PMA may, in good faith, dispute the correctness of any invoice or any adjustment to an invoice, rendered under this Agreement, and CSP may adjust any invoice for any arithmetic or computational error within twelve (12) months of the date the invoice, or adjustment to an invoice, was rendered. In the event an invoice or portion thereof, or any other claim or adjustment arising hereunder, is disputed, PMA shall be required to make payment of the undisputed portion of the invoice when due, with notice of the objection given to CSP. Any invoice dispute or invoice adjustment shall be in writing and shall state the basis for the dispute or adjustment. Payment of the disputed amount shall not be Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Columbus Southern Power Company Original Sheet No. 24 Rate Schedule FERC No. 342 required until the dispute is resolved. Upon resolution of the dispute, any required payment shall be made within two (2) Business Days of such resolution along with interest accrued at the interest rate specified in Section 7.4 from and including the due date to but excluding the date paid. Inadvertent overpayments shall be returned upon request or deducted by CSP from subsequent payments, with interest accrued at the interest rate specified in Section 7.4 from and including the date of such overpayment to but excluding the date repaid or deducted by CSP. Any dispute with respect to an invoice is waived unless PMA notifies CSP in accordance with this Section 7.3 within twelve (12) months after the invoice is rendered or any specific adjustment to the invoice is made. If an invoice is not rendered within twelve (12) months after the close of the Month during which performance under this Agreement occurred, the right to payment for such performance is waived. 7.4. APPLICABLE INTEREST RATE. All interest calculations under this Agreement (other than interest included in calculating the monthly bill under Schedule B) shall use a rate per annum equal to the Federal Funds Rate (as published by the Board of Governors of the Federal Reserve System as from time to time in effect). Such interest shall be calculated on the basis of the actual number of Days elapsed over a year of three hundred sixty (360) Days. ARTICLE VIII TRANSMISSION SERVICES 8.1. RESPONSIBILITIES. PMA shall be responsible for arranging for transmission service and ancillary services for Energy dispatched from the Available Capacity from the Delivery Points, as provided in the Applicable OATT or other applicable tariffs. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Columbus Southern Power Company Original Sheet No. 25 Rate Schedule FERC No. 342 ARTICLE IX INTERRUPTION AND CURTAILMENTS 9.1. SCHEDULED OUTAGES. CSP and PMA shall jointly agree on the scheduling of outages for maintenance, repairs, equipment replacements, scheduled inspections, and other foreseeable cause of outages at any CSP generating unit listed in Schedule A, provided however, that in the case of any of the CCD Units, such scheduling shall be subject to the provisions of the CCD Agreements applicable to such unit. 9.2. NOTIFICATION OF UNSCHEDULED OUTAGES. CSP shall notify PMA as soon as is feasible of any unscheduled outage at any of CSP's generating units listed in Schedule A, including the anticipated duration of such unscheduled outage as soon as such duration can reasonably be estimated, and shall update such reports as new information becomes available, until all affected units have been restored to full service. ARTICLE X FORCE MAJEURE 10.1. DEFINITION. Force Majeure includes sabotage, strikes or other labor difficulties, riots, civil disturbances, acts of God, acts of public enemies, drought, earthquake, flood, explosion, fire, lightning, landslides, or similar cataclysmic event, or appropriation, diversion, or interruption of service under this Agreement by any court or governmental authority having jurisdiction thereof, or any other cause, whether of the kind enumerated herein or otherwise, that is beyond the reasonable control of, and without the fault or negligence of, the Party claiming Force Majeure. Economic hardship of any Party shall not constitute a Force Majeure event under this Agreement, including the loss of any market or the inability of PMA to economically Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Columbus Southern Power Company Original Sheet No. 26 Rate Schedule FERC No. 342 use or resell the CSP Generating Capacity or associated Energy. An event constituting force majeure, or otherwise excusing performance, under any of the CCD Agreements shall constitute a Force Majeure event under this Agreement with respect to the Parties' rights and obligations to the portion of the CSP Generating Capacity and associated Energy attributable to any of the CCD Units to which such CCD Agreement is applicable. 10.2. PERFORMANCE EXCUSED. If any Party is rendered wholly or partially unable to perform under this Agreement because of a Force Majeure event, that Party shall be excused from such obligations to the extent that the occurrence of the Force Majeure event prevents such Party's performance, provided that: (a) the non-performing Party promptly, but in no case longer than three (3) Business Days after the occurrence of the Force Majeure event, gives the other Party written notice describing in reasonable detail the nature of the Force Majeure event; (b) the suspension of performance shall be of no greater scope and of no longer duration than is reasonably required by the Force Majeure event; and (c) the non-performing Party used Good Utility Practice to remedy its inability to perform. 10.3. STRIKE ISSUES. No Party to this Agreement shall be required to settle a strike affecting it, except when, in its best judgment, such a settlement appears advisable. 10.4. PAYMENTS NOT EXCUSED. Nothing in this Article X shall excuse either CSP or PMA from making payment when due of the cost components set forth in Article VI or for any other amounts due under any provision of this Agreement. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Columbus Southern Power Company Original Sheet No. 27 Rate Schedule FERC No. 342 ARTICLE XI DEFAULTS 11.1. EVENTS OF DEFAULT. The following constitute Events of Default by a Party under this Agreement: 11.1.1. BANKRUPTCY. The Bankruptcy of either Party shall be an Event of Default by that Party. 11.1.2. VIOLATION OR NONCOMPLIANCE WITH GOVERNMENTAL REQUIREMENT. Violation or noncompliance with a Governmental Requirement by a Party or its agent shall be an Event of Default by that Party, if the violation or noncompliance has or may have a Material Adverse Effect on the non-defaulting Party with respect to its rights or obligations under this Agreement. For purposes of this Agreement, a "Material Adverse Effect" is any impact or effect that deprives a Party of all or a substantial portion of its reasonably expected benefits under this Agreement, whether directly or by increasing that Party's burdens or costs under this Agreement. 11.1.3. FAILURE TO PERFORM. The failure of a Party to perform a material obligation under this Agreement shall be an Event of Default by that Party. 11.2. NOTICE OF DEFAULT AND OPPORTUNITY TO CURE. Upon the occurrence of an Event of Default, the non-defaulting Party may deliver a written Notice of Default to the defaulting Party. Except for the event set forth in Section 11.1.1. for which the non-defaulting Party may terminate this. Agreement immediately, the Notice of Default shall begin the running of a cure period of Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Columbus Southern Power Company Original Sheet No. 28 Rate Schedule FERC No. 342 thirty (30) Days, at the end of which the non-defaulting Party may terminate this Agreement if the default has not been cured; provided, however, that if the default cannot reasonably be cured within said thirty (30)-day period and the defaulting Party shall have commenced to cure such failure within said period and shall thereafter proceed with reasonable diligence and good faith to cure such failure, then the cure period shall be extended for such longer period of time (but not more than ninety (90) days total, including the original thirty (30)-day period) as shall be necessary to accomplish such cure with all reasonable diligence (so long as such extended period will not cause an immediate Material Adverse Effect on the non-defaulting Party and provided further that the occurrence of any such immediate Material Adverse Effect shall terminate the extended period). 11.3. NO WAIVER. If a non-defaulting Party does not give the Notice of Default provided in Section 11.2, or does not terminate this Agreement after the running of the cure period, notwithstanding the failure of the defaulting Party to cure, in whole or in part, the default, the non-defaulting Party shall not waive any rights it has under this Agreement, including the right to give a new Notice of Default as to the uncured default. 11.4. DISPUTE RESOLUTION. Any dispute as to the application of this Article shall be resolved through the dispute resolution procedures provided in Article XII. ARTICLE XII DISPUTE RESOLUTION 12.1. PRESENTATION OF DISPUTE. If either Party believes that a dispute has arisen as to the meaning or application of this Agreement, it shall present that matter to the Operating Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Columbus Southern Power Company Original Sheet No. 29 Rate Schedule FERC No. 342 Committee in writing, and shall provide a copy of that writing to the other Party pursuant to the notice provisions of Section 16.10 of this Agreement. 12.2. INABILITY OF OPERATING COMMITTEE TO REACH AGREEMENT. If the Operating Committee is unable to reach agreement on any dispute within thirty (30) days after the dispute is presented to it, the matter shall be referred to the chief operating officers of the Parties for resolution in the manner that such individuals shall agree is appropriate; provided, however, that any Party involved in a dispute may invoke the arbitration provisions set forth in Section 12.3 at any time after the end of the thirty (30)-day period provided for the Operating Committee to reach agreement if the Operating Committee has not reached agreement. 12.3. ARBITRATION. 12.3.1. COMMENCEMENT OF ARBITRATION PROCEEDING. If the Parties are unable to resolve a dispute through the Operating Committee within thirty (30) days after the dispute is presented to the Operating Committee pursuant to Section 12.1, or through reference of the matter to the chief operating officers of the Parties pursuant to Section 12.2, either Party may commence arbitration proceedings by providing written notice to the other Party, detailing the nature of the dispute, designating the issue(s) to be arbitrated, identifying the provisions of this Agreement under which the dispute arose, and setting forth such Party's proposed resolution of such dispute. 12.3.2. APPOINTMENT OF ARBITRATOR. Within ten (10) days of the date of the notice of arbitration, a representative of each Party shall meet for the purpose of selecting Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Columbus Southern Power Company Original Sheet No. 30 Rate Schedule FERC No. 342 an arbitrator. If the Parties' representatives are unable to agree on an arbitrator within fifteen (15) days of the date of the notice of arbitration, then an arbitrator shall be selected in accordance with the procedures of the American Arbitration Association ("AAA"). Whether the arbitrator is selected by the Parties' representatives or in accordance with the procedures of the AAA, the arbitrator shall have the qualifications and experience in the occupation, profession, or discipline relevant to the subject matter of the dispute. 12.3.3. ARBITRATION PROCEEDINGS. Any arbitration proceeding shall be subject to the Federal Arbitration Act, 9 U.S.C. ss. ss. 1 ET SEQ. (1994), as it may be amended, or any successor enactment thereto, and shall be conducted in accordance with the commercial arbitration rules of the AAA in effect on the date of the notice to the extent not inconsistent with the provisions of this Article XII. 12.3.4. AUTHORITY OF ARBITRATOR. The arbitrator shall be bound by the provisions of this Agreement where applicable, and shall have no authority to modify any terms and conditions of this Agreement in any manner. The arbitrator shall render a decision resolving the dispute in an equitable manner, and may determine that monetary damages are due to a Party or may issue a directive that a Party take certain actions or refrain from taking certain actions, but shall not be authorized to order any other form of relief; provided, however, that nothing in this Article shall preclude the arbitrator from rendering a decision that adopts the resolution of the dispute proposed by a Party. Unless otherwise agreed to by the Parties, the arbitrator shall render a decision within one hundred twenty (120) days of Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Columbus Southern Power Company Original Sheet No. 31 Rate Schedule FERC No. 342 appointment, and shall notify the Parties to this Agreement in writing of such decision and the reasons supporting such decision. The decision of the arbitrator shall be final and binding upon the Parties, and any award may be enforced in any court of competent jurisdiction. 12.3.5. EXPENSES AND COSTS. The fees and expenses of the arbitrator shall be shared equally by the Parties, unless the arbitrator specifies a different allocation. All other expenses and costs of the arbitration proceeding shall be the responsibility of the Party incurring such expenses and costs. 12.3.6. LOCATION OF ARBITRATION PROCEEDINGS. Unless otherwise agreed by the Parties, any arbitration proceedings shall be conducted in Columbus, Ohio. 12.3.7. CONFIDENTIALITY. Except as provided in this Article, the existence, contents, or results of any arbitration proceeding under this Article may not be disclosed without the prior written consent of the Parties, provided, however, that any Party may make disclosures as may be required to fulfill regulatory obligations to any agencies having jurisdiction, and may inform its lenders, affiliates, auditors, and insurers, as necessary, under pledge of confidentiality, and may consult with expert consultants as required in connection with an arbitration proceeding under pledge of confidentiality. 12.3.8. FERC JURISDICTION OVER CERTAIN DISPUTES. Nothing in this Agreement shall be construed to preclude any Party from filing a petition or complaint with FERC with respect to any claim over which FERC has jurisdiction. In such case, the Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Columbus Southern Power Company Original Sheet No. 32 Rate Schedule FERC No. 342 other Party may request that FERC reject the petition or complaint or otherwise decline to exercise its jurisdiction. If FERC declines to act with respect to all or part of a claim, the portion of the claim not so accepted by FERC may be resolved through arbitration, as provided in this Article. To the extent that FERC asserts or accepts jurisdiction over all or part of a claim, the decisions, findings of fact, or orders of FERC shall be final and binding, subject to judicial review under the Federal Power Act, and any arbitration proceedings that may have commenced prior to the assertion or acceptance of jurisdiction by FERC shall be stayed, pending the outcome of the FERC proceedings. The arbitrator shall have no authority to modify, and shall be conclusively bound by, any decisions, findings of fact, or orders of FERC; provided, however, that to the extent that any decisions, findings of fact, or orders of FERC do not provide a final or complete remedy to a Party seeking relief, such Party may proceed to arbitration under this Article to secure such a remedy, subject to any FERC decisions, findings, or orders. 12.4. EXCLUSIVE MEANS OF DISPUTE RESOLUTION. The procedures set forth in this Article XII shall be the exclusive means for resolving disputes arising under this Agreement and shall survive this Agreement to the extent necessary to resolve any disputes pertaining to this Agreement. Except as provided in Sections 12.3.1 and 12.3.8, neither Party shall have the right to bring any dispute for resolution by a court, agency, or other entity having jurisdiction over this Agreement, unless both Parties agree in writing to such procedure. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Columbus Southern Power Company Original Sheet No. 33 Rate Schedule FERC No. 342 ARTICLE XIII INDEMNIFICATION; LIMITATION OF LIABILITY 13.1. RESPONSIBILITIES. Subject to Section 13.2, each Party shall indemnify and hold harmless the other Party and its owners, officers, directors, employers, representatives, and agents for, against, and from any claim, liability, damage, loss, or expenses of any kind or nature (including reasonable attorneys' fees) for any claims, suits, judgments, demands, actions, or liabilities, in each such instance to the extent determined to be attributed to the negligence, gross negligence, willful misconduct, or strict liability in tort or breach of this Agreement by the indemnitor or its owners, officers, directors, employers, representatives, and agents (it being the intention of the Parties that each Party is entitled to reciprocal and comparative indemnity). The provisions of this Section 13.1 shall survive the expiration or termination of this Agreement. 13.2. LIMITATION OF LIABILITY. FOR BREACH OF ANY PROVISION OF THIS AGREEMENT, A PARTY'S LIABILITY SHALL BE LIMITED TO DIRECT ACTUAL DAMAGES ONLY. SUCH DIRECT ACTUAL DAMAGES SHALL BE THE SOLE AND EXCLUSIVE REMEDY, AND ALL OTHER REMEDIES OR DAMAGES AT LAW OR IN EQUITY ARE WAIVED. UNLESS EXPRESSLY HEREIN PROVIDED, NO PARTY SHALL BE LIABLE FOR CONSEQUENTIAL, INCIDENTAL, PUNITIVE, EXEMPLARY, OR INDIRECT DAMAGES, LOST PROFITS OR OTHER BUSINESS INTERRUPTION DAMAGES, BY STATUTE, IN TORT OR CONTRACT, UNDER ANY INDEMNITY PROVISION OR OTHERWISE. IT IS THE INTENT OF THE PARTIES THAT THE LIMITATIONS HEREIN IMPOSED ON REMEDIES AND THE MEASURE OF DAMAGES BE WITHOUT REGARD TO THE CAUSE OR CAUSES RELATED THERETO, Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Columbus Southern Power Company Original Sheet No. 34 Rate Schedule FERC No. 342 INCLUDING THE NEGLIGENCE OF ANY PARTY, WHETHER SUCH NEGLIGENCE BE SOLE, JOINT OR CONCURRENT, OR ACTIVE OR PASSIVE. 13.3. LIMITATION OF ACTIONS. No Party shall present a claim under this Agreement for damages or other relief with respect to any action or omission of the other Party that occurred more than twenty-four (24) Months before the claim is asserted. With respect to billing disputes, any claim for reduction or increase must be presented within twelve (12) Months after the bill was rendered. ARTICLE XIV REGULATORY REQUIREMENTS 14.1. REQUIRED REGULATORY APPROVALS AND ACTIONS. In the event that any regulatory agency with jurisdiction to approve or disapprove this Agreement finally disapproves this Agreement, then the Agreement shall terminate on December 31, 2001 or the date of disapproval, whichever is later. No regulatory disapproval shall be final for purposes of terminating this Agreement until all motions for reconsideration or appeals of the disapproval letter have been decided and the time for any further appeal shall have elapsed without such further appeal having been noticed. 14.2. REGULATORY REVIEW. If, during review of this Agreement, any regulatory agency with jurisdiction and authority to do so orders the modification of any term or condition, or orders the alteration of any charge(s), or in any way conditions its approval of this Agreement, and either CSP or PMA determines that such order, action, or decision has or will have a Material Adverse Effect on it (as that term is defined in Section 11.1.2), CSP and PMA shall negotiate in good faith to agree on modified terms and conditions mutually agreeable to them that are consistent with such regulatory order, action, or decision and that preserve, to the maximum extent Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Columbus Southern Power Company Original Sheet No. 35 Rate Schedule FERC No. 342 possible, the balance of economic benefits and burdens previously created by this Agreement before the issuance of such regulatory order, action, or decision. ARTICLE XV BOOKS AND RECORDS 15.1. BOOKS AND RECORDS. CSP shall keep such books and records with respect to the costs of owning, operating, and maintaining or improving the generating units listed in Schedule A of which it is the sole owner and such other pertinent information under this Agreement as shall be required (a) to allow PMA to verify the accuracy of CSP's billing statements, and (b) to comply with FERC and other regulatory authority requirements. CSP shall endeavor in good faith to make available to PMA such similar information to which CSP has access under the CCD Agreements, to the extent permitted under such agreements. 15.2. AUDITS. PMA shall have the right, at its sole expense, upon reasonable notice and during normal Business Day hours, to examine CSP's books and records to the extent reasonably necessary to verify the accuracy of any statement, charge, or computation made pursuant to this Agreement, for a period of up to one (1) year after such statement, charge or computation has been supplied to PMA. 15.3. COOPERATION IN CONNECTION WITH REGULATORY AND JUDICIAL PROCEEDINGS. To the extent that any Party requires relevant information in the possession of another Party for regulatory or judicial purposes, the Party possessing such information shall cooperate with the other Party to provide the information required to satisfy the inquiry; provided, however, that a Party may deem any information in its possession to be privileged or confidential, and to this extent, the Party seeking such information for regulatory or judicial purposes shall put forth its best efforts Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Columbus Southern Power Company Original Sheet No. 36 Rate Schedule FERC No. 342 to protect the privileged or confidential status of such information, including promptly notifying the other Party that the information has been requested, and petitioning the applicable regulatory or judicial body for a protective order protecting the privileged or confidential status of the information. ARTICLE XVI MISCELLANEOUS 16.1. INTERPRETATION. In this Agreement: (a) unless otherwise specified, references to any Article, Section, Schedule or Exhibit are references to such Article, Section, Schedule or Exhibit of this Agreement; (b) the singular includes the plural and the plural includes the singular; (c) unless otherwise specified, each reference to a Governmental Requirement includes all provisions amending, modifying, supplementing or replacing such Governmental Requirement from time to time; (d) the words "including," "includes" and "include" shall be deemed to be followed by the words "without limitation"; (e) unless otherwise specified, each reference to any agreement includes all amendments, modifications, supplements, and restatements made to such agreement from time to time which are not prohibited by this Agreement; (f) the descriptive headings of the various Articles and Sections of this Agreement have been inserted for convenience of reference only and shall in no way modify or restrict the terms and provisions thereof, and (g) "herein," "hereof," "hereto" and "hereunder" and similar terms refer to this Agreement as a whole. 16.2. PARTIAL INVALIDITY. Wherever possible, each provision of this Agreement shall be interpreted in a manner as to be effective and valid under applicable law, but if any provision contained herein shall be found to be invalid, illegal, or unenforceable in any respect and for any Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Columbus Southern Power Company Original Sheet No. 37 Rate Schedule FERC No. 342 reason, such provision shall be ineffective to the extent, but only to the extent, of such invalidity, illegality, or unenforceability without invalidating the remainder of the provision or any other provision of this Agreement, unless such a construction would be unreasonable. If such a construction would be unreasonable or would deprive a Party of a material benefit under this Agreement, the Parties shall seek to amend this Agreement to remove the invalid portion and otherwise provide the benefit, unless prohibited by law. 16.3. ASSIGNMENT. Any transfer or assignment by either Party of any or all rights, benefits or responsibilities under this Agreement shall not relieve the transferring Party of any responsibility under this Agreement unless the other Party so consents; provided, however, that consent to a release of an assigning Party's responsibilities shall not be unreasonably withheld. 16.4. SUCCESSORS INCLUDED. Reference to any individual, corporation, or other entity shall be deemed a reference to such individual, corporation, or other entity together with its successors and permitted assigns from time to time. 16.5. APPLICABLE LAWS, REGULATIONS, ORDERS, APPROVALS, AND PERMITS. This Agreement is made subject to all existing and future applicable Governmental Requirements, including federal, state, and local laws and to all existing and future duly promulgated orders or other duly authorized actions of governmental authorities having jurisdiction over the matters set forth in this Agreement. 16.6. CHOICE OF LAW AND JURISDICTION. The interpretation and performance of this Agreement shall be in accordance with the laws of the State of Ohio, excluding conflicts of law principles that would require the application of the laws of a different jurisdiction. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Columbus Southern Power Company Original Sheet No. 38 Rate Schedule FERC No. 342 16.7. ENTIRE AGREEMENT. This Agreement supersedes all previous representations, understandings, negotiations, and agreements either written or oral between the Parties or their representatives with respect to the subject matter hereof, and constitutes the entire agreement of the Parties with respect to the subject matter hereof. 16.8. COUNTERPARTS TO THIS AGREEMENT. This Agreement may be executed in any number of counterparts, each of which shall be an original, but all of which together shall constitute one and the same instrument. 16.9. AMENDMENTS. It is contemplated by the Parties that it may be appropriate from time to time to change, amend, modify, or supplement this Agreement, including the Schedules and any other attachments that may be made a part of this Agreement, to reflect changes in operating practices or costs of operations or for other reasons. Any such changes to this Agreement shall be in writing executed by the Parties and, if appropriate, subject to approval or acceptance for filing by the FERC. 16.10. NOTICES. Unless otherwise provided in this Agreement, any notice, consent, or other communication required to be made under this Agreement shall be in writing and shall be delivered in person, by certified mail (postage prepaid, return receipt requested), or by nationally recognized overnight courier (charges prepaid), in each case properly addressed to such Party as shown below, or sent by facsimile transmission to the facsimile number indicated below. Any Party may from time to time change its address for the purposes of notices, consents, or other communications to that Party by a similar notice specifying a new address, but no such change shall become effective until it is actually received by the Party sought to be charged with its Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Columbus Southern Power Company Original Sheet No. 39 Rate Schedule FERC No. 342 contents. All notices, consents, or other communications required or permitted under this Agreement that are addressed as provided in this Section 16.10 shall be deemed to have been given (a) upon delivery if delivered in person, given by overnight courier or certified mail, or (b) upon automatically generated confirmation if given by facsimile. CSP: Columbus Southern Power Company 1 Riverside Plaza Columbus, OH 43215 Telefacsimile number: 614-223-2352 PMA: Power Marketing Affiliate 1 Riverside Plaza Columbus, OH 43215 Telefacsimile number: 614-324-5096 16.11. WAIVERS. The failure of either Party to enforce at any time any provision of this Agreement shall not be construed as a waiver of such provision. No such failure to enforce a provision shall affect in any way the validity of this Agreement or any portion thereof or the right of that Party thereafter to enforce each and every provision of this Agreement. To be effective, a waiver under this Agreement must be in writing and specifically state that it is a waiver. No waiver of any breach of this Agreement shall be held to constitute a waiver of any other or subsequent breach. 16.12. INDEPENDENT CONTRACTORS. CSP and PMA are independent contractors. Nothing contained herein shall be deemed to create an association, joint venture, partnership or principal/agent relationship between CSP and PMA hereto or impose any partnership obligation Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Columbus Southern Power Company Original Sheet No. 40 Rate Schedule FERC No. 342 or liability on either of them. Neither CSP nor PMA shall have any right, power or authority to enter into any agreement or commitment, act on behalf of or otherwise bind the other Party in any way 16.13. NO THIRD-PARTY BENEFICIARIES. Nothing in this Agreement, whether express or implied, is intended to confer any rights or remedies under or by reason of this Agreement on any persons other than the Parties and their respective permitted successors and permitted assigns. Nor is anything in this Agreement intended to relieve or discharge the obligation or liability of any third persons to either Party or give any third person any right of subrogation or action against either Party. 16.14. FURTHER ASSURANCES. If either Party determines in its reasonable discretion that any further instruments, assurances, or other things are necessary or desirable to carry out the terms of this Agreement, the other Party shall execute and deliver all such instruments or assurances, and do all things reasonably necessary or desirable to carry out the terms of this Agreement. 16.15. CONFIDENTIALITY. Each Party agrees that it will maintain in strictest confidence all documents, materials and other information marked "Confidential" or "Proprietary" by the disclosing Party ("Confidential Information") which it shall have obtained regarding another Party during the course of the negotiations leading to, and its performance of, this Agreement (whether obtained before or after the date of this Agreement). Each Party also agrees that it will maintain in strictest confidence, and treat as Confidential Information (whether marked "Confidential" or "Proprietary" or not) all non-public information regarding the condition or operation of any generating unit or plant that is the subject of this Agreement. Confidential Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Columbus Southern Power Company Original Sheet No. 41 Rate Schedule FERC No. 342 Information shall not be communicated to any third person by a Party (other than to its affiliates, counsel, accountants, financial or tax advisors, or insurance consultants or in connection with its financing); PROVIDED that in the event the receiving Party is required by law, regulation or court order to disclose any Confidential Information, the receiving Party will promptly notify the disclosing Party in writing prior to making any such disclosure in order to facilitate the disclosing Party's seeking a protective order or other appropriate remedy from the proper authority and further PROVIDED that the receiving Party further agrees that if the disclosing Party ultimately discloses such Confidential Information to the requesting legal or regulatory body, it will furnish only that portion of the Confidential Information which is legally required and will exercise all reasonable efforts to obtain reliable assurances that confidential treatment will be accorded the Confidential Information. The obligations of nondisclosure and restricted use of Confidential Information shall survive the expiration or other termination of this Agreement until such obligations expire in accordance with their respective terms. 16.16. JOINT PREPARATION. This Agreement shall be deemed to have been jointly prepared by both Parties, and no ambiguity herein shall be construed for or against either Party based upon the identity of the author of this Agreement or any portion thereof. IN WITNESS WHEREOF, the Parties have executed this Agreement as of the date set forth at the beginning of this Agreement. COLUMBUS SOUTHERN POWER COMPANY By: ---------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Columbus Southern Power Company Original Sheet No. 42 Rate Schedule FERC No. 342 POWER MARKETING AFFILIATE By: ---------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Columbus Southern Power Company Original Sheet No. 43 Rate Schedule FERC No. 342 SCHEDULE A CSP GENERATING UNITS SUBJECT TO THIS AGREEMENT ---------------------------------------------- MAXIMUM DEPENDABLE END OF RENEWAL UNIT kW NET OUTPUT INITIAL TERM NOTICE DATE ---- ------------------ ------------ ----------- Beckjord* 53 Conesville 1 125 Conesville 2 125 Conesville 3 165 Conesville 4* 339 Conesville 5 375 Conesville 6 375 Picway 100 Stuart 1 152 Stuart 2* 152 Stuart 3* 152 Stuart 4* 152 Zimmer* 330 Total 2,595 * indicates CSP share of jointly-owned unit Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Columbus Southern Power Company Original Sheet No. 44 Rate Schedule FERC No. 342 SCHEDULE B ------------------------------------------------------------------------------- Schedule B ------------------------------------------------------------------------------- Page 1 of 5 ------------------------------------------------------------------------------- UNIT POWER SALES AGREEMENT ------------------------------------------------------------------------------- CALCULATION OF MONTHLY POWER BILL ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- Line Component Reference Amount ------------------------------------------------------------------------------- 1. Return on Common Equity P.2, L.14 0 ------------------------------------------------------------------------------- 2. Return on Other Capital P.3, L.5 0 ------------------------------------------------------------------------------- 3. Net Operating Expenses P.4, L.8 0 ------------------------------------------------------------------------------- 4. Provision for Federal Income P.5, L.13 0 Taxes ------------------------------------------------------------------------------- 5. LESS: Revenue from sales to Wholesale Customers 0 ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- 6. Power Bill Amount (Current L.1 + L.2 + L.3 + L.4 - 0 Month) L.5 ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- 7. Prior Billing Adjustment ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- 8. Total Power Bill L.6 + L.7 ----------------------------------------------------------------------========= Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Columbus Southern Power Company Original Sheet No. 45 Rate Schedule FERC No. 342 SCHEDULE B ------------------------------------------------------------------------------- Schedule B ------------------------------------------------------------------------------- Page 2 of 5 ------------------------------------------------------------------------------- UNIT POWER SALES AGREEMENT ------------------------------------------------------------------------------- CALCULATION OF MONTHLY RETURN ON COMMON EQUITY ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- Line Description Reference Prior Month Balance ------------------------------------------------------------------------------- 1. Long Term Debt FERC 221-226 0 ------------------------------------------------------------------------------- 2. Short Term Debt FERC 231, 233 0 ------------------------------------------------------------------------------- 3. Preferred Stock FERC 204-206 0 ------------------------------------------------------------------------------- 4. Common Equity FERC 201-203, 207- 0 218 ------------------------------------------------------------------------------- 5. LESS: Temporary Cash Investments FERC 124,134-136, 0 145 ------------------------------------------------------------------------------- 6. Total Capitalization L.1 + L.2 + L.3 + L.4 - 0 L.5 ------------------------------------------------------------------------------- 7. 40% of Capitalization L.6 X 40% 0 ------------------------------------------------------------------------------- 8. Lesser of CE or 40% of Cap Lesser of L.4 or L.7 0 ------------------------------------------------------------------------------- 9. X Monthly Equity Return Rate Annual Rate of 0.92500% 11.1%/12 ------------------------------------------------------------------------------- 10. Sub-Total L.8 X L.9 0 ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- PLUS: ------------------------------------------------------------------------------- 11. Common Equity exceeding 40% of cap L.4 - L.7 0 ------------------------------------------------------------------------------- 12. X Weighted Cost of Long and Short-Term Debt Outstanding ------------------------------------------------------------------------------- 13. Sub-Total L.11 X L.12 0 ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- 14. Common Equity Return L.10 + L.13 0 --------------------------------------------------------------------=========== Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Columbus Southern Power Company Original Sheet No. 46 Rate Schedule FERC No. 342 SCHEDULE B ------------------------------------------------------------------------------- Schedule B ------------------------------------------------------------------------------- Page 3 of 5 ------------------------------------------------------------------------------- UNIT POWER SALES AGREEMENT ------------------------------------------------------------------------------- CALCULATION OF MONTHLY RETURN ON OTHER CAPITAL ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- Line Description Reference Prior Month Balance ------------------------------------------------------------------------------- 1. Interest Expense on Long Term Debt L.8 0 ------------------------------------------------------------------------------- 2. PLUS: Interest Expense on Short Term Debt L.11 0 ------------------------------------------------------------------------------- 3. Net Interest Expense L.1 + L.2 0 ------------------------------------------------------------------------------- 4. PLUS: Preferred Stock Dividend Requirement FERC 437 0 ------------------------------------------------------------------------------- 5. Return on Other Capital L.3 + L.4 0 -------------------------------------------------------------------============ ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- Net Interest Expense Calculation ------------------------------------------------------------------------------- 6. Long Term Debt Outstanding FERC 221-226 0 ------------------------------------------------------------------------------- 7. MULTIPLIED BY: Weighted Cost of Long Term Annual Rate / 12 0 Debt ------------------------------------------------------------------------------- 8. Interest Expense on Long Term Debt L.6 X L.7 0 ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- 9. Short Term Debt Outstanding FERC 231, 233 0 ------------------------------------------------------------------------------- 10. MULTIPLIED BY: Weighted Cost of Short Term Annual Rate / 12 0 Debt ------------------------------------------------------------------------------- 11. Interest Expense on Short Term Debt L.9 X L.10 ------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Columbus Southern Power Company Original Sheet No. 47 Rate Schedule FERC No. 342 SCHEDULE B ------------------------------------------------------------------------------- Schedule B ------------------------------------------------------------------------------- Page 4 of 5 ------------------------------------------------------------------------------- UNIT POWER SALES AGREEMENT ------------------------------------------------------------------------------- CALCULATION OF MONTHLY OPERATING EXPENSES ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- Line Description Reference Prior Month Charges ------------------------------------------------------------------------------- 1. Provision for Depreciation FERC 403 0 ------------------------------------------------------------------------------- 2. Provision for Amortization FERC 404-407 0 ------------------------------------------------------------------------------- 3. Operating and Maintenance FERC 500-935 0 Expense ------------------------------------------------------------------------------- 4. Taxes, other than FIT FERC 408, 409 0 ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- 5. Operating Expense L.1 + L.2 + L.3 + L.4 0 ------------------------------------------------------------------------------- 6. LESS: Operating Revenue FERC 440-456 (Note) ------------------------------------------------------------------------------- 7. PLUS: Other Income and FERC 412-426 0 Deductions ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- 8. Net Operating Expense L.5 - L.6 + L.7 0 ----------------------------------------------------------------------========= ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- Note: Does not include Revenue from PMA in a/c 454. ------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Columbus Southern Power Company Original Sheet No. 48 Rate Schedule FERC No. 342 SCHEDULE B ------------------------------------------------------------------------------- Schedule B ------------------------------------------------------------------------------- Page 5 of 5 ------------------------------------------------------------------------------- UNIT POWER SALES AGREEMENT ------------------------------------------------------------------------------- CALCULATION OF FEDERAL INCOME TAXES ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- Line Description Reference Amount ------------------------------------------------------------------------------- 1. Return on Common Equity P.1, L.1 0 ------------------------------------------------------------------------------- 2. Return on Other Capital P.1, L.2 0 ------------------------------------------------------------------------------- 3. Total Return L.1 + L.2 0 ------------------------------------------------------------------------------- 4. PLUS: Deferred Federal Income Tax FERC 410-411 0 ------------------------------------------------------------------------------- 5. LESS: Interest Expense P.3, L.3 0 ------------------------------------------------------------------------------- 6. PLUS: Schedule M 0 ------------------------------------------------------------------------------- 7. Sub-Total L.3 + L.4 - L.5 + 0 L.6 ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- 8. MULTIPLIED BY: Gross-up FIT / (1 - FIT) ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- 9. Current Federal Income Tax L.7 X L.8 0 ------------------------------------------------------------------------------- 10. PLUS: Deferred Federal and State L.4 0 Income Tax ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- 11. Total Federal Income Tax - Current L.9 + L.10 0 Month ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- 12. True-up on Federal Income Tax from Prior Month ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- 13. Total Federal Income Tax L.11 + L.12 0 ------------------------------------------------------------------============= Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Columbus Southern Power Company Original Sheet No. 49 Rate Schedule FERC No. 342 SCHEDULE C CCD AGREEMENTS (Each of the following agreements shall be as amended and supplemented from time to time.) BECKJORD UNIT 6 o Amended Basic Generating Agreement Re: Unit 6, Walter C. Beckjord Station, dated as of December 29, 1964, between The Cincinnati Gas and Electric Company ("Cincinnati"), Columbus and Southern Ohio Electric Company ("Columbus") and the Dayton Power and Light Company ("Dayton"). o Unit 6 Walter C. Beckjord Station Operation Agreement, dated as of February 26, 1968, among Cincinnati, Columbus, and Dayton. o Basic Transmission Agreement Re Beckjord-Greene Line, dated as of October 1, 1964, between Cincinnati, Dayton and Columbus. CONESVILLE UNIT 4: o Recommendation and Agreement, dated January 8, 1971, between Cincinnati, Columbus and Dayton with respect to Conesville Unit 4. o Conesville Station Basic Generating Agreement, dated as of July 1, 1970, between Cincinnati, Columbus, and Dayton. o Unit 4 Conesville Station Operation Agreement, dated as of May 30, 1973, among Cincinnati, Columbus and Dayton. o Basic Transmission Agreement No. 3 (Conesville Unit 4 Transmission), dated as of March 1, 1973, between Cincinnati, Columbus, and Dayton. STUART UNITS 1 - 4: o Stuart Station Basic Generating Agreement, dated as of December 29, 1966, between Cincinnati, Columbus and Dayton. o J. M. Stuart Electric Generating Station Operation Agreement, dated as of June 1, 1969, among Cincinnati, Columbus and Dayton. o Basic Transmission Agreement No. 2, dated as of December 29, 1966, between Cincinnati, Columbus and Dayton. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 Columbus Southern Power Company Original Sheet No. 50 Rate Schedule FERC No. 342 ZIMMER: o Basic Generating Agreement Re: Wm. H. Zimmer Nuclear Power Station, dated as of August 29, 1969, among Cincinnati, Columbus and Dayton. o Wm. H. Zimmer Unit 1 Operation Agreement, dated as of February 22, 1979, among Cincinnati, Columbus and Dayton. o Basic Transmission Agreement No. 4 (Zimmer Transmission), dated as of January 1, 1982, between Cincinnati, Columbus and Dayton. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on: July 24, 2001 ATTACHMENT 8 SPORN OPERATING AGREEMENT Appalachian Power Company Original Sheet No. 1 Rate Schedule FERC No. 351 -------------------------------------------------------------------------------- OPERATING AGREEMENT For PHILIP SPORN PLANT APPALACHIAN POWER COMPANY OHIO POWER COMPANY and AMERICAN ELECTRIC POWER SERVICE CORPORATION, AS AGENT DATED: ___________ -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Appalachian Power Company Original Sheet No. 2 Rate Schedule FERC No. 351 -------------------------------------------------------------------------------- THIS OPERATING AGREEMENT ("Agreement") dated as of____________________ between Appalachian Power Company ("Appalachian"), d/b/a American Electric Power, a Virginia corporation qualified as a foreign corporation in West Virginia; Ohio Power Company ("Ohio"), an Ohio corporation qualified as a foreign corporation in West Virginia (collectively hereinafter sometimes referred to as the "Owners"); and American Electric Power Service Corporation ("Agent"), a New York corporation qualified as a foreign corporation in West Virginia. WITNESSETH: WHEREAS, Appalachian owns two 150,000 kilowatt generating units ("Sporn Unit Nos. 1 and 3") at the Philip Sporn Plant ("Sporn Plant") located along the Ohio River near New Haven, West Virginia, and Ohio owns two 150,000 kilowatt generating units and one 450,000 kilowatt generating unit ("Sporn Unit Nos. 2, 4 and 5") at the Sporn Plant; and WHEREAS, the Owners desire that Appalachian operate and maintain the Sporn Plant in accordance with the provisions hereof, effective January 1, 2002 or such other date as authorized by the Federal Energy Regulatory Commission ("FERC"); and WHEREAS, the Owners are subsidiaries of American Electric Power Company, Inc., the parent company of an integrated public utility holding company system, and use the services of the Agent (an affiliated company engaged solely in the business of furnishing essential services to the Owners and to other affiliated companies), as outlined in the Restated and Amended Interconnection Agreement, dated as of even or approximately even date herewith, by and between Appalachian, Kentucky Power Company, Indiana Michigan Power Company, and the Agent. -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Appalachian Power Company Original Sheet No. 3 Rate Schedule FERC No. 351 -------------------------------------------------------------------------------- NOW, THEREFORE, in consideration of the premises and for the purposes hereinabove recited, and in consideration of the mutual covenants hereinafter contained, the signatories agree as follows: ARTICLE ONE FUNCTIONS OF APPALACHIAN AND ITS AGENT 1.1 Appalachian and its Agent shall operate and maintain the Sporn Plant in accordance with good utility practice consistent with procedures employed by Appalachian and Ohio at their other generating stations, and in conformity with the terms and conditions of this Agreement. 1.2 Appalachian and its Agent shall keep all necessary books of record, books of account and memoranda of all transactions involving the Sporn Plant, and shall make computations and allocations on behalf of the Owners, as required under this Agreement. The books of record, books of account and memoranda shall be kept by Appalachian and its Agent in such manner as to conform, where so required, to the Uniform System of Accounts prescribed by the FERC for Public Utilities and Licensees ("Uniform System of Accounts"), and to the rules and regulations of other regulatory bodies having jurisdiction as they may from time to time be in effect. 1.3 The Owners may establish such joint bank accounts as may from time to time be appropriate. 1.4 As soon as practicable after the end of each month, Appalachian and its Agent shall furnish to Ohio a statement setting forth the dollar amounts associated with the operation and maintenance of the Sporn Plant applicable to Appalachian and Ohio for such month. -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Appalachian Power Company Original Sheet No. 4 Rate Schedule FERC No. 351 -------------------------------------------------------------------------------- The Owners shall, on a timely basis, deposit sufficient dollar amounts in the appropriate bank accounts to cover their respective costs. 1.5 Appalachian and its Agent may obtain such materials, labor and other services as it considers necessary in connection with the performance of the functions to be performed by it hereunder from such sources or through such persons as it may designate. ARTICLE TWO APPORTIONMENT OF CAPACITY AND ENERGY 2.1 Each Owner shall have the primary right to demand and use at any and all times the entire available kilowatt output capacity of the units it owns at the Sporn Plant and the electric energy associated with such capacity so demanded and used. ARTICLE THREE ADDITIONS, REPLACEMENTS AND RENEWALS 3.1 Installation of additional facilities or replacement of existing facilities with other facilities may at any time or from time to time be made by either Owner on its side of the median line and the Owner making such installation or replacement shall pay the entire cost thereof and shall be vested with absolute title thereto; provided, however, that if the units of the Sporn Plant are being operated together as a single station at the time such installation or replacement is made, all features of such installation or replacement which may affect the satisfactory, economical and/or safe operation of the Sporn Plant as a whole and all items which involve capital expenditures which cannot be performed under previously obtained authorizations from the other Owner shall be submitted in writing to -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Appalachian Power Company Original Sheet No. 5 Rate Schedule FERC No. 351 -------------------------------------------------------------------------------- the other Owner for approval by such Owner before such installation or replacement is made. 3.2 If any such installation or replacement requires structures or facilities to be installed upon the property of the other Owner, such other Owner shall grant any necessary easements for the structures or facilities which do not interfere with the use or development of its own units, and, if such structures or facilities are incorporated subsequently into an installation or replacement or its own, it shall purchase them at their book value. 3.3 The cost of new jointly-owned property and the costs incurred in installing any such new jointly-owned property shall be apportioned between the Owners based upon the ratio of each Owner's capacity in the units it owns at the Sporn Plant to the sum of the capacity of all of the units at the Sporn Plant. Additions to existing jointly-owned property and replacements of sections or components of existing jointly-owned property shall be apportioned based upon the Owners' historical ownership interests in such jointly-owned property. ARTICLE FOUR WORKING CAPITAL REQUIREMENTS 4.1 Appalachian and Ohio shall periodically mutually determine the amount of funds required for use as working capital in meeting payrolls and other expenses incurred in the operation and maintenance of Sporn Plant and in buying materials and supplies (inclusive of fuel) for Sporn Plant. 4.2 Appalachian and Ohio shall from time to time provide their share of working capital requirements in respective amounts proportionate to the ratio of each Owner's capacity in -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Appalachian Power Company Original Sheet No. 6 Rate Schedule FERC No. 351 -------------------------------------------------------------------------------- the units it owns at the Sporn Plant to the sum of the capacity of all of the units at the Sporn Plant. ARTICLE FIVE APPORTIONMENT OF COST OF OPERATING AND MAINTAINING THE SPORN PLANT 5.1 The costs incurred during or accrued for each calendar month in operating the Sporn Plant, as shown by the cost statements described in Article One, shall be assigned between the Owners. Appalachian and its Agent will, to the extent practicable, determine all Sporn Plant operating costs that are directly attributable to a specific unit for assignment to and payment by the Owner of that unit. The portion of the operating costs not directly attributable to a specific unit which are to be allocated to Ohio shall be equal to the sum of (i) two times the product of (a) 50% of total operating costs incurred and (b) the sum of (x) 150/1,050 and (y) 1/5, and (ii) the product of (a) 50% of total operating costs incurred and (b) the sum of (x) 450/1,050 and (y) 1/5. The remaining portion of such non-attributable operating costs shall be allocated to Appalachian. 5.2 The costs incurred during or accrued for each calendar month in maintaining the Sporn Plant, as shown by the cost statements described in Article One, shall be assigned between the Owners. Appalachian will, to the extent practicable, determine all Sporn Plant maintenance costs that are directly attributable to a specific unit for assignment to and payment by the Owner of that unit. The portion of the maintenance costs not directly attributable to a specific unit which are to be allocated to Ohio shall be equal to the sum of (i) two times the product of (a) 100% of total maintenance costs incurred and (b) 150/1,050, and (ii) the product of (a) 100% of total maintenance costs incurred and (b) -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Appalachian Power Company Original Sheet No. 7 Rate Schedule FERC No. 351 -------------------------------------------------------------------------------- 450/1,050. The remaining portion of such non-attributable maintenance costs shall be allocated to Appalachian. 5.3 The Agent, pursuant to direction from the Operating Committee, shall continue to procure and deliver fuel to each of the generating units at the Sporn Plant. Except for any unit for which Ohio has exercised the option described in Section 5.3.1, each Owner will pay for the minimum load and incremental hourly average Fuel Costs (based on average heat rates) of the units it owns at the Sporn Plant. This average will be based on the output of each individual generating unit. Fuel Costs will include the cost of the fuel itself, the cost of fuel transportation, and any carrying charges associated with fuel. 5.3.1 Ohio shall have the option, on six (6) months' notice, to supply the fuel necessary to operate one or more of the units it owns at the Sporn Plant. This option must be noticed at the same time as to all generating units at the Sporn Plant owned by Ohio that are served from the same physical fuel inventory. The option, once noticed, may not be revoked without Appalachian's consent. (a) If it exercises the option described in this Section 5.3. 1, Ohio shall have the right to use delivery and storage facilities, including rights of access, owned by Appalachian or the Agent or under contract to Appalachian or the Agent for the delivery to or storage of such fuel at the Sporn Plant, for use in connection with the unit(s) for which it has exercised such option. Ohio shall pay a monthly charge reflecting the proportional cost of its use of fuel delivery and storage facilities in each month. -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Appalachian Power Company Original Sheet No. 8 Rate Schedule FERC No. 351 -------------------------------------------------------------------------------- (b) In the event that Ohio exercises the option described in this Section 5.3.1 the Operating Committee will identify, and determine the appropriate allocation to Ohio of rights and obligations under, the applicable fuel supply contract(s), and any associated transportation contract(s), for fuel for the unit(s) as to which the option is exercised. Appalachian and its Agent, as necessary, shall assign to Ohio, and Ohio shall accept assignment of, that portion of Appalachian's and its Agents' rights under such contracts which the Operating Committee has determined should be allocated to Ohio for fuel for the unit(s) as to which the option has been exercised. If Ohio exercises the option provided in this subsection, but for any reason the fuel supply that is Ohio's responsibility is not timely delivered to the subject generating unit(s), Ohio shall not have the right to commit or dispatch the units affected. 5.3.2. In the event that Ohio exercises the option to supply fuel described in Section 5.3.1 with respect to any unit, the specifications for the fuel(s) supplied for that unit will be established and, when appropriate, modified, by the Operating Committee. Fuel will be subject to inspection and certification procedures as the Operating Committee may decide. Fuel inventories at each unit that is the subject of the option, or at the Sporn Plant, may be physically commingled, but separate accounts will be maintained to reflect the fuel credited to each Owner and used by each Owner at each unit. The Operating Committee will develop procedures to avoid imbalances between the amount of fuel each Owner delivers and the -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Appalachian Power Company Original Sheet No. 9 Rate Schedule FERC No. 351 -------------------------------------------------------------------------------- amount of fuel each Owner uses, and shall take any steps necessary for the correction of any imbalance by settlement or payment as soon as feasible, but in no event shall imbalances be permitted to exist for more than six months without settlement or payment. The Fuel Costs of each Owner with respect to an individual unit will be equal to the sum of minimum load and hourly average Fuel Costs (based on average heat rates at the unit's level of capacity utilization) associated with the Energy that each schedules from that unit. 5.3.3. In the event that Ohio exercises the option to supply fuel described in Section 5.3.1 with respect to any unit, Appalachian will assign to Ohio the fuel inventory, as of the date of the option takes effect, for the generating units affected by the exercise of the option. ARTICLE SIX OPERATING COMMITTEE 6.0 By written notice to each other, each of the Owners, and the Agent shall name one representative ("Operating Representative") and one alternate to act for it in matters pertaining to operating arrangements under this Agreement. For purposes of Sections 7.0 through 7.3 of this Agreement, Parties shall include the Owners and the Agent. Any Party may change its Operating Representative or alternate at any time by written notice to the other Parties. The three Operating Representatives for the respective Parties, or their alternates, shall comprise the Operating Committee. All decisions, directives, or other actions by the Operating Committee must be by unanimous agreement of the Operating Representatives of the Owners. The Operating Representative of the Agent, or -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Appalachian Power Company Original Sheet No. 10 Rate Schedule FERC No. 351 -------------------------------------------------------------------------------- of any third party that provides services in replacement of the Agent shall be free to express the views of the Agent or such third party on any matter, but shall not have a vote on the Operating Committee. If the Operating Representatives of Appalachian and Ohio are unable to agree on any matter, the matter will be resolved by dispute resolution. 6.1 The Operating Committee shall have the following responsibilities. a. Review and approval of an annual budget and annual operating plan, including determination of the emission allowances required to be acquired by the Owners. b. Establishment and review of procedures and systems for dispatch, notification of dispatch, and unit commitment under this Agreement. c. Establishment and monitoring of procedures for communication and coordination with respect to unit capacity availability, fuel-firing options, and scheduling of the generating capacity, including scheduling of outages for maintenance, repairs, equipment replacements, scheduled inspections, and other foreseeable cause of outages at any generating unit, as well as the return of any unit to availability following an unplanned outage. d. Decisions on capital expenditures for facilities at the Sporn Plant owned jointly by the Owners. e. Determinations as to changes in the unit capability of the units and decisions on unit retirement. f. Establishment and modification of billing procedures under this Agreement. g. Specification of fuels, oversight of fuel inspection and certification procedures, management of fuel inventories, and allocation of rights under fuel supply and transportation contracts in accordance with Section 5.3. 1 (b). -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Appalachian Power Company Original Sheet No. 11 Rate Schedule FERC No. 351 -------------------------------------------------------------------------------- h. Establishment of, termination of, and approval of any change or amendment to, operating arrangements between Appalachian and the Agent or any replacement third party with respect to any of the generating units. i. Review and approval of plans and procedures designed to insure compliance with any environmental law, regulation, ordinance or permit, including procedures for allocating and using emission allowances or for any programs that permit averaging at more than one unit for compliance. j. Other duties as assigned by agreement of the Owners. 6.2 The Operating Committee shall meet at least quarterly, and at such other times as any Party may reasonably request. 6.3 The Parties shall cooperate in providing to the Operating Committee the information it reasonably needs to carry out its duties, and to supplement or correct such information on a timely basis. 6.4 Appalachian and Ohio shall be individually responsible for any fees charged by FERC on the basis of the sales or transmission by each of capacity or energy at wholesale in interstate commerce. 6.5 Capital repairs and improvements for facilities at the Sporn Plant owned jointly by the Owners will be determined by the Operating Committee pursuant to the annual budgeting process set forth in Section 6.6. Expenditures that the Operating Committee determines have been or will be incurred exclusively for one Owner shall be assigned exclusively to that Owner. 6.6 At least 90 days before the start of each Operating Year, Appalachian and its Agent shall submit to the Operating Committee a proposed annual budget with respect to the Sporn -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Appalachian Power Company Original Sheet No. 12 Rate Schedule FERC No. 351 -------------------------------------------------------------------------------- Plant generating units, a proposed annual operating plan with respect to those generating units, and an estimate and schedule of costs to be incurred for major maintenance or replacement items with respect to those generating units during the next six-year period. The annual budget shall be presented on a month-by-month basis for each month during the next operating year, and shall include an operating budget, a capital budget, an estimate of the cost of any major repairs that Appalachian and its Agent anticipates will occur during such operating year with respect to the Sporn Plant generating units, and an itemized estimate of all projected non-fuel variable operating expenses relating to Appalachian's and its Agent's operation of those generating units during that operating year. The members of the Operating Committee will meet and work in good faith to agree upon the final annual budget and final annual operating plan. Once approved, the annual budget and annual operating plan shall remain in effect throughout the applicable operating year, subject to such changes, revisions, amendments, and updating as the Operating Committee may determine. ARTICLE SEVEN GOVERNMENTAL AUTHORITIES This Agreement is subject to the regulatory powers of any State or Federal agency having jurisdiction. All amounts paid by Ohio to Appalachian must be based upon its costs determined in accordance with Rules 90 and 91 of the Rules and Regulations of the Securities and Exchange Commission pursuant to the Public Utility Holding Company Act of 1935. -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Appalachian Power Company Original Sheet No. 13 Rate Schedule FERC No. 351 -------------------------------------------------------------------------------- ARTICLE EIGHT MISCELLANEOUS 8.1 This Agreement shall inure to the benefit of and be binding upon the signatories hereto and their respective successors and assigns, but this Agreement may not be assigned by any signatory without the written consent of the other, which consent shall not be unreasonably withheld. 8.2 The interpretation and performance of this Agreement shall be in accordance with the laws of the State of Ohio, excluding conflict of laws principles that would require the application of the laws of a different jurisdiction. 8.3 This Agreement supercedes and replaces the Original Operating Agreement as of the date this Agreement becomes effective. 8.4 This Agreement supercedes any and all previous representations, understandings, negotiations, and Agreements, either written or oral, that may have existed between the signatories or their representatives with respect to operation of the Sporn Plant, and constitutes the entire agreement of the signatories with respect to the operation of the Sporn Plant. ARTICLE NINE EFFECTIVE DATE AND TERMINATION This Agreement is effective January 1, 2002 or such other date as authorized by the FERC. This Agreement may be terminated (a) upon not less than one year's written notice by either Owner or (b) without notice if performance hereunder conflicts with any rule, regulation or order of the Securities and Exchange Commission or any state commission or other state body with jurisdiction. -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Appalachian Power Company Original Sheet No. 14 Rate Schedule FERC No. 351 -------------------------------------------------------------------------------- ARTICLE TEN DISPUTE RESOLUTION 10.1 If either Owner believes that a dispute has arisen as to the meaning or application of this Agreement, it shall present that matter to the Operating Committee in writing, and shall provide a copy of that writing to the other Owner. 10.2 If the Operating Committee is unable to reach agreement on any dispute within thirty (30) days after the dispute is presented to it, the matter shall be referred to the chief operating officers of the Owners for resolution in the manner that such individuals shall agree is appropriate; provided, however, that either Owner may invoke the arbitration provisions set forth in Section 10.3 at any time after the end of the thirty (30)-day period provided for the Operating Committee to reach agreement if the Operating Committee has not reached agreement. 10.3 If the Owners are unable to resolve a dispute through the Operating Committee within thirty (30) days after the dispute is presented to the Operating Committee pursuant to Section 10. 1, or through reference of the matter to the chief operating officers of the Owners pursuant to Section 10.2, either Owner may commence arbitration proceedings by providing written notice to the other Owner, detailing the nature of the dispute, designating the issue(s) to be arbitrated, identifying the provisions of this Agreement under which the dispute arose, and setting forth such Owner's proposed resolution of such dispute. 10.3.1 Within ten (10) days of the date of the notice of arbitration, a representative of each Owner shall meet for the purpose of selecting an arbitrator. If the Owner's -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Appalachian Power Company Original Sheet No. 15 Rate Schedule FERC No. 351 -------------------------------------------------------------------------------- representatives are unable to agree on an arbitrator within fifteen (15) days of the date of the notice of arbitration, then an arbitrator shall be selected in accordance with the procedures of the American Arbitration Association ("AAA"). Whether the arbitrator is selected by the Owner's representatives or in accordance with the procedures of the AAA, the arbitrator shall have the qualifications and experience in the occupation, profession, or discipline relevant to the subject matter of the dispute. 10.3.2 Any arbitration proceeding shall be subject to the Federal Arbitration Act, 9 U.S.C. SS. SS. 1 ET SEQ. (1994), as it may be amended, or any successor enactment thereto, and shall be conducted in accordance with the commercial arbitration rules of the AAA in effect on the date of the notice to the extent not inconsistent with the provisions of this Article Ten. 10.3.3 The arbitrator shall be bound by the provisions of this Agreement where applicable, and shall have no authority to modify any terms and conditions of this Agreement in any manner. The arbitrator shall render a decision resolving the dispute in an equitable manner, and may determine that monetary damages are due to an Owner or may issue a directive that an Owner take certain actions or refrain from taking certain actions, but shall not be authorized to order any other form of relief, provided, however, that nothing in this Article shall preclude the arbitrator from rendering a decision that adopts the resolution of the dispute proposed by an Owner. Unless otherwise agreed to by the Owners, the arbitrator shall render a decision within one hundred twenty (120) days of appointment, and shall notify the Owners in writing of such decision and the reasons -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Appalachian Power Company Original Sheet No. 16 Rate Schedule FERC No. 351 -------------------------------------------------------------------------------- supporting such decision. The decision of the arbitrator shall be final and binding upon the Owners, and any award may be enforced in any court of competent jurisdiction. 10.3.4 The fees and expenses of the arbitrator shall be shared equally by the Owners, unless the arbitrator specifies a different allocation. All other expenses and costs of the arbitration proceeding shall be the responsibility of the Owner incurring such expenses and costs. 10.3.5 Unless otherwise agreed by the Owners, any arbitration proceedings shall be conducted in Columbus, Ohio. 10.3.6 Except as provided in this Article, the existence, contents, or results of any arbitration proceeding under this Article may not be disclosed without the prior written consent of the Owners, provided, however, that either Owner may make disclosures as may be required to fulfill regulatory obligations to any agencies having jurisdiction, and may inform its lenders, affiliates, auditors, and insurers, as necessary, under pledge of confidentiality, and may consult with expert consultants as required in connection with an arbitration proceeding under pledge of confidentiality. 10.3.7 Nothing in this Agreement shall be construed to preclude either Owner from filing a petition or complaint with FERC with respect to any claim over which FERC has jurisdiction. In such case, the other Owner may request that FERC reject the petition or complaint or otherwise decline to exercise its jurisdiction. If FERC declines to act with respect to all or part of a claim, the portion of the claim not so accepted by FERC may be resolved through arbitration, as provided -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Appalachian Power Company Original Sheet No. 17 Rate Schedule FERC No. 351 -------------------------------------------------------------------------------- in this Article. To the extent that FERC asserts or accepts jurisdiction over all or part of a claim, the decisions, findings of fact, or orders of FERC shall be final and binding, subject to judicial review under the Federal Power Act, and any arbitration proceedings that may have commenced prior to the assertion or acceptance of jurisdiction by FERC shall be stayed, pending the outcome of the FERC proceedings. The arbitrator shall have no authority to modify, and shall be conclusively bound by, any decisions, findings of fact, or orders of FERC; provided, however, that to the extent that any decisions, findings of fact, or orders of FERC do not provide a final or complete remedy to an Owner seeking relief, such Owner may proceed to arbitration under this Article to secure such a remedy, subject to any FERC decisions, findings, or orders. 10.4 The procedures set forth in this Article Ten shall be the exclusive means for resolving disputes arising under this Agreement and shall survive this Agreement to the extent necessary to resolve any disputes pertaining to this Agreement. Except as provided in Sections 10.3 and 10.3.7, neither Owner shall have the right to bring any dispute for resolution by a court, agency, or other entity having jurisdiction over this Agreement, unless both Owners agree in writing to such procedure. 10.5 To the extent that a dispute involves the actions, inactions or responsibilities of the Agent under this Agreement, the provisions of this Article Ten shall be applicable to such dispute. For such purposes, the Agent shall be treated as an Owner in applying the provisions of this Article Ten. -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Appalachian Power Company Original Sheet No. 18 Rate Schedule FERC No. 351 -------------------------------------------------------------------------------- IN WITNESS WHEREOF, the parties hereto have caused this agreement to be signed by their respective officers thereunto duly authorized, and their corporate seals to be hereunto affixed on the day and year first above written. APPALACHIAN POWER COMPANY BY ________________________________________ OHIO POWER COMPANY BY ________________________________________ AMERICAN ELECTRIC POWER SERVICE CORPORATION BY ________________________________________ -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 ATTACHMENT 9 Amos Operating Agreement Appalachian Power Company Original Sheet No. 1 Rate Schedule FERC No. 350 -------------------------------------------------------------------------------- OPERATING AGREEMENT For JOHN E. AMOS PLANT Unit No. 3 APPALACHIAN POWER COMPANY OHIO POWER COMPANY and AMERICAN ELECTRIC POWER SERVICE CORPORATION, AS AGENT DATED:__________ -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Appalachian Power Company Original Sheet No. 2 Rate Schedule FERC No. 350 -------------------------------------------------------------------------------- THIS OPERATING AGREEMENT ("Agreement") dated between Appalachian Power Company ("Appalachian"), a Virginia corporation qualified as a foreign corporation in West Virginia; Ohio Power Company ("Ohio") (such two parties hereinafter sometimes referred to as the "Owners"); and American Electric Power Service Corporation ("Agent"), a New York corporation qualified as a foreign corporation in West Virginia. WITNESSETH THAT: WHEREAS, Appalachian owns two 800,000 kilowatt generating units ("Amos Units No. 1 and 2") at the John E. Amos Plant ("Amos Plant") located along the Kanawha River near Scary, West Virginia, Amos Units No. 1 and 2 having been placed into commercial operation by Appalachian on September 1, 1971 and June 6, 1972, respectively; and WHEREAS, the 1,300,000 kilowatt generating unit at the Amos Plant ("Amos Unit No. 3") is operated in conjunction with Amos Units No. 1 and 2, and is jointly owned by Appalachian and Ohio. WHEREAS, Appalachian and Ohio own and will utilize, as tenants in common, various facilities associated with Amos Plant which are useful and/or necessary for operation of Amos Units No. 1, 2 and 3 and which cannot be properly associated specifically with any individual unit, the investment associated with such general facilities having been allocated to Amos Unit No. 3 in the ratio of 13/29 (references hereinafter to the General Facilities shall mean the general facilities associated with Amos Unit No. 3); and WHEREAS, the Owners desire that Appalachian shall operate and maintain Amos Unit No. 3 and the General Facilities in accordance with the provisions set forth herein; and -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Appalachian Power Company Original Sheet No. 3 Rate Schedule FERC No. 350 -------------------------------------------------------------------------------- WHEREAS, the Owners are subsidiaries of American Electric Power Company, Inc., the parent company of an integrated public utility holding company system, and use the services of the Agent, (an affiliated company engaged solely in the business of furnishing essential services to the Owners and to other affiliated companies), as outlined in the Restated and Amended Interconnection Agreement, dated as of even or approximately even date herewith, by and between Appalachian, Kentucky Power Company, Indiana Michigan Power Company and the Agent; NOW THEREFORE, in consideration of the premises and for the purposes hereinabove recited, and in consideration of the mutual covenants hereinafter contained, the signatories agree as follows: ARTICLE ONE FUNCTIONS OF APPALACHIAN AND ITS AGENT 1.1 Appalachian and its Agent shall act in all matters associated with the operation and maintenance of Amos Unit No. 3 and the General Facilities as provided in this Agreement, with no profit to Appalachian. 1.2 Appalachian and its Agent shall operate and maintain Amos Unit No. 3 and the General Facilities in accordance with good utility practice consistent with procedures employed by Appalachian and Ohio at their other generating stations, and in conformity with the terms and conditions of this Agreement. 1.3 Appalachian and its Agent shall keep all necessary books of record, books of account and memoranda of all transactions involving Amos Unit No. 3 and the General Facilities, and shall make computations and allocations on behalf of the -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Appalachian Power Company Original Sheet No. 4 Rate Schedule FERC No. 350 -------------------------------------------------------------------------------- Owners, as required under this Agreement. The books of record, books of account and memoranda shall be kept by Appalachian and its Agent in such manner as to conform, where so required, to the Uniform System of Accounts as prescribed by the Federal Energy Regulatory Commission ("FERC") for Public Utilities and Licensees ("Uniform System of Accounts"), and to the rules and regulations of other regulatory bodies having jurisdiction as they may from time to time be in effect. 1.4 The Owners shall establish such joint bank accounts as may from time to time be required or appropriate. 1.5 As soon as practicable after the end of the month, Appalachian and its Agent shall furnish to Ohio a statement setting forth the dollar amounts associated with the operation and maintenance of Amos No. 3 and the General Facilities as allocated hereunder to Appalachian and Ohio for such month. The Owners shall, on a timely basis, deposit sufficient dollar amounts in the appropriate bank accounts to cover their respective allocations of such costs. 1.6 Appalachian and its Agent shall obtain such materials, labor and other services as it considers necessary in connection with the performance of the functions to be performed by it hereunder from such sources or through such persons as it may designate. ARTICLE TWO APPORTIONMENT OF CAPACITY AND ENERGY 2.1 The Total Net Capability of Amos Unit No. 3 at the Amos Unit No. 3 low-voltage busses, after taking into account auxiliary load demand, is 1,300,000 kilowatts. The -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Appalachian Power Company Original Sheet No. 5 Rate Schedule FERC No. 350 -------------------------------------------------------------------------------- Owners may from time to time modify the Total Net Capability of Amos Unit No. 3 as they may mutually agree. 2.2 The Total Net Generation of Amos Unit No.3 during a given period, as determined by the requirements of Appalachian and Ohio, shall mean the electrical output of the Amos Unit No. 3 generator during such period, measured in kilowatt hours by suitable instruments, reduced by the energy used by auxiliaries for the unit during such period. 2.3 In any hour, Appalachian and Ohio shall share the minimum load responsibility of Amos Unit No. 3 in respective amounts proportionate to their ownership interests in Amos Unit No. 3 at such time. Each Owner shall independently dispatch its share of the generating capacity between minimum and full load. 2.4 In any hour during which Amos Unit No. 3 is out of service, the energy used by Amos Unit No. 3 auxiliaries during such hour shall be provided by Appalachian and Ohio in respective amounts proportionate to their ownership interests in Amos Unit No. 3 at such time. 2.5 Appalachian shall at all times accept Ohio's share of Amos Unit No. 3 Total Net Generation into its transmission system at the low-voltage busses of Amos Unit No. 3, and shall deliver Ohio's share of energy used by Amos Unit No. 3 auxiliaries when the unit is out of service, as part of the energy interchange between and Appalachian and Ohio. -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Appalachian Power Company Original Sheet No. 6 Rate Schedule FERC No. 350 -------------------------------------------------------------------------------- ARTICLE THREE REPLACEMENTS, ADDITIONS, AND RETIREMENTS 3.1 Appalachian and its Agent shall from time to time after the initial construction of Amos Unit No. 3, make or cause to be made any necessary additions to, replacements of, and retirements of capitalizable facilities associated with Amos Unit No. 3 and the General Facilities as may be mutually agreed upon by the Owners. 3.2 The dollar amounts associated with any additions to, replacements of, or retirements of capitalizable facilities associated with Amos Unit No. 3 and the General Facilities shall be allocated to Appalachian and Ohio in respective amounts proportionate to their ownership interests in Amos Unit No. 3 at the time such additions, replacements, or retirements are made. ARTICLE FOUR WORKING CAPITAL REQUIREMENTS 4.1 Appalachian and Ohio shall periodically mutually determine the amount of funds required for use as working capital in meeting payrolls and other expenses incurred in the operation and maintenance of Amos Unit No. 3 and the General Facilities, and in buying materials and supplies (exclusive of fuel) for Amos Unit No. 3 and the General Facilities. -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Appalachian Power Company Original Sheet No. 7 Rate Schedule FERC No. 350 -------------------------------------------------------------------------------- 4.2 Appalachian and Ohio shall from time to time provide their share of working capital requirements in respective amounts proportionate to their ownership interests at such time in Amos Unit No. 3. ARTICLE FIVE INVESTMENT IN FUEL 5.1 Appalachian and its Agent shall establish and maintain reserves of coal in stock pile for Amos Plant of such quality and in such quantities as Appalachian and its Agent shall determine to be required to provide adequate fuel reserves against interruptions of normal fuel supply. 5.2 Appalachian in agreement with Ohio may establish and maintain separate coal stock piles for Amos Units 1 and 2 and/or for Amos Unit No. 3 in addition to or instead of a common coal stock pile for all Amos Plant units. 5.3 The Amos Unit No. 3 coal stock pile shall consist of the sum of the tons of coal in any separate coal stock pile established for Amos Unit No. 3 and the tons of coal associated with Amos Unit No 3 in any common coal stock pile established for all Amos Plant units. 5.4 Except as otherwise provided in Section 6.2, the Owners shall make such monthly investments in the common coal stock pile associated with Amos Unit No. 3 as are necessary to maintain the number of tons in such coal stock pile, after taking into account the coal consumption from the common coal stock pile by Amos Unit No. 3 during such month, at a level equal to the product of (a) the total number of tons of coal in the common coal stock pile at the Amos Plant at the end of such month and -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Appalachian Power Company Original Sheet No. 8 Rate Schedule FERC No. 350 -------------------------------------------------------------------------------- (b) the ratio of (i) the sum of the number of tons of coal consumed by Amos Unit No. 3 from the common coal stockpile during such month and projected by Appalachian and its Agent to be consumed by Amos Unit No. 3 from the common coal stock pile during the eleven calendar months subsequent to such month, and (ii) the total number of tons of coal projected by Appalachian to be consumed at the Amos Plant from the common coal stock pile during such twelve-month period. 5.5 Except as otherwise provided in Section 6.2, at any time, Appalachians's and Ohio's respective shares of the investment in the common coal stock pile associated with Amos Unit No. 3, as determined by the provisions of Section 5.4, and in any separate coal stock pile for Amos Unit No. 3 shall be proportionate to their ownership interests at such time in Amos Unit No. 3. 5.6 The Owners recognize that under certain circumstances it may be more equitable to establish the number of tons of coal associated with Amos Unit No. 3 in the common coal stock pile on the basis of actual coal consumption during the preceding twelve month period rather than on the basis of forecasts, and agree that upon mutual consent of the Owners through its Operating Committee, such alternative method may from time to time be employed. 5.7 Fuel oil reserves and fuel oil charged to operation for Amos Unit No. 3 shall be owned and accounted for between the Owners in the same manner as coal. -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Appalachian Power Company Original Sheet No. 9 Rate Schedule FERC No. 350 -------------------------------------------------------------------------------- ARTICLE SIX APPORTIONMENT OF STATION COSTS 6.1 Except as otherwise provided in Section 6.2, the allocation to the Owners of fuel expense associated with Amos Unit No. 3 shall be determined by Appalachian and its Agent as follows: (a) In any calendar month, the unit cost of coal received for the Amos Plant common coal stock pile associated with Amos Unit No. 3 shall be determined by Appalachian and its Agent by dividing (i) the sum of the total delivered cost of coal received for the Amos Plant common coal stock pile during such month and the associated total coal storage costs, coal unloading costs and fuel handling costs incurred during such month, by (ii) the total number of tons of coal delivered to the Amos Plant common coal stock pile during such month. (b) In any calendar month, the total cost of coal received for the Amos Plant common coal stock pile to be charged to the Amos Unit No. 3 fuel in stock shall be determined by Appalachian and its Agent by multiplying (i) the unit cost of coal received for such common coal stock pile associated with Amos Unit No. 3 for such month as determined by the provisions of Section 6.1 (a) by (ii) the number of tons of coal received for such common stock pile associated with Amos Unit No. 3 during such month as determined by the provisions of Section 5.4. -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Appalachian Power Company Original Sheet No. 10 Rate Schedule FERC No. 350 -------------------------------------------------------------------------------- (c) In any calendar month, the total cost of coal received for any separate coal stock pile for Amos Unit No. 3 shall be determined by Appalachian and its Agent by multiplying (i) the unit cost of delivered coal received for such separate coal stock pile, including coal storage costs, coal unloading costs, and fuel handling costs incurred, during such month by (ii) the number of tons of coal received for such separate coal stock pile during such month. (d) The number of tons of coal consumed by Amos Unit No. 3 in each calendar month from the Amos Plant common coal stock pile and from any separate coal stock pile for Amos Unit No. 3 shall be determined by Appalachian and its Agent and shall be converted into a dollar amount by adding (i) the product of (a) the average cost per ton of coal associated with Amos Unit No. 3 in the Amos Plant coal stock pile at the close of such month, and (b) the number of tons of coal consumed by Amos Unit No. 3 from the Amos Plant common coal stock pile during such month, to (ii) the product of (c) the average cost per ton of coal in any separate coal stock pile for Amos Unit No. 3 at the close of such month, and (d) the number of tons of coal consumed by Amos Unit No. 3 from such separate coal stock pile during such month. Such dollar amount shall be credited to the Amos Unit No. 3 fuel in stock pile and charged to Amos Unit 3 fuel consumed. (e) In each calendar month, Appalachian's and Ohio's respective shares of Amos Unit No. 3 fuel consumed expense as determined hereinabove shall be proportionate to each Owner's dispatch of Amos Unit No. 3 in such month. -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Appalachian Power Company Original Sheet No. 11 Rate Schedule FERC No. 350 -------------------------------------------------------------------------------- (f) Fuel oil reserves will be owned and accounted for in the same manner as coal stock pile, and fuel oil consumed will be charged to Amos Unit No. 3 and allocated to the Owners in the same manner as coal consumed. (g) Appalachian and its Agent shall allocate any Amos Plant common coal stock pile fuel inventory adjustments to Amos Unit No. 3 in the ratio of the total number of tons of coal consumed by Amos Unit No. 3 from such common coal stock pile during the twelve-month period preceding the annual coal storage survey to the total number of tons of coal consumed at Amos Plant from such common coal stock pile during such twelve-month period. 6.2 Ohio shall have the option, on six (6) months' notice, to supply the fuel necessary to operate its Assigned Capacity in Amos Unit No. 3. For purposes of this Agreement, Ohio's Assigned Capacity in Amos Unit No. 3 shall be equal to two-thirds of the Total Net Capability of such unit, and Appalachian's Assigned Capacity shall be equal to one-third of the Total Net Capability of such unit. The option, once noticed, may not be revoked without Appalachian's consent. 6.2.1 If it exercises the option described in Section 6.2, Ohio shall have the right to use delivery and storage facilities, including rights of access, owned by Appalachian or its Agent or under contract to Appalachian or its Agent for the delivery to or storage of such fuel at the Amos Plant, for use in connection with Amos Unit No. 3. Ohio shall pay a monthly charge reflecting the proportional cost of its use of fuel delivery and storage facilities in each month. -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Appalachian Power Company Original Sheet No. 12 Rate Schedule FERC No. 350 -------------------------------------------------------------------------------- 6.2.2 In the event that Ohio exercises the option described in Section 6.2, the Operating Committee will identify and determine the appropriate allocation to Ohio of rights and obligations under the applicable fuel supply contract(s), and any associated transportation contract(s), for fuel for Ohio's Assigned Capacity in Amos Unit No. 3. Appalachian or its Agent, as necessary, shall assign to Ohio, and Ohio shall accept, assignment of that portion of Appalachian's and its Agent's rights and obligations under such contracts which the Operating Committee has determined should be allocated to Ohio for fuel for Ohio's Assigned Capacity in Amos Unit No. 3. If Ohio exercises the option provided in this subsection, but for any reason the fuel supply that is Ohio's responsibility is not timely delivered to Amos Unit No. 3, Ohio shall not have the right to commit or dispatch Amos Unit No. 3. 6.2.3. In the event that Ohio exercises the option to supply fuel described in Section 6.2 with respect to its Assigned Capacity in Amos Unit No. 3, the specifications for the fuel(s) supplied for that unit will be established and, when appropriate, modified, by the Operating Committee. Fuel will be subject to inspection and certification procedures as the Operating Committee may decide. Fuel inventories at Amos Unit No. 3, or at the Amos Plant, may be physically commingled, but separate accounts will be maintained to reflect the fuel credited to each Owner and used by each Owner at each unit. The Operating Committee will develop procedures to avoid imbalances between the amount of fuel each Owner delivers and the amount of fuel each Owner uses, and shall take any steps necessary for the -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Appalachian Power Company Original Sheet No. 13 Rate Schedule FERC No. 350 -------------------------------------------------------------------------------- correction of any imbalance by settlement or payment as soon as feasible, but in no event shall imbalances be permitted to exist for more than six months without settlement or payment. The Fuel Costs of each Owner with respect to Amos Unit No. 3 will be equal to the sum of minimum load and hourly average Fuel Costs (based on average heat rates at the unit's level of capacity utilization) associated with the energy that each schedules from that unit. 6.2.4 In the event that Ohio exercises the option to supply fuel described in Section 6.2 with respect to its Assigned Capacity in Amos Unit No. 3, Appalachian will assign to Ohio a fraction of the fuel inventory as of the date of the option takes effect for Amos Unit No. 3. The fraction shall be determined by multiplying Ohio's Assigned Capacity Percentage by the total fuel inventory of Amos Unit No. 3 on the date of assignment. For purposes of this Agreement, Ohio's Assigned Capacity Percentage shall be two-thirds (66.7%). 6.3 For each calendar month, Appalachian and its Agent will, to the extent practicable, determine all Amos Plant operations expenses and associated overheads, as accounted for under the FERC Uniform System of Accounts, that are directly attributable to Amos Unit No. 3 for such month. In each calendar month, the portion allocable to Amos Unit No. 3 of all Amos Plant monthly operations costs and associated overheads not directly attributable to Amos Unit No. 1, No. 2 or No. 3 shall be equal to the product of (a) 50% of the total Amos Plant operations costs and associated overheads not directly attributable to Amos Units No. 1, No. 2 or No. 3 in such calendar month, and (b) the sum of (i) the ratio of the Total Net Capability of -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Appalachian Power Company Original Sheet No. 14 Rate Schedule FERC No. 350 -------------------------------------------------------------------------------- Amos Unit No. 3 for such month to the sum of the Total Net Capabilities for such month of all generating units located at Amos Plant, and (ii) the quotient of one, divided by the total number of generating units located at Amos Plants. For purposes of this Section 6.2 and Section 6.3, the Total Net Capability of each of Amos Units No. 1 and No. 2 shall be 800,000 kilowatts, subject to being modified by Appalachian by written notice to Ohio, and the Total Net Capability of Amos Unit No. 3 shall be determined in accordance with Section 2.1. 6.4 For each calendar month, Appalachian and its Agent will, to the extent practicable, determine all Amos Plant maintenance expenses and associated overheads, as accounted for under the FERC Uniform System of Accounts, that are directly attributable to Amos Unit No. 3 for such month. The portion allocable to Amos Unit No. 3 of all Amos Plant monthly maintenance expenses and associated overheads not directly attributable to Amos Units No. 1, 2, or 3 shall be equal to the product of (a) the total of such Amos Plant expenses in each calendar month, and (b) the ratio of (i) the Total Net Capability of Amos Unit No. 3 for such month, to (ii) the sum of the Total Net Capabilities for such month of all the generating units located at Amos Plant. 6.5 In each calendar month, Appalachian's and Ohio's respective shares of operations and maintenance expenses associated with Amos Unit No. 3, as determined in accordance with Sections 6.2 and 6.3, shall be proportionate to their respective ownership interests in Amos Unit No. 3 in such month. 6.6 Each Owner shall bear the cost of all taxes attributable to its respective ownership interest in Amos Unit No. 3 and the General Facilities. -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Appalachian Power Company Original Sheet No. 15 Rate Schedule FERC No. 350 -------------------------------------------------------------------------------- ARTICLE SEVEN OPERATING COMMITTEE 7.0 By written notice to each other, the Owners and the Agent, each shall name one representative ("Operating Representative") and one alternate to act for it in matters pertaining to operating arrangements under this Agreement. For purposes of Sections 7.0 through 7.3 of this Agreement, the term "Parties" shall include the Owners, and also shall include the Agent or alternate at any time by written notice by the Agent to the Owners. The Operating Representatives for the respective Parties, or their alternates, shall comprise the Operating Committee. All decisions, directives, or other actions by the Operating Committee must be by unanimous agreement of the Operating Representatives of Appalachian and Ohio. The Operating Representative of the Agent, or of any third party that provides services in replacement of the Agent, shall be free to express the views of the Agent or such third party on any matter, but shall not have a vote on the Operating Committee. If the Operating Representatives of Appalachian and Ohio are unable to agree on any matter, the matter will be resolved through the dispute resolution procedures set forth in Article Ten. 7.1 The Operating Committee shall have the following responsibilities: a) Review and approval of an annual budget and annual operating plan, including determination of the emission allowances required to be acquired by Appalachian and Ohio. -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Appalachian Power Company Original Sheet No. 16 Rate Schedule FERC No. 350 -------------------------------------------------------------------------------- b) Establishment and review of procedures and systems for dispatch, notification of dispatch, and unit commitment for Amos Unit No. 3 under this Agreement, including any commitment of Called Capacity pursuant to Section 7.5.2. c) Establishment and monitoring of procedures for communication and coordination with respect to Amos Unit No. 3 capacity availability, fuel-firing options, and scheduling of outages for maintenance, repairs, equipment replacements, scheduled inspections, and other foreseeable cause of outages at Amos Unit No. 3, as well as the return Amos Unit No. 3 to availability following an unplanned outage. d) Decisions on capital expenditures, including unit upgrades and repowering of Amos Unit No. 3. e) Determinations as to changes in the unit capability of Amos Unit No. 3 and decisions on unit retirement. f) Establishment and modification of billing procedures under this Agreement. g) Specification of fuels, oversight of fuel inspection and certification procedures, management of fuel inventories for Amos Unit No. 3, and allocation of rights under fuel supply and transportation contracts in accordance with Section 6.2.2. h) Establishment of, termination of, and approval of any change or amendment to, operating arrangements between Appalachian and the Agent or any replacement third party with respect to Amos Unit No. -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Appalachian Power Company Original Sheet No. 17 Rate Schedule FERC No. 350 -------------------------------------------------------------------------------- 3; provided, however, that the Agent or any replacement third party shall participate in discussions pursuant to this subsections 7.1.h only if and to the extent requested to do so by both Appalachian and Ohio. i) Review and approval of plans and procedures designed to insure compliance at Amos Unit No. 3 with any environmental law, regulation, ordinance or permit, including procedures for allocating and using emission allowances or for any programs that permit averaging at more than one unit for compliance. j) Other duties as assigned by agreement of Appalachian and Ohio. 7.2 The Operating Committee shall meet at least quarterly, and at such other times as any Party may reasonably request. 7.3 The Parties shall cooperate in providing to the Operating Committee the information it reasonably needs to carry out its duties, and to supplement or correct such information on a timely basis. 7.4 Appalachian and Ohio will each make an initial unit commitment for Amos Unit No. 3 one business day ahead of real-time dispatch. 7.5 For purposes of this Section 7.5 and subsections of this Section, the terms "Party" or "Parties" refers only to Appalachian and Ohio, or both of them, as the case may be. 7.5.1 If Amos Unit No. 3 is designated to be committed by both Parties, such unit will be brought on line or kept on line. If neither Party designates Amos Unit No. 3 to be committed, such unit will remain off line or to be taken offline. 7.5.2 When Amos Unit No. 3 is designated to be committed by one Party, but designated not to be committed by the other Party, the unit will be brought on -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Appalachian Power Company Original Sheet No. 18 Rate Schedule FERC No. 350 -------------------------------------------------------------------------------- line or kept on line if the Party designating the unit for commitment undertakes to pay any applicable start-up costs for the unit, as well as any applicable minimum running costs for the unit thereafter, in which event the unit shall be brought on line or kept on line, as the case may be. The Party so designating the unit shall have the right to schedule and dispatch up to all of the Available Capacity of the unit. The Party exercising this right shall be referred to as the "Calling Party," and the capacity called by that Party in excess of its Assigned Capacity Percentage of the Available Capacity of that unit shall be referred to as its "Called Capacity." The other Party shall be referred to as the "Non-Calling" Party. The Calling Party shall provide reasonable notice to the Non-Calling Party of its call, including any start-up or shut-down time for Amos Unit No. 3. For purposes of this Agreement, Ohio's Assigned Capacity Percentage shall be as defined in Section 6.2, and Appalachian's Assigned Capacity Percentage shall be one-third (33.33%). Available Capacity means that portion of an Owner's Assigned Capacity in Amos Unit No. 3 that is currently capable of being dispatched. 7.5.3 The Non-Calling Party can reclaim any Called Capacity attributable to its Assigned Capacity share from Amos Unit No. 3 by giving the Calling Party notice equal to the normal start-up time for the unit. At the end of the notice period, the Non-Calling Party shall have the right to schedule and dispatch the recalled capacity. At that point, the Non-Calling Party shall resume its responsibility for its share of any applicable start-up costs for unit, and prospectively shall bear its responsibility for the costs associated with its -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Appalachian Power Company Original Sheet No. 19 Rate Schedule FERC No. 350 -------------------------------------------------------------------------------- Assigned Capacity from the unit. For purposes of this Section 7.5.3, an Owner's Assigned Capacity in Amos Unit No. 3 will be equal to the product of (a) the Owner's Assigned Capacity Percentage multiplied by (b) the Available Capacity of Amos Unit No. 3, as each of these terms is defined in Section 7.5.2. 7.5.4 If any capacity remains available but is not dispatched from a Party's Available Capacity with respect to the Amos Unit No. 3 committed as a result of the initial unit commitment, the other Party may only schedule and dispatch such capacity pursuant to agreement with the non-dispatching Party. 7.6 Appalachian and Ohio shall be individually responsible for any fees charged by FERC on the basis of the sales or transmission by each of capacity or energy at wholesale in interstate commerce. 7.7 EMISSION ALLOWANCE. To the extent such assignment has not previously occurred, on or before the effective date of this Agreement, Appalachian and its Agent will assign to Ohio a fraction of each vintage year of Emission Allowances, issues by the U.S. Environmental Protection Agency ("USEPA") pursuant to Title IV of the Clean Air Act Amendments of 1990 and any regulations thereunder ("Title IV Emission Allowances"), that it has received from the Administrator of USEPA with respect to Amos Unit No. 3 in the past and has not expended as of the date of assignment. In addition, Appalachian will assign to Ohio a fraction of such Title IV Emission Allowances which were purchased by Appalachian or its Agent and held in any account for use at Amos Unit No. 3. In each case, the fraction of such Title IV Emission Allowances to be assigned by Appalachian to Ohio will be determined by -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Appalachian Power Company Original Sheet No. 20 Rate Schedule FERC No. 350 -------------------------------------------------------------------------------- multiplying Ohio's Assigned Capacity Percentage, as specified in Section 6.2.4, by the total of such Title IV Emission Allowances that Appalachian or its Agent has received or purchased for Amos Unit No. 3 and has not expended as of the date of assignment. Thereafter, Title IV Emission Allowances received by Appalachian with respect to Amos Unit No. 3 will be shared by the Appalachian and Ohio in accordance with the Assigned Capacity Percentage of each of them. For this purpose, Appalachian's Assigned Capacity Percentage shall be one-third (33.33%). To the extent that additional Title IV Emission Allowances are required for operation of Amos Unit No. 3, Appalachian and Ohio will each be responsible for acquiring sufficient Title IV Emission Allowances to satisfy the Title IV Emission Allowances required because of its dispatch of energy from that unit. The Agent will also determine the number and allocation of Title IV Emission Allowances to be supplied to any third-party unit operator under applicable designated representative agreements. On or before January 10 of each year, the Agent shall determine and notify Appalachian and Ohio of the number of additional Title IV Emission Allowances consumed by each of them through December 31 of the previous year, and Appalachian and Ohio shall each transfer into the Amos Unit No. 3 U.S. EPA Allowance Transfer System account that number of Title IV Emission Allowances with a small compliance margin by January 31 of that year. In the event that Appalachian or Ohio fails to surrender the required number of Title IV Emission Allowances by January 31, the Agent shall purchase the required number of Title IV Emission Allowances, and Appalachian or Ohio, as the case may be, shall reimburse the Agent for such purchases, with interest at the Federal Funds Rate (as published -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Appalachian Power Company Original Sheet No. 21 Rate Schedule FERC No. 350 -------------------------------------------------------------------------------- by the Board of Governors of the Federal Reserve System as from time to time in effect) running from the date of purchases to the date of payment. The Operating Committee will develop procedures to be implemented after the end of each calendar year to account for the Title IV Emission Allowances required by the use of Amos Unit No. 3 by Appalachian and Ohio and to correct any imbalance between Title IV Emission Allowances supplied and Title IV Emission Allowances used through the end of the preceding year by settlement or payment. 7.8 Capital repairs and improvements to Amos Unit No. 3 will be determined by the Operating Committee pursuant to the annual budgeting process set forth in Section 7.9. Expenditures that the Operating Committee determines have been or will be incurred exclusively for one Owner shall be assigned exclusively to that Owner. 7.9 At least 90 days before the start of each operating year, Appalachian and its Agent shall submit to the Operating Committee a proposed annual budget with respect to Amos Unit No. 3, a proposed annual operating plan with respect to that unit, and an estimate and schedule of costs to be incurred for major maintenance or replacement items with respect to that unit during the next six-year period. The annual budget shall be presented on a month-by-month basis for each month during the next operating year, and shall include an operating budget, a capital budget, an estimate of the cost of any major repairs that Appalachian and its Agent anticipates will occur during such operating year with respect to Amos Unit No. 3, and an itemized estimate of all projected non-fuel variable operating expenses relating to Appalachian's and its Agent's operation of that generating unit during that operating year. The members of the Operating Committee will meet and work in good faith to -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Appalachian Power Company Original Sheet No. 22 Rate Schedule FERC No. 350 -------------------------------------------------------------------------------- agree upon the final annual budget and final annual operating plan. Once approved, the annual budget and annual operating plan shall remain in effect throughout the applicable operating year, subject to such changes, revisions, amendments, and updating as the Operating Committee may determine. ARTICLE EIGHT EFFECTIVE DATE AND TERM 8.1 The effective date of this Agreement shall be January 1, 2002, or such other date as authorized by the Federal Energy Regulatory Commission. 8.2 The Agreement shall remain in force until such time as Ohio or Appalachian has entirely divested itself of any ownership interest in Amos Unit No. 3 and the General Facilities, other than assignment or other transfer of such ownership interests to another AEP affiliate. ARTICLE NINE GENERAL 9.1 This Agreement shall inure to the benefit and be binding upon the signatories hereto and their respective successors and assigns, but this Agreement may not be assigned by any signatory without the written consent of the others, which consent shall not unreasonably withheld. 9.2 This Agreement is subject to the regulatory authority of any State or Federal agency having jurisdiction. -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Appalachian Power Company Original Sheet No. 23 Rate Schedule FERC No. 350 -------------------------------------------------------------------------------- 9.3 The interpretation and performance of this Agreement shall be in accordance with the laws of the State of Ohio, excluding conflict of laws principles that would require the application of the laws of a different jurisdiction. 9.4 This Agreement supercedes any and all previous representations, understandings, negotiations, and Agreements, either written or oral, that may have existed between the signatories or their representatives with respect to operation of the Plant, and constitutes the entire agreement of the signatories with respect to the operation of the Plant. ARTICLE TEN DISPUTE RESOLUTION 10.1 If either Owner believes that a dispute has arisen as to the meaning or application of this Agreement, it shall present that matter to the Operating Committee in writing, and shall provide a copy of that writing to the other Owner. 10.2 If the Operating Committee is unable to reach agreement on any dispute within thirty (30) days after the dispute is presented to it, the matter shall be referred to the chief operating officers of the Owners for resolution in the manner that such individuals shall agree is appropriate; provided, however, that either Owner involved in a dispute may invoke the arbitration provisions set forth in Section 10.3 at any time after the end of the thirty (30)-day period provided for the Operating Committee to reach agreement if the Operating Committee has not reached agreement. 10.3 If the Owners are unable to resolve a dispute through the Operating Committee within thirty (30) days after the dispute is presented to the Operating Committee pursuant to Section 10.1, or through reference of the matter to the chief operating -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Appalachian Power Company Original Sheet No. 24 Rate Schedule FERC No. 350 -------------------------------------------------------------------------------- officers of the Owners pursuant to Section 10.2, either Owner may commence arbitration proceedings by providing written notice to the other Owner, detailing the nature of the dispute, designating the issue(s) to be arbitrated, identifying the provisions of this Agreement under which the dispute arose, and setting forth such Owner's proposed resolution of such dispute. 10.3.1 Within ten (10) days of the date of the notice of arbitration, a representative of each Owner shall meet for the purpose of selecting an arbitrator. If the Owner's representatives are unable to agree on an arbitrator within fifteen (15) days of the date of the notice of arbitration, then an arbitrator shall be selected in accordance with the procedures of the American Arbitration Association ("AAA"). Whether the arbitrator is selected by the Owner's representatives or in accordance with the procedures of the AAA, the arbitrator shall have the qualifications and experience in the occupation, profession, or discipline relevant to the subject matter of the dispute. 10.3.2 Any arbitration proceeding shall be subject to the Federal Arbitration Act, 9 U.S.C. ss. ss. 1 ET SEQ. (1994), as it may be amended, or any successor enactment thereto, and shall be conducted in accordance with the commercial arbitration rules of the AAA in effect on the date of the notice to the extent not inconsistent with the provisions of this Article Ten. 10.3.3 The arbitrator shall be bound by the provisions of this Agreement where applicable, and shall have no authority to modify any terms and conditions of this Agreement in any manner. The arbitrator shall render a decision resolving the dispute in an equitable manner, and may determine that -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Appalachian Power Company Original Sheet No. 25 Rate Schedule FERC No. 350 -------------------------------------------------------------------------------- monetary damages are due to an Owner or may issue a directive that an Owner take certain actions or refrain from taking certain actions, but shall not be authorized to order any other form of relief; provided, however, that nothing in this Article shall preclude the arbitrator from rendering a decision that adopts the resolution of the dispute proposed by an Owner. Unless otherwise agreed to by the Owners, the arbitrator shall render a decision within one hundred twenty (120) days of appointment, and shall notify the Owners in writing of such decision and the reasons supporting such decision. The decision of the arbitrator shall be final and binding upon the Owners, and any award may be enforced in any court of competent jurisdiction. 10.3.4 The fees and expenses of the arbitrator shall be shared equally by the Owners, unless the arbitrator specifies a different allocation. All other expenses and costs of the arbitration proceeding shall be the responsibility of the Owner incurring such expenses and costs. 10.3.5 Unless otherwise agreed by the Owners, any arbitration proceedings shall be conducted in Columbus, Ohio. 10.3.6 Except as provided in this Article, the existence, contents, or results of any arbitration proceeding under this Article may not be disclosed without the prior written consent of the Owners, provided, however, that either Owner may make disclosures as may be required to fulfill regulatory obligations to any agencies having jurisdiction, and may inform its lenders, affiliates, auditors, and insurers, as necessary, under pledge of confidentiality, and may -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Appalachian Power Company Original Sheet No. 26 Rate Schedule FERC No. 350 -------------------------------------------------------------------------------- consult with expert consultants as required in connection with an arbitration proceeding under pledge of confidentiality. 10.3.7 Nothing in this Agreement shall be construed to preclude either Owner from filing a petition or complaint with FERC with respect to any claim over which FERC has jurisdiction. In such case, the other Owner may request that FERC reject the petition or complaint or otherwise decline to exercise its jurisdiction. If FERC declines to act with respect to all or part of a claim, the portion of the claim not so accepted by FERC may be resolved through arbitration, as provided in this Article. To the extent that FERC asserts or accepts jurisdiction over all or part of a claim, the decisions, findings of fact, or orders of FERC shall be final and binding, subject to judicial review under the Federal Power Act, and any arbitration proceedings that may have commenced prior to the assertion or acceptance of jurisdiction by FERC shall be stayed, pending the outcome of the FERC proceedings. The arbitrator shall have no authority to modify, and shall be conclusively bound by, any decisions, findings of fact, or orders of FERC; provided, however, that to the extent that any decisions, findings of fact, or orders of FERC do not provide a final or complete remedy to an Owner seeking relief, such Owner may proceed to arbitration under this Article to secure such a remedy, subject to any FERC decisions, findings, or orders. 10.4 The procedures set forth in this Article Ten shall be the exclusive means for resolving disputes arising under this Agreement and shall survive this Agreement to the extent necessary to resolve any disputes pertaining to this Agreement. Except as -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Appalachian Power Company Original Sheet No. 27 Rate Schedule FERC No. 350 -------------------------------------------------------------------------------- provided in Sections 10.3 and 10.3.7, neither Owner shall have the right to bring any dispute for resolution by a court, agency, or other entity having jurisdiction over this Agreement, unless both Owners agree in writing to such procedure. 10.5 To the extent that a dispute involves the actions, inactions or responsibilities of the Agent under this Agreement, the provisions of this Article Ten shall be applicable to such dispute. For such purposes, the Agent shall be treated as an Owner in applying the provisions of this Article Ten. IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be executed by their officers thereunto duly authorized as of the date first above written. APPALACHIAN POWER COMPANY BY:____________________________________ Title:____________________________ OHIO POWER COMPANY BY:____________________________________ Title:____________________________ AMERICAN ELECTRIC POWER SERVICE CORPORATION BY:____________________________________ Title:____________________________ -------------------------------------------------------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 ATTACHMENT 10 ROCKPORT OPERATING AGREEMENT Indiana Michigan Power Company Original Sheet No. 1 Rate Schedule FERC No. 347 OPERATING AGREEMENT For ROCKPORT STEAM ELECTRIC GENERATION STATION Units No. 1 and 2 INDIANA MICHIGAN POWER COMPANY KENTUCKY POWER COMPANY AEP GENERATING COMPANY POWER MARKETING AFFILIATE and AMERICAN ELECTRIC POWER SERVICE CORPORATION, AS AGENT DATED:___________________ Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Indiana Michigan Power Company Original Sheet No. 2 Rate Schedule FERC No. 347 This OPERATING AGREEMENT ("Agreement") dated __________ between Indiana Michigan Power Company ("I&M"), an Indiana corporation; and AEP Generating Company ("AEGCO"), an Ohio corporation qualified to do business in Indiana (such parties being hereinafter sometimes referred to as the "Owners"); Kentucky Power Company ("KPCO"), a Kentucky corporation qualified to do business in Indiana; and Power Marketing Affiliate (PMA"), a ________________ corporation qualified to do business in Indiana (KPCO and PMA being hereinafter sometimes referred to as "Non-Owners"); and American Electric Power Service Corporation ("Agent"), a New York corporation qualified to do business in Indiana. WITNESSETH: WHEREAS, I&M, and AEGCO are parties to an Owners' Agreement, dated as of March 31, 1982, as amended, pursuant to which said companies acquired undivided ownership interests in Unit No. 1 ("Unit No. 1 ") and Unit No. 2 ("Unit No. 2") of the Rockport Steam Electric Generating Station (the "Plant"), located near Rockport, Indiana, on the Ohio River; WHEREAS, I&M and AEGCO are parties to a Unit Power Agreement dated as of March 31, 1982, which assigns certain rights to capacity and associated energy of the Plant from AEGCO to I&M; WHEREAS, AEGCO and KPCO are parties to a Unit Power Agreement, dated as August 1, 1984, which assigns certain rights to capacity and associated energy of the plant from AEGCO to KPCO; Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Indiana Michigan Power Company Original Sheet No. 3 Rate Schedule FERC No. 347 WHEREAS, I&M and PMA are parties to an Assignment Agreement, dated _____________, which assigns certain rights to capacity and of associated energy of Unit No. 1 from I&M to PMA; WHEREAS, the Owners and Non-Owners desire that I&M shall operate and maintain Units No. 1 and 2 of the Plant in accordance with the provisions set forth herein; and WHEREAS, the Owners and Non-Owners are subsidiaries of American Electric Power Company, Inc., the parent company of an integrated public utility holding company system, and use the services of the Agent (an affiliated company engaged solely in the business of furnishing essential services to the Owners and to other affiliated companies), as outlined in the Restated and Amended Interconnection Agreement, dated _______________, by and between I&M, KPCO, Appalachian Power Company, and the Agent. NOW THEREFORE, in consideration of the premises and for the purposes hereinabove recited, and in consideration of the mutual covenants hereinafter contained, the signatories hereto agree as follows: ARTICLE ONE FUNCTIONS OF INDIANA MICHIGAN POWER COMPANY AND ITS AGENT 1.1 I&M and its Agent shall act in all matters associated with the operation and maintenance of the Plant as provided in this Agreement, with no profit to I&M. 1.2 I&M and its Agent shall operate and maintain the Plant in accordance with good utility practice consistent with procedures employed by I&M and KPCO at their other generating stations, and in conformity with the terms and conditions of this Agreement. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Indiana Michigan Power Company Original Sheet No. 4 Rate Schedule FERC No. 347 1.3 I&M and its Agent shall keep all necessary books of record, books of account and memoranda of all transactions involving the Plant, and shall make computations and allocations on behalf of the Owners, as required under this Agreement. The books of record, books of account and memoranda shall be kept by I&M in such manner as to conform, where so required, to the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission ("FERC") for Public Utilities and Licensees ("Uniform System of Accounts"), and to the rules and regulations of other regulatory bodies having jurisdiction as they may from time to time be in effect. 1.4 The Owners shall establish such joint bank accounts as may from time to time be required or appropriate. 1.5 As soon as practicable after the end of each month, I&M and its Agent shall furnish to KPCO, AEGCO and PMA a statement setting forth the dollar amounts associated with the operation and maintenance of the Plant as allocated hereunder to I&M, KPCO and AEGCO and thereby a portion assigned to PMA for such month. The Owners shall, on a timely basis, deposit sufficient dollar amounts in the appropriate bank accounts to cover the current cash requirements of their respective allocations of such costs. 1.6 I&M and its Agent shall obtain such materials, labor and other services as it considers necessary in connection with the performance of the functions to be performed by it hereunder from such sources or through such persons as it may designate. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Indiana Michigan Power Company Original Sheet No. 5 Rate Schedule FERC No. 347 ARTICLE TWO APPORTIONMENT OF CAPACITY AND ENERGY 2.1 The Total Net Capability of Units No. 1 and 2 of the Plant, after taking into account auxiliary load demand, is 1,300,000 kilowatts each. The Owners and Non-Owners may from time to time modify the Total Net Capability of Units No. 1 and 2 as they may mutually agree. 2.2 The Total Net Generation of Units No. 1 and 2 during a given period, as determined by the system requirements of I&M, KPCO, AEGCO and PMA, shall mean the electrical output of Units No. 1 and 2 generators during such period, measured at the low voltage busses in kilowatt-hours by suitable instruments, reduced by the energy used by auxiliaries for the units and other plant use during such period. 2.3 In any hour, I&M, KPCO, AEGCO and PMA shall share the Total Net Capability of Units No. 1 and 2 in respective amounts proportionate to their ownership or assignment interests in Units No. 1 and 2 at such time. In any hour, the Total Net Generation of Units No. 1 and 2 shall be allocated separately by unit to each of the Owners and Non-Owners in accordance with the following; (a) The Net Generation of Unit No. 1 and/or Unit No. 2 assigned to meet a direct unit power commitment with a non-affiliated party (i.e., non-system sale) shall first be allocated to the Owner(s) which are party to such direct Unit Power Agreement; (b) The Net Generation of Unit No. 1 assigned to meet the dispatch request of PMA of its assigned generation entitlement shall next be allocated to PMA. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Indiana Michigan Power Company Original Sheet No. 6 Rate Schedule FERC No. 347 (c) The Net Generation of Units No. 1 and 2 not so assigned shall be shared by the Owners and KPCO in respective amounts proportionate to their ownership or assignment interests in Units No. 1 and 2 at such time until the Net Generation allocated to any Owner or KPCO in accordance with Sections 2.3(a) and 2.3(c) equals that Owner's or KPCO's owned or assigned share of the unit's Net Capability; (d) The Net Generation of Units No. 1 and 2 not allocated in accordance with Sections 2.3(a), 2.3(b) and 2 (c) shall be allocated to the remaining Owner(s) in relative amounts proportionate to their ownership interests such that no Owner shall be allocated amounts in any hour that exceed that Owner's share of that unit's Total Net Capability. 2.4 In any hour during which either Unit No. 1 or Unit No. 2 is out of service, the energy used by Unit No. 1 or Unit No. 2 auxiliaries during such hour shall be provided by I&M, KPCO, AEGCO and PMA in respective amounts proportionate to their ownership or assignment interests in Units No. 1 and 2 at such time. 2.5 I&M shall at all times accept the proportionate shares of Units No. 1 and 2 Total Net Generation to which KPCO, AEGCO and PMA may be entitled into its transmission system at the low-voltage busses of Units No. 1 and 2, and shall deliver the share of energy that KPCO, AEGCO and PMA are obligated to provide for use of Units No. 1 and 2 auxiliaries when either of such units is out of service, as part of the energy interchange between I&M, KPCO, AEGCO and PMA. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Indiana Michigan Power Company Original Sheet No. 7 Rate Schedule FERC No. 347 ARTICLE THREE REPLACEMENTS, ADDITIONS, AND RETIREMENTS 3.1 I&M and its Agent shall from time to time make or cause to be made any necessary additions to, replacements of, and retirements of capitalizable facilities associated with the Plant as may be mutually agreed upon by the Owners and Non-Owners. 3.2 The dollar amounts associated with any additions to, replacements of, or retirements or capitalizable facilities associated with the Plant shall be allocated to I&M and AEGCO in respective amounts proportionate to their ownership interests in the Plant at the time such additions, replacements, or retirements are made. ARTICLE FOUR WORKING CAPITAL REQUIREMENTS 4.1 I&M and AEGCO shall periodically mutually determine the amount of funds required for use as working capital in meeting payrolls and other expenses incurred in the operation and maintenance of the Plant, and in buying materials and supplies (exclusive of fuel) for the Plant. 4.2 I&M and AEGCO shall from time to time provide their share of working capital requirements in respective amounts proportionate to their ownership interests at such time in the Plant. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Indiana Michigan Power Company Original Sheet No. 8 Rate Schedule FERC No. 347 ARTICLE FIVE INVESTMENT IN FUEL 5.1 I&M and its Agent shall establish and maintain reserves of coal in stock for the Plant of such quality and in such quantity as I&M and its Agent shall determine to be required to provide adequate fuel reserves against interruptions of normal fuel supply. Each of the Owners shall be responsible for the cost of maintaining its respective ownership share of such fuel reserves in terms of tons. 5.2 Fuel oil reserves and fuel oil charged to operation for Units No. 1 and 2 shall be owned and accounted for between the Owners in the same manner as coal. 5.3 PMA and KPCO shall have the option, on six (6) months' notice, to supply the fuel necessary to operate its Assigned Capacity in Unit No. 1 and/or Unit No. 2. As of the effective date of this Agreement, PMA's Assigned Capacity in Unit No. 1 shall be equal to 35% of the Total Net Capability of Unit No. 1, KPCO's Assigned Capacity shall be equal to 15% of the Total Net Capability of Unit No 1 and Unit No. 2, and I&M's Assigned Capacity shall be equal to 35% of the Total Net Capability of such Unit No. 1, and I&M's owned capacity shall be equal to 50% of the Total Net Capacity of Unit No. 1 and Unit No. 2. The Operating Committee shall adjust these Assigned Capacities to reflect subsequent changes in the Owners' and Non-Owners' ownership or assigned rights in Units No. 1 and 2. The option, once noticed, may not be revoked without I&M's consent. 5.3.1 If a Non-Owner exercises the option described in Section 5.3 with respect to Unit No. 1 and/or Unit No. 2, the Non-Owner shall have the right to use delivery and storage facilities, including rights of access, owned by I&M or its Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Indiana Michigan Power Company Original Sheet No. 9 Rate Schedule FERC No. 347 Agent or under contract to I&M or its Agent for the delivery to or storage of such fuel at the Plant, for use in connection with such unit(s). The Non-Owner shall pay a monthly charge reflecting the proportional cost of its use of fuel delivery and storage facilities in each month. 5.3.2 In the event that a Non-Owner exercises the option described in Section 5.3 with respect to Unit No. 1 and/or Unit No. 2, the Operating Committee will identify, and determine the appropriate allocation to such Non-Owner of rights and obligations under, the applicable fuel supply contract(s), and any associated transportation contract(s), for fuel for such Non-Owner's Assigned Capacity in such unit(s). I&M and its Agent, as necessary, shall assign to such Non-Owner, and such Non-Owner shall accept assignment of, I&M's and its Agent's rights and obligations under such contracts which the Operating Committee has determined should be allocated to such Non-Owner for fuel for the unit(s) as to which the option has been exercised. If a Non-Owner exercises the option provided in this subsection, but for any reason the fuel supply that is such Non-Owner's responsibility is not timely delivered to such unit, such Non-Owner shall not have the right to commit or dispatch such unit. 5.3.3. In the event that a Non-Owner exercises the option to supply fuel described in Section 5.3 with respect to its Assigned Capacity in Unit No. 1 and/or Unit No. 2, the specifications for the fuel(s) supplied for such unit(s) will be established and, when appropriate, modified, by the Operating Committee. Fuel will be subject to inspection and certification procedures as the Operating Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Indiana Michigan Power Company Original Sheet No. 10 Rate Schedule FERC No. 347 Committee may decide. Fuel inventories at such unit(s), or at the Plant, may be physically commingled, but separate accounts will be maintained to reflect the fuel credited to each Owner and Non-Owner and used by each Owner and Non-Owner at each unit. The Operating Committee will develop procedures to avoid imbalances between the amount of fuel each Owner and Non-Owner delivers and the amount of fuel each Owner and Non-Owner uses, and shall take any steps necessary for the correction of any imbalance by settlement or payment as soon as feasible, but in no event shall imbalances be permitted to exist for more than six months without settlement or payment. The Fuel Costs of each Owner and Non-Owner with respect to any Plant Unit will be equal to the sum of minimum load and hourly average Fuel Costs (based on average heat rates at the unit's level of capacity utilization) associated with the energy that each schedules from that unit. 5.3.4 In the event that a Non-Owner exercises the option to supply fuel described in Section 5.3 with respect to its Assigned Capacity in Unit No. 1 and/or Unit No. 2, I&M will assign to such Non-Owner a fraction of the fuel inventory as of the date the option takes effect for such unit(s). The fraction shall be determined by multiplying to such Non-Owner's Assigned Capacity Percentage by the total fuel inventory of such unit(s) on the date of assignment. As of the effective date of this Agreement, PMA's Assigned Capacity Percentage with respect to Unit No. 1 shall be 35% and KPCO's Assigned Capacity Percentage shall be 15% with respect to each of Unit No. 1 and Unit No. 2. The Operating Committee shall adjust these Assigned Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Indiana Michigan Power Company Original Sheet No. 11 Rate Schedule FERC No. 347 Capacity Percentages to reflect any subsequent changes in the Owners' and Non-Owners' ownership or assigned rights in Units No. 1 and 2. The assignment shall be at the book value of the total inventory of that unit as of the date of assignment, less book value of the same fraction of the same inventory on the effective date of this Agreement. ARTICLE SIX APPORTIONMENT OF GENERATING STATION COSTS 6.1 For each calendar month, I&M and its Agent will, to the extent practicable, determine all Plant operation and maintenance expenses, as accounted for under the FERC Uniform System of Accounts, that are directly attributable separately to Unit No. 1 and Unit No. 2. In each calendar month, the portion allocable to Unit No. 1 of such expenses not directly attributable to Unit No. 1 or Unit No. 2 shall equal the product of (a) the total of such Plant expenses in each calendar month, and (b) the ratio of (i) the Total Net Capability of Unit No. 1 for such month and (ii) the Total Net Capability of the Plant for such month. The portion of such expenses not allocated to Unit No. 1 shall be allocated to Unit No. 2. 6.2 In each calendar month, the operation and maintenance expenses other than fuel associated with Units No. 1 and 2 shall be apportioned to I&M and AEGCO in proportion with their respective ownership interests in Units No. 1 and 2 in such month. 6.3 Each Owner shall bear the cost of all taxes directly attributable to its respective ownership interest in Units No. 1 and 2. Any taxes not directly assigned shall be Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Indiana Michigan Power Company Original Sheet No. 12 Rate Schedule FERC No. 347 apportioned to the Owners in accordance with their respective ownership interests in Units No. 1 and 2 in such month. ARTICLE SEVEN OPERATING COMMITTEE/UNIT DISPATCH 7.0 By written notice to each other, each Owner, Non-Owner and the Agent shall name one representative ("Operating Representative") and one alternate to act for it in matters pertaining to operating arrangements under this Agreement. For purpose of Sections 7.0 through 7.3 of this Agreement, the term "Parties" shall include the Owners, the Non-Owners and the Agent. The Operating Representatives for the respective Parties, or their alternates, shall comprise the Operating Committee. All decisions, directives, or other action by the Operating Committee must be by unanimous agreement of the Operating Representatives of I&M, KPCO, AEGCO and PMA. The Operating Representative of the Agent, or of any third party that provides services in replacement of the Agent, shall be free to express the views of the Agent or such third party on any matter, but shall not have a vote on the Operating Committee. If the Operating Representatives of I&M, KPCO, AEGCO and PMA are unable to agree on any matter, the matter will be resolved through the dispute resolution procedures set forth in Article Nine. 7.1 The Operating Committee shall have the following responsibilities: a) Review and approval of the annual budget and annual operating plan, including determination of emission allowances required to be acquired by I&M, AEGCO, KPCO and PMA. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Indiana Michigan Power Company Original Sheet No. 13 Rate Schedule FERC No. 347 b) Establishment of review of procedures and systems for dispatch, notification of dispatch, and unit commitment for the Plant under this Agreement, including any commitment of Called Capacity pursuant to Section 7.5.2. c) Establishment and monitoring of procedures for communication and coordination with respect to Plant capacity availability, fuel-firing options, and scheduling of outages for maintenance, repairs, equipment replacements, scheduled inspections, and other foreseeable cause of outages at any generating unit, as well as the return of any unit to availability following an unplanned outage. d) Decisions on capital expenditures, including unit upgrades and repowering of the Plant. e) Determinations as to changes in the unit capability of the Plant and decisions on unit retirement. f) Establishment and modification of billing procedures under this Agreement. g) Specification of fuels, oversight of fuel inspection and certification procedures, management of fuel inventories for the Plant and allocation of rights and obligations under fuel supply and transportation contracts in accordance with Section 5.3.2. h) Establishment of, termination of, and approval of any change or amendment to, operating arrangements between I&M and the Agent or any replacement third party with respect to any of the Plant generating Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Indiana Michigan Power Company Original Sheet No. 14 Rate Schedule FERC No. 347 units; provided, however, that the Agent or any replacement third party shall participate in discussions pursuant to this subsections 7.1.h only if and to the extent requested to do so by all of the Parties except the Agent. i) Review and approval of plans and procedures designed to insure compliance at the Plant with any environmental law, regulation, ordinance or permit, including procedures for allocating and using emission allowances or for any programs that permit averaging at more than one unit for compliance. j) Other duties as assigned by agreement of the Parties. 7.2 The Operating Committee shall meet at least quarterly, and at such other times as any Party may reasonably request. 7.3 The Parties shall cooperate in providing to the Operating Committee the information it reasonably needs to carry out its duties, and to supplement or correct such information on a timely basis. 7.4 The Agent on behalf of the Owners, and Non-Owners will each make initial unit commitments for the Plant one business day ahead of real-time dispatch. 7.5 For purposes of this Section and subsections of this Section, the terms "Party" or "Parties" refers to the Owners and the Non-Owners, or any of them, as the case may be. 7.5.1 Plant units designated to be committed by all Parties will be brought on line or kept on line and any unit at the Plant that no Party designated to be committed will remain off line or to be taken offline. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Indiana Michigan Power Company Original Sheet No. 15 Rate Schedule FERC No. 347 7.5.2 When a Plant unit is designated to be committed by one or more Parties with Assigned Capacity in such unit, but designated not to be committed by one or more Parties with Assigned Capacity in such unit, the unit will be brought on line or kept on line if the Part(ies) designating the unit for commitment undertakes to pay any applicable start-up costs for the unit, as well as any applicable minimum running costs for the unit thereafter, in which event the unit shall be brought on line or kept on line, as the case may be. The Part(ies) so designating the unit shall have the right to schedule and dispatch up to all of the Assigned Capacity of the unit available for dispatch. Each Party exercising this right shall be referred to as the "Calling Party," and the capacity called by that Party in excess of its Assigned Capacity Percentage of the Assigned Capacity of that unit available for dispatch shall be referred to as its "Called Capacity." The other Parties shall be referred to as the "Non-Calling Parties." Each Calling Party shall provide reasonable notice to the Non-Calling Parties of its call, including any start-up or shut-down time for each unit subject to its call. 7.5.3 A Non-Calling Party can reclaim any Called Capacity attributable to its Assigned Capacity share from any Plant unit by giving the appropriate Calling Part(ies) notice equal to the normal start-up time for the unit. At the end of the notice period, a Non-Calling Party shall have the right to schedule and dispatch the recalled capacity. At that Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Indiana Michigan Power Company Original Sheet No. 16 Rate Schedule FERC No. 347 point, the Non-Calling Party shall resume its responsibility for its share of any applicable start-up costs for unit, and prospectively shall bear its responsibility for the costs associated with its Assigned Capacity from the unit. 7.5.4 If any capacity remains available but is not dispatched from a Party's Assigned Capacity available for dispatch with respect to the unit committed as a result of the initial unit commitment, the other Parties may only schedule and dispatch such capacity pursuant to agreement with the non-dispatching Party. 7.6 I&M, KPCO, AEGCO and PMA shall be individually responsible for any fees charged by FERC on the basis of sales or transmission by each of capacity or energy at wholesale in interstate commerce. 7.7 To the extent such assignment has not previously occurred, on or before the effective date of this Agreement, the Agent, for the Owners, will assign to each of the Non-Owners the fraction, equal to such Non-Owner's Assigned Capacity Percentage of Unit No. 1 or Unit No. 2, of each vintage year of Emission Allowances, issued by the U.S. Environmental Protection Agency ("USEPA") pursuant to Title IV of the Clean Air Act Amendments of 1990 and any regulations thereunder ("Title IV Emission Allowances"), that it has received from the Administrator of USEPA with respect to any such units in the past and has not expended as of the date of assignment. In addition, the Agent, for the Owners, will assign to each of the Non-Owners, a fraction of such Title IV Emission Allowances which were purchased and held in any Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Indiana Michigan Power Company Original Sheet No. 17 Rate Schedule FERC No. 347 account for use at each unit in which the Non-Owner has Assigned Capacity. The fraction of such Title IV Emission Allowances to be assigned by the Agent, for the Owners, will be determined by multiplying such Non-Owner's Assigned Capacity Percentage in each unit by the total of such Title IV Emission Allowances that it has received or purchased for such unit and has not expended as of the date of assignment. Thereafter, Title IV Emission Allowances received with respect to those generating units will be shared by the Owners and Non-Owners in accordance with the Assigned Capacity Percentage of each of them in each unit. To the extent that additional Title IV Emission Allowances are required, the Owners and Non-Owners will each be responsible for acquiring sufficient Title IV Emission Allowances to satisfy the Title IV Emission Allowances required because of its dispatch of energy from each unit. The Agent will also determine the number and allocation of Title IV Emission Allowances to be supplied to any third-party unit operator under applicable designated representative agreements. On or before January 10 of each year, the Agent shall determine and notify the Owners and Non- Owners of the number of additional emission allowances consumed by each of them through December 31 of the previous year, and the Owners and Non-Owners shall each transfer into the appropriate generating unit U.S. EPA Allowance Transfer System account that number of Title IV Emission Allowances with a small compliance margin by January 31 of that year. In the event that any of the Owners or Non-Owner fails to surrender the required number of emission allowances by January 31, the Agent shall purchase the Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Indiana Michigan Power Company Original Sheet No. 18 Rate Schedule FERC No. 347 required number of emission allowances, and the Owner or Non-Owner, as the case may be, shall reimburse the Agent for such purchases, with interest at the Federal Funds Rate (as published by the Board of Governors of the Federal Reserve System as from time to time in effect) running from the date of the purchases to the date of payment. The Operating Committee will develop procedures to be implemented after the end of each calendar year to account for the Title IV Emission Allowances required by the use of each unit by the Owners and Non-Owners and to correct any imbalance between emission allowances supplied and emission allowances used through the end of the preceding year by settlement or payment. 7.8 Capital repairs and improvements will be determined by the Operating Committee pursuant to the annual budgeting process set forth in Section 7.9. Expenditures that the Operating Committee determines have been or will be incurred exclusively for one Owner shall be assigned exclusively to that Owner. 7.9 At least 90 days before the start of each Operating Year, I&M and its Agent shall submit to the Operating Committee a proposed annual budget with respect to the Plant generating units, a proposed annual operating plan with respect to those generating units, and an estimate and schedule of costs to be incurred for major maintenance or replacement items with respect to those generating units during the next six-year period. The annual budget shall be presented on a month-by-month basis for each month during the next operating year, and shall include an operating budget, a capital budget, an Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Indiana Michigan Power Company Original Sheet No. 19 Rate Schedule FERC No. 347 estimate of the cost of any major repairs that I&M and its Agent anticipate will occur during such operating year with respect to the Plant generating units and an itemized estimate of all projected non-fuel variable operating expenses relating to I&M's and its Agent's operation of those generating units during that operating year. The members of the Operating Committee will meet and work in good faith to agree upon the final annual budget and final annual operating plan. Once approved, the annual budget and annual operating plan shall remain in effect throughout the applicable operating year, subject to such changes, revisions, amendments, and updating as the Operating Committee may determine. ARTICLE EIGHT GENERAL 8.1 This Agreement shall inure to the benefit of and be binding upon the signatories hereto and their respective successors and assigns, but this Agreement may not be assigned by any signatory without the written consent of the other signatories, which consent shall not be unreasonably withheld. 8.2 This Agreement is subject to the regulatory authority of any state or federal agency having jurisdiction. 8.3 The interpretation and performance of this Agreement shall be in accordance with the laws of the State of Indiana, excluding conflict of laws principles that would require the application of the laws of a different jurisdiction. Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Indiana Michigan Power Company Original Sheet No. 20 Rate Schedule FERC No. 347 8.4 This Agreement supercedes any and all previous representations, understandings, negotiations, and agreements, either written or oral, that may have existed between the signatories or their representatives with respect to operation of the Plant, and constitutes the entire agreement of the signatories with respect to the operation of the Plant. ARTICLE NINE DISPUTE RESOLUTION 9.1 If any Owner or Non-Owner believes that a dispute has arisen as to the meaning or application of this Agreement, it shall present that matter to the Operating Committee in writing, and shall provide a copy of that writing to the other Owners and Non-Owners. 9.2 If the Operating Committee is unable to reach agreement on any dispute within thirty (30) days after the dispute is presented to it, the matter shall be referred to the chief operating officers of the Owners and Non-Owners involved in the dispute for resolution in the manner that such individuals shall agree is appropriate; provided, however, that any Owner or Non-Owner involved in a dispute may invoke the arbitration provisions set forth in Section 9.3 at any time after the end of the thirty (30)-day period provided for the Operating Committee to reach agreement if the Operating Committee has not reached agreement. 9.3 If the Owners and Non-Owners involved in a dispute are unable to resolve the dispute through the Operating Committee within thirty (30) days after the dispute is presented to the Operating Committee pursuant to Section 9.1, or through reference of the matter to the chief operating officers of such Owners and Non-Owners pursuant to Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Indiana Michigan Power Company Original Sheet No. 21 Rate Schedule FERC No. 347 Section 9.2, any Owner or Non-Owner involved in the dispute may commence arbitration proceedings by providing written notice to the other Owners or Non-Owners involved in the dispute, detailing the nature of the dispute, designating the issue(s) to be arbitrated, identifying the provisions of this Agreement under which the dispute arose, and setting forth such Owner's or Non-Owners' proposed resolution of such dispute. 9.3.1 Within ten (10) days of the date of the notice of arbitration, a representative of each Owner and Non-Owner involved in the dispute shall meet for the purpose of selecting an arbitrator. If the Owners' and Non-Owners' representatives are unable to agree on an arbitrator within fifteen (15) days of the date of the notice of arbitration, then an arbitrator shall be selected in accordance with the procedures of the American Arbitration Association ("AAA"). Whether the arbitrator is selected by the Owners' and Non-Owners' representatives or in accordance with the procedures of the AAA, the arbitrator shall have the qualifications and experience in the occupation, profession, or discipline relevant to the subject matter of the dispute. 9.3.2 Any arbitration proceeding shall be subject to the Federal Arbitration Act, 9 U. S.C. SS.SS. 1 ET SEQ. (1994), as it may be amended, or any successor enactment thereto, and shall be conducted in accordance with the commercial arbitration rules of the AAA in effect on the date of the notice to the extent not inconsistent with the provisions of this Article Nine. 9.3.3 The arbitrator shall be bound by the provisions of this Agreement where applicable, and shall have no authority to modify any terms and conditions of Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Indiana Michigan Power Company Original Sheet No. 22 Rate Schedule FERC No. 347 this Agreement in any manner. The arbitrator shall render a decision resolving the dispute in an equitable manner, and may determine that monetary damages are due to an Owner or Non-Owner or may issue a directive that an Owner or Non-Owner take certain actions or refrain from taking certain actions, but shall not be authorized to order any other form of relief; provided, however, that nothing in this Article shall preclude the arbitrator from rendering a decision that adopts the resolution of the dispute proposed by an Owner or Non-Owner. Unless otherwise agreed to by the Owners and Non-Owners involved in the dispute, the arbitrator shall render a decision within one hundred twenty (120) days of appointment, and shall notify the Owners and Non-Owners in writing of such decision and the reasons supporting such decision. The decision of the arbitrator shall be final and binding upon the Owners and Non-Owners, and any award may be enforced in any court of competent jurisdiction. 9.3.4 The fees and expenses of the arbitrator shall be shared equally by the Owners and Non-Owners involved in the dispute, unless the arbitrator specifies a different allocation. All other expenses and costs of the arbitration proceeding shall be the responsibility of the Owner or Non-Owner incurring such expenses and costs. 9.3.5 Unless otherwise agreed by the Owners and Non-Owners involved in the dispute, any arbitration proceedings shall be conducted in Columbus, Ohio. 9.3.6 Except as provided in this Article, the existence, contents, or results of any arbitration proceeding under this Article may not be disclosed without the prior written consent of the Owners and Non-Owners involved in the dispute, Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Indiana Michigan Power Company Original Sheet No. 23 Rate Schedule FERC No. 347 provided, however, that any such Owner or Non-Owner may make disclosures as may be required to fulfill regulatory obligations to any agencies having jurisdiction, and may inform its lenders, affiliates, auditors, and insurers, as necessary, under pledge of confidentiality, and may consult with expert consultants as required in connection with an arbitration proceeding under pledge of confidentiality. 9.3.7 Nothing in this Agreement shall be construed to preclude any Owner or Non-Owner from filing a petition or complaint with FERC with respect to any claim over which FERC has jurisdiction. In such case, the other Owners or Non-Owners may request that FERC reject the petition or complaint or otherwise decline to exercise its jurisdiction. If FERC declines to act with respect to all or part of a claim, the portion of the claim not so accepted by FERC may be resolved through arbitration, as provided in this Article. To the extent that FERC asserts or accepts jurisdiction over all or part of a claim, the decisions, findings of fact, or orders of FERC shall be final and binding, subject to judicial review under the Federal Power Act, and any arbitration proceedings that may have commenced prior to the assertion or acceptance of jurisdiction by FERC shall be stayed, pending the outcome of the FERC proceedings. The arbitrator shall have no authority to modify, and shall be conclusively bound by, any decisions, findings of fact, or orders of FERC; provided, however, that to the extent that any decisions, findings of fact, or orders of FERC do not provide a final or complete remedy to an Owner or Non-Owner seeking relief, such Owner or Non-Owner may proceed to Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Indiana Michigan Power Company Original Sheet No. 24 Rate Schedule FERC No. 347 arbitration under this Article to secure such a remedy, subject to any FERC decisions, findings, or orders. 9.4 The procedures set forth in this Article Nine shall be the exclusive means for resolving disputes arising under this Agreement and shall survive this Agreement to the extent necessary to resolve any disputes pertaining to this Agreement. Except as provided in Sections 9.3 and 9.3.7, no Owner or Non-Owner shall have the right to bring any dispute for resolution by a court, agency, or other entity having jurisdiction over this Agreement, unless all of the Owners and Non-Owners agree in writing to such procedure. 9.5 To the extent that a dispute involves the actions, inactions or responsibilities of the Agent under this Agreement, the provisions of this Article Nine shall be applicable to such dispute. For such purposes, the Agent shall be treated as an Owner or Non-Owner in applying the provisions of this Article Nine. IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be executed by their officers thereunto duly authorized as of the date first above written. INDIANA MICHIGAN POWER COMPANY BY: ---------------------------------- KENTUCKY POWER COMPANY BY: ---------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 Indiana Michigan Power Company Original Sheet No. 25 Rate Schedule FERC No. 347 AEP GENERATING COMPANY BY: ---------------------------------- POWER MARKETING AFFILIATE BY: ---------------------------------- AMERICAN ELECTRIC POWER SERVICE CORPORATION BY: ---------------------------------- Issued by: J. Craig Baker Effective Date: January 1, 2002 Senior Vice President, Regulation & Public Policy Issued on July 24, 2001 ATTACHMENT 11 AGREEMENT TO TERMINATE INTERIM ALLOWANCE AGREEMENT AND NOTICE OF TERMINATION OF INTERIM ALLOWANCE AGREEMENT AGREEMENT TERMINATING INTERIM ALLOWANCE AGREEMENT APPALACHIAN POWER COMPANY, KENTUCKY POWER COMPANY, INDIANA MICHIGAN POWER COMPANY, OHIO POWER COMPANY, COLUMBUS SOUTHERN POWER COMPANY, AND AMERICAN ELECTRIC POWER SERVICE CORPORATION AS AGENT EFFECTIVE JANUARY 1, 2002 AGREEMENT TERMINATING INTERIM ALLOWANCE AGREEMENT This Agreement Terminating Interim Allowance Agreement ("Termination Agreement") is made and entered into as of this ____ day of ________________, 2001, by and among Appalachian Power Company ("APO"), a Virginia corporation; Columbus Southern Power Company ("CSP"), an Ohio corporation; Indiana Michigan Power Company ("I&M"), an Indiana corporation; Kentucky Power Company ("KPO"), a Kentucky corporation; Ohio Power Company ("OPO"), an Ohio corporation; said companies (herein sometimes called "Members" when referred to collectively and "Member" when referred to individually) being affiliated companies of the integrated public utility electric system known as the American Electric Power System ("AEP"); and American Electric Power Service Corporation ("Agent"), a New York corporation, being a service company engaged solely in the business of furnishing essential services to the aforesaid companies and the other affiliated companies. The Members and the Agent are herein referred to collectively as the "Parties" and individually as "Party." WHEREAS, the Members own and operate electric facilities in the states herein indicated: (a) APO in Tennessee, Virginia, and West Virginia, (b) CSP in Ohio, (c) I&M in Indiana and Michigan, (d) KPO in Kentucky, and (e) OPO in Ohio and West Virginia; WHEREAS, the Parties have entered into an Interconnection Agreement, dated July 6, 1951, with modifications thereto, which provides for certain understandings, conditions, and procedures designed to achieve the full benefits and advantages available through the coordinated planning and operation of the Members' power supply facilities ("AEP Interconnection Agreement"); -2- WHEREAS, APO, KPO, I&M and the Agent have entered into a Restated and Amended Interconnection Agreement, dated as of even or approximately even date herewith ("Amended Interconnection Agreement"), which modifies the AEP Interconnection Agreement; WHEREAS, OPO and CSP are not parties to the Amended Interconnection Agreement; WHEREAS, the Parties entered into the AEP System Interim Allowance Agreement, dated as of July 28, 1994, as subsequently amended ("Interim Allowance Agreement"), which provides for the allocation of air emissions allowances among the Members in connection with certain transactions undertaken by one or more of the Members pursuant to the AEP Interconnection Agreement; WHEREAS, the Amended Interconnection Agreement makes provision for allocation of emissions allowances; and WHEREAS, the Parties have determined that the Interim Allowance Agreement can be terminated as of the effective date of the Amended Interconnection Agreement. NOW, THEREFORE, in consideration of the premises and the mutual covenants and agreements herein set forth, the Parties mutually agree as follows: 1. TERMINATION OF INTERIM ALLOWANCE AGREEMENT. Subject to the Federal Energy Regulatory Commission's ("FERC") approval or acceptance for filing, the Interim Allowance Agreement shall be terminated as of the later of January 1, 2001 or the date that the Amended Interconnection Agreement becomes effective in accordance with the terms thereof. 2. ENTIRE AGREEMENT. This Termination Agreement constitutes the entire understanding between the Parties, and supersedes any and all previous understanding -3- between the Parties, with respect to the subject matter hereof. This Termination Agreement shall be binding upon and inure to the benefit of the Parties, and their respective successors and assigns 3. CHOICE OF LAW. This Termination Agreement shall be interpreted, construed and governed by the laws of the State of Ohio, without regard to any applicable conflict of laws provision. 4. FURTHER ASSURANCES. If any Party determines in its reasonable discretion that any further instruments, assurances, or other things are necessary or desirable to carry out the terms of this Termination Agreement, the other Parties shall execute and deliver all such instruments or assurances, and do all things reasonably necessary or desirable to carry out the terms of this Termination Agreement. 5. COUNTERPARTS. This Termination Agreement may be executed in any number of counterparts, each of which shall be an original, but all of which together shall constitute one and the same instrument. 6. AMENDMENTS. No amendments or changes to this Termination Agreement shall be binding unless made in writing and duly executed by all of the Parties and accepted or approved by the FERC. 7. NO THIRD PARTY BENEFICIARIES. This Termination Agreement does not create rights of any character whatsoever in favor of any person, corporation, association, entity or power supplier, other than the Parties, and the obligations herein assumed by the Parties are solely for the use and benefit of the Parties. Nothing in this Termination Agreement shall be construed as permitting or vesting, or attempting to permit or vest, in any person, corporation, association, entity or power supplier, other than the -4- Parties, any rights hereunder or in any of the resources or facilities owned or controlled by the Parties or the use thereof. 8. WAIVERS. Any waiver at any time by a Party of its rights with respect to a default under this Termination Agreement, or with respect to any other matter arising in connection with this Termination Agreement, shall not be deemed a waiver with respect to any subsequent default or matter. Any delay, short of the statutory period of limitation, in asserting or enforcing any right under this Termination Agreement, shall not be deemed a waiver of such right. 9. SECTION HEADINGS. The descriptive headings of the Sections of this Termination Agreement are used for convenience only, and shall not modify or restrict any of the terms and provisions thereof. 10. NOTICE. Any notice or demand for performance required or permitted under any of the provisions of this Tennination Agreement shall be deemed to have been given on the date such notice, in writing, is deposited in the U.S. mail, postage prepaid, certified or registered mail, addressed to the Parties at the addresses specified below: Appalachian Power Company 1 Riverside Plaza Columbus, Ohio 43215 Kentucky Power Company 1 Riverside Plaza Columbus, Ohio 43215 Indiana Michigan Power Company 1 Riverside Plaza Columbus, Ohio 43215 Columbus Southern Power Company 1 Riverside Plaza Columbus, Ohio 43215 -5- Ohio Power Company 1 Riverside Plaza Columbus, Ohio 43215 AGENT 1 Riverside Plaza Columbus, Ohio 43215 or in such other form or to such other address as the Parties may stipulate. 11. REGULATORY AUTHORIZATION. This Termination Agreement is subject to and conditioned upon its approval or acceptance for filing without material condition or modification by the FERC. In the event that this Termination Agreement is not so approved or accepted for filing in its entirety without modification, or the FERC subsequently modifies this Termination Agreement upon complaint or upon its own initiative, any Party may terminate this Termination Agreement by giving notice to the other Parties within thirty days. IN WITNESS WHEREOF, the Parties have caused this Termination Agreement to be executed and attested by their duly authorized officers on the day and year first above written. APPALACHIAN POWER COMPANY By:_______________________________________ Title:____________________________________ KENTUCKY POWER COMPANY By:_______________________________________ Title:____________________________________ INDIANA MICHIGAN POWER COMPANY By:_______________________________________ -6- By:_______________________________________ Title:____________________________________ OHIO POWER COMPANY By:_______________________________________ Title:____________________________________ COLUMBUS SOUTHERN POWER COMPANY By:_______________________________________ Title:____________________________________ AMERICAN ELECTRIC POWER SERVICE CORPORATION By:_______________________________________ Title:____________________________________ -7- ATTACHMENT 11 (CONTINUED) NOTICE OF TERMINATION OF INTERIM ALLOWANCE AGREEMENT Appalachian Power Company Supplement No. 9 to First Revised Sheet No. 1 Rate Schedule FPC No. 20 Columbus Southern Power Company Supplement No. 3 to Rate Schedule FERC No. 30 Indiana Michigan Power Company Supplement No. 10 to Rate Schedule FPC No. 17 Kentucky Power Company Supplement No. 6 to Rate Schedule FPC No. 11 Ohio Power Company Supplement No. 9 to Rate Schedule FPC No. 23 NOTICE OF CANCELLATION ---------------------- Cancels Appalachian Power Company Supplement No. 9 to Rate Schedule FPC No. 20 Columbus Southern Power Company Supplement No. 3 to Rate Schedule FERC No. 30 Indiana Michigan Power Company Supplement No. 10 to Rate Schedule FPC No. 17 Kentucky Power Company Supplement No. 6 to Rate Schedule FPC No. 11 Ohio Power Company Supplement No. 9 to Rate Schedule FPC No. 23 Effective: January 1, 2002 UNITED STATES OF AMERICA FEDERAL ENERGY REGULATORY COMMISSION Appalachian Power Company ) Docket No. ER01-___-000 Columbus Southern Power Company ) Indiana Michigan Power Company ) Kentucky Power Company ) Ohio Power Company ) NOTICE OF TERMINATION (__________________) Notice is hereby given that effective on January 1, 2002, Modification No. 1 to the AEP System Interim Allowance Agreement (designated as Appalachian Power Company Supplement No. 9 to Rate Schedule FPC No. 20, Columbus Southern Power Company Supplement No. 3 to Rate Schedule FERC No. 30, Indiana Michigan Power Company Supplement No. 10 to Rate Schedule FPC No. 17, Kentucky Power Company Supplement No. 6 to Rate Schedule FPC No. 11, Ohio Power Company Supplement No. 9 to Rate Schedule FPC No. 23) filed with the Federal Energy Regulatory Commission by American Electric Power Service Corporation, on behalf of Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company, and Ohio Power Company and accepted for filing on August 30, 1996 in Docket No. ER96-2213-000, is to be terminated in accordance with the mutual consent of the parties thereto. Appalachian Power Company By: /s/ Henry W. Fayne --------------------------- Henry W. Fayne Vice-President of Appalachian Power Company Columbus Southern Power Company By: /s/ Henry W. Fayne ------------------------ Henry W. Fayne Vice-President of Columbus Southern Power Company Ohio Power Company By: /s/ Henry W. Fayne --------------------------- Henry W. Fayne Vice-President of Ohio Power Company Indiana Michigan Power Company By: /s/ Henry W. Fayne ------------------------ Henry W. Fayne Vice-President of Indiana Michigan Power Company Kentucky Power Company By: /s/ Henry W. Fayne --------------------------- Henry W. Fayne Vice-President of Kentucky Power Company American Electric Power Service Corporation By: /s/ Henry W. Fayne ------------------------ Henry W. Fayne Executive Vice-President of American Electric Power Service Corporation Dated: July 20, 2001 ATTACHMENT 12 TABLE COMPARING COSTS SHARED UNDER THE CURRENT AEP-EAST INTERCONNECTION AGREEMENT, THE AEP-WEST OPERATING AGREEMENT, AND THE SYSTEM INTEGRATION AGREEMENT AND THE PROPOSED AMENDMENTS AEP EAST INTERCONNECTION AGREEMENT / AEP WEST OPERATING AGREEMENT SUMMARY 2002 2003 2004 ---- ---- ---- $ millions Expected Change From Existing Agreements.(1) ( ) = cost reduction I&M (16) (8) (5) APCo (25) (33) (8) KPCo (24) 10 (19) PSO (5) (6) (15) SWEPCo 12 2 (3) Expected Change Over Total Revenues (%).(2) I&M -1.5% -0.8% -0.5% APCo -1.8% -2.4% -0.6% KPCo -8.8% 3.7% -7.0% PSO -0.6% -0.7% -1.8% SWEPCo 1.2% 0.2% -0.3% (1) Forecasted change in total fuel and purchase power costs. (2) Total 2000 Actual Retail & Wholesale Sales. (Source: FERC Form 1) $ millions ---------- I&M 1,037 APCo 1,385 KPCo 272 PSO 855 SWEPCo 977 AEP EAST: COMPARISON OF 5 CO. VS. 3 CO. AGREEMENT I&M 5 COMPANY AGREEMENT 2002 2003 2004 ================================================================================ SUPPLY COSTS LESS POOL/OSS REVENUES ($ millions): Costs: Fuel (151) 263 255 278 Var. O&M 41 59 72 Rockport Demand 54 57 58 External Purchases (excl. capacity) 0 0 1 Capacity 2 1 3 Prim. Ener. Rec. less Deliv. (63) (45) (56) Capacity Settlement -- -- -- ------ ------ ------ 298 328 355 Revenue: Capacity Settlement 30 32 31 SIA Off System Sharing (5) (1) 3 Off Sys. Sales Margin 76 62 53 Off Sys. Sales Cost Recov. 25 24 38 ------ ------ ------ 126 117 124 NET. ( ) = cost (172) (211) (231) GWh: Generation 34,962 32,802 34,999 Purchases 13 15 43 Prim. Ener. Rec. less Deliv. (7,063) (4,940) (5,715) Off System Sales (1,787) (1,338) (2,150) Other (1,850) (1,695) (1,770) ------ ------ ------ NET 24,275 24,845 25,407 TOTAL AFFECTED COST (m/kwh) 7.08 8.51 9.10 NET ENERGY COST (m/kwh) 7.21 7.53 7.28 ================================================================================ 3 COMPANY AGREEMENT 2002 2003 2004 ================================================================================ SUPPLY COSTS LESS POOL/OSS REVENUES ($ millions): Costs: Fuel (151) 264 258 280 Var. O&M 41 56 72 Rockport Demand 54 57 58 External Purchases (excl. capacity) 1 1 1 Capacity -- -- 1 Prim. Ener. Rec. less Deliv. (94) (77) (87) Capacity Settlement -- -- -- ------ ------ ------ 266 295 328 Revenue: Capacity Settlement -- -- -- SIA Off System Sharing (10) (6) (6) OFF Sys. Sales Margin 93 72 68 Off Sys. Sales Cost Recov. 26 26 38 ------ ------ ------ 110 92 100 NET. ( ) = cost (156) (203) (226) GWh: Generation 35,043 33,051 35,149 Purchases 25 58 70 Prim. Ener. Rec. less Deliv. (7,124) (5,184) (5,900) Off Sys. Sales (1,820) (1,386) (2,141) Other (1,850) (1,695) (1,770) ------ ------ ------ NET 24,275 24,845 25,408 TOTAL AFFECTED COST (m/kwh) 6.43 8.18 8.89 NET ENERGY COST (m/kwh) 5.93 6.28 6.15 Note: "Total Affected Cost" those costs affected under the proposed modifications. "Net Energy Cost" reflects FERC Account 151 fuel costs (which are a sub-set of Total Affected Costs). BAKER AEP EAST: COMPARISON OF 5 CO. VS. 3 CO. AGREEMENT APCo 5 Company Agreement 2002 2003 2004 ================================================================================ SUPPLY COSTS LESS POOL/OSS REVENUES ($ millions): Costs: Fuel (151) 398 438 431 Var. O&M 45 86 86 Rockport Demand -- -- -- External Purchases (excl. capacity) 3 4 5 Capacity 4 2 4 Prim. Ener. Rec. less Deliv. 111 90 117 Capacity Settlement 126 136 136 ------ ------- ------ 687 756 778 Revenue: Capacity Settlement -- -- -- SIA Off System Sharing (8) (1) 5 Off Sys. Sales Margin 124 102 87 Off Sys. Sales Cost Recov. 79 84 82 ------ ------ ------ 195 185 173 NET. ( ) = cost (493) (571) (606) GWh: Generation 33,294 36,095 34,541 Purchases 93 142 174 Prim. Ener. Rec. less Deliv. 9,175 6,705 8,543 Off System Sales (5,538) (5,147) (4,704) Other -- -- -- ------ ------ ------ NET 37,025 37,795 38,554 TOTAL AFFECTED COST (m/kwh) 13.31 15.11 15.71 NET ENERGY COST (m/kwh) 11.71 11.85 12.23 ================================================================================ 3 Company Agreement 2002 2003 2004 ================================================================================ SUPPLY COSTS LESS POOL/OSS REVENUES ($ millions): Costs: Fuel (151) 397 447 435 Var. O&M 45 85 90 Rockport Demand -- -- -- External Purchases (excl. capacity) 20 30 21 Capacity 16 13 16 Prim. Ener. Rec. less Deliv. 129 54 128 Capacity Settlement -- -- -- ------ ------ ------ 607 630 689 Revenue: Capacity Settlement -- -- -- SIA Off System Sharing (2) (2) (2) Off Sys. Sales Margin 5 10 5 Off Sys. Sales Cost Recov. 86 85 88 ------ ------ ------ 89 92 91 NET. ( ) = cost (518) (538) (598) GWh: Generation 33,092 36,670 34,704 Purchases 584 1,043 674 Prim. Ener. Rec. less Deliv. 9,313 5,184 8,202 Off Sys. Sales (5,963) (5,102) (5,026) Other -- -- -- ------ ------ ------ NET 37,025 37,795 38,554 TOTAL AFFECTED COST (m/kwh) 13.99 14.23 15.51 NET ENERGY COST (m/kwh) 12.42 11.83 12.85 Note: "Total Affected Cost" those costs affected under the proposed modifications. "Net Energy Cost" reflects FERC Account 151 fuel costs (which are a sub-set of Total Affected Costs). AEP EAST: COMPARISON OF 5 CO. VS. 3 CO. AGREEMENT KPCo 5 COMPANY AGREEMENT 2002 2003 2004 ================================================================================ SUPPLY COSTS LESS POOL/OSS REVENUES ($ millions): Costs: Fuel (151) 121 98 130 Var. O&M 12 25 24 Rockport Demand 37 39 40 External Purchases (excl. capacity) 0 0 0 Capacity 1 0 1 Prim. Ener. Rec. less Deliv. (31) 1 (34) Capacity Settlement 13 14 15 ------ ----- ------ 154 178 176 Revenue: Capacity Settlement -- -- -- SIA Off System Sharing (2) (0) 1 Off Sys. Sales Margin 27 22 19 Off Sys. Sales Cost Recov. 11 15 10 ------ ----- ------ 36 37 30 NET. ( ) = cost (117) (141) (146) GWh: Generation 10,724 8,527 10,758 Purchases 12 16 28 Prim. Ener. Rec. less Deliv. (2,296) 51 (2,237) Off System Sales (842) (841) (640) Other -- -- -- ------ ----- ------ NET 7,598 7,752 7,909 TOTAL AFFECTED COST (m/kwh) 15.44 18.19 18.41 NET ENERGY COST (m/kwh) 10.44 10.93 10.87 ================================================================================ 3 COMPANY AGREEMENT 2002 2003 2004 ================================================================================ SUPPLY COSTS LESS POOL/OSS REVENUES ($ millions): Costs Fuel (151) 121 98 130 Var. O&M 14 25 27 Rockport Demand 37 39 40 External Purchases (excl. capacity) 0 1 1 Capacity 2 2 2 Prim. Ener. Rec. less Deliv. (35) 23 (41) Capacity Settlement -- -- -- ------ ----- ------ 139 187 160 Revenue: Capacity Settlement -- -- -- SIA Off System Sharing (4) (2) (2) Off Sys. Sales Margin 38 24 25 Off Sys. Sales Cost Recov. 12 15 10 ------ ----- ------ 46 36 33 NET. ( ) = cost (93) (151) (127) GWh: Generation 10,702 8,544 10,806 Purchases 19 31 48 Prim. Ener. Rec. less Deliv. (2,189) (0) (2,302) Off Sys. Sales (935) (822) (643) Other -- -- -- ------ ----- ------ NET 7,598 7,752 7,909 TOTAL AFFECTED COST (m/kwh) 12.25 19.43 16.06 NET ENERGY COST (m/kwh) 9.74 13.85 10.09 Note: "Total Affected Cost" those costs affected under the proposed modifications. "Net Energy Cost" reflects FERC Account 151 fuel costs (which are a sub-set of Total Affected Costs). AEP WEST: COMPARISON OF 4 CO. VS. 2 CO. AGREEMENT PSO 4 COMPANY AGREEMENT 2002 2003 2004 ================================================================================ SUPPLY COSTS LESS POOL/OSS REVENUES ($ millions): Costs: Fuel (151) 400 392 383 Var. O&M 16 13 14 External Purchases (excl. capacity) 173 149 138 Capacity -- -- -- Prim. Ener. Rec. less Deliv. (59) (55) (48) Capacity Settlement -- -- -- ------ ------ ------ 529 500 487 Revenue: SIA Off System Sharing 11 1 (7) Off Sys. Sales Margin 23 21 20 Off Sys. Sales Cost Recov. 25 29 29 ------ ------ ------ 59 51 42 NET. ( ) = cost (471) (449) (445) GWh: Generation 15,532 16,778 17,493 Purchases 5,095 4,466 4,243 Prim. Ener. Rec. less Deliv. (1,392) (1,417) (1,398) Off System Sales (629) (833) (957) Other -- -- -- ------ ------ ------ NET 18,607 18,994 19,381 TOTAL AFFECTED COST (m/kwh) 25.30 23.62 22.96 NET ENERGY COST (m/kwh) 26.25 24.09 22.92 ================================================================================ 2 COMPANY AGREEMENT 2002 2003 2004 ================================================================================ SUPPLY COSTS LESS POOL/OSS REVENUES ($ millions): Costs: Fuel (151) 395 375 365 Var. O&M 15 13 13 External Purchases (excl. capacity) 164 147 138 Capacity -- -- -- Prim. Ener. Rec. less Deliv. (13) (11) (9) Capacity Settlement -- -- -- ------ ------ ------ 562 524 507 Revenue: SIA Off System Sharing 10 7 7 Off Sys. Sales Margin 41 34 32 Off Sys. Sales Cost Recov. 45 41 39 ------ ------ ------ 96 82 78 NET. ( ) = cost (466) (443) (430) GWh: Generation 15,315 16,215 16,823 Purchases 4,334 3,911 3,846 Prim. Ener. Rec. less Deliv. 129 107 71 Off Sys. Sales (1,171) (1,239) (1,359) Other -- -- -- ------ ------ ------ NET 18,607 18,994 19,381 TOTAL AFFECTED COST (m/kwh) 25.02 23.31 22.18 NET ENERGY COST (m/kwh) 26.96 24.79 23.47 Note: "Total Affected Cost" those costs affected under the proposed modifications. "Net Energy Cost" reflects FERC Account 151 fuel costs (which are a sub-set of Total Affected Costs). AEP WEST: COMPARISON OF 4 CO. VS. 2 CO. AGREEMENT SWEPCo 4 COMPANY AGREEMENT 2002 2003 2004 ================================================================================ SUPPLY COSTS LESS POOL/OSS REVENUES ($ millions): Costs: Fuel (151) 255 259 262 Var. O&M 12 12 11 External Purchases (excl. capacity) 36 39 42 Capacity -- -- -- Prim. Ener. Rec. less Deliv. (22) (36) (35) Capacity Settlement -- -- -- ------ ------ ------ 280 273 280 Revenue: SIA Off System Sharing 11 1 (6) Off Sys. Sales Margin 23 17 18 Off Sys. Sales Cost Recov. 30 24 29 ------ ------ ------ 63 42 41 NET. ( ) = cost (217) (231) (239) GWh: Generation 13,313 13,844 14,132 Purchases 1,279 1,370 1,473 Prim. Ener. Rec. less Deliv. (1,161) (1,584) (1,513) Off System Sales (680) (646) (871) Other -- -- -- ------ ------ ------ NET 12,751 12,984 13,221 TOTAL AFFECTED COST (m/kwh) 17.01 17.82 18.09 NET ENERGY COST (m/kwh) 18.71 18.26 18.16 ================================================================================ 2 COMPANY AGREEMENT 2002 2003 2004 ================================================================================ SUPPLY COSTS LESS POOL/OSS REVENUES ($ millions): Costs: Fuel (151) 239 235 240 Var. O&M 12 12 11 External Purchases (excl. capacity) 23 23 27 Capacity -- -- -- Prim. Ener. Rec. less Deliv. 13 11 9 Capacity Settlement -- -- -- ------ ------ ------ 286 281 286 Revenue: SIA Off System Sharing 6 4 4 Off Sys. Sales Margin 22 19 17 Off Sys. Sales Cost Recov. 29 25 29 ------ ------ ------ 57 47 50 NET. ( ) = cost (229) (234) (236) GWh: Generation 13,065 13,315 13,552 Purchases 867 757 859 Prim. Ener. Rec. less Deliv. (129) (107) (71) Off Sys. Sales (1,042) (981) (1,119) Other -- -- -- ------ ------ ------ NET 12,751 12,984 13,221 TOTAL AFFECTED COST (m/kwh) 17.99 17.99 17.89 NET ENERGY COST (m/kwh) 19.28 18.83 18.60 Note: "Total Affected Cost" those costs affected under the proposed modifications. "Net Energy Cost" reflects FERC Account 151 fuel costs (which are a sub-set of Total Affected Costs).