-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, QTHUxYdwXejgBOIYyvw7kx+aPJ/HkcA9eQicrmhXw/SPT4U3RnG9zsrHX2rj+IUZ 7kb7wR1ecWmEY2vGTZysjg== 0000950123-99-007892.txt : 19990823 0000950123-99-007892.hdr.sgml : 19990823 ACCESSION NUMBER: 0000950123-99-007892 CONFORMED SUBMISSION TYPE: U-1/A PUBLIC DOCUMENT COUNT: 10 FILED AS OF DATE: 19990820 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: SEC FILE NUMBER: 070-09381 FILM NUMBER: 99696770 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 AMERICAN ELECTRIC POWER COMPANY, INC. 1 File No. 70-9381 SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 * * * AMENDMENT NO. 3 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 --------------------------- and CENTRAL AND SOUTH WEST CORPORATION 1616 Woodall Rodgers Freeway, Dallas, Texas 75202 --------------------------- (Name of companies and top registered holding company parents filing this statement and address of principal executive offices) * * * Armando A. Pena Wendy G. Hargus Treasurer Treasurer American Electric Power Company, Inc. Central and South West Corporation 1 Riverside Plaza 1616 Woodall Rodgers Freeway Columbus, OH 43215 Dallas, TX 75202 Susan Tomasky Jeffrey D. Cross Senior Vice President and General Counsel Vice President and General Counsel American Electric Power Company, Inc. AEP Resources, Inc. 1 Riverside Plaza 1 Riverside Plaza Columbus, OH 43215 Columbus, OH 43215
2 Marianne K. Smythe Joris M. Hogan Wilmer, Cutler & Pickering Milbank, Tweed, Hadley & McCloy LLP 2445 M Street, N.W. 1 Chase Manhattan Plaza Washington, DC 20037-1420 New York, NY 10005
(Names and addresses of agents for service) 2 3 TABLE OF CONTENTS Page ITEM 1. DESCRIPTION OF MERGER 1 A. INTRODUCTION 1 B. DESCRIPTION OF THE 3 PARTIES TO THE MERGER 1. General Description 3 2. Description of 12 Energy Sales and Facilities 3. Electric Coordination 22 C. DESCRIPTION OF MERGER AND STATEMENT AS TO CONSIDERATION 25 1. Background of the Merger 25 2. Merger Agreement 26 3. Reasons for the Merger 27 4. AEP Management 28 Following the Merger ITEM 2. FEES, COMMISSIONS AND EXPENSES 28 ITEM 3. APPLICABLE STATUTORY PROVISIONS 29 A. SECTION 10(b) 31 1. Section 10(b)(1) 31 2. Section 10(b)(2) 40 3. Section 10(b)(3) 47 B. SECTION 10(c) 50 4 1. Section 10(c)(1) 50 2. Section 10(c)(2) 71 C. SECTION 10(f) 73 D. INTRA-SYSTEM FINANCING AND OTHER COMMISSION AUTHORIZATIONS 73 E. SERVICE AGREEMENT; APPROVAL OF METHODOLOGY FOR ALLOCATING COSTS UNDER THE SERVICE AGREEMENT 74 F. ACQUISITION OF NON-UTILITY BUSINESSES 75 G. ORGANIZATION OF MERGER SUB; ACQUISITION OF MERGER SUB COMMON STOCK 76 ITEM 4. REGULATORY APPROVAL 76 A. ANTITRUST CONSIDERATIONS 77 B. ATOMIC ENERGY ACT 77 C. FEDERAL POWER ACT 78 D. COMMUNICATIONS ACT 78 E. ARKANSAS COMMISSION 78 F. LOUISIANA COMMISSION 78 G. OKLAHOMA COMMISSION 79 H. TEXAS COMMISSION 79 I. INDIANA COMMISSION 4 5 J. KENTUCKY COMMISSION K. MISSOURI COMMISSION L. AFFILIATE CONTRACTS 80 ITEM 5. PROCEDURE 80 ITEM 6. EXHIBITS AND FINANCIAL STATEMENTS 80 ITEM 7. INFORMATION AS TO ENVIRONMENTAL 82 EFFECTS GLOSSARY OF TERMS The following abbreviations or acronyms used in this Application-Declaration are defined below: 250 MW Contract Path Contractual reservation of 250 MW over the Ameren system providing firm point-to-point transmission service from AEP's Breed-Casey interconnection with Ameren to CSW's MOKANOK line interconnection with Ameren AEGCo AEP Generating Company AEP American Electric Power Company, Inc. before the Merger, unless the context indicates otherwise AEPC AEP Communications, LLC AEP Common Stock AEP common stock, $6.50 par value AEPES AEP Energy Services, Inc. (formerly, AEP Energy Solutions, Inc.) AEPRESCO AEP Resources Service Company (formerly, AEP Energy Services, Inc.) AEP Resources AEP Resources, Inc. AEPSC American Electric Power Service Corporation
5 6 AEP System American Electric Power System, an integrated electric utility system owned and operated by AEP's U.S. electric utility subsidiaries Alliance RTO Application Application of Alliance RTO for Approval of Transaction under Section 203 of the Federal Power Act, FERC Docket No. EC99-80 (filed June 3, 1999) Ameren Ameren Corporation, a public utility holding company registered under the 1935 Act Antitrust Division Antitrust Division of U.S. Department of Justice APCo Appalachian Power Company Applicants AEP and CSW Arkansas Commission Arkansas Public Service Commission Atomic Energy Act Atomic Energy Act of 1954, as amended C3 Communications C3 Communications, Inc. Central Dispatch Planning Computer software program, developed by the Applicants using proprietary technology and technology licensed from third parties, which forecasts the generation needs of the Combined System and schedules each generating unit accordingly Central Economic Dispatch Computer software program, developed by the Applicants using proprietary technology and technology licensed from third parties, which adjusts, every four seconds, the dispatch of each generating unit within the Combined System Combined Company AEP following the Merger Combined System System resulting from combination of the AEP System and CSW System following the Merger Commission Securities and Exchange Commission CPL Central Power and Light Company CSPCo Columbus Southern Power Company
6 7 CSW Central and South West Corporation before the Merger, unless the context indicates otherwise CSW Common Stock CSW common stock, $3.50 par value CSW Credit CSW Credit, Inc. CSW Energy CSW Energy, Inc. CSW Energy Services CSW Energy Services, Inc. CSW International CSW International, Inc. CSW Leasing CSW Leasing, Inc. CSWS Central and South West Services, Inc. CSW System CSW Electric Power System, an integrated electric utility system, owned and operated by CSW's U.S. electric utility subsidiaries D.C. Circuit U.S. Court of Appeals for the District of Columbia Circuit Division Commission's Division of Investment Management DOJ U.S. Department of Justice Duke Duke Energy Corporation, an integrated energy and energy services provider including an electric public utility ECAR East Central Area Reliability Council Energy Act Energy Policy Act of 1992 EnerShop EnerShop Inc. Entergy Entergy Corporation, a public utility holding company registered under the 1935 Act ERCOT Electric Reliability Council of Texas EWG Exempt Wholesale Generator
7 8 Exchange Ratio specified in the Merger Agreement of converting CSW Common Stock for AEP Common Stock, i.e., each share of CSW Common Stock converts into 0.60 shares of AEP Common Stock Excluded Shares Shares of CSW Common Stock owned by AEP, Merger Sub or any other direct or indirect subsidiary of AEP and shares of CSW Common Stock that are owned by CSW or any direct or indirect subsidiary of CSW, in each case not held on behalf of third parties FCC Federal Communications Commission FERC Federal Energy Regulatory Commission FERC Stipulation Stipulation of American Electric Power Company, Inc., Central and South West Corporation, and Commission Trial Staff, FERC Docket No. EC 98-40 (filed June 24, 1999) FPA Federal Power Act FTC Federal Trade Commission FUCO Foreign Utility Company HHI Herfindahl-Hirschman Index HSR Act Hart-Scott-Rodino Antitrust Improvements Act of 1976 HVDC High Voltage Direct Current I&M Indiana Michigan Power Company Indiana Commission Indiana Utility Regulatory Commission IPP Independent Power Producer ISO Independent System Operator Kentucky Commission Kentucky Public Service Commission KPCo Kentucky Power Company KgPCo Kingsport Power Company
8 9 Kv Kilovolt KwH Kilowatt hours Louisiana Commission Louisiana Public Service Commission Merger Business combination of AEP and CSW pursuant to the Merger Agreement Merger Agreement Agreement and Plan of Merger, dated as of December 21, 1997 among CSW, AEP and Merger Sub in which Merger Sub will be merged with and into CSW and CSW will become a wholly-owned subsidiary of AEP Merger Sub Augusta Acquisition Corporation, to become a wholly owned subsidiary of AEP Missouri Commission Missouri Public Service Commission MOKANOK Line 345 Kv transmission line jointly owned by PSO, UE, Associated Electric Cooperative and Kansas Gas and Electric Company. Morgan Stanley Morgan Stanley & Co. Incorporated, an investment banking firm and CSW's financial adviser with respect to the Merger MW Megawatts Nanyang Electric Nanyang General Light Electric Co., Ltd. NCE New Century Energies, Inc. NEPOOL New England Power Pool 1935 Act Public Utility Holding Company Act of 1935, as amended 1995 Report The Regulation of Public Utility Holding Companies (report to Congress by the Division, June 1995) NRC Nuclear Regulatory Commission OASIS Open Access Same-Time Information System OATT Open Access Transmission Tariff
9 10 OG&E Oklahoma Gas & Electric Company Ohio Commission Public Utilities Commission of Ohio Oklahoma Commission Corporation Commission of the State of Oklahoma OPCo Ohio Power Company PG&E PG&E Corporation, a public utility holding company PSNH Public Service Company of New Hampshire PSO Public Service Company of Oklahoma QF Qualifying Facility as defined in the Public Utility Regulatory Policies Act of 1978 Registration Statement Joint Proxy Statement/Prospectus dated April 16, 1998 of AEP and CSW RTO Regional Transmission Organization Salomon Salomon Smith Barney Inc., an investment banking firm and AEP's financial adviser with respect to the Merger SEEBOARD SEEBOARD plc, one of the 12 regional electricity companies formed due to the restructuring and subsequent privatization of the United Kingdom electricity industry in 1990 Southern The Southern Company, a public utility holding company registered under the 1935 Act SPP Southwest Power Pool STP South Texas Project, a two-unit nuclear electricity generating station in which CPL owns a 25.2% interest STP Operating STP Nuclear Operating Company SWEPCO Southwestern Electric Power Company Texas Commission Public Utility Commission of Texas
10 11 UE Union Electric Company, a public utility and a wholly owned subsidiary of Ameren West Virginia Commission West Virginia Public Service Commission WPCo Wheeling Power Company WR Western Resources, Inc. WTU West Texas Utilities Company Yorkshire Electricity Yorkshire Electricity Group plc, one of the 12 regional electricity companies formed due to the restructuring and subsequent privatization of the United Kingdom electricity industry in 1990
ITEM 1. DESCRIPTION OF MERGER Applicants, pursuant to Sections 6, 7, 9(a)(1) and 10, 11, 12, 13, 32 and 33 of the 1935 Act and the rules thereunder, hereby amend and restate the Form U-1 Application-Declaration in File No. 70-9381 ("Application-Declaration"). As set forth in greater detail below, Applicants hereby request the following authority from the Commission with respect to the proposed Merger of AEP, a New York corporation, and CSW, a Delaware corporation: a. the acquisition by AEP of all of the issued and outstanding CSW Common Stock; b. the acquisition by AEP of common stock of Merger Sub; c. the issuance of AEP Common Stock to effect the Merger; d. the amendment of AEP's existing authority to authorize the Combined Company to support the financing arrangements and to conduct the business activities of CSW (as discussed in Item 3.D below); e. the adoption of a service agreement to permit, under Section 13 of the 1935 Act and the Commission's rules thereunder, AEPSC (the surviving service company for the Combined System after CSWS is merged into AEPSC) to render services to the Combined Company's utility and non-utility subsidiaries and an expansion of AEP's allocation factors following the Merger (as discussed in Item 3.E below); and f. the acquisition by AEP of CSW's non-utility businesses (to the extent jurisdictional, as discussed in Item 3.F below). Applicants further request that the Commission grant such other authority as may be necessary in connection with the Merger. 11 12 A. INTRODUCTION This Application-Declaration seeks approvals relating to the proposed Merger of AEP and CSW. Pursuant to the Merger Agreement, AEP will acquire all of the issued and outstanding shares of CSW Common Stock. Both AEP and CSW are registered with the Commission as holding companies under the 1935 Act. (References to "AEP" or "CSW" refer to each Applicant and/or its subsidiaries, jointly or separately.) AEP owns all of the outstanding shares of common stock of seven U.S. electric utility operating subsidiaries: APCo, CSPCo, I&M, KPCo, KgPCo, OPCo and WPCo. The service area of AEP's electric utility subsidiaries covers portions of Indiana, Kentucky, Michigan, Ohio, Tennessee, Virginia and West Virginia. AEP also owns all of the common stock of AEGCo and AEPSC, among others. AEP indirectly owns 50% of the outstanding share capital of Yorkshire Electricity. CSW owns all of the outstanding shares of common stock of four U.S. electric utility operating subsidiaries: CPL, PSO, SWEPCO and WTU. The service area of CSW's electric utility subsidiaries covers portions of Arkansas, Louisiana, Oklahoma and Texas. CSW also owns all of the common stock of CSWS, among others, and indirectly owns all of the outstanding share capital of SEEBOARD. The Merger Agreement provides for a business combination of AEP and CSW in which Merger Sub will be merged into CSW. CSW will be the surviving corporation and will become a wholly owned subsidiary of AEP. Immediately following the Merger, the Combined Company will be a holding company with respect to CSW, which, in turn, will be a holding company with respect to the electric utility subsidiaries and other subsidiaries it currently owns (with the exception of CSWS, which will be merged into AEPSC, and CSW Credit, which will be directly held by the Combined Company). AEP's utility and non-utility subsidiaries will remain subsidiaries of AEP, and CSW's utility and non-utility subsidiaries, which will continue to be owned by CSW, will become indirect subsidiaries of AEP (except for CSWS and CSW Credit). The final ownership structure has not yet been determined. Upon consummation of the Merger, each share of issued and outstanding CSW Common Stock (other than Excluded Shares) will be exchangeable for 0.60 shares of AEP Common Stock. The former holders of CSW Common Stock will own approximately 40% of the outstanding shares of AEP Common Stock after the Merger. The only voting securities of AEP that will be publicly held will be AEP Common Stock; the Merger is expected to have no effect on the issued and outstanding public debt securities, preferred stock and/or preferred trust securities of CSW and the respective subsidiaries of AEP and CSW. With respect to the cost of capital of AEP and CSW, the nationally recognized rating agencies of Moody's Investors Service, Standard & Poor's, Duff & Phelps and Fitch reaffirmed their rating of the outstanding first mortgage bonds, commercial paper and other rated securities of AEP and CSW and/or their subsidiaries shortly after the Merger announcement. Since that time, there has been no merger-related change in any of the ratings by the rating agencies. 12 13 The Merger will produce substantial benefits to the public, investors and consumers and will meet all applicable standards of the 1935 Act. Applicants believe that the Merger offers significant strategic and financial benefits to them and to their respective shareholders, as well as to their employees, customers and the communities in which they provide service. These benefits include, among others: (i) The Combined Company will operate more efficiently and be better equipped to keep rates low in an increasingly competitive electric utility industry; (ii) The Combined Company will achieve savings through the elimination of duplication in corporate and administrative programs, greater efficiencies in operations and business processes, improved purchasing power, and the combination of two workforces; (iii) The Merger will result in a Combined Company with a stronger financial base, improved position in the credit markets and greater market diversity; (iv) The Merger will diversify the service territory of the Combined System, reducing exposure to local changes in economic and competitive conditions; and (v) The Merger will enhance the profitability of the Combined Company through increased scale. Applicants estimate the net non-fuel savings from the Merger to be nearly $2 billion and the net fuel-related savings to be approximately $98 million over the first ten years following the Merger. The projected Merger fuel and non-fuel savings are discussed in greater detail in Item 3.B.2 below. A copy of the Merger Agreement is incorporated by reference and attached as Exhibit B-1. At their Annual Meeting on May 27, 1998, holders of AEP Common Stock overwhelmingly approved the shareholder actions necessary to effect the Merger. The following day, holders of CSW Common Stock overwhelmingly approved the Merger at their Annual Meeting. Various aspects of the Merger are subject to the approval of this Commission as well as the: (i) FERC; (ii) NRC; (iii) FCC; (iv) Louisiana Commission; (v) Oklahoma Commission; and (vi) Arkansas Commission. In addition, the Applicants must obtain pre-Merger clearance from the DOJ according to procedures set forth in the HSR Act and a determination by the Texas Commission that the Merger is consistent with the public interest. Applicants have made filings with each of these regulatory agencies. The NRC approved the transfer of control of CPL's NRC licenses, a copy of which is filed as Exhibit D-6.2 and incorporated by reference. In July 1999, Applicants filed with the DOJ under the HSR Act. On July 29, 1999, Applicants filed an application with the FCC to transfer control of certain licenses held by CSW subsidiaries to AEP, a copy of which is filed as Exhibit D-9.1. Orders approving the Merger have been received from the Arkansas Commission, the Louisiana Commission, the Oklahoma Commission, the Kentucky Commission, and the Indiana Commission, copies of which are filed as Exhibit D-2.2, Exhibit D-3.2, Exhibit D-4.2, Exhibit D-7.1, and Exhibit D-8.1, respectively, and incorporated by reference. At FERC, a procedural schedule has been adopted which directs the Administrative Law Judge to issue an Initial Decision no later than November 24, 1999. This schedule will 13 14 allow FERC to issue a decision no later than March 2000. To realize the benefits of the Merger promptly, Applicants ask that the Commission review this Application-Declaration and issue an order approving the Merger and granting authority for the attendant transactions set forth above as expeditiously as practicable without a hearing. B. DESCRIPTION OF THE PARTIES TO THE MERGER 1. General Description a. AEP AEP, a New York corporation, has its principal executive offices at 1 Riverside Plaza, Columbus, Ohio. AEP was incorporated under the laws of the State of New York in 1906 and reorganized in 1925. AEP is a registered public utility holding company that owns all of the outstanding shares of common stock of seven U.S. electric utility operating subsidiaries: APCo, CSPCo, I&M, KPCo, KgPCo, OPCo and WPCo. Most of the operating revenues of AEP and its subsidiaries are derived from sales of electricity. AEP also owns, either directly or indirectly, all of the common stock of four material non-utility businesses -- AEP Resources, AEPRESCO, AEPC, and AEPES -- and all of the common stock of two other businesses -- AEGCo and AEPSC. AEP indirectly owns 50% of the outstanding share capital of Yorkshire Electricity. AEP and its subsidiaries are subject to the broad regulatory provisions of the 1935 Act administered by the Commission. Various of its subsidiaries are also subject to regulation by the FERC under the FPA with respect to rates for interstate sale at wholesale and transmission of electric power, accounting and other matters and construction and operation of hydroelectric projects. AEP's electric utility operating subsidiaries serve approximately 3 million customers in Indiana, Kentucky, Michigan, Ohio, Tennessee, Virginia and West Virginia. The generating and transmission facilities of these subsidiaries are physically interconnected, and their operations are coordinated, as a single integrated electric utility system. Transmission networks are interconnected with extensive distribution facilities in the territories served. At December 31, 1997, the U.S. subsidiaries of AEP had a total of 17,844 employees. AEP, as such, has no employees. The electric utility operating subsidiaries of AEP are each described below: APCo (organized in Virginia in 1926) is engaged in the generation, sale, purchase, transmission and distribution of electric power to approximately 877,000 customers in the southwestern portion of Virginia and southern West Virginia, and in supplying electric power at wholesale to other electric utility companies and municipalities in those states and in Tennessee. At December 31, 1997, APCo had 3,877 employees. Among the principal industries served by APCo are coal mining, primary metals, chemicals and textile mill products. A comparatively small part of the properties and business of APCo is located in the northeastern end of Tennessee. APCo's retail rates and certain other matters are subject to regulation by the West Virginia Commission and the State Corporation Commission of Virginia. 14 15 CSPCo (organized in Ohio in 1937, the earliest direct predecessor company having been organized in 1883) is engaged in the generation, sale, purchase, transmission and distribution of electric power to approximately 621,000 customers in central and southern Ohio, and in supplying electric power at wholesale to other electric utilities and to municipally owned distribution systems within its service area. At December 31, 1997, CSPCo had 1,802 employees. Among the principal industries served by CSPCo are food processing, chemicals, primary metals, electronic machinery and paper products. CSPCo's retail rates and certain other matters are subject to regulation by the Ohio Commission. I&M (organized in Indiana in 1925) is engaged in the generation, sale, purchase, transmission and distribution of electric power to approximately 549,000 customers in northern and eastern Indiana and southwestern Michigan, and in supplying electric power at wholesale to other electric utility companies, rural electric cooperatives and municipalities. At December 31, 1997, I&M had 3,306 employees. Among the principal industries served by I&M are primary metals, transportation equipment, electrical and electronic machinery, fabricated metal products, rubber and miscellaneous plastic products and chemicals and allied products. I&M's retail rates and certain other matters are subject to regulation by the Indiana Commission and the Michigan Public Service Commission. I&M also is subject to regulation by the NRC under the Atomic Energy Act with respect to the operation of its nuclear generation plant. KPCo (organized in Kentucky in 1919) is engaged in the generation, sale, purchase, transmission and distribution of electric power to approximately 168,000 customers in eastern Kentucky, and in supplying electric power at wholesale to other utilities and municipalities in Kentucky. At December 31, 1997, KPCo had 731 employees. The principal industries served by KPCo include coal mining, petroleum refining, primary metals and chemicals. KPCo's retail rates and certain other matters are subject to regulation by the Kentucky Commission. KgPCo (organized in Virginia in 1917) provides electric service to approximately 43,000 customers in Kingsport and eight neighboring communities in northeastern Tennessee. KgPCo has no generating facilities of its own. It purchases electric power distributed to its customers from APCo. At December 31, 1997, KgPCo had 85 employees. The principal industries served by KgPCo include chemicals and allied products, paper products, stone, clay, glass and concrete products, textiles and printing products. KgPCo's retail rates and certain other matters are subject to regulation by the Tennessee Regulatory Authority. OPCo (organized in Ohio in 1907 and reincorporated in 1924) is engaged in the generation, sale, purchase, transmission and distribution of electric power to approximately 679,000 customers in the northwestern, east central, eastern and southern sections of Ohio, and in supplying electric power at wholesale to other electric utility companies and municipalities. At December 31, 1997, OPCo and its wholly owned subsidiaries had 4,376 employees. Among the principal industries served by OPCo are primary metals, rubber and plastic products, stone, clay, glass and concrete products, 15 16 petroleum refining and chemicals. OPCo's retail rates and certain other matters are subject to regulation by the Ohio Commission. WPCo (organized in West Virginia in 1883 and reincorporated in 1911) provides electric service to approximately 42,000 customers in northern West Virginia. WPCo has no generating facilities of its own. It purchases electric power distributed to its customers from OPCo. At December 31, 1997, WPCo had 94 employees. The principal industries served by WPCo include chemicals, coal mining and primary metal products. WPCo's retail rates and certain other matters are subject to regulation by the West Virginia Commission. AEGCo was organized in Ohio in 1982 as an electric generating company. AEGCo sells power at wholesale to I&M, KPCo and Virginia Electric and Power Company, an unaffiliated public utility. AEGCo has no employees. AEPSC provides, at cost, accounting, administrative, information systems, engineering, financial, legal, maintenance and other services to the AEP companies. The executive officers of AEP and its public utility subsidiaries are all employees of AEPSC. AEP, primarily through AEP Resources, AEPRESCO, AEPC, and AEPES, pursues new non-utility business opportunities, particularly those which allow use of its expertise. These subsidiaries are described below: AEP Resources' primary business is development of, and investment in, EWGs, FUCOs, QFs and other energy-related domestic and international investment opportunities and projects. AEP Resources indirectly owns 50% of the outstanding share capital of Yorkshire Electricity. Yorkshire Electricity is principally engaged in the distribution of electricity to approximately 2.1 million customers in its authorized service territory which is comprised of 3,860 square miles and located centrally on the east coast of England. AEP Resources' indirect subsidiary, AEP Pushan Power, LDC, has a 70% interest in Nanyang Electric, a joint venture organized to develop and build two 125 MW coal-fired generating units near Nanyang City in the Henan Province of The Peoples' Republic of China. Funding for the construction of the generating units has commenced and will continue through completion thereof, which is expected to occur sometime before the end of 1999. A subsidiary of AEP Resources also has an equity interest, which, subject to certain conditions, could reach 20%, in Pacific Hydro Limited, an Australian company that develops and operates hydroelectric facilities. In December 1998, AEP Resources, through wholly-owned subsidiaries, acquired CitiPower Pty., an electric distribution and retail sales company in Victoria, Australia. CitiPower Pty. serves approximately 240,000 customers in a service area that covers approximately 100 square miles in the city of Melbourne. 16 17 In December 1998, AEP Resources acquired from Equitable Resources, Inc. midstream gas operations consisting of: (i) a 2,000-mile intrastate pipeline system in Louisiana, (ii) four natural gas processing plants that straddle the pipeline, and (iii) a storage facility, including an existing salt dome storage cavern and a second cavern under construction, both connected to the most active gas trading area in North America. The pipeline and storage facility are interconnected to 15 interstate and 23 intrastate pipelines. The gas trading and marketing group included in this purchase was acquired by AEPES. AEP received approval from the Commission under the 1935 Act to issue and sell securities in an amount up to 100% of its consolidated retained earnings (approximately $1,645,000,000 at June 30, 1998) for investment in EWGs and FUCOs through AEP Resources. American Elec. Power Co., HCAR No. 26864 (Apr. 27, 1998). AEPRESCO offers engineering, construction, project management and other consulting services for projects involving transmission, distribution or generation of electric power both domestically and internationally. AEPC, an "exempt telecommunications company" under the 1935 Act, was formed in 1997 to pursue opportunities in the telecommunications field. AEPC operates a fiber optic line that runs through Kentucky, Ohio, Virginia and West Virginia. This fiber optic line is capable of providing high speed telecommunications capacity to other telecommunications companies. In addition to establishing and providing fiber optic services, AEPC also made investments in two companies engaged in providing digital personal communications services, the West Virginia PCS Alliance, LLC and the Virginia PCS Alliance, LLC. AEPES is authorized to engage in energy-related activities, including marketing electricity, gas and other energy commodities. As noted above, AEPES acquired the gas trading and marketing group of Equitable Resources, Inc. AEPES is an energy-related company under Rule 58. AEP Common Stock is listed on the New York Stock Exchange, Inc. under the trading symbol, "AEP." As of August 31, 1998, there were 190,915,648 shares of AEP Common Stock outstanding. All shares of the common stock of APCo, CSPCo, I&M, KPCo, KgPCo, OPCo and WPCo are held by AEP. APCo has four series of cumulative preferred stock issued and outstanding, one of which is listed on a public securities exchange. As of June 30, 1998, there were 194,902 shares of its 4-1/2% Cumulative Preferred Stock outstanding (listed on the Philadelphia Stock Exchange); 77,100 shares of its 5.90% Series Cumulative Preferred Stock outstanding; 61,500 shares of its 5.92% Cumulative Preferred Stock outstanding; and 84,500 shares of its 6.85% Cumulative Preferred Stock outstanding. CSPCo has one series of cumulative preferred stock outstanding that is not listed on a public securities exchange. As of June 30, 1998, there were 250,000 shares of its 7% Cumulative Preferred Stock outstanding. 17 18 I&M has seven series of cumulative preferred stock outstanding, none of which is listed on any public securities exchange. As of June 30, 1998, there were 59,767 shares of its 4-1/8% Cumulative Preferred Stock outstanding; 14,912 shares of its 4.56% Cumulative Preferred Stock outstanding; 19,131 shares of its 4.12% Cumulative Preferred Stock outstanding; 167,000 shares of its 5.90% Cumulative Preferred Stock outstanding; 202,500 shares of its 6-1/4% Cumulative Preferred Stock outstanding; 182,500 shares of its 6-7/8% Cumulative Preferred Stock outstanding; and 132,450 shares of its 6.30% Cumulative Preferred Stock outstanding. OPCo has seven series of cumulative preferred stock outstanding, none of which is listed on a public securities exchange. As of June 30, 1998, there were 15,393 shares of its 4.08% Cumulative Preferred Stock outstanding; 103,821 shares of its 4-1/2% Cumulative Preferred Stock outstanding; 23,100 shares of its 4.20% Cumulative Preferred Stock outstanding; 32,474 shares of its 4.40% Cumulative Preferred Stock outstanding; 82,500 shares of its 5.90% Cumulative Preferred Stock outstanding; 31,000 shares of its 6.02% Cumulative Preferred Stock outstanding; and 5,000 shares of its 6.35% Cumulative Preferred Stock outstanding. AEP's consolidated operating revenues for the twelve months ended June 30, 1998, after eliminating intercompany transactions, were $8,195,575,000. Consolidated assets of AEP and its subsidiaries as of June 30, 1998, were approximately $17.8 billion, consisting of $11.6 billion in net electric utility property, plant and equipment and $6.2 billion in other corporate assets. More detailed information concerning AEP and its subsidiaries is contained in AEP's Annual Report on Form 10-K for the year ended December 31, 1998, and the Quarterly Report on Form 10-Q for the quarter ended March 31, 1999, each of which is attached and incorporated by reference as Exhibits G-15 and G-16, respectively. b. CSW CSW, incorporated under the laws of Delaware in 1925, has its principal executive offices at 1616 Woodall Rodgers Freeway, Dallas, Texas. CSW is a public utility holding company registered under the 1935 Act that owns all of the common stock of four U.S. electric utility operating subsidiaries: CPL, PSO, SWEPCO, and WTU. CSW also owns all of the common stock of CSWS, CSW Energy, CSW International, C3 Communications, EnerShop, CSW Energy Services, and CSW Credit, and indirectly owns all of the outstanding share capital of SEEBOARD. In addition, CSW owns 80% of the outstanding shares of common stock of CSW Leasing. CSW's electric utility subsidiaries are public utility companies engaged in generating, purchasing, transmitting, distributing and selling electricity. CSW's U.S. electric utility operating subsidiaries serve approximately 1.7 million customers in portions of Texas, Oklahoma, Louisiana and Arkansas. These companies serve a mix of residential, commercial and diversified industrial customers. CSW and its subsidiaries are subject to the broad regulatory provisions of the 1935 Act administered by the Commission. Various of the subsidiaries are also subject to regulation by the FERC under the FPA with respect to rates for interstate sale at wholesale and transmission of electric power, accounting and other matters and construction and operation of hydroelectric projects. 18 19 At December 31, 1997, the U.S. subsidiaries of CSW had 7,254 employees. CSW, as such, has no employees. The electric utility operating subsidiaries of CSW are described below: CPL (organized in Texas in 1945) is engaged in the generation, sale, purchase, transmission and distribution of electric power to approximately 628,000 customers in portions of south Texas, and in supplying electric power at wholesale to other electric utility companies and municipalities. At December 31, 1997, CPL had 1,668 employees. The principal industries served by CPL include manufacturing, mining, agricultural, transportation and public utilities sectors. The Texas Commission has original jurisdiction over retail rates in the unincorporated areas and appellate jurisdiction over retail rates in the incorporated areas served by CPL. CPL is also subject to regulation by the NRC under the Atomic Energy Act with respect to the operation of its ownership interest in a nuclear generating plant. PSO (organized in Oklahoma in 1913) is engaged in the generation, sale, purchase, transmission and distribution of electric power to approximately 481,000 customers in portions of eastern and southwestern Oklahoma, and in supplying electric power at wholesale to other electric utility companies and municipalities. At December 31, 1997, PSO had 1,273 employees. The principal industries served by PSO include natural gas and oil production, oil refining, steel processing, aircraft maintenance, paper manufacturing and timber products, glass, chemicals, cement, plastics, aerospace, telecommunications and rubber goods. PSO is subject to the jurisdiction of the Oklahoma Commission with respect to retail rates. SWEPCO (organized in Delaware in 1912) is engaged in the generation, sale, purchase, transmission and distribution of electric power to approximately 416,000 customers in portions of northeastern Texas, northwestern Louisiana and western Arkansas, and in supplying electric power at wholesale to other electric utility companies and municipalities. At December 31, 1997, SWEPCO had 1,529 employees. The principal industries served by SWEPCO include mining, manufacturing, chemical products, petroleum products, agriculture and tourism. SWEPCO is subject to the jurisdiction of the Arkansas Commission and the Louisiana Commission with respect to retail rates, as well as the Texas Commission as set forth in the description of the regulation of CPL above. WTU (organized in Texas in 1927) is engaged in the generation, sale, purchase, transmission and distribution of electric power to approximately 187,000 customers in portions of central west Texas, and in supplying electric power at wholesale to other electric utility companies and municipalities. At December 31, 1997, WTU had 907 employees. WTU serves manufacturing and processing plants producing cotton seed products, oil products, electronic equipment, precision and consumer metal products, meat products, gypsum products and carbon fiber products. The territory also has several military installations and state correctional institutions. WTU is subject to the jurisdiction of the Texas Commission as set forth in the description of the regulation of CPL above. CSWS performs, at cost, various accounting, engineering, tax, legal, financial, electronic data processing, centralized economic dispatching of electric power and other services for the 19 20 CSW companies, primarily for CSW's U.S. electric utility subsidiaries. After the Merger, services performed by CSWS will be performed by AEPSC. CSW's material non-utility businesses are conducted through CSW Energy, CSW International, CSW Energy Services, C3 Communications, CSW Credit, EnerShop and CSW Leasing. These subsidiaries are described below: CSW Energy develops, owns and operates independent power production and cogeneration facilities within the U.S. Currently, CSW Energy has ownership interests in seven projects, six in operation and one in development. CSW International engages in international activities, including developing, acquiring, financing and owning EWGs and FUCOs, either alone or with local or other partners. CSW International indirectly owns all of the outstanding share capital of SEEBOARD. CSW acquired indirect control of SEEBOARD in April 1996. SEEBOARD's principal regulated businesses are the distribution and supply of electricity. SEEBOARD is engaged in other businesses, including gas supply, electricity generation and electrical contracting. SEEBOARD's service area covers approximately 3,000 square miles in southeast England. The service area extends from the outlying areas of London to the English Channel. CSW received approval from the Commission under the 1935 Act to issue and sell securities in an amount up to 100% of its consolidated retained earnings (approximately $1,781,000,000 at June 30, 1998) for investment in EWGs and FUCOs through CSW Energy and CSW International. Central and South West Corp., et al., HCAR No. 26653 (January 24, 1997). CSW Energy Services was formed to compete in restructured electric utility markets and serves as an energy service provider to wholesale and retail customers. It also engages in the business of marketing, selling, and leasing to certain consumers throughout the United States certain electric vehicles and retrofit kits subject to limitations imposed by the Commission. C3 Communications has two main lines of business. C3 Communications' Utility Automation Division specializes in providing automated meter reading and related services to investor-owned municipal and cooperative electric utilities. C3 Communications also offers systems to aggregate meter data from a variety of technologies and vendor products that span multiple communication mode infrastructures including broadband, wireless network, power line carrier and telephony-based systems. C3 Communications is an "exempt telecommunications company" under the 1935 Act. CSW Credit was originally formed to purchase, without recourse, accounts receivable from the CSW electric utility subsidiaries to reduce working capital requirements. Because CSW Credit's capital structure is more highly leveraged than that of the CSW electric utility subsidiaries and due to CSW Credit's higher short-term debt ratings, CSW's overall cost of capital is lower. Subsequent to its formation, under the 1935 Act, CSW Credit's business has expanded to include the purchase, without recourse, 20 21 of accounts receivable from certain non-affiliated parties subject to limitations imposed by the Commission. EnerShop, an energy-related company under Rule 58, provides energy services to commercial, industrial, institutional and governmental customers in Texas. These services help reduce a customer's operating costs through increased energy efficiencies and improved equipment operations. EnerShop utilizes the skills of local trade allies in offering services that include facility analysis; project management; engineering design; equipment procurement; and construction and performance monitoring. CSW Leasing, approved by the Commission in 1985, is a joint venture with CIT Group/Capital Equipment Financing. It was formed to invest in leveraged leases. CSW Common Stock is listed on the New York Stock Exchange, Inc., and the Chicago Stock Exchange, Inc., under the trading symbol, "CSR." As of August 31, 1998, there were 212,461,876 shares of CSW Common Stock issued and outstanding. All shares of the common stock of CPL, PSO, SWEPCO and WTU are held by CSW. CPL has five series of cumulative preferred stock issued and outstanding. As of June 30, 1998, there were 42,048 shares of 4.00% Series Cumulative Preferred Stock outstanding; 17,476 shares of 4.20% Series Cumulative Preferred Stock outstanding; 750,000 shares of Auction Money Market Cumulative Preferred Stock outstanding; 425,000 shares of Auction Series A Cumulative Preferred Stock outstanding; and 425,000 shares of Auction Series B Cumulative Preferred Stock outstanding. CPL has one series of 8.00% Cumulative Quarterly Income Preferred Securities issued and outstanding, which are listed on the NYSE. As of June 30, 1998, the principal amount of $150,000,000 of such trust preferred securities was outstanding. PSO has two series of cumulative preferred stock issued and outstanding. As of June 30, 1998, there were 44,640 shares of 4.00% Series Cumulative Preferred Stock outstanding and 8,069 shares of 4.24% Series Cumulative Preferred Stock outstanding. PSO has one series of 8.00% Trust Originated Preferred Securities issued and outstanding, which are listed on the NYSE. As of June 30, 1998, the principal amount of $75,000,000 of such trust preferred securities was outstanding. SWEPCO has three series of cumulative preferred stock issued and outstanding. As of June 30, 1998, there were 37,739 shares of 5.00% Series Cumulative Preferred Stock outstanding; 1,908 shares of 4.65% Series Cumulative Preferred Stock outstanding; and 7,386 shares of 4.28% Series Cumulative Preferred Stock outstanding. SWEPCO has one series of 7.875% Trust Preferred Securities issued and outstanding, which are listed on the NYSE. As of June 30, 1998, the principal amount of $110,000,000 of such trust preferred stock was outstanding. WTU has one series of cumulative preferred stock issued and outstanding. As of June 30, 1998, there were 23,675 shares of 4.40% Series Cumulative Preferred Stock outstanding. CSW's consolidated operating revenues for the twelve months ended June 30, 1998, after eliminating intercompany transactions, were approximately $5.4 billion. Consolidated assets of CSW and its subsidiaries as of June 30, 1998 were approximately $13.8 billion, consisting of 21 22 $8.4 billion in net electric utility property, plant and equipment and $5.4 billion in other corporate assets. More detailed information concerning CSW and its subsidiaries is contained in CSW's Annual Report on Form 10-K for the year ended December 31, 1998 and the Quarterly Report on Form 10-Q for the quarter ended March 31, 1999, each of which is attached and incorporated by reference as Exhibits G-17 and G-18, respectively. c. Merger Sub Merger Sub, a transitory subsidiary of AEP, was incorporated under the laws of the State of Delaware, solely for the purpose of effecting the Merger. Merger Sub has no operations other than those contemplated by the Merger Agreement. AEP will own all the outstanding common stock, $0.01 par value per share, of Merger Sub. A copy of the Certificate of Incorporation and By-laws of Merger Sub are incorporated by reference and attached as Exhibits A-3 and A-4, respectively. The principal executive office of Merger Sub will be located at 1 Riverside Plaza, Columbus, Ohio. 2. Description of Energy Sales and Facilities a. AEP (i) Energy Sales KwH of Electric Energy Sold (in millions) Company Twelve Months Ended December 31, 1997 APCo 46,658 CSPCo 22,601 I&M 34,546 KPCo 12,408 KgPCo 1,774 OPCo 55,875 WPCo 1,795 AEP Total 145,423(a) (a) Total after the elimination of intercompany transactions. (ii) Electric Generating Facilities At December 31, 1997, subsidiaries of AEP owned (or leased where indicated) generating plants with the net power capabilities (winter rating) shown in the following table:
Net Megawatt Owner, Plant Type and Name Location (Near) Capability AEGCo: Steam--Coal Fired: Rockport Plant (AEGCo share) Rockport, Indiana 1,300(a)
22 23 APCo: Steam--Coal-Fired: John E. Amos, Units 1 & 2 St. Albans, West Virginia 1,600 John E. Amos, Unit 3 (APCo share) St. Albans, West Virginia 433(b) Clinch River Carbo, Virginia 705 Glen Lyn Glen Lyn, Virginia 335 Kanawha River Glasgow, West Virginia 400 Mountaineer New Haven, West Virginia 1,300 Philip Sporn, Units 1 & 3 New Haven, West Virginia 308 Hydroelectric--Conventional: Buck Ivanhoe, Virginia 10 Byllesby Byllesby, Virginia 20 Claytor Radford, Virginia 76 Leesville Leesville, Virginia 40 London Montgomery, West Virginia 16 Marmet Marmet, West Virginia 16 Niagara Roanoke, Virginia 3 Reusens Lynchburg, Virginia 12 Winfield Winfield, West Virginia 19 Hydroelectric--Pumped Storage: Smith Mountain Penhook, Virginia 565 5,858 CSPCo: Steam--Coal-Fired: Beckjord, Unit 6 New Richmond, Ohio 53(c) Conesville, Units 1-3, 5 & 6 Coshocton, Ohio 1,165 Conesville, Unit 4 Coshocton, Ohio 339(c) Picway, Unit 5 Columbus, Ohio 100 Stuart, Units 1-4 Aberdeen, Ohio 608(c) Zimmer Moscow, Ohio 330(c) 2,595 I&M: Steam--Coal-Fired: Rockport Plant (I&M share) Rockport, Indiana 1,300(a) Tanners Creek Lawrenceburg, Indiana 995 Steam--Nuclear: Donald C. Cook Bridgman, Michigan 2,110 Gas Turbine: Fourth Street Fort Wayne, Indiana 18(d) Hydroelectric--Conventional: Berrien Springs Berrien Springs, Michigan 3 Buchanan Buchanan, Michigan 2 Constantine Constantine, Michigan 1 Elkhart Elkhart, Indiana 1
23 24 Mottville Mottville, Michigan 1 Twin Branch Mishawaka, Indiana 3 4,434 KPCo: Steam--Coal-Fired: Big Sandy Louisa, Kentucky 1,060 OPCo: Steam--Coal Fired: John E. Amos, Unit 3 (OPCo share)St. Albans, West Virginia 867(b) Cardinal, Unit 1 Brilliant, Ohio 600 General James M. Gavin Cheshire, Ohio 2,600(e) Kammer Captina, West Virginia 630 Mitchell Captina, West Virginia 1,600 Muskingum Beverly, Ohio 1,425 Philip Sporn, Units 2, 4 & 5 New Haven, West Virginia 742 Hydroelectric--Conventional: Racine Racine, Ohio 48 8,512 Total Generating Capability.. 23,759 SUMMARY: Total Steam-- Coal-Fired...................................................... 20,795 Nuclear......................................................... 2,110 Total Hydroelectric-- Conventional.................................................... 271 Pumped Storage.................................................. 565 Other........................................................... 18 Total Generating Capability 23,759
(a) Unit 1 of the Rockport Plant is owned one-half by AEGCo and one-half by I&M. Unit 2 of the Rockport Plant is leased one- half by AEGCo and one-half by I&M. The leases terminate in 2022 unless extended. (b) Unit 3 of the John E. Amos Plant is owned one-third by APCo and two-thirds by OPCo. (c) Represents CSPCo's ownership interest in generating units owned in common with two unaffiliated public utilities, Cincinnati Gas & Electric Company and Dayton Power and Light Company. (d) Leased from the City of Fort Wayne, Indiana. Since 1975, I&M has leased and operated the assets of the municipal system of the City of Fort Wayne, Indiana under a 35-year lease with a provision for an additional 15-year extension at the election of I&M. (e) The scrubber facilities at the Gavin Plant are leased. The lease terminates in 2010 unless extended. 24 25 APCo, CSPCo, I&M, KPCo and OPCo are parties to an Interconnection Agreement, dated July 6, 1951, as amended, defining how they share the costs and benefits associated with the AEP System's generating plants. Sharing is based upon each company's "member-load-ratio," which is calculated monthly on the basis of each company's maximum peak demand in relation to the sum of the maximum peak demands of all five companies during the preceding 12 months. Since 1995, APCo, CSPCo, I&M, KPCo and OPCo have been parties to the AEP System Interim Allowance Agreement which provides, among other things, for the transfer of SO2 allowances associated with transactions under the Interconnection Agreement. The following table shows the net credits or (charges) allocated among the parties under the Interconnection Agreement and Interim Allowance Agreement during the years ended December 31, 1995, 1996 and 1997.
1995 1996 1997(a) ---------------- -------------- ---------------- (in thousands) APCo....................... $(252,000) $(258,000) $(237,000) CSPCo...................... (143,000) (145,000) (138,000) I&M........................ 118,000 121,000 67,000 KPCo....................... 23,000 2,000 20,000 OPCo....................... 254,000 280,000 288,000
(a) Includes credits and charges from allowance transfers related to the transactions. (iii) Electric Transmission and Other Facilities The following table sets forth, as of December 31, 1997, the total overhead circuit miles of transmission and distribution lines of the AEP System, APCo, CSPCo, I&M, KPCo and OPCo and that portion of the total representing 765 Kv lines:
TOTAL OVERHEAD CIRCUIT MILES OF TRANSMISSION AND CIRCUIT MILES OF 765 DISTRIBUTION LINES KV LINES -------------------- ---------------------- AEP System................. 127,864(a)(b) 2,022 APCo....................... 49,534 641 CSPCo...................... 14,820(a) --- I&M........................ 20,855 614 KPCo....................... 10,136 258 OPCo....................... 29,448 509
(a) Includes 766 miles of 345 Kv lines jointly owned with non-affiliates. (b) Includes lines of other AEP System companies not shown. AEP is a member of ECAR. ECAR's membership includes 29 major electricity suppliers located in nine states serving more than 36 million people. Membership is voluntary, and the current full members are those utilities whose generation and transmission have an impact on the 25 26 reliability of the interconnected electric systems in the region. ECAR members interchange power and energy with one another on a firm, economy and emergency basis. As of December 31, 1997, the AEP System was interconnected through 120 high-voltage transmission interconnections with 26 neighboring electric utility systems. The all-time and 1997 one-hour peak system demands were 25,940,000 and 24,485,000 kilowatts, respectively (which included 7,314,000 and 4,400,000 kilowatts, respectively, of scheduled deliveries to unaffiliated systems which the AEP System might, on appropriate notice, have elected not to schedule for delivery) and occurred on June 17, 1994 and January 17, 1997, respectively. The net dependable capacity to serve the system load on such dates, including power available under contractual obligations, was 23,457,000 and 23,669,000 kilowatts, respectively. The all-time and 1997 one-hour internal peak demands were 19,557,000 and 19,381,000 kilowatts, respectively, and occurred on February 5, 1996 and January 17, 1997, respectively. The net dependable capacity to serve the system load on such dates, including power dedicated under contractual arrangements, was 23,765,000 and 23,669,000 kilowatts, respectively. APCo, CSPCo, I&M, KPCo and OPCo are parties to the Transmission Equalization Agreement, dated April 1, 1984 (the "Transmission Agreement"), which defines the method pursuant to which the parties share the costs associated with their relative ownership of the extra-high-voltage transmission system (which includes facilities rated 345 Kv and above) and certain facilities operated at lower voltages (which includes facilities rated 138 Kv and above). Like the Interconnection Agreement, sharing is based upon each company's "member-load-ratio." Other assets owned by AEP include electric distribution systems located throughout its service area, and property, plant and equipment owned or leased supporting its electric utility functions. AEP also owns or leases other physical properties, including real property, and other facilities necessary to conduct its operations. (iv) Fuel Supply The following table shows the sources of power used by the AEP System to generate electricity:
1995 1996 1997(a) ------ ------ --------- Coal......................... 88% 87% 92% Nuclear...................... 11% 12% 7% Hydroelectric and other...... 1% 1% 1% Total.......................... 100% 100% 100%
AEP's average cost of fuel per million BTUs for the calendar years ended December 31, 1995, 1996, and 1997 was 145 cents, 140 cents and 140 cents, respectively. b. CSW 26 27 (i) Energy Sales
KwH of Electric Energy Sold (in millions) Company Twelve Months Ended December, 31, 1997 CPL 21,839 PSO 15,616 SWEPCO 22,533 WTU 7,335 CSW Total 63,157(a)
(a) Total after elimination of intercompany transactions. (ii) Electric Generating Facilities At December 31, 1997, the U.S. electric utility subsidiaries of CSW owned (or leased where indicated) generating plants with the net power capabilities (based on summer ambient and water conditions) shown in the following table:
Net Megawatt Owner, Plant Type and Name Location (Near) Capability CPL: Steam--Gas: B.M. Davis Corpus Christi, TX 697 E.S. Joslin Point Comfort, TX 249 J.L. Bates Palm View (Mission), TX 182 La Palma San Benito, TX 195 Laredo Laredo, TX 176 Lon C. Hill Corpus Christi, TX 528 Neuces Bay Corpus Christi, TX 559 Victoria Victoria, TX 482 Steam--Nuclear: STP Bay City, TX 630(b) Steam--Coal: Coleto Creek Fannin (Goliad), TX 632 Oklaunion Vernon, TX 53(c) Hydroelectric--Conventional: Eagle Pass Eagle Pass, TX 6 CT--Gas: La Palma #7 San Benito, TX 48 4,437 CT/Steam--Gas: Comanche Lawton, OK 273(a) Steam--Gas: Northeastern 1 & 2 Oologah, OK 637
27 28 Riverside Jenks, OK 916 Southwest Washita, OK 475 Tulsa Tulsa, OK 415 Steam--Coal: Northeastern 3 & 4 Oologah, OK 900 Oklaunion Vernon, TX 106(d) CT--Gas: Weleetka Weleetka, OK 163 Diesel--Diesel: Diesels Oklahoma 25 3,910 SWEPCO: Steam-Gas: Arsenal Hill Shreveport, LA 110 Knox Lee Longview, TX 471 Lieberman Mooringsport, LA 273 Lone Star Lone Star (Avinger), TX 50 Wilkes Avinger, TX 880 Steam--Lignite: Dolet Hills Naborton, LA 262(e) Pirkey Hallsville, TX 580(f) Steam--Coal: Flint Creek Gentry, AR 264(g) Welsh Pittsburg, TX 1,584 4,474 WTU: Steam-Gas: Abilene Abilene, TX 7 Fort Phantom Abilene, TX 362 Lake Pauline Quanah, TX 45 Oak Creek Blackwell, TX 85 Paint Creek Haskell, TX 237 CT-Gas: Fort Stockton Ft. Stockton, TX 5 CT/Steam--Gas: Rio Pecos Girvin, TX 137(a) San Angelo San Angelo, TX 125(a) Steam--Coal: Oklaunion Vernon, TX 370(h) Diesel--Diesel: Presidio Presidio, TX 2 Vernon Vernon, TX 9 1,384 Total Generating Capability 14,205
28 29 SUMMARY: Steam--Gas.................................................. 8,031 Steam--Nuclear.............................................. 630 Steam--Coal................................................. 3,909 Hydroelectric--Conventional................................. 6 CT--Gas..................................................... 216 CT/Steam--Gas............................................... 535 Diesel--Diesel.............................................. 36 Steam--Lignite.............................................. 842 14,205
(a) Normally operated as combined cycle. (b) CPL owns 25.2% of STP (c) CPL owns 7.81% of Oklaunion. (d) PSO owns 15.6% of Oklaunion. (e) SWEPCO owns 40.234% of Dolet Hills. Central Louisiana Electric Company, Northeast Texas Electric Cooperative and Oklahoma Municipal Power Authority own the rest of the interests in Dolet Hills. (f) SWEPCO owns 85.936% of Pirkey. Northeast Texas Electric Cooperative and Oklahoma Municipal Power Authority own the rest of the interests in Pirkey. (g) SWEPCO owns half of Flint Creek and Arkansas Electric Cooperative Corporation owns the other half. (h) WTU owns 54.7% of Oklaunion. (Non-affiliates own 12.29% of Oklaunion) All of the generating facilities described above are located on land owned by CSW's U.S. electric utility subsidiaries or, in the case of jointly owned facilities, jointly with other participants. The principal plants and properties of CSW's electric utility subsidiaries are subject to liens of first mortgage indentures under which CSW's electric utility subsidiaries' first mortgage bonds are issued. As part of Applicants' proposed mitigation plan filed with the FERC, Applicants agreed to divest 250 MW of capacity in ERCOT and 300 MW of generation capacity in SPP. In the proceedings before the Texas Commission, Applicants entered into a settlement with the staff of the Texas Commission under which they agreed to divest 1604 MW of generation capacity in ERCOT (including the 250 MW of generating capacity contained in the proposed FERC mitigation plan). The generation units subject to divestiture include Lon Hill Units 1-4 (CPL)--546 MW; Nueces Bay Plant (CPL)--559 MW; Joslin Unit 1 (CPL)--249 MW; Frontera Plant (CSW Energy)--250 MW; and Northeastern Generating Plant (PSO)--300 MW. The timing of divestiture of the generation capacity located in ERCOT and SPP is conditioned upon there being no violation of the criteria for pooling-of-interests accounting treatment of the Merger. If it is determined that the ERCOT divestiture can proceed immediately after the Merger closes without jeopardizing pooling-of-interests accounting treatment for the Merger, sale of the plants would begin no later than 90 days after the Merger closes. Absent that determination, the divestiture 29 30 would occur approximately two years after the Merger closes to satisfy the requirements to use pooling-of-interests accounting treatment. The divestiture of generation capacity located in SPP is also conditioned upon the plant no longer being required to meet PSO's native load demand requirements following electric industry restructuring in Oklahoma. In addition to the generating facilities described above, CSW has ownership interests in nonutility electrical generating facilities. Information concerning U.S. facilities is listed below. Operating Facilities - United States Capacity Capacity Ownership Company Location Total Committed Interest Status Brush II......... CSW Energy Colorado 68 68 47% QF Ft. Lupton....... CSW Energy Colorado 272 272 50% QF Mulberry......... CSW Energy Florida 120 110 50% QF Orange Cogen..... CSW Energy Florida 103 97 50% QF Newgulf.......... CSW Energy Texas 85 n/a 100% IPP Sweeny........... CSW Energy Texas 330 90 50% QF Total....... 978 637 CPL, WTU, PSO, SWEPCO, and CSWS are parties to a Restated and Amended Operating Agreement dated as of January 1, 1997 ("CSW Operating Agreement"). The CSW Operating Agreement requires CSW's U.S. electric utility operating subsidiaries to maintain specified annual planning reserve margins and requires the subsidiaries that have capacity in excess of the required margins to make such capacity available for sale to other subsidiaries as capacity commitments. The CSW Operating Agreement also delegates to CSWS the authority to coordinate the acquisition, disposition, planning, design and construction of CSW's generating units and to supervise the operation and maintenance of a central control center. CSWS, as agent for the CSW System, schedules the energy output of the system capability to obtain the lowest cost of energy for serving aggregate system demand and coordinates off-system purchases and sales. The CSW Operating Agreement has been accepted for filing and allowed to become effective by the FERC. (iii) Electric Transmission and Other Facilities The following table sets forth the total circuit miles of transmission and distribution lines of the CSW U.S. electric utility operating subsidiaries as of December 31, 1997: TOTAL CIRCUIT MILES TOTAL CIRCUIT MILES OF TRANSMISSION OF DISTRIBUTION 30 31 LINES LINES --------------- --------------- CPL... 4,915 28,110 PSO... 3,563 17,916 SWEPCO 3,372 14,240 WTU... 4,490 8,606 ----- ----- Total. 16,340 68,872 CSW's U.S. electric utility subsidiaries' electric transmission and distribution facilities are mostly located over or under highways, streets and other public places or property owned by others, for which permits, grants, easements or licenses have been obtained. CPL and WTU are members of ERCOT, which operates in Texas. Other ERCOT members include Texas Utilities Electric Company, Houston Lighting & Power Company, Texas Municipal Power Agency, Texas Municipal Power Pool, Lower Colorado River Authority, the municipal systems of San Antonio, Austin and Brownsville, the South Texas and Medina Electric Cooperatives, and several other interconnected systems and cooperatives. PSO and SWEPCO are members of the SPP, which includes 18 investor-owned utilities, 11 municipalities, 11 cooperatives, 3 state and 1 federal agency as well as IPPs and power marketers operating in the states of Arkansas, Kansas, Louisiana, Oklahoma and parts of Mississippi, Missouri, New Mexico and Texas. ERCOT members interchange power and energy with one another on a firm, economy and emergency basis, as do the members of the SPP. The highest all-time maximum coincident system demand through 1997 was 13,105 MW on July 28, 1997. The 1997 net dependable capacity to serve the system load was 14,290 MW. Power generation at the time of the peak was 12,817 MW and net purchases at the time of the peak were 288 MW. CPL, WTU, PSO, SWEPCO and CSWS are parties to a Transmission Coordination Agreement dated as of January 1, 1997 ("TCA"). The TCA establishes a coordinating committee, which is charged with the responsibility of overseeing the coordinated planning of the transmission facilities of CSW's U.S. electric utility operating subsidiaries, including the performance of transmission planning studies, the interaction of such subsidiaries with ISOs and other regional bodies interested in transmission planning and compliance with the terms of the OATT filed with the FERC and the rules of the FERC relating to such tariff. Under the TCA, CSW's U.S. electric utility subsidiaries have delegated to CSWS the responsibility of monitoring the reliability of their transmission systems and administering the OATT on their behalf. The TCA also provides for the allocation among CSW's U.S. electric utility operating subsidiaries of revenues collected for transmission and ancillary services provided under the OATT. The TCA has been accepted for filing by the FERC effective as of January 1, 1997, and is the subject of proceedings commenced to consider the reasonableness of its terms and conditions. 31 32 (iv) Fuel Supply The following table shows the sources of power used by the CSW System to generate electricity: 1995 1996 1997 Natural Gas 47% 40% 38% Coal 36% 42% 44% Lignite 9% 10% 10% Nuclear 8% 8% 8% Total.. 100% 100% 100% CSW's average cost of fuel per million BTUs for the calendar years ended December 31, 1995, 1996, and 1997 was 158 cents, 181 cents and 183 cents, respectively. 3. Electric Coordination The Combined System will be physically interconnected and economically operated as a single interconnected and coordinated system. Upon implementation of the System Integration Agreement and the System Transmission Integration Agreement and through the use of Central Dispatch Planning and Central Economic Dispatch, the Combined System will have a central dispatch system capable of scheduling the generating resources of the Combined System on an economical, real-time basis. The Combined System will be physically interconnected through the 250 MW Contract Path. Each aspect of the electric coordination and interconnection of the Combined System is discussed below: a. System Integration Agreement and System Transmission Integration Agreement. The System Integration Agreement provides for the coordination of generation within the Combined System. The System Transmission Integration Agreement provides for the coordination of transmission within the Combined System. The agreements, each of which will take effect upon consummation of the Merger, are described in the Testimony of J. Craig Baker and Dennis W. Bethel before the FERC which are filed with Exhibit D-1.1 and incorporated by reference. The agreements and their functions are summarized below. As noted, the System Integration Agreement provides for the coordination of generation within the Combined System. AEPSC will coordinate the planning, operation and maintenance of generating capacity resources and the dispatch of electricity throughout the Combined System. The coordination of generation is accomplished through two computer software programs: Central Dispatch Planning and Central Economic Dispatch. Central Dispatch Planning forecasts (usually on a day-ahead basis, although sometimes several days ahead) the generation needs of the Combined System and determines the least-cost allocation of generation resources available within the Combined System necessary to meet the forecasted obligations. The central dispatch 32 33 is based on anticipated fuel costs, load levels, wholesale power market conditions, planned unit maintenance (which units are out of service or operating below normal operating limits), and prevailing transmission capabilities (including capacity reserved by third parties). During the morning of normal working days (Monday through Friday), Central Dispatch Planning will have scheduled hourly the following day's generation for every unit in the Combined System (with the exception of Friday, when generation is scheduled for Saturday, Sunday and Monday). Central Economic Dispatch computes at regular intervals (currently every four seconds) the most economic generation dispatch base points resulting from current operating obligations. While Central Dispatch Planning is based on predictive conditions, Central Economic Dispatch is a real-time function that continuously evaluates current operating conditions, and, based on least-cost allocations and existing transmission constraints, issues new dispatch instructions to each generating unit within the Combined System. Central Dispatch Planning and Central Economic Dispatch will be ready to serve the Combined System prior to the effectiveness of the Merger, and, accordingly, each will be available to the Combined System immediately upon consummation of the Merger. Each will utilize the existing electronic communication infrastructures currently in place in each of the AEP System and the CSW System. The existing electronic communication infrastructures will feed data to, and receive instructions from, Central Dispatch Planning and Central Economic Dispatch via a high speed data link. The System Transmission Integration Agreement provides for the coordinated planning, operation and maintenance of the Combined System's transmission facilities and the assignment among the Combined System's operating companies of third-party transmission costs incurred to coordinate post-Merger operations. AEPSC will coordinate the planning, operation and maintenance of transmission facilities and capacity of the Combined System. The Combined System will be subject to regulation by the FERC with respect to transmission and the Combined System intends to operate in full compliance with all applicable FERC rules and orders regarding, among other things, tariffs, billing and revenue allocation, immediately upon the consummation of the Merger. In this regard, the Applicants have entered into a stipulation with FERC Trial Staff resolving all issues between them regarding the System Integration Agreement, the Transmission Reassignment Tariff, and the System Transmission Integration Agreement. The Stipulation with FERC Trial Staff is filed as Exhibit D-1.4 and incorporated by reference. b. 250 MW Contract Path The Combined Company will transmit power from east to west over the 250 MW Contract Path. The 250 MW Contract Path's term is from June 1, 1999 to May 31, 2003, which may be renewed through the Ameren OATT. AEPSC will coordinate the planning of the transmission capacity interconnecting the Combined System. In order to increase its firm transmission service rights on the MOKANOK Line, CSW's subsidiary, PSO, entered into an agreement with WR to provide firm point-to-point transmission service for the transfer of 38 MW of power from Ameren. The point of receipt and delivery for the 38 MW of power will be the point of interface with Ameren and WR's and PSO's undivided interest in the MOKANOK Line. PSO and another CSW subsidiary, SWEPCO, will transmit the 33 34 38 MW of power from the interface between PSO's and WR's undivided interest in the MOKANOK Line to PSO's 345 Kv bus at its Northeastern Generating Station. PSO will transmit the remaining 212 MW of power over its undivided interest in the MOKANOK Line from the interconnection with Ameren on the MOKANOK Line to PSO's 345 Kv bus at its Northeastern Generating Station. In order to enable the 250 MW Contract Path to accommodate a 250 MW firm transfer, CSW and Ameren agreed that Ameren would upgrade Ameren's Albion Substation in order to increase available transfer capability into Ameren from the east during the summer peak period. The upgrade, effected by installing a 138 Kv reactor, was completed on August 1, 1998. Applicants have committed to avoid any possible anticompetitive concerns attributable to the Merger by agreeing to limit their reservation of firm transmission service from east to west to 250 MW unless the FERC authorizes them to go above this limit. See Dr. William Hieronymus' testimony filed as an exhibit to Exhibit D-1.2 and incorporated herein by reference. c. Additional Power Transfers The Applicants expect that from time to time there will be opportunity to transfer energy economically in the Combined Company from west to east. In these circumstances, Applicants will make use of their rights to nominate secondary points of receipt and delivery under their transmission service agreements with WR and Ameren. PSO has the right to transfer approximately 113 MW of energy on a non-firm basis across the MOKANOK Line. Ameren's OASIS postings indicate that there are more than 1000 MW of transfer capability across the Ameren system from the MOKANOK Line to the east. In addition to the use of the 250 MW Contract Path, quantities in excess of the 250 MW can be moved within the Combined System in any given hour by using non-firm transmission rights. Such additional transfers would be made when circumstances indicate that they would be economical for post-Merger system operations after taking into consideration opportunity costs. See generally, Testimony of J. Craig Baker, filed with Exhibit D-1.1 and incorporated herein by reference. As part of the FERC Stipulation, Applicants agreed to waive the Combined Company's priority with respect to its use of the HVDC ties for unplanned (i.e., non-firm) transactions in ERCOT and non-firm transactions in the SPP. See Exhibit D-1.2, Supplemental Testimony of Stephen Jones at 15-17. This waiver of priority would not apply to planned (i.e., firm) transactions that are submitted to ERCOT or other transfers of firm capacity between the Applicants' SPP and ERCOT control areas, including the use of the North HVDC tie to export the output of the Oklaunion generation station to PSO and to Oklahoma Municipal Power Authority, both located in the SPP.(1) Thus, the Applicants would continue to use the HVDC ties - ----------------------- (1) CSW's firm transmission capacity has always been adequate to integrate its operations, and there has never been a need to assert a priority for unplanned transactions over the HVDC ties. As a general matter, the HVDC ties are available and are not typically constrained. In fact, CSW has the only existing reservation on the North HVDC tie, and there are no reservations on the East HVDC tie after the summer of 1999. As a result, Applicants do not expect their waiver of priority for non-firm use of the HVDC ties to affect the integration of their system in any manner. 34 35 to integrate CSW's Texas assets with its non-Texas assets in the same manner that previously has been approved by the Commission. d. Future Participation in an RTO On June 3, 1999, AEP and four other utilities filed the Alliance RTO Application, which is currently pending at FERC. CSW is participating in the ERCOT independent regional transmission plan for the portion of its system that is within ERCOT and is participating in discussions with other interested parties about the formation of an RTO that would include its utility systems located in the SPP.(2) Participation in these RTOs will enhance system reliability after the Merger as described below. The Applicants' goal ultimately is to further enhance the reliability of the Combined System through participation in a regional RTO. RTOs provide strengthened assurances to the marketplace that transmission service will be available to all eligible customers on a non-discriminatory basis. In addition, RTOs can enhance regional reliability and, if properly structured and configured, improve economic efficiencies and provide access to a broad range of buyers and sellers across a large geographic region. Until such time as the Combined Company transfers certain control area functions related principally to reliability and access to one or more RTOs, all facets of the centralized coordination of the transmission facilities of the Combined Company's system will be accomplished through the System Transmission Integration Agreement. At such time as AEP transfers to the RTO certain control area operations relating principally to system reliability and access, the remaining functions of the Combined Company's transmission system will continue to be coordinated through the System Integration Transmission Agreement. Participation in RTOs can enhance the reliability of the Combined Company's system in several ways. In the Notice of Proposed Rulemaking regarding RTOs,(3) FERC found that an RTO would improve efficiencies in the management of the transmission grid (RTO NOPR mimeo at 90); would improve grid reliability (RTO NOPR mimeo at 95); would improve market performance (RTO NOPR mimeo at 98); and would facilitate lighter governmental regulation (RTO NOPR mimeo at 101). It is FERC's view that all utilities should participate in a FERC-approved RTO. - ----------------------- (2) In the order of the Oklahoma Commission approving the Merger, AEP is required to file with the FERC, not later than six months before retail competition commences in the State, or December 31, 2001, an application to, transfer the operational control of bulk transmission facilities owned, controlled and/or operated by AEP that are currently located in the SPP to a FERC-approved RTO that is directly interconnected with the AEP system. See Exhibit 4.2, at 17. (3) Notice of Proposed Rulemaking, Regional Transmission Organizations, Docket No. RM99-2-000, 87 FERC Paragraph. 61,173 (May 13, 1999) ("RTO NOPR"). 35 36 C. DESCRIPTION OF MERGER AND STATEMENT AS TO CONSIDERATION 1. Background of the Merger AEP and CSW are seeking to merge to further their mutual strategy of adapting to an era of historic changes in the electric utility industry. The electric utility industry is in the process of a transformation to greater levels of competition in the wholesale and retail energy markets. Technological advances, consumer pressures and federal and state legislative and regulatory initiatives are forces affecting this transformation. Efficient, low cost suppliers of energy with a diverse customer base will be best prepared to compete successfully in the resulting electric energy marketplace. Historically, competition in the wholesale and retail electric energy markets was limited. In the wholesale market, this limitation was due to various barriers to entry, including the difficulties in obtaining transmission service over utility systems located between potential buyers and sellers and the possibility of regulation under the 1935 Act. Pursuant to the Energy Act, however, Congress authorized the FERC to exempt certain wholesale power sellers from regulation under the 1935 Act. In 1996, the FERC issued Orders 888 and 889 requiring utilities to provide non-discriminatory, open-access transmission service upon request. These regulatory developments have resulted in an active, competitive wholesale market for electricity. Although the retail market for electricity currently is less developed than the wholesale market, most states in which the electric utility operating subsidiaries of AEP and CSW provide retail service have adopted or are actively considering legislative or regulatory action permitting retail customers to select their electricity supplier and obligating utilities to provide transmission and distribution service to competitors. Because of these ongoing legislative and regulatory activities, the managements of AEP and CSW have concluded that there will soon be increased competition in the retail sector of the business. Electric utility companies must adapt quickly to this evolving competitive environment if they are to succeed in it. Many companies are pursuing consolidation to diversify business risks and create new opportunities for earnings growth. Assets, such as a utility's transmission network and low cost generation, will be key factors in structuring the successful electric utility of the future. Customers in a competitive market will choose electric suppliers that are efficient and responsive. For the past several years, AEP and CSW separately have been focusing their strategic planning activities on preparing for this fundamental evolution. AEP and CSW have now determined that a merger of the two companies is the best way to achieve their compatible long-term goals. 2. Merger Agreement The following is not a complete description of the Merger Agreement and is qualified in its entirety by reference to the Merger Agreement, which is attached and incorporated by reference as Exhibit B-l. The Merger Agreement provides for a business combination of AEP and CSW in which Merger Sub will be merged with and into CSW. CSW will be the surviving corporation and will 36 37 become a wholly-owned subsidiary of AEP. Upon the consummation of the Merger, each issued and outstanding share of CSW Common Stock (other than the Excluded Shares) will be exchangeable for 0.60 shares of AEP Common Stock. Based on the price of AEP Common Stock on December 19, 1997, the transaction would be valued at $6.6 billion. Each issued and outstanding share of AEP Common Stock will be unchanged as a result of the Merger. The former holders of CSW Common Stock will own approximately 40% of the issued and outstanding AEP Common Stock after the Merger. The Merger is subject to customary closing conditions, including the receipt of all necessary governmental approvals, including the approval of the Commission. The Merger is designed to qualify as a tax-free reorganization under Section 368(a) of the Internal Revenue Code of 1986, as amended, and will be treated as a "pooling-of-interests" for accounting purposes. 3. Reasons for the Merger The Merger offers significant opportunities to create additional value for shareholders, customers and employees of the Combined Company. The benefits of the Merger include the following: - - COST SAVINGS - The Combined Company will be more efficient than either company standing alone. Merging will allow the companies to create efficiencies in operations and business processes, eliminate duplicative functions, enhance their purchasing power, and combine two workforces. The Combined Company should realize Merger-related non-fuel savings of nearly $2 billion over the first ten years following the Merger, net of transaction and transition costs, and net fuel-related savings of approximately $98 million over the same period. - - COMPETITIVE PRICES AND SERVICES - The Combined Company will use the efficiencies arising from the Merger to compete effectively in the increasingly competitive marketplace. Sales to industrial, large commercial and wholesale customers are at greatest near-term exposure to increased competition; these customers will choose among potential suppliers those best able to meet their demands for reliable, low-cost power. The Merger will enable the Combined Company to serve customers more efficiently and effectively. - - FINANCIAL STRENGTH - By combining the market capitalization of the individual companies, the Merger will result in a Combined Company with a stronger financial base, improved position in the credit markets, and greater market diversity. - - GREATER DIVERSIFICATION - The combination of AEP and CSW will diversify the Combined System's service territory, reducing exposure to adverse changes in any sector's economic and competitive conditions. The Combined Company will expand relationships with existing customers and develop relationships with new customers in its service area, using its combined distribution channels to market a portfolio of innovative energy-related products at competitive prices. The Merger will result in a Combined Company with more diversity in fuel and generation, which will reduce dependence upon any one sector of the energy industry and exposure to fluctuations in certain commodity prices. - - INCREASED SCALE - As competition intensifies within the industry, scale will be one contributor to overall business success. Scale is important in many areas, including utility 37 38 operations, product development, advertising and corporate services. Profitability of the Combined Company will be enhanced by the expanded customer base and the synergies in all of these areas. 4. AEP Management Following the Merger The Board of Directors of the Combined Company immediately following the Merger will consist of 15 members and will be reconstituted to include all then-current board members of AEP, Mr. E. R. Brooks (the current Chairman of CSW) and four additional outside directors of CSW to be nominated by AEP. Dr. E. L. Draper, Jr., will be the Chairman and Chief Executive Officer of the Combined Company. The Merger Agreement also provides that, from and after its effectiveness, the Combined Company's corporate headquarters will be located in Columbus, Ohio. ITEM 2. FEES, COMMISSIONS AND EXPENSES Thousands Filing fee for Form S-4 $1,759 Accountants' fees * Legal fees and expenses * Shareholder communication and proxy solicitation expenses * NYSE listing fee * Exchanging, printing and engraving stock certificates * expenses * Investment bankers' fees and expenses * Consulting fees * Miscellaneous * Total * (*) To be filed by amendment. The total fees, commissions and expenses expected to be incurred for transaction and regulatory processing costs are estimated to be approximately $53 million. ITEM 3. APPLICABLE STATUTORY PROVISIONS The following sections of the 1935 Act and the Commission's rules relate to the Merger: SECTION OR RULE TRANSACTIONS TO WHICH SECTION OR RULE RELATES UNDER THE 1935 ACT 38 39 6, 7, 12, 32 and 33 Issuance of AEP Common Stock; amendment and rules existing to AEP's financing authority to allow thereunder the Combined Company to engage in financing arrangements authorized for CSW; all financing transactions that do not involve a financing for the purposes of acquiring an EWG or FUCO. 9, 10, 11 and Acquisition by AEP of CSW Common Stock rules thereunder and Merger common stock; indirect acquisition by AEP of securities of, and interests in the business of, CSW's subsidiary companies, including the non-utility subsidiaries; authority for the Combined Company to conduct the business activities of CSW. 13 and rules Merger of CSWS into AEPSC with AEPSC as thereunder the surviving service company; approval of service agreement and method for allocating costs under the service agreement.
Section 9(a)(1) of the 1935 Act provides that unless the acquisition has been approved by the Commission under Section 10, 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 9(a)(1) is applicable to the proposed Merger because the transaction involves the acquisition by AEP of CSW Common Stock and the Merger Sub common stock, and the indirect acquisition of the securities of and interests in the businesses of CSW's subsidiary companies. As set forth more fully below, the Merger fully complies with Section 10 of the 1935 Act: - - The Merger will not create detrimental interlocking relations or a detrimental concentration of control; - - The consideration and fees to be paid in the Merger are fair and reasonable; - - The Merger will not result in an unduly complicated capital structure for the Combined Company; - - The Merger is in the public interest and the interests of investors and consumers; - - The Combined System will be a single integrated public utility system; - - The Merger equitably distributes voting power among the investors in the Combined Company and does not unduly complicate the structure of the holding company system; 39 40 - - The Merger tends toward the economical and efficient development of an integrated electric utility system; and - - The Merger will comply with all applicable state laws. Under Sections 9 and 10, Congress gave the Commission the responsibility for "supervision over the future development of utility-holding company systems." The Southern Co., HCAR No. 25639 (Sept. 22, 1992) (citations omitted) [hereinafter "Southern"]. Section 1(c) of the 1935 Act directs the Commission to interpret all provisions of the 1935 Act to meet the problems and eliminate the evils set forth in the 1935 Act in order to protect the interests of investors, consumers and the general public. Accordingly, the Commission's mandate under these sections is "to prevent acquisitions which would be 'attended by the evils which have featured the past growth of holding companies.'" American Elec. Power Co., HCAR No. 20633 (July 21, 1978) (quoting H.R. Rep. No. 1318, 74th Cong., 1st Sess. 16 (1935)) [hereinafter "AEP"]. These evils include the "growth and extension of holding companies [that] bears no relation to economy of management and operation or the integration and coordination of related operating properties." Section 1(b)(4) of the 1935 Act. As the Supreme Court has recognized, the 1935 Act is an "intricate statutory scheme" which must be given "practical sense and application." SEC v. New England Elec. Sys., 384 U.S. 176 (1966), rev'g and remanding 346 F.2d 399 (1st Cir. 1966), rev'g, New England Elec. Sys., 41 SEC 888 (1964), on remand, 376 F.2d 107 (1st Cir. 1967), rev'd, 390 U.S. 207 (1968). In administering the 1935 Act, the Commission must "weigh policies [of the 1935 Act] against each other and against the needs of particular situations." Union Elec. Co., HCAR No. 18368 (Apr. 10, 1974), aff'd sub nom. City of Cape Girardeau v. SEC, 521 F.2d 324 (D.C. Cir. 1975) (citation omitted) [hereinafter "Union Electric"]. The Commission is not disposed to "apply concepts such as res judicata or stare decisis to the essentially regulatory and policy determinations called for in a Holding Company Act case . . . ." AEP, supra. In considering whether to approve an acquisition, the Commission "must make that determination in light of contemporary circumstances . . . and [its] present view of the Act's requirements." Southern, supra (citations omitted). The Merger complies with the 1935 Act. In light of contemporary circumstances, the Merger does not result in any of the concerns the 1935 Act was intended to address. In this regard, the Merger will benefit the public interest and the interests of investors and consumers. Adequate safeguards, through both state and federal regulation, ensure that the public interest and the interests of investors and consumers continue to be protected. Approval of the Merger is consistent with previous merger transactions approved by the Commission under the 1935 Act. Each subsection of Section 10 of the 1935 Act is addressed below, as well as the public policies underlying the 1935 Act, as they relate to the Merger. A. SECTION 10(b) Section 10(b) of the 1935 Act provides that, if the requirements of Section 10(f) are satisfied, the Commission shall approve an acquisition under Section 9(a) unless: 40 41 (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 whosoever paid, to be given, directly or indirectly, in connection with such acquisition is not reasonable or does not bear a 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. 1. Section 10(b)(1) Section 10(b)(1) of the 1935 Act requires the Commission to approve a proposed acquisition unless it finds that the proposed 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." As this Section clearly indicates, a merger does not run afoul of Section 10(b)(1) merely because it causes interlocking relations or a concentration of control. Rather, a merger will fail the balancing test set forth in this Section only when the detrimental effects, if any, from any such interlocking relations or concentration of control caused by the merger outweigh the benefits of the merger. a. Interlocking Relations By its nature, any merger results in interlocking relations between previously unrelated companies. As the Commission has previously noted: "[W]ith any addition of a new subsidiary to a holding company system, the Acquisition will result in certain interlocking relationships between [the two merging entities]." Northeast Utilities, HCAR No. 25221 (Dec. 21, 1990), modified on other grounds, HCAR No. 25273 (Mar. 15, 1991), aff'd sub nom. City of Holyoke Gas & Elec. Dep't v. SEC, 972 F.2d 358 (D.C. Cir. 1992) (citation omitted). [hereinafter "Northeast I"]. Such "interlocking relationships are necessary to integrate [the two merging entities.]" Id. The Merger Agreement provides for the Board of Directors of the Combined Company to be composed of members drawn from the Boards of Directors of both AEP and CSW. Specifically, the Board of Directors of the Combined Company will consist of 15 members including the current Chairman of the Board of CSW and four other outside directors of CSW to be nominated by AEP. This combined Board of Directors for the Combined Company is necessary to assure the effective integration and operation of the Combined Company. As discussed below in Item 3.B.2, the Merger will result in benefits to the public interest and the interests of investors and consumers. As such, the interlocking relations do not harm, but rather, promote the interests which Section 10(b)(1) is meant to protect. 41 42 b. Concentration of Control Under the Section 10(b)(1) concentration of control test, the Commission "considers various factors, including the size of the resulting system and the competitive effects of the acquisition." Entergy Corp., HCAR No. 25952 (Dec. 17, 1993), request for reconsideration denied, HCAR No. 26037 (Apr. 28, 1994), remanded sub nom. Cajun Elec. Power Coop. Inc. v. SEC, 1994 WL 704047 (D.C. Cir. Nov. 16, 1994) (citations omitted). [hereinafter "Entergy"]. These factors are discussed below. (i) Size As the terms of Section 10(b)(1) dictate and as the Commission has recognized, Section 10(b)(1) does not "impose any precise limits on holding company growth." AEP, supra. Congress condemned the "growth and extension of holding companies [that] bears no relation to economy of management and operation or the integration and coordination of related operating properties." Section 1(b)(4) of the 1935 Act. The Commission has rejected a mechanical size analysis under Section 10(b)(1) in favor of assessing the size of the resulting system as it relates to the efficiencies and economies that can be achieved through the integration and coordination of the new system's utility operations. Entergy, supra (rejecting "conclusory assertions that the combined systems would be too large to satisfy [Section 10(b)(1)]" and finding that merger created a "large system, but not one that exceeds the economies of scale of current electrical generation and transmission technology.") Section 10(b)(1) allows the Commission to "exercise its best judgment as to the maximum size of a holding company in a particular area, considering the state of the art and the area or region affected." AEP, supra. Other recent transactions confirm that the Commission evaluates the resulting size of a merging entity in terms of the overall effects of the merger. For example, in Centerior Energy Corp., HCAR No. 24073 (Apr. 29, 1986) [hereinafter "Centerior"], the Commission stated that a "determination of whether to prohibit enlargement of a system by acquisition is to be made on the basis of all the circumstances, not on the basis of size alone." See also, Northeast I, supra (applying standard articulated in Centerior, supra, to find acquisition satisfied Section 10(b)(1)). Likewise, the Division recommended in its 1995 Report that the Commission approach its analysis of merger and acquisition transactions in a flexible manner with an emphasis on whether the transaction creates an entity subject to effective regulation and results in economies and efficiencies as opposed to focusing on rigid, mechanical tests. 1995 Report at 66-70. In short, size alone is not suspect. Rather, as the 1935 Act provides, the concern is an enlargement of the system that is "of a kind or to an extent detrimental to the public interest or the interest of investors or consumers" caused "by the growth and extension of holding companies [that] bears no relation to economy of management and operation or the integration and coordination of related operating properties." Sections 10(b)(1) and 1(b)(4) of the 1935 Act. For purposes of comparison, the table below provides certain operating information derived from publicly available documents for a selected group of public utility systems. Each public utility system, with the exception of CSW, consistently ranks at or near the top of virtually all categories presented. These data identify and rank the largest public utility systems in the United States. Among the utilities presented, AEP currently ranges from the second to the fifth largest public utility system in the United States depending on the criterion of measurement. 42 43 Giving effect to the Merger as of December 31, 1997, on a pro forma basis, the Combined Company would have ranged from the largest to the fourth largest public utility system in the United States, again depending on the criterion of measurement. (As of December 31, 1997)
U.S. Operating Electric Revenues Total Assets Customers System ($Millions) ($Millions) ($Millions) Duke 16,309 24,020 2.0 Southern 12,611 35,271 3.7 Entergy 9,562 27,001 2.5 PG&E 15,400 30,557 4.5 CSW 5,268 13,451 1.7 AEP 6,161 16,615 3.0 Combined Company 11,352(a) 30,066 4.7 U.S. U.S. Sales in Market Generating KwH Capitalization Capacity System (Billions) ($Millions)(b) (MW) Duke 77.5 19,924 17,246 Southern 156.5 17,942 31,146 Entergy 106.8 7,361 21,727 PG&E 79.4 12,661 13,583 CSW 63.2 5,743 14,205 AEP 145.4 9,808 23,759 Combined Company 208.6 16,381(c) 37,964
(a) Gives effect to certain reclassifications expected to be adopted by the Combined Company upon completion of the Merger. (b) Based on number of shares outstanding multiplied by the closing stock price at December 31, 1997. (c) Gives effect to the conversion of CSW Common Stock to AEP Common Stock following the Merger at the Exchange Ratio. The table above does not reflect Applicants' agreement, as part of the Texas settlement, to divest 1604 MW of generation capacity in ERCOT and, as part of Applicants' FERC mitigation plan, to divest 300 MW of generation capacity in SPP. Even without taking into account these divestitures of generation capacity, the data show that, as of December 31, 1997, Southern and PG&E would have been larger than the Combined Company in total assets; Duke, Southern, and PG&E would have been larger than the Combined Company in terms of operating revenues; and Duke and Southern would have been larger than the Combined Company in total market capitalization. Thus, the data show that the Combined Company will be comparable in size to other large public utility systems. Moreover, the size of the Combined Company would not cause a concentration of control within the relevant region under existing Commission precedent. In Northeast I, supra, the Commission approved a merger in which the combined system would have 29% of the peak load capacity, 36.7% of the total assets and less than one-third of the operating revenues, number of electric customers and KwH sales when compared to the regional electric utility industry. The Commission further noted that these figures were well below the 40% level that would have resulted in the merger the Commission blocked for other reasons in New England Elec. Sys., HCAR No. 18801 (Feb. 4, 1975) ("NEES Decision"). Id. at n. 53 (when measured by operating revenues, number of electric customers, KwH sales, KwH capacity and electric power generated in KwH, the combined companies in the NEES Decision would have represented "about 40% of New England"). 43 44 Applicants propose that the relevant region for evaluating the size of the Combined Company should include the Combined Company and those electric utilities directly interconnected with AEP and/or CSW ('Interconnected Utilities').(4) See Entergy, supra (Commission adopted the applicants' definition of the relevant region for purposes of measuring size to include applicants and those electric utilities directly interconnected with either or both). As the table below indicates, the size of the Combined Company compared to the size of the Interconnected Utilities and the Combined Company varies from 10 percent to 16 percent depending on the criterion of measurement. Further, if data from the Applicants' historical wholesale customers are added to these Interconnected Utilities data (the sum equaling the relevant destination markets for purposes of measuring market power as described in the testimony of Dr. Hieronymus before the FERC, attached as exhibits to Exhibits D-1.1 and D-1.2 and summarized in Item 3.A.1.b.(ii)., 'Antitrust Considerations', infra), then the size of the Combined Company as a percentage of the destination markets identified by Dr. Hieronymus is even smaller.
Net Electric Utility Electric Number of Total Net Plant Revenues Electric Generation ($Thousands) ($Thousands) Customers MwH Sales (MwH) Interconnected Utilities $169,463,307 $ 69,737,780 28,075,111(a) 1,224,545,371 1,092,704,814 Combined Company $ 18,512,582$ 9,097,234 4,614,541 194,998,011 199,222,365 Total $187,975,889 $78,835,014 32,689,652 1,419,534,382 1,291,927,179 % of Total represented by Combined Company 10% 12% 15% 14% 16%
(a) The customers of the Tennessee Valley Authority and Southwestern Power Administration are not included in this figure, since these federal power marketing agencies typically do not have retail customers. The Tennessee Valley Authority has 160 - ------------------------- (4) Interconnected Utilities include Brownsville Public Utilities Board, Carolina Power & Light Co., Central Illinois Light Co., Central Illinois Public Service Co., Central Louisiana Electric Co. Inc., Cincinnati Gas & Electric, Commonwealth Edison Co., Consumers Energy Co., Dayton Power & Light Co., Duke Power Co., Entergy, Duquesne Light Co., Empire District Electric Co., Grand River Dam Authority, Houston Light & Power Co., Illinois Power Co., Indianapolis Power & Light Co., Kentucky Utilities Co., Louisville Gas and Electric Co., Lower Colorado River Authority, Monongahela Power Co., Northern Indiana Public Service Co., Ohio Edison Co., Ohio Valley Electric Corp., Oklahoma Gas and Electric Co., PSI Energy Inc., San Antonio Public Service Board, Southwestern Public Service Co., Texas Utilities Electric Co., The Cleveland Electric Illuminating Co., The Toledo Edison Co., Union Electric Company, Virginia Electric & Power Co., West Penn Power Co., Western Resources Inc., Southwestern Power Administration, and Tennessee Valley Authority. Certain other municipalities and co-ops interconnect with AEP and/or CSW; however, due to the lack of publicly available information regarding them, their data are not included herein. 44 45 distributor customers and Southwestern Power Administration has 92 customers comprised of municipalities, federal agencies and cooperatives. Sources: Edison Electric Institute, Electrical Utility Data, EZStat Query System (1996); EIA Publication-Financial Statistics of Major US Investor-Owned Electric Utilities (1996); EIA Publication Financial Statistics of Major US Publicly-Owned Electric Utilities (1996). Specifically, as the table above indicates, at December 31, 1996, the Combined Company would have represented no more than the following percentages of the utility industry in the region, in terms of the above criteria: net electric plant (10%); electric revenues (12%); number of electric customers (15%); MwH sales (14%); and net generation (16%). As such, the size of the Combined Company relative to the relevant region is significantly below the 40% threshold previously cited by the Commission. In fact, two of these percentages would be even less if the data reflected Applicants' agreement, as part of the Texas settlement, to divest 1604 MW of generation capacity in ERCOT and, as part of Applicants' FERC mitigation plan, to divest 300 MW of generation capacity in SPP. By definition, any merger creates an entity larger than each of the constituent parts. However, the size of the Combined Company will not exceed the economies of scale of current electrical generation and transmission technology and, therefore, does not exceed the maximum size of a holding company considering the "state of the art." Technological changes have resulted in power being transmitted over greater distances with less line loss, single integrated computer networks that more efficiently dispatch generation sources and control constricted transmission areas, and generation technologies that have reduced the cost of power and increased the flexibility of power plant siting. Moreover, changes in the regulatory and legal framework have resulted in an increase in non-utility generators, non-utility marketers and brokers. Together, these technological, legal and regulatory changes have resulted in increased competition within the industry.(5) Given these present realities, the size of the Combined System will not result in a "concentration of control" of a kind or to an extent detrimental to the interests of the public, investors or consumers. As described in detail below in Item 3.B.2, the Merger is expected to yield significant economies and efficiencies. Net non-production savings of nearly $2 billion and net fuel-related savings of approximately $98 million are projected over the first ten years. These savings will be realized by investors and customers. (ii) Antitrust Considerations The Commission's analysis under Section 10(b)(1) also includes a consideration of federal antitrust policies.(6) If the Commission determines that an acquisition will tend towards the concentration of control of public utility companies, it balances this effect against the benefits from the acquisition to determine whether the acquisition passes the Section 10(b)(1) balancing test. The Commission "has approved acquisitions that decrease competition when it concludes - ------------------------- (5) The "state of the art" is discussed in depth in Item 3.B.1.a below. (6) See, e.g., Conectiv, HCAR No. 26832 (Feb. 25, 1998) [hereinafter "Conectiv"]. 45 46 that the acquisitions would result in benefits such as possible economies of scale, elimination of the duplication of facilities and activities, sharing of production capacity and reserves, and generally more efficient operations." Northeast I, supra. The Commission has also explained that the "antitrust ramifications of an acquisition must be considered in light of the fact that public utilities are regulated monopolies and that federal and state administrative agencies regulate the rates charged consumers." Id. When assessing the possible anticompetitive effects of a proposed acquisition, the Commission is -- primarily concerned with the structure of public utility holding company systems. The Commission, however, has also considered anticompetitive issues involving the allocation of excess generating capacity, transmission access and the flow of electricity over transmission lines of a holding company system. Entergy, supra (citations omitted). The FERC has jurisdiction over the Merger under Section 203 of the FPA. It will make a finding as to whether the Merger is consistent with the public interest based, in part, upon consideration of the anticompetitive consequences, if any, of the proposed transaction. The Commission has relied upon the expertise of other federal regulators in determining the anticompetitive effects of proposed merger transactions, and the D.C. Circuit has upheld the Commission's ability to watchfully defer to other regulators: [W]hen the SEC and another regulatory agency both have jurisdiction over a particular transaction, the SEC may 'watchfully defer[]' to the proceedings held before -- and the result reached by -- that other agency. Madison Gas & Elec. Co. v. SEC, 168 F.3d 1337, 1341-42 (D.C. 1999), citing City of Holyoke Gas & Elec. Dep't v. SEC, 972 F.2d 358 (D.C. Cir. 1992) (dismissing challenge to order approving merger that asserted Commission could not rely on FERC and state review of competitive effects) [hereinafter "Madison Gas"]. Consistent with the foregoing, the Division in its 1995 Report recommended that "the SEC avoid duplicative review of acquisitions and, where possible, defer to the work of other regulators in reviewing acquisitions." 1995 Report at 66. In this case, the SEC can watchfully defer to other agencies (namely, the DOJ and the FERC) on the question of competitive issues because consummation of the Merger may not take place until and unless potential competitive concerns have been addressed by these agencies under the HSR Act procedures as well as under Section 203 of the FPA. If the Commission determines to approve the Merger (subject to the FERC's approval of the Merger and/or the DOJ's lack of challenge to the transaction), it can defer to these agencies even if their proceedings are not yet complete because the Commission retains ongoing authority under Section 20(a) of the 1935 Act to rescind or further condition its approval of a transaction. Id. ii(a). The Role of the DOJ Pursuant to the HSR Act, AEP and CSW are required to file with the DOJ Premerger Notification and Report Forms. See 16 C.F.R. Parts 801 through 803. The purpose of the HSR Act reporting requirements is to "facilitate evaluation of the antitrust implications of the 46 47 proposed transaction and, where the competitive consequences appear substantial, to permit the DOJ to challenge the legality of the transaction."(7) The HSR Act prohibits consummation of the Merger until the statutory waiting period has expired or been terminated. In July 1999, Applicants filed with the DOJ under the HSR Act. ii(b). The Role of the FERC AEP and CSW filed a joint application with the FERC on April 30, 1998, (see Exhibit D-1.1 filed herewith), as supplemented on January 13, 1999, (see Exhibit D-1.2 filed herewith), pursuant to Section 203 of the FPA for approval of the Merger. Applicants and the FERC Trial Staff entered into the FERC Stipulation under which major issues related to the Merger were resolved, including all significant competition and rate issues (see Exhibit D-1.3 filed herewith). The application, as supplemented, conformed to FERC Order No. 592 in which the FERC adopted the DOJ/FTC Merger Guidelines as the framework for analyzing the impact of a merger on competition in affected markets.(8) The AEP/CSW application to the FERC contained testimony by Dr. William Hieronymus analyzing the Merger pursuant to FERC Order No. 592. Copies of Dr. Hieronymus' testimony are filed as exhibits to Exhibits D-1.1 and D-1.2. The analysis presented therein measures the competitive effect of the Merger within the relevant destination markets. Dr. Hieronymus concludes that, with the mitigation measures which the Applicants propose as a condition of the Merger, the Merger will not adversely affect competition in any of the destination markets that were analyzed. Dr. Hieronymus' testimony is summarized below: (x) Product Markets The FERC presumes the long-term capacity market to be competitive, unless special factors exist that limit the ability of long-term capacity markets to develop. The evidence demonstrates that the Combined Company will not control transmission access, fuel supplies or generation plant sites. Accordingly, the Combined Company will not have market power in long-term capacity markets. For the shorter term markets, the FERC applies a market screen analysis to determine if a merger raises competitive concerns. For that purpose, the FERC uses four product measures: 1) Total Capacity; 2) Uncommitted Capacity; 3) Available Economic Capacity; and 4) Economic Capacity. With respect to the Total Capacity measure, the overall size of the market will be in excess of 340,000 MW in 1999, growing to almost 360,000 MW in 2001. The Total Capacity of the Combined System is approximately 39,000 MW (less the 1604 MW of generating assets - ------------------------- (7) Premerger Practice Notification Manual at xi (American Bar Association 1991). (8) Inquiry Concerning the Commission's Merger Policy under the Federal Power Act: Policy Statement, Order No. 592, Docket No. RM96-6-000, Regulations Preambles, Paragraph 31,044 at 30,109 (December 30, 1996). 47 48 located in ERCOT and 300 MW of generating assets located in SPP that Applicants have agreed to divest). Applying the screening analysis, Dr. Hieronymus concluded that the market is unconcentrated (an HHI of less than 1000) and, accordingly, the Merger has no anti-competitive impact with respect to Total Capacity. With respect to the Uncommitted Capacity measure, CSW Energy has 705 MW of uncommitted capacity and AEP has 495 MW of uncommitted capacity. The combination of the uncommitted capacity represents less than a 15 percent combined market share. Dr. Hieronymus concluded that the market of Uncommitted Capacity is unconcentrated and mergers in such markets are presumed to have no anti-competitive impact. With respect to the Economic Capacity measure, Dr. Hieronymus concluded that when the Applicants' mitigation proposal is taken into account, the Merger significantly deconcentrates the CSW SPP and ERCOT markets and results in HHI changes below the FERC Order 592 threshold in all but a handful of destination markets. (The exceptions involve destination markets in which the Combined Company will have a miniscule market share because the Applicants' use of the 250 MW Contract Path will serve to increase the already high market share of one or more incumbent sellers that are unrelated to either Applicant.) With respect to the Available Economic Capacity measure, Dr. Hieronymus concluded that, for the most part, CSW's SPP and ERCOT markets are deconcentrated. The AEP market is either deconcentrated or reflects zero HHI changes in all time periods. The HHI changes for almost all of the other relevant destination markets and time periods are below the FERC Order No. 592 threshold or are zero or are negative (meaning that the market is deconcentrated). The few exceptions are in destination markets in which the Applicants have little or no post-merger market share. With the inclusion of the 250 MW Contract Path to interconnect the Applicants' systems, a few additional failures under the screening analysis resulted for the Economic Capacity Measure in the SPP and ERCOT markets. As to those markets that did not fall below the minimum benchmark, Applicants, in their application filed with the FERC, as supplemented, proposed mitigation measures to offset any increase in market concentration so as to reduce the HHI to fall within safe harbor levels. AEP and CSW propose to divest ownership of 550 MW of generation capacity (300 MW in the SPP and 250 MW in the ERCOT) by means of auction. (As part of the settlement with the staff of the Texas Commission, Applicants have now agreed to divest 1604 MW of generating assets located in ERCOT, which includes the 250 MW of generating assets located in ERCOT that will be divested as part of the proposed FERC mitigation measures). The auction process for the ERCOT and SPP generation capacity is conditioned upon there being no violation of the pooling-of-interests accounting treatment used for the Merger. If it is determined that the ERCOT divestiture can proceed immediately after the Merger closes without jeopardizing pooling-of-interests accounting treatment for the Merger, sale of the plants would begin no later than 90 days after the Merger closes. Absent that determination, the divestiture would occur approximately two years after the Merger closes to satisfy the requirements to use pooling-of-interests accounting treatment. The 300 MW of generation to be divested in SPP is also conditioned upon the plant no longer being required to meet PSO's native 48 49 load demand requirements following electric industry restructuring in Oklahoma and is no longer required to satisfy SPP reliability criteria. Until these conditions are met, the Combined Company will sell 300 MW hours of energy per hour in a system power sale. The divestiture process for the ERCOT capacity will begin after the completion of the Merger, unless the Commission determines that a sale within two years of the Merger will cause the pooling-of-interests accounting treatment to be unavailable. The proposed sales and subsequent divestitures are, therefore, specifically structured to meet any concerns that the increases in market concentration in the SPP and ERCOT markets, without correction, could have anti-competitive effects on those markets. In interpreting the estimated market shares and HHIs, it is important to recognize that non-firm energy markets have a number of characteristics that make the exercise of market power, either jointly or unilaterally, extremely unlikely. In particular, the numerous ways energy transactions can be packaged, the diversity of the participants in an evolving and increasingly competitive market, and the fact that buyers are also sellers at various times will make it exceedingly difficult for the Combined Company to exercise market power through coordinated behavior. As a further mitigation measure, Applicants agreed to waive the Combined Company's priority with respect to its use of the HVDC ties. As noted in Item I.B. above, the waiver applies to unplanned (i.e., non-firm) transactions in ERCOT and non-firm transactions in SPP. In sum, it is clear that the Merger will have little or no effect on competition in the relevant product markets. (y) Vertical Markets The Merger raises no vertical concerns. AEP and CSW are not transmission competitors and each operates under FERC Order No. 888 OATTs. AEP and CSW have filed a joint Order No. 888 compliance tariff applicable to the Combined System to be made effective as of the Merger closing date. Hence, Applicants are not in a position to favor each other in operating their transmission systems. As part of the FERC Stipulation and settlements with the staffs of various state commissions, AEP and CSW each have committed to join an ISO or RTO, thus eliminating any remaining concerns regarding the transmission facilities' impact on competition. Through the ISO or RTO, the transmission facilities will be operated for the benefit of the system users in a competitive and non-discriminatory manner. In this regard, on June 3, 1999, AEP joined with four other utilities in filing the Alliance RTO Application, which is currently pending at FERC. CSW is participating in the ERCOT independent regional transmission plan for the portion of its system that is within ERCOT and is participating in discussions with other interested parties about the formation of an RTO that would include utility systems in the SPP. As part of the settlement with the staff of the Texas Commission, Applicants agreed that they would obtain the Texas Commission's prior approval before withdrawing from either ERCOT or the SPP. The Merger raises no vertical issues relating to ownership or control of scarce generating capacity. There are a number of projects under development and construction in Texas which 49 50 will be capable of selling into ERCOT and/or the SPP, including an 800 MW merchant plant located in Grimes County; a 350 MW merchant plant located in Uvalde County; a 300-400 MW gas-fired cogeneration facility located at Reynolds Metals' Sherwin alumina production plant near Corpus Christi; a 1,100 MW gas-fired, combined cycle plant whose output will be sold to Texas Utilities for two years; a 1,000 MW gas-fired combined cycle facility located in Edinburg, Texas; a 700 MW merchant plant is planned for Magic Valley Electric Cooperative; a 510 MW addition is planned for a cogeneration facility located in Pasadena, Texas; a 500 MW gas-fired combined cycle facility located in Hidalgo County, Texas.(9) By utilizing the Combined Company's OATT, customers within the Combined Company's service territory will be able to access numerous suppliers that independently have constructed substantial generating capacity in the past and that have located both within and outside the service territory. In the longer term, with the introduction of retail competition, it is expected that retail customers will have access to energy service providers with different generation sources and mixes. In addition, Applicants submitted to the FERC testimony by J. Stephen Henderson demonstrating that, irrespective of the existence of an ISO or RTO, the Merger will not create any ability or incentive for the Combined Company to (1) use AEP's transmission system to limit competition in relevant markets into which CSW sells electricity, or (2) use CSW's transmission system to limit competition in relevant markets into which AEP sells electricity. A copy of Mr. Henderson's testimony is filed as an exhibit to Exhibit D-1.2 and is incorporated by reference. AEP and CSW also presented testimony by Raymond Maliszewski explaining, among other things, that the configuration of the AEP System does not permit AEP to affect adversely load flows on third party systems by departing from economic dispatch of the AEP System. A copy of Mr. Maliszewski's testimony is filed herewith as Exhibit D-1.2. In sum, Dr. Hieronymus' testimony demonstrates that taking into account the Combined Company's mitigation measures, the Merger presents no competitive problems. Thus, the Merger can be expected to obtain required approval and clearance from the FERC. See Madison Gas & Electric (the Commission is entitled to defer to FERC's expertise in evaluating the competitive aspects of a merger). To the extent the Commission finds that there is any concentration of control resulting from the Merger, Applicants believe any such concentration of control is far outweighed by the benefits accruing to the public, investors and consumers from the Merger, as more fully discussed in Item 3.B.2 below. Thus, the Merger will not "tend toward . . . the concentration of control" of public utility companies, of a kind or to an extent detrimental to the public interest or the interests of investors or customers within the meaning of Section 10(b)(1). 2. Section 10(b)(2) Section 10(b)(2) of the 1935 Act requires the Commission to approve the Merger unless it finds that the consideration, including all fees, commissions and other remuneration, is unreasonable or does not bear a fair relation to the sums invested in, or the earning capacity of the utility assets underlying the securities to be acquired. - ------------------------- (9) Power Generation Markets Quarterly, First Quarter 1999. 50 51 a. Reasonableness of Consideration Section 10(b)(2) "does not demand a mathematical equivalence of values for the terms of the exchange." Entergy, supra. Prices arrived at through arm's length negotiations are particularly persuasive evidence that the Section 10(b)(2) requirement is met. See, e.g., Northeast I, supra, (citing Ohio Power, HCAR No. 16753 (June 8, 1970)). Moreover, the assistance of independent consultants in setting consideration is deemed to be evidence that the requirement is met. See, e.g., Northeast I, supra (citing Southern Co., HCAR No. 24579 (Feb. 12, 1988)). The Commission also "independently analyze[s] the financial and operating performances of [the combining entities]" with respect to such factors as relative market values and dividends per share. Centerior, supra. Finally, the Commission considers whether the shareholders have approved the acquisition. Entergy, supra. Under the standards applied by the Commission in previous utility mergers, the consideration to be paid by AEP in the Merger is reasonable and bears a fair relation to the earning capacity of the utility assets underlying the CSW Common Stock to be acquired, in compliance with Section 10(b)(2). Based on the Exchange Ratio set forth in the Merger Agreement, the consideration offered by AEP will be AEP Common Stock which had a market value on December 19, 1997, the last trading day before the Merger was announced, of approximately $6.6 billion, or approximately $31.20 per share of CSW Common Stock, which was approximately 20% above the closing price of CSW Common Stock on December 19, 1997. Applicants' belief that the consideration is fair and reasonable is based on the following reasons, each of which is discussed in detail below: - Arm's length negotiations between AEP and CSW conducted in a competitive context resulted in the proposed Exchange Ratio; - An opinion from AEP's financial adviser, Salomon, states that the consideration to be paid by AEP with respect to the Merger is fair, from a financial point of view, to AEP; - An opinion from CSW's financial adviser, Morgan Stanley, states that the consideration to be received by CSW's shareholders with respect to the Merger is fair, from a financial point of view, to CSW's shareholders; - Valuation analysis demonstrates the fairness of consideration as evidenced by the comparative market prices of, and dividends paid on, the AEP and CSW Common Stock; - The Applicants' shareholders approved the shareholder actions necessary to effect the Merger; and - The inclusion of required closing conditions in the Merger Agreement serves to assure that the Merger will be consummated on terms that are fair to Applicants and their shareholders. (i) Competitive Negotiations 51 52 The chief executive officers of AEP and CSW had informal discussions on several occasions from January 1997 to March 1997 regarding a merger of the companies. With CSW's stock price depressed in late April 1997 as a result, in the opinion of CSW management, of adverse action by the Texas Commission, CSW management terminated discussions with AEP. From May through September 1997, CSW management continued to explore a variety of strategic alternatives. As part of this analysis, CSW management, in consultation with its advisers, developed a list of screening criteria for use in analyzing potential merger partners. CSW also considered other strategic alternatives which could be pursued without a business combination. At a meeting of the CSW Board of Directors on September 27, 1997, management recommended to the CSW Board of Directors that CSW seek a merger that could enhance CSW's ability to implement its long-term vision. The CSW Board of Directors unanimously authorized CSW management to pursue its search for an appropriate merger partner while continuing to evaluate CSW's stand-alone options. In September 1997, the chief executive officers of AEP and CSW resumed their discussions regarding a stock-for-stock merger. During the ensuing months, CSW's management also held preliminary discussions, and exchanged non-public information, with three other electric utilities regarding a possible business combination and continued to evaluate other stand-alone alternatives. CSW management met with the CSW Board of Directors and a committee of the CSW Board of Directors on many occasions during October-December 1997 to update the directors and receive direction on the course of their discussions. On November 24, 1997, CSW management and CSW's advisers met with a committee of the CSW Board of Directors to discuss the progress of the strategic alternative evaluation process. The committee authorized CSW management to send to four strategic merger candidates a letter requesting each to advise CSW as to whether, and on what terms, it was interested in pursuing a strategic combination with CSW. On December 11, 1997, CSW received affirmative responses to the request letters from AEP and two of the three other companies. On December 12, 1997, CSW management and advisers met with a committee of the CSW Board of Directors to discuss the responses and the status of the strategic merger candidate evaluation process. After analyzing the responses and CSW's other stand-alone alternatives, the committee determined that AEP appeared to be the best strategic merger partner for CSW and that a merger with AEP on the right terms would be more likely to restore and enhance long-term stockholder value than any of the other merger or stand-alone strategic alternatives. Following negotiations between the chief executive officers of each company, CSW and AEP agreed to proceed with merger negotiations on the basis of a proposed exchange ratio of 0.60 shares of AEP Common Stock for each share of CSW Common Stock. The Board of Directors of both companies approved the Merger Agreement in meetings on December 21, 1997, and the Merger Agreement was signed that afternoon. The Exchange Ratio was agreed to by the Applicants after extensive deliberations between the two companies involving senior management personnel assisted by financial and legal advisers skilled in mergers and acquisitions transactions. Moreover, the negotiations were carried out in a competitive context with other companies. 52 53 For further information regarding the background of the proposed Merger between AEP and CSW, reference is made to the Joint Proxy Statement and Prospectus filed as Exhibit C-2 and incorporated herein by reference. (ii) Fairness Opinions As discussed above, the Boards of Directors of AEP and CSW approved the Merger Agreement and the transactions contemplated thereby. Prior to such approvals, the Boards received opinions from AEP's and CSW's respective financial advisers as to the fairness of the proposed consideration. AEP's Board of Directors received a written opinion from Salomon that, based upon specified procedures and assumptions, the consideration to be paid by AEP with respect to the proposed Merger is fair, from a financial point of view, to AEP. CSW's Board of Directors received a written opinion from Morgan Stanley that the proposed consideration is fair, from a financial point of view, to the shareholders of CSW. No limitations were imposed by the AEP Board or the CSW Board upon Salomon or Morgan Stanley, respectively, with respect to the investigations made or procedures followed by their respective financial advisers. In arriving at their respective opinions, Salomon and Morgan Stanley reviewed (i) the terms of the Merger Agreement; (ii) certain publicly available business and financial information relating to AEP and CSW; (iii) certain other internal information concerning AEP and CSW, including financial projections provided to them by AEP and CSW; (iv) certain publicly available information concerning the trading of, and the trading market for AEP's and CSW's Common Stock; (v) certain publicly available information with respect to other companies they believed to be comparable to AEP and CSW and the trading markets for such other companies' securities; and (vi) certain publicly available information concerning the nature and terms of other transactions they considered relevant to their inquiry. They also met with officers and employees of AEP and CSW to discuss the foregoing as well as other matters relevant to the Merger. Copies of the fairness opinions are filed as Annexes II and III to Exhibit C-2 and are incorporated by reference. Salomon's fairness opinion was based on eight valuation analyses relating to, respectively, Discounted Cash Flow Analysis-CSW; Comparable Company Analysis-CSW; Analysis of Selected Utility Company Mergers and Acquisitions; Discounted Cash Flow Analysis-AEP; Comparable Company Analysis-AEP; Historical Trading Ratios Analysis; Contribution Analysis; and Pro Forma Analysis of the Merger. These analyses supported the fairness of the proposed consideration, from a financial perspective, to be paid by AEP and are summarized below: Discounted Cash Flow Analysis-CSW. This analysis was based on certain operating and financial assumptions for CSW in years 1997 to 2006 provided by CSW and adjusted by the management of AEP. From this analysis, Salomon derived a range of the implied equity value per share of CSW Common Stock of approximately $25 to $29. In addition, Salomon derived a per share present value of the expected Merger savings of $5. Thus, Salomon derived a reference range for the implied value per share of CSW Common Stock, including savings, of approximately $30 to $34. 53 54 Comparable Company Analysis-CSW. Salomon reviewed certain publicly available financial, operating, and stock market information for CSW and five other publicly-traded utility companies Salomon considered comparable to CSW. Salomon derived the implied value of the CSW shares on (1) a stand-alone basis ($21 to $25 per share); (2) with the Merger savings ($26 to $30 per share); and (3) including a 30% control premium, but no Merger savings ($27.50 to $32.50 per share). Analysis of Selected Utility Company Mergers and Acquisitions. Salomon reviewed a set of completed and proposed utility mergers announced since August 1996. Salomon calculated multiples based on the offer price for each target company to such company's respective pre-announcement market price, book value, earnings and cash flow per share. From this analysis, Salomon derived a reference range for the implied equity value per CSW share of $27 to $35. Discounted Cash Flow Analysis-AEP. This analysis was based on certain operating and financial assumptions for AEP in years 1997 to 2006 provided by AEP. From this analysis, Salomon derived a range of the implied equity value per share of AEP Common Stock of approximately $42 to $49. Comparable Company Analysis-AEP. Salomon reviewed certain publicly available financial, operating, and stock market information for AEP and five other publicly-traded utility companies Salomon considered comparable to AEP. Salomon derived a range of the implied equity value per share of AEP Common Stock of approximately $44 to $52. Historical Trading Ratios Analysis. Salomon also reviewed the daily closing prices of CSW Common Stock and AEP Common Stock during the period from December 15, 1992 through December 15, 1997 and the historical trading ratios over such period. During that period the average historical trading ratio was 0.70. The ratio on December 15, 1997 was 0.52. Contribution Analysis. Salomon reviewed the relative contributions of each of AEP and CSW to estimated net income and other indicators of the Combined Company for each of the years 1997 to 2006. This analysis showed that CSW is expected to contribute a percentage of the Combined Company's net income ranging from approximately 34% to 40% in 1997 to 2003 before leveling off at 39% in the years 2004 to 2006. CSW stockholders would own approximately 40% of the outstanding shares of the Company based on the Exchange Ratio. Pro Forma Analysis of the Merger. Salomon also analyzed certain pro forma effects resulting from the proposed combination for the years 2000 through 2006. This analysis was based on financial and operating assumptions for AEP and CSW, as provided to Salomon by AEP, and assumed the realization of the cost savings projected by AEP management to result from the Merger. Based on such analysis, Salomon concluded that the Merger would be somewhat dilutive to AEP shareholders for the years 2000-2002 and somewhat accretive for the remaining years of the forecast. Salomon noted that the transaction would generally produce earnings per share accretion of 10% or more each year for CSW shareholders, but would result in a lower dividend per original CSW share of more than 10% through 2003, the reduction continuing to decline thereafter. (iii) Comparative market prices of and dividends paid on common stock. 54 55 Market prices at which securities are traded have always been strong indicators as to values. As shown below, most quarterly price data for CSW Common Stock and AEP Common Stock, high and low, for the years 1996 and 1997 provide support for the calculation of the Exchange Ratio.
AEP - ------------------------------------------------------------------------------------- High Low Dividends - ------------------------------------------------------------------------------------- 1996 1st Qtr........... 44-3/4 40-1/8 0.60 2nd Qtr........... 42-3/4 38-5/8 0.60 3rd Qtr........... 43-1/8 40 0.60 4th Qtr........... 42-1/2 39-1/2 0.60 - ------------------------------------------------------------------------------------- 1997 1st Qtr........... 43-3/16 40 0.60 2nd Qtr........... 42-1/2 39-1/8 0.60 3rd Qtr........... 46-5/8 41-1/2 0.60 4th Qtr........... 52 45-1/4 0.60 - ------------------------------------------------------------------------------------- CSW - ------------------------------------------------------------------------------------- High Low Dividends - ------------------------------------------------------------------------------------- 1996 1st Qtr........... 28-1/2 26-3/8 0.435 2nd Qtr........... 28-7/8 26-1/2 0.435 3rd Qtr........... 28-1/2 25-3/4 0.435 4th Qtr........... 28 25-1/2 0.435 - ------------------------------------------------------------------------------------- 1997 1st Qtr........... 26 20-3/4 0.435 2nd Qtr........... 22-1/4 18 0.435 3rd Qtr........... 22-9/16 19-1/2 0.435 4th Qtr........... 27-1/2 20 0.435 - -------------------------------------------------------------------------------------
(iv) Shareholder Approval In addition, the holders of AEP Common Stock and the holders of CSW Common Stock overwhelmingly approved the shareholder actions necessary to effect the Merger. At the Annual Meeting of Shareholders of AEP held on May 27, 1998, holders of approximately (i) 71% of all outstanding AEP Common Stock approved an amendment to the Restated Certificate of Incorporation of AEP increasing the number of authorized shares of AEP Common Stock, and (ii) 72% of all outstanding AEP Common Stock approved the issuance of the AEP Common Stock, each necessary to effect the Merger. Holders of approximately 82% of all outstanding CSW Common Stock approved the Merger at the Annual Meeting of Stockholders of CSW held on May 28, 1998. (v) Merger Agreement Finally, the Merger Agreement contains a number of closing conditions that help ensure the continued reasonableness of the consideration. Under Section 8.1(g), it is a condition precedent to closing, applicable to both AEP and CSW, that "there shall not have occurred and remain in effect a Divestiture Event with respect to [either company]."(10) Pursuant to Sections 8.2 and 8.3, AEP and CSW are each required to affirm that all representations made with respect to the Merger Agreement are true and correct as of the date of closing, including the representation that no Material Adverse Effect(11) shall have occurred and that there shall exist no fact or - ------------------------- (10) "Divestiture Event" means "any Law, Regulation or Order adopted or issued by a Governmental Authority that requires the divestiture of a substantial portion of the generating assets of . . ." CSW or AEP. (11) "Material Adverse Effect" means "any change or effect that is material and adverse to the business, condition (financial or otherwise) or results of operations or prospects of a specified Person and 55 56 circumstance which may reasonably be expected to give rise to a Material Adverse Effect. Other closing conditions ensure that the Merger will not be consummated in the event of onerous or burdensome regulatory orders or conditions. b. Reasonableness of Fees The various categories of fees, commissions and expenses in connection with the transaction and regulatory processing costs for the Merger are set forth in Item 2 to this Application-Declaration. Applicants together expect to incur total transaction and regulatory processing costs of approximately $53 million, including financial advisory fees of approximately $31 million. Applicants believe that these estimated fees and expenses bear a fair relation to the value of CSW and the savings to be achieved by the Merger and are fair and reasonable in light of the size and complexity of the Merger. Northeast Utilities, HCAR No. 25548 (June 3, 1992), modified on other grounds, HCAR No. 25550 (June 4, 1992) [hereinafter "Northeast II"] (Commission considers whether fees and expenses bear a fair relation to the value of the company to be acquired and the savings to be achieved by the acquisition). Based on the price of AEP Common Stock on December 19, 1997, the transaction would be valued at $6.6 billion. As discussed in Item 3.B.2 below, net nonproduction savings of nearly $2 billion and net fuel-related savings of approximately $98 million are projected over the first ten years after the Merger. Moreover, the estimated overall fees are reasonable compared to the overall fees approved by the Commission in other merger transactions. The total fees of $53 million to be incurred by Applicants represent approximately 0.8% of the value of consideration to be paid by AEP, based on the price of AEP Common Stock on December 19, 1997. The Commission has approved fees, commissions and expenses of $46.5 million in connection with the acquisition of PSNH by Northeast, representing approximately 2% of the value of the assets to be acquired (Northeast I; Northeast II); $47.12 million in connection with the reorganization of Cincinnati Gas and Electric and PSI Resources as subsidiaries of CINergy (CINergy Corp., HCAR No. 26146 (Oct. 21, 1994) [hereinafter "CINergy"]) and $38 million in fees, commissions and expenses in connection with Entergy's acquisition of Gulf States Utilities Company, representing approximately 1.7% of the value of the consideration paid to Gulf States' shareholders (Entergy, supra). The investment banking fees of approximately $31 million to be incurred by Applicants represent approximately 0.47% of the value of consideration to be paid by AEP, based on the price of AEP Common Stock on December 19, 1997. These fees incurred by Applicants resulted from a marketplace in which investment banking firms actively compete with each other to act as financial advisers to merger participants. The Commission has previously approved financial advisory fees of approximately $10.6 million, representing approximately 0.46% of the value of the assets to be acquired (Northeast I, supra and Northeast II, supra), financial advisory fees - -------------------------------------------------------------------------------- its subsidiaries, if any, taken as a whole; provided, however, that, as used in this definition the word material shall have the meaning accorded thereto in Section 11 of the Securities Act." 56 57 representing approximately 0.96% of the aggregate value of the acquisition, (Southern Co., HCAR No. 24579 (Feb. 12, 1988), modified on other grounds, HCAR No. 24579A (February 26, 1988), and Amendment No. 9 to Southern Form U-1 (April 13, 1988)), and financial advisory fees of $8.3 million, representing approximately 0.36% of the value of the consideration paid to Gulf States' shareholders (Entergy, supra and Amendment No. 24 to Entergy Form U-1 (Nov. 18, 1993)). As indicated in Item 2 above, the fees and expenses which are not yet finalized will be filed by amendment when they become available. For all of the above reasons, the consideration and fees to be paid are fair and reasonable in compliance with Section 10(b)(2). 3. Section 10(b)(3) Section 10(b)(3) of the 1935 Act requires the Commission to approve a proposed acquisition unless the acquisition would unduly complicate the capital structure of the holding company system, or would be detrimental to the public interest, the interest of investors or consumers or the proper functioning of such holding company system. a. Capital Structure The Commission has found that an acquisition does not unduly complicate the capital structure of the holding company system where the effect of a proposed acquisition on the acquirer's capital structure is negligible and the debt to equity ratio due to the acquisition is well within "the 65/30% debt/common equity ratio generally prescribed by the Commission." Entergy, supra (citing Northeast I). The Commission has approved common equity to total capitalization ratios as low as 27.6%. See Northeast I, supra. In this regard, the proposed combination of AEP and CSW will not unduly complicate the capital structure of the Combined System. The only changes to the capital structure of AEP will be the acquisition by AEP of CSW Common Stock and the addition of the capital structure of CSW to AEP's capital structure. CSW and its subsidiaries have publicly held debt and have publicly held preferred stock or preferred trust securities, and all CSW Common Stock will be held by AEP and incorporated within AEP's consolidated financial statements. At December 31, 1997, the respective capital structures of AEP and CSW were as follows:
AEP CSW (in $ millions) (in $ millions) Common Stock Equity............................ $ 4,677 45.52% $ 3,556 44.27% Preferred Stock................................ 175 1.70% 203 2.53% Long-Term Debt................................. 5,424 52.78% 8,937 49.02% Trust Preferred Securities..................... -0- -0- 335 4.17% Total......................................... $10,276 100.00% $ 8,031 100.00%
If the Merger had been consummated on December 31, 1997, the pro forma consolidated capital structure of the Combined Company as of such date (according to generally accepted 57 58 accounting principles, assuming that the Merger is treated as a "pooling-of-interests" under Accounting Principles Board Opinion No. 16) would have been as follows:
Combined Company Pro Forma (in $ millions) Common Stock Equity............................ $8,233 44.97% Preferred Stock................................ 378 2.06% Long-Term Debt................................. 9,361 51.13% Total......................................... 335 1.83% $18,307 100.00%
(a) Includes $53 million of transactions and regulatory processing costs. As can be seen from the above tables, the debt to equity ratio is not altered to any considerable degree by the Merger. The Combined Company's pro forma consolidated common equity to total capitalization ratio of 44.8% is substantially higher than Northeast Utilities' recently approved 27.6% common equity position and comfortably exceeds the "traditionally acceptable 30% level." Northeast I, supra. Finally, the common stock that AEP proposes to issue in the Merger has the same par value, same rights (including voting rights) and preference as to dividends and distributions as the AEP Common Stock presently outstanding. All of the issued and outstanding CSW Common Stock will be owned by AEP as a result of the Merger. As such, there will be no publicly held minority common stock interest in CSW following the Merger. Thus, the Merger does not complicate the capital structure of AEP. b. Public Interest, Interest of Investors and Consumers, and Proper Functioning of Holding Company System Section 10(b)(3) also requires the Commission to determine whether the proposed Merger will be detrimental to the public interest, the interest of investors or consumers or the proper functioning of the Combined System. As discussed in greater detail in Item 3.B.2 below, the Merger will enable the Combined Company to operate more efficiently and economically than either AEP or CSW could operate independently of the Merger. The Merger will result in substantial, otherwise unavailable, benefits to the public and to consumers and investors of both companies -- specifically, savings through labor cost savings, facilities consolidation, corporate and administrative programs, non-fuel purchasing economies, and efficiencies from the combined utility operations. These savings will be passed on to shareholders and consumers. The shareholders, whose interests are protected by the disclosure requirements of the Securities Act of 1933 and the Securities and Exchange Act of 1934, have overwhelmingly approved the shareholder actions necessary to effect the Merger. See Southern, supra (stating that "[c]oncerns with respect to investors have been largely addressed by developments in the federal securities laws and in the securities markets themselves.") The interests of consumers are protected by both state and federal regulation. 58 59 Simply stated, the Merger will create an entity that will be poised to respond effectively to the fundamental changes that have taken and will continue to take place in the markets for electric power as such markets are being deregulated and restructured and will create an entity prepared to compete effectively for consumer's business. As such, consumers, investors, and the public will be the ultimate beneficiaries of the Merger. In sum, because the Merger does not add any complexity to AEP's capital structure and is in the public interest and the interests of investors and consumers, the requirements of Section 10(b)(3) are met. B. Section 10(c) Section 10(c) of the 1935 Act establishes additional standards for approval of the Merger. Under Section 10(c), the Commission cannot approve: (1) an acquisition of securities or utility assets, or of any other interest, which is unlawful under the provisions of Section 8 or is detrimental to the carrying out of the provisions of Section 11; or (2) the acquisition of securities or utility assets of a public utility or holding company unless the Commission finds that such acquisition will serve the public interest by tending towards the economical and efficient development of an integrated public utility system. 1. Section 10(c)(1) Section 10(c)(1) requires that the proposed acquisition be lawful under the provisions of Section 8 of the 1935 Act. Section 8 prohibits an acquisition by a registered holding company of an interest in an electric and gas utility serving substantially the same area without the express approval of the state commission when that state's law prohibits or requires approval of the acquisition. Because neither CSW nor AEP has any direct or indirect interest in any gas utility company, this section is not applicable to the Merger. Section 10(c)(1) also requires that the Merger not be detrimental to the carrying out of the provisions of Section 11. Section 11(b)(1) generally requires a registered holding company system to limit its operations "to a single integrated public-utility system, and to such other businesses as are reasonably incidental, or economically necessary or appropriate to the operations of such integrated public-utility system." Section 11(b)(2) directs the Commission "to ensure that the corporate structure or continued existence of any company in the holding-company system does not unduly or unnecessarily complicate the structure, or unfairly or inequitably distribute voting power among security holders, of such holding-company system." The following analysis demonstrates that the Merger meets the standards of Section 11. a. Section 11(b)(1) (Single integrated public utility system) The Commission has found that the system of each of the Applicants is a single integrated electric utility system. See AEP, supra (finding that AEP is a single integrated system); Central and South West Corp., HCAR No. 22439 (April 1, 1982) (terminating a Section 11(b)(1) hearing and upholding a 1945 determination by the Commission that CSW comprises 59 60 one integrated public utility system). The following analysis supports a determination by the Commission that the Merger of these two utility systems will result in a single integrated electric utility system under Section 11(b)(1). Section 2(a)(29)(A) of the 1935 Act defines an integrated public utility system, as applied to an electric utility system, as: a system consisting of one or more units of generating plants and/or transmission lines and/or distribution facilities, whose utility assets, whether owned by one or more electric utility companies, are physically interconnected or capable of physical interconnection and which under normal conditions may be economically operated as a single interconnected and coordinated system confined in its operations to a single area or region, in one or more States, not so large as to impair (considering the state of the art and the area or region affected) the advantages of localized management, efficient operation, and the effectiveness of regulation. Under this definition, the Commission has established four standards that must be met before the Commission will find that an integrated public utility system will result from a proposed merger of two separate systems: (i) the utility assets of the systems must be physically interconnected or capable of physical interconnection; (ii) the utility assets, under normal conditions, must be economically operated as a single interconnected and coordinated system; (iii) the system must be confined in its operations to a single area or region; and (iv) the system must not be so large as to impair (considering the state of the art and the area or region affected) the advantages of localized management, efficient operation, and the effectiveness of regulation. See, e.g., Environmental Action, Inc., v. SEC, 895 F.2d 1255, 1263 (9th Cir. 1990) (citing In re Electric Energy Inc., 38 SEC 658, 668 (1958)).(12) As demonstrated below, the Merger meets each of these standards. - ------------------------- (12) Although the integrated utility system requirement has been interpreted to involve a four-part test, Applicants submit that the requirement can be fairly interpreted to involve only a three-part test. The plain reading of the integration requirement suggests the last two tests should be read as one test. The requirement provides, in pertinent part, that the "system [be] confined in its operations to a single area or region, in one or more States, not so large as to impair (considering the state of the art and the area or region affected) the advantages of localized management, efficient operation, and the effectiveness of regulation." There is no "and" inserted between "single area or region" and "not so large as to impair" leading to the conclusion that there are two distinct tests which the "system" must meet. Rather, the sentence construction leads to the conclusion that it is the "single area or region" which must not be so large as to result in the specified impairments. In any event, the proposed Merger meets either the three-part test, as set forth in the statute, or the four-part test. 60 61 The Commission must interpret the statutory integration standards "to meet the problems and eliminate the evils enumerated in [the 1935 Act.]" Section 1(c). In so interpreting the integration standards, the Commission must balance the 1935 Act's various objectives. See, e.g., Union Electric, supra (the Commission noted that in the past it had "exercise[d] [its] discretion so as to allow the expeditious consummation of plans that would make for financial simplification even though they fell far short of full compliance with the Act's integration standards" because "with respect to the enforcement of this complex multifaceted and far-reaching statute" it had "found it necessary or appropriate to subordinate some statutory objectives to others."). The various aspects of the integration standard cannot be considered independently of one another and the other objectives of the 1935 Act. See, e.g., Middle West Corp., HCAR No. 4846 (Jan. 24, 1944) (the Commission noted that while it was difficult to reach the conclusion that the systems constituted a single system given the geographic spread of the properties, the integration test was met due to the "contemplated savings resulting from closely coordinated operation and joint planning with respect to the routing of power and the installation of facilities."); Middle West Corp., HCAR No. 5606 (Feb. 16, 1945) (the Commission found that the combined system was not too large "in light of demonstrated disadvantages of lack of coordination."); Sempra Energy, HCAR No. 26971 (Feb. 1, 1999) [hereinafter "Sempra"], citing North American Co., 18 SEC 459, 463 (1945)(in connection with evaluating the integration standard for gas utility systems, the Commission has "read each standard of section 2(a)(29)(B) in connection with the other provisions of the section"). Where the acquisition will result in significant economies and efficiencies to the benefit of the public, investors and consumers, Commission precedent supports a flexible interpretation of the integration standards to further the very interests that the 1935 Act was meant to protect. The Commission has recognized that the 1935 Act "creates a system of pervasive and continuing economic regulation that must in some measure at least be refashioned from time to time to keep pace with changing economic and regulatory climates." Southern, supra (quoting Union Electric, supra). The Commission interprets the 1935 Act and its integration standards "in light of [] changed and changing circumstances." Sempra, supra (interpreting the integration standards of the 1935 Act in light of developments in the gas industry). Accord, NIPSCO Industries, Inc., HCAR No. 26975 (Feb. 10, 1999) [hereinafter "NIPSCO"]. The Commission has cited with favor U.S. Supreme Court and Circuit Court of Appeals cases(13) that recognized the need of an agency to "adapt [its] rules and policies to the demands of changing circumstances"(14) and to "treat experience not as a jailer but as a teacher."(15) As the definition of an integrated public utility system suggests, and as the Commission has previously observed, Section 11 is not intended to impose "rigid concepts" but rather creates a "flexible" standard designed "to accommodate changes in the electric utility industry." UNITIL Corp., HCAR No. 25524 (April 24, 1992) [hereinafter "Unitil"]; see also Yankee Atomic Elec. - ------------------------- (13) Rust v. Sullivan, 500 U.S. 173 (1991); American Trucking Assns., Inc. v. Atchison, T.&S.F.R. Co., 387 U.S. 397 (1967); Shawmut Assn. v. SEC, 146 F.2d 791 (1st Cir. 1945). (14) NIPSCO, supra, citing Rust v. Sullivan at 186-187. Accord, Sempra, supra at n. 23. (15) NIPSCO, supra, citing Shawmut Assn. v. SEC at 796-97. Accord, Sempra, supra at n. 23. 61 62 Co., HCAR No. 13048 (Nov. 25, 1955) [hereinafter "Yankee Atomic"] ("We think it is clear from the language of Section 2(a)(29)(A), which defines an integrated public utility system, that Congress did not intend to imposed [sic] rigid concepts with respect thereto." (citations omitted)). Section 2(a)(29)(A) expressly directs the Commission to consider the "state of the art" in analyzing size and to apply "normal conditions" as the standard for determining whether a system may be economically operated as a single coordinated system. The Commission is not constrained by its past decisions interpreting the integration standards based on a different "state of the art." See AEP, supra (noting that the state of the art -- technological advances in generation and transmission, unavailable thirty years prior -- served to distinguish a prior case and justified "large systems spanning several states.") The concept of what constitutes an integrated public utility system has evolved in light of the dramatic changes in the law, technology and structure of the industry since the passage of the 1935 Act over 60 years ago. In recent years, the "state of the art" has changed enormously. As the Energy Information Administration of the Department of Energy aptly noted, "The era of competition in the electric industry is upon us." Energy Information Administration, Department of Energy, The Changing Structure of the Electric Power Industry: An Update (last modified May 30, 1997) . The initial groundwork for competition was laid by the passage of PURPA in 1978, which opened wholesale markets to certain non-utility producers. PURPA created a new class of non-utility generators, QFs, from which utilities were required to buy power. The passage of the Energy Act in 1992 marked another significant step towards the deregulation of the electric power industry. The Energy Act was designed, among other things, to foster competition in the wholesale market through (a) amendments to the 1935 Act that facilitated and encouraged the ownership and operation of generating facilities by EWGs (which may include IPPs as well as affiliates of electric utilities) and (b) amendments to the FPA, authorizing the FERC under certain conditions to order utilities that own transmission facilities to provide wholesale transmission services for other utilities and entities generating electric power. FERC Order Nos. 888 and 889, issued in April 1996, taken together provide that public utilities must file OATTs permitting open access to transmission and must functionally or actually unbundle their transmission services, by requiring them to use their own transmission tariffs in making off-system and third-party sales. In response to deregulation in the wholesale market for electricity, many state legislatures and regulatory commissions either have adopted or currently are considering the adoption of "retail customer choice" provisions. In general terms, these initiatives require the electric utility to transmit electric power over its transmission and distribution system to a retail customer in its service territory. A requirement to transmit directly to retail customers permits retail electric customers to purchase electric power, at the election of such customers, either from the electric utility in whose service area they reside or from another electric service provider or directly from an electric generator source. As of the date of this filing, state electric restructuring plans have been adopted by the state public utility commissions or legislatures in approximately twenty four states, and all but a few states currently are studying or taking action aimed at restructuring their electric markets. Of the states in which the Combined Company will operate, restructuring legislation has been 62 63 adopted in Oklahoma, Virginia, Arkansas, Texas, and Ohio. Investigations have been commenced which are expected to lead to restructuring plans in the remaining states in which the Combined Company will operate. In Oklahoma, legislation allowing retail competition was passed in April 1997, and amended in September, 1998. Retail choice is scheduled to commence by July 1, 2002. Currently, restructuring related studies are being conducted and are expected to be completed by October, 1999. In March 1999, Virginia enacted a new law to restructure the electric utility industry in that state. Under the restructuring law, a transition to choice of supplier for retail customers will commence on January 1, 2002 and be completed, subject to a finding by the Virginia State Corporation Commission that an effective competitive market exists, by January 1, 2004. Provisions allowing for an acceleration or limited delay in this schedule are also contained in the law. Except as provided in the law, the generation of electricity will not be subject to rate regulation after January 1, 2002. Additionally, each Virginia electric utility is required by 2001 to join or establish a regional transmission entity which will manage and control transmission assets. The Virginia restructuring law also provides an opportunity for recovery of just and reasonable net stranded costs. On April 15, 1999, the Governor of Arkansas signed into law a comprehensive restructuring bill that calls for retail competition to start as early as January 1, 2002, but in no event later than June 30, 2003. Under the measure, utilities may recover transition and net stranded costs and may use securitization to mitigate stranded costs. Utilities that recover stranded costs must freeze rates for residential and small commercial customers for three years, and, for those utilities that do not recover stranded costs, rates must be frozen for one year. Utilities must functionally unbundle into generation, transmission, and distribution units by either creating separate divisions, nonaffiliated companies, separate affiliated companies, or by selling assets to a third party. The Arkansas Commission can force divestiture of generation assets to alleviate market power, and it can decide if stockholders should share stranded cost recovery with ratepayers. On June 18, 1999, the Governor of Texas signed legislation enacting retail competition in Texas. Under the legislation, full retail competition is scheduled to commence by January 1, 2002. Electric rates are frozen for a three year period from January 1, 1999 to January 1, 2002 and, thereafter, a 6% rate reduction will be offered to residential and small commercial consumers. In addition, no power generation company may own and/or control more than 20% of the installed generation capacity in ERCOT. On July 6, 1999, the governor of Ohio signed a bill that restructured the electric utility industry in Ohio affecting OPCo and CSPCo. Under the law, customer choice in electric energy supply is to begin on January 1, 2001, with a transition period to end by December 31, 2005. The law provides Ohio electric utilities the opportunity to recover regulatory assets and other potential stranded costs. The Ohio Commission will address recovery of stranded costs and other issues based on each utility's transition plan which is to be filed by the end of 1999. 63 64 Taken together, these fundamental changes in the legal and regulatory framework governing the electric utility industry are producing the following structural changes: - FERC Order No. 888 and the concomitant development of ISOs and FERC's recent Notice of Proposed Rulemaking regarding the development of RTOs are moving the electric power industry to a disaggregation of control over generation and transmission. Utilities that retain control of their generation capacity are ceding significant control over their transmission capacity, and vice-versa. Consequently, the "1935 model" of an integrated public utility holding company as one that combines generation and transmission is being supplanted by a different model in which the two functions are separated. - One goal of the above-described disaggregation is to eliminate ownership of transmission facilities as a barrier to entry into power markets for those who are ready to compete for customers traditionally served by electric utilities. If nondiscriminatory access to transmission facilities is guaranteed, distance will be significantly reduced as a barrier to competition. - An electricity futures market and electricity spot markets, as well as newly formed entities, such as power marketers, brokers, ISOs and RTOs, have emerged as new market structures and participants. More than 100 marketers have registered with the FERC to trade in electric power. See "Restructuring Energy Industries: Lessons From Natural Gas," Energy Information Administration, Natural Gas Monthly, May 1997. One way in which investor-owned utilities are seeking to improve their position in today's increasingly competitive market is through mergers and acquisitions. Between 1986 and 1996, thirty-nine electric investor-owned utilities merged with other utilities in the industry. Energy Information Administration, Department of Energy, The Restructuring of the Electric Power Industry: A Capsule of Issues and Events (Feb. 10, 1998). Between 1992 and the first half of 1998, 48 investor-owned electric utilities have been involved in the domestic merger and acquisition process. Edison Electric Institute, "Merger & Acquisitions," EEI Financial Information (August 28, 1998). AEP and CSW are seeking to merge to further their mutual strategy of adapting to these historic changes in the electric utility industry. Finally, recent years have witnessed technological advances unforeseeable in 1935. Developments in telecommunications and computer technology, along with parallel technological breakthroughs in transportation, have dramatically reduced, if not eliminated, distance as a significant barrier to centralized management and coordinated operation of any enterprise. It is a truism that today's "global village" is a much smaller place than the world of 1935. Developments in the transportation industry have greatly reduced travel times. And information travels instantly. Computers provide "real time" information to central management, providing it with comprehensive, timely information and the capacity to assert central control over diverse operations. In 1935, "an electric utility system generally included local generation, transmission and distribution, [and] little long-distance transmission . . ." Unitil, supra. Power plants were 64 65 relatively small and isolated, and there was no economical way to transmit power over any great distance. 1995 Report at 1, n. 1 (citation omitted). In today's world, "improved transmission and monitoring technologies have increased the feasible geographic bounds for supply choice; a geographic radius of 1,000 miles or more is currently considered reasonable for choosing among supply options." Rodney E. Stevenson & David W. Penn, "Discretionary Evolution: Restructuring the Electric Utility Industry," Land Economics, Vol. 71, No. 3 (August 1, 1995). Technological advances have occurred with respect to the "size" of transmission lines. The building and expansion of the bulk power transmission networks (345 Kv to 765 Kv lines) throughout the United States has allowed for the transfer of large amounts of power over great distances. The construction of such facilities has increasingly made it possible for electric utilities with service territories over large geographic areas to share resources in providing more reliable and economic service to their customers. There were less than 100 circuit miles of 345 Kv lines prior to 1950 and less than 100 circuit miles of 500 Kv lines prior to 1960. Electric Power Research Institute, Transmission Line Reference Book (2d ed., revised, 1987) at 15 [hereinafter "Transmission Line"]. The first 765 Kv lines in the United States were built for AEP and were energized in 1970. Id. at 14. Transmission lines above 189 Kv have grown from 7,800 circuit miles in 1950 to 151,700 circuit miles in 1995. Edison Electric Institute, EEI Pocketbook of Electric Utility Industry Statistics (42d ed. 1997) at 38. The contribution percentage of these lines above 189 Kv as compared to all transmission lines above 22 Kv has grown from 3.3 % in 1950 to 22.6 % in 1995. Id. Technological advances have also occurred with respect to the "type" of transmission lines. The application of HVDC technology provides the ability to transmit bulk power over longer distances with less energy loss and normally with a smaller investment than with alternating current ("AC") transmission lines. This technology provides an economical way to interconnect separated AC power grids and enables power transfers to occur between these systems such that it not only provides for improved economies, but also provides improvements in reliability. HVDC technology was not commercially applied in the United States for bulk power transfers until 1970, with the operation of the Pacific Intertie, Stage 1 USA. Transmission Line at 17. From 1968 to 1981, there were 11,326 MWs of HVDC capacity added in North America. Id. HVDC capacity has continued to be added in different areas of the United States since 1981. In fact, the CSW System constructed and placed in service a 220 MW HVDC interconnection between the SPP and ERCOT in December 1984. In August 1995, another HVDC interconnection rated at 600 MW owned by CSW and several other electric utility partners was placed in service between the same two power pools, but at a different location. The application of phase shifting transformers, series compensation, and flexible alternating current transmission system ("FACTS") technology has also provided the ability to improve and control the transfer of power and energy across expansive transmission networks. Their use historically has been more selective because of the operational problems that accompany their day- to-day use. However, over the years with improvements in technology and operating experience, their application is becoming more common. New flexible alternating FACTS technology can increase the capacity of existing transmission lines by approximately 20 to 40 percent. Electricity: Innovation and Competition, Hearing Before the Subcomm. of Energy and Power of the House Comm. on Commerce, 105th Cong. 38 (1997) (statement of Robert B. Schainker, Manager, Substations, Transmissions and Substation Business Area Power Delivery 65 66 Group, Electric Power Research Institute). Such technology "help[s] electric utilities operate their bulk power networks closer to their inherent thermal limits, while maintaining and/or improving network security and reliability." Id. Advances in telecommunications and computer technology have improved the ability to economically dispatch power systems and control power flow across such systems. Improvements in telecommunication technology and the growth in coverage area of telecommunications systems have allowed for the quick and reliable transfer of data necessary to control and dispatch from a single location generation that can be scattered over large geographic areas. During the last 10 to 15 years, the expansion of microwave and fiber optic networks has provided utilities the ability to transfer information at much greater speeds, with improved quality, and greater reliability. Prior to the 1970s, data was transferred at baud rates as low as 75 baud (bit per second), sometimes being transmitted over the power lines themselves. Today, data transferred from the field to central control centers is at a minimum 1200-baud rate to accomplish 2 second scan rates. Larger data transfers between control centers are normally accomplished at transfer rates from 56 kbaud to 224 kbaud. Computer technology necessary to economically dispatch power systems and to control power flow across the bulk power transmission system has advanced significantly since 1935, especially within the last ten years. The improvements provided by fast and reliable telecommunication network allow for the control and economic dispatch of power systems that extend over large geographic areas, providing system operators an almost real time ability to monitor and control the power system. Current control systems include software programs that can help the operator analyze the real time operation of the power system and look for potential problems before they occur. These complex programs have the ability to suggest corrective measures and, in some cases, implement responses without system operator participation. Such programs provide utilities greater ability to obtain more capability out of their existing electric system, improve system reliability, and improve economies. See, e.g., discussion of Central Dispatch Planning and Central Economic Dispatch in Item 1.B.3.a, supra. In addition, significant improvements in transmission and resource planning have occurred since 1935. There are several software packages available today that enable the system planner to model the operation of most of the equipment used on a power system. Studies can be performed that not only evaluate power transfer capabilities, but also allow the system planner to add different types of equipment to determine their impact on increasing power transfer capabilities. Development of such software has enabled the system planner to determine what equipment functions best as well as where and when it should be installed. Further technological advances can be expected in the future as "power engineers" explore the potential for computers to optimize the efficiency and reliability of the North American power network. Leslie Lamarre, "The Digital Revolution," EPRI Journal, Jan./Feb. 1998. The fundamental changes in technology outlined above dramatically alter the "state of the art" which Congress, more than sixty years ago, directed the Commission to consider. Such fundamental changes led the Division, in the 1995 Report, to state that it intends to apply a more flexible interpretation of the integration requirements under the 1935 Act; and the Division recommended that the Commission "respond realistically to the changes in the utility industry and interpret more flexibly each piece of the integration equation." 1995 Report at 67. The 66 67 Division further noted that in considering the integration requirements, the Commission should place more focus on the acquisition's "demonstrated economies and efficiencies." Id. at 69. Each of the four integration standards is discussed below. (i) Interconnection The Combined System will be physically interconnected or capable of interconnection. The required method of interconnection is not defined in the 1935 Act. The Commission has recognized that the interconnection requirement should be applied flexibly to allow for methods of interconnection beyond simply a transmission line owned by the merging utilities. In this regard, the Commission has found (which finding was upheld on appeal) sufficient a "three-year 'firm contract' to use a transmission line owned by two unrelated parties." WPL Holdings at 2262-63, aff'd, Madison Gas & Electric; Conectiv Inc., 66 S.E.C. Docket 1260 (1998) [hereinafter "WPL Holdings"] ("Delmarva and [Atlantic City Electric] are interconnected through their undivided interests in, and/or rights to use, the same regional generation facilities and extra-high voltage transmission facilities, as well as through their contractual rights to use the transmission facilities of other members of the PJM regional power pool") [hereinafter Conectiv]; Northeast I, supra (interconnection standard met where combining entities reached an agreement to obtain service by utilities with a transmission line interconnecting the two systems); Centerior, supra (interconnection standard met where merging systems could be interconnected through a power transmission line, owned by an unaffiliated company, that each had the right to use). The Division has recommended that the Commission "respond realistically to the changes in the utility industry and interpret more flexibly each piece of the integration equation," including the physical integration requirement. 1995 Report at 67. The means through which two utilities are physically capable of sharing power has expanded with changes in the industry. Utility companies can now share power through power pool arrangements, reliability councils, RTOs, and ISOs. The 1935 Act does not require two merging utilities to demonstrate, at the time of the merger application, the method through which they will be interconnected throughout the lifetime of the combined system. Northeast I supra (Commission approved a merger where the combining utilities only had an absolute right to use a third party transmission line for 10 years). The statute also does not require that the merging utilities be interconnected from the outset. Rather, the merging utilities need only be "capable of interconnection" to meet the physical interconnection requirement.(16) - ------------------------- (16) To meet the Section 11(b)(1) integration standard, the utility assets of the currently existing system need only be "capable of physical interconnection" based on the definition found in Section 2(a)(29)(A). In another recent case, two merging utilities had no contract path but merely an intention to construct a new transmission tie-line within five years in order to interconnect their systems. On that basis, the Commission found that the merging utilities were "capable of being interconnected." New Century Energies Inc., 65 S.E.C. 277, 314-16 (1997) [hereinafter New Century Energies]. By any 67 68 As noted in Item 1.B.3 above, AEP and CSW will interconnect their systems through the 250 MW Contract Path across the Ameren system. Under Commission precedent, this satisfies the interconnection requirement of Section 2(a)(29)(A). Moreover, the Applicants have the ability through the Ameren OATT to renew the Contract Path. Thus, the Contract Path provides the Applicants with the means to meet the interconnection standard under the Act and, at the same time, preserves flexibility to enter into more favorable arrangements should they become available during the four-year term of the Ameren contract. As noted above, the electric industry is in the process of dynamic change; there is growing pressure on public utilities to restructure and increasing competition in the marketplace. Applicants believe that within the next four years there may be transmission interconnection alternatives available as a result of these changes and that the Commission therefore should find the Contract Path to be sufficient. Although the precise method of interconnection has not yet been determined four years into the future, the Applicants commit to continue to meet the interconnection requirement at that time. As noted in Item 1.B.3., Applicants have committed to limit their reservation of firm transmission service from east to west to 250 MW unless the FERC authorizes them to go above this limit.(17) See Dr. Hieronymus' testimony filed as an exhibit to Exhibit D-1.2. As discussed above in Item 1.B.3, Applicants' goal ultimately is to further enhance the interconnection of the Combined System through participation in a regional RTO (subject to the need of the CSW-ERCOT companies to continue participation in the ERCOT ISO). Assuming that the Combined Company belongs to a single RTO, the RTO will have the capability to use the other members' transmission lines to transmit power within the Combined System. The effect is the same even if the Combined Company belongs to separate but contiguous RTOs, provided the RTOs are not permitted to erect economic barriers between them.(18) In this regard, the Commission has found that the transmission rights associated with being a member of an ISO help to satisfy the interconnection requirement. Conectiv, supra. (ii) Single Interconnected and Coordinated System - -------------------------------------------------------------------------------- reasonable measure, an intention to construct a tie-line is far more tenuous than an actual physical interconnection, by contract or otherwise. (17) Applicants have committed to limit their reservation of firm transmission service to avoid potential anticompetitive effects as a result of the Merger, which is an additional consideration under the 1935 Act. In applying the 1935 Act, the Commission must 'weigh policies [of the 1935 Act] against each other and against the needs of particular situations.' Union Electric, supra. The limitations to which the applicants have agreed represent a reconciliation of the various objectives of the 1935 Act in furtherance of the interests which the 1935 Act was meant to protect, those of investors, consumers and the public. (18) In this regard, the Commission has previously approved a merger where the merging utilities were in more than one reliability council. See New Century Energies, supra (approving a merger in which one of the merging utility systems was located in the southwest corner of the eastern United States electricity grid and was a member of the Southwest Power Pool, a regional reliability coordinating organization in the eastern grid, and the other merging utility system was located in the western United States electrical grid and was a member of the Western Systems Coordinating Council, a reliability council for members in the western United States electrical grid). 68 69 The Combined System will be capable of being economically operated as a single interconnected and coordinated system, as required by Section 2(a)(29)(A). The Commission has "interpreted this language to refer to the physical operation of utility assets as a system in which, among other things, the generation and/or flow of current within the system may be centrally controlled and allocated as need or economy directs." Conectiv, supra (citing North American Co., 11 SEC 194, 242 (1942), aff'd, SEC v. North American Co., 133 F.2d 148 (2d Cir. 1943), aff'd on constitutional issues, 327 U.S. 686 (1946)). Through this standard, Congress "intended that the utility properties be so connected and operated that there is coordination among all parts, and that those parts bear an integral operating relationship to one another." Id. (citing Cities Services Co., 14 SEC 28, 55 (1943)). The Commission has considered advances in technology and the particular operating circumstances in applying this integration standard. Unitil, supra (citation omitted). For example, in Unitil, the Commission found that participation in a power pool was sufficient to meet the economic integration standards even though the "definition [of economic integration] reflects an assumption that the holding company would coordinate the operations of the integrated system." Similarly, in approving the acquisition of PSNH by Northeast, the Commission noted that "the operation of the generating and transmission facilities of PSNH and the Northeast operating companies is coordinated and centrally dispatched under the NEPOOL Agreement [a regional power pool agreement]." Northeast I, supra at n. 85. In Conectiv, supra, the Commission noted that in addition to coordinated operation through an ISO, Conectiv would also have a central operating transmission and generation control center for the essentially local functions of the Conectiv system, thereby meeting the standard. The Combined System will operate as a single interconnected and coordinated system through the centralized coordination of generation and transmission. The centralized coordination within the Combined System will be accomplished under the System Integration Agreement and the System Transmission Integration Agreement, both of which will take effect upon consummation of the Merger, as described above in Item 1.B.3. Through Central Dispatch Planning, the coordination of each generation unit in the Combined System will be scheduled on a day ahead basis. Central Economic Dispatch will compute at regular intervals (currently every four seconds) the most economic generation base points as dictated by current operating conditions and will adjust the dispatch of each generating unit in the Combined System. Taken together, the software programs are designed to forecast and economically dispatch all generation resources to meet the load requirements of the Combined System every four seconds, twenty-four hours a day. The Applicants' goal ultimately is to further enhance the coordination of their companies through participation in a regional RTO. The RTOs that are evolving under FERC's direction perform similar planning and reliability functions that regional reliability councils have performed in the past. Participation in RTOs can enhance the Combined Company's system reliability in several ways. In the RTO NOPR, as noted above, the FERC found that an RTO would improve efficiencies in the management of the transmission grid (RTO NOPR mimeo at 90); would improve grid reliability (RTO NOPR mimeo at 95); would improve market performance (RTO NOPR mimeo at 98); and would facilitate lighter governmental regulation (RTO NOPR mimeo at 101). In addition, RTOs are assuming the functions of administering transmission service tariffs and performing real time system security and balancing functions that are related to maintaining reliability and ensuring 69 70 non-discriminatory access to transmission facilities. Thus, AEP's participation in an RTO is expected to enhance its ability to operate the Combined System in an efficient and reliable manner. Until such time as the Combined Company transfers certain control area functions related principally to reliability and access to one or more RTOs, all facets of the centralized coordination of the transmission facilities of the Combined Company's system will be accomplished through the System Transmission Integration Agreement. At such time as AEP transfers to the RTO certain control area operations relating principally to system reliability and access, the remaining functions of the Combined Company's transmission system will continue to be coordinated through the System Integration Transmission Agreement. In addition thereto, the Combined System will be coordinated in a variety of ways beyond simply the coordination of the generation and transmission within the system. AEPSC will be the designated agent under the System Integration Agreement. AEPSC's major functions will be to coordinate the planning and design or purchase of new generation facilities, the operation and maintenance of generating capacity resources, economic dispatch, centralized trading and marketing activities, acquisition and provision of transmission services needed for inter-zone power transfers and billing and administration. In addition, the accounting functions of the Combined System will be prepared and consolidated through the use of a single enterprise-wide financial system. This financial system will include a general ledger module, accounts receivable and cash remittance processing modules, an accounts payable module, a purchasing and materials management module, owned and leased assets modules as well as a single integrated timekeeping and payroll system. These systems will enable the Combined Company to have a single accounting organization which will be managed by a single team in one or more locations. In applying the 1935 Act's integration standard, the Commission looks beyond simply the coordination of the generation and transmission within the system to the coordination of other activities. See, e.g., General Public Utilities Corp., HCAR No. 13116 (Mar. 2, 1956) [hereinafter "GPU"] (integration is accomplished through power dispatching by a central load dispatcher as well as through coordination of maintenance and construction requirements); Middle South Utilities, HCAR No. 11782 (March 20, 1953), petition to reopen denied, HCAR No. 12978 (Sept. 13, 1955), rev'd sub nom. Louisiana Public Service Comm'n v. SEC, 235 F.2d 167 (5th Cir. 1956), rev'd, 353 U.S. 368 (1957), reh'g denied, 354 U.S. 928 (1957) (integration is accomplished through an operating committee which coordinates not only the scheduling of generation and system dispatch, but also makes and keeps records and necessary reports, coordinates construction programs and provides for all other interrelated operations involved in the coordination of generation and transmission); The North American Co., HCAR No. 10320 (Dec. 28, 1950) (economic integration is demonstrated by the exchange of power, the coordination of future power demand, the sharing of extensive experience with regard to engineering and other operating problems, and the furnishing of financial aid to the company being acquired). The coordination and integration of the Combined System is expected to be further achieved through the coordination and integration of information system networks; procurement 70 71 organizations and organizational structures for Power Generation, Nuclear Generation, and Energy Delivery and Customer Relations. Each is discussed below: - Analysis completed to date has concluded that there are approximately 600 information systems software packages which support either AEP or CSW operations. This initial analysis has concluded that these packages can be organized under a single, integrated information system network with the capability of being operated from a single location. The network will be supported by a single data center and will have common software tools and a single centralized IT development organization. The individual integration teams are currently analyzing the various software systems being used by each of the companies in order to identify the single best system to be utilized to support the Combined Company in each area. - AEP and CSW each have created centralized procurement organizations which assist the business units in preparing bid solicitations, procuring materials and supplies and managing the inventory required to support the assets of each business unit. The Combined Company expects to utilize a single organizational structure to accomplish these activities. - AEP and CSW each have created four substantially equivalent business unit management and organizational structures: Power Generation, Nuclear Generation, and Energy Delivery and Customer Relations. Each of these business units has created a combination of central management and engineering groups with regional and field organizations designed to provide the services of the business unit as efficiently as possible. The integration teams are studying how best to integrate these activities. It is anticipated that each of the business unit structures recommended for the Combined Company will be similar to the existing single, integrated organizational structure that is being used in AEP and CSW. - AEP and CSW currently utilize a single service company model to provide support services, including office, finance, treasury, legal, corporate communications and other corporate services. Upon the merger of AEPSC and CSWS, these services would be effectively provided by combined groups handling office, finance, treasury, legal, corporate communications and other corporate services. As dictated by the language under Section 2(a)(29)(A) that the coordinated system be "economically operated," the Commission further analyzes whether the coordinated operation of the system results in economies and efficiencies. See, e.g., City of New Orleans v. SEC, 969 F.2d 1163, 1168 (D.C. Cir. 1992) (Court supported Commission's reading of the term "economically" to mean "that facilities, in addition to their physical interconnection, be consolidated so as to take advantage of efficiencies"); WPL Holdings, Inc., HCAR No. 26856 (Apr. 14, 1998) (discussing this integration standard as it relates to the requirement under Section 10(c)(2) that the acquisition tend towards the economic and efficient development of an integrated system and noting that the applicants introduced substantial evidence concerning the 71 72 efficiencies to be realized by the combined operation of the merging companies' generation and transmission systems). The Applicants expect to realize significant economies and efficiencies as a result of the Merger. As described in Item 3.B.2 below, Applicants estimate the net non-fuel savings from the Merger to be nearly $2 billion and the net fuel-related savings to be approximately $98 million over the first ten years following the Merger. In short, pursuant to the System Integration Agreement, the Combined System will be centrally and efficiently planned and dispatched. Pursuant to the System Transmission Integration Agreement, the operation and management of transmission within the Combined System will be centrally overseen. Thus, as with other merger applications approved by the Commission, the Combined System will be capable of being economically operated as a single interconnected and coordinated system. The Combined System will be "economically operated" as a coordinated system as further demonstrated by the variety of means through which its operations will be coordinated and the efficiencies and economies expected to be realized by the Merger as described below in Item 3.B.2. (iii) Single Area or Region As required by Section 2(a)(29)(A), the Combined System's operations will be confined to a "single area or region in one or more States." While the terms "area" and "region" are not defined in the 1935 Act, it is clear that the "single area or region" requirement does not mandate that a system's operations be confined to a small geographic area. The Section specifically provides that a region can encompass more than one state. As Ganson Purcell, Chairman of the Securities and Exchange Commission, testified before the Subcommittee of the House Committee on Interstate and Foreign Commerce in 1946: I wish to make it clear that the Act does not require that an integrated utility system be broken up, whether or not it crosses State lines, or that a holding company necessary to integrate the properties of several operating companies be abolished. . . .(19) He further stated: [T]he Commission has not imposed any narrow limit on the concept of what is an integrated utility system. Recently, . . . we found that . . . [a] system serving 1700 communities in seven states[] was an integrated electric utility system. . . .(20) No absolute size limitation is specified. The terms "area" or "region," by their nature, are capable of flexible interpretation, which permits the Commission to respond to the current state of the industry and allows the Commission to give the terms practical meaning and effect. The - ------------------------- (19) Study of Operations Pursuant to the Public Utility Holding Company Act of 1935: Part 3: Hearings Before the House Subcomm. on Securities of the House Comm. on Interstate and Foreign Commerce, 79th Cong. 856 (1946) (statement of Ganson Purcell, Chairman of the Securities and Exchange Commission). (20) Id. at 857 (referring to American Gas and Electric system). 72 73 Commission has found that the single area or region test should be applied flexibly when doing so does not undercut the policies of the 1935 Act "against 'scatteration' -- the ownership of widely dispersed utility properties which do not lend themselves to efficient operation and effective state regulation." NIPSCO, supra (applying single area or region requirement with respect to gas utility system); accord, Sempra, supra. The 1935 Act itself provides, and the Commission recognizes, that the question of size must be informed by practical considerations, including its effect, if any, on the "advantages of localized management, efficient operation, and the effectiveness of regulation"(21) in light of "the state of the art and the area or region affected" as discussed in Item 3.B.1.a.(iv) below.(22) In considering size, the Commission has consistently found that utility systems spanning multiple states satisfy the single area or region requirement of the 1935 Act. For example, the Entergy system covers portions of four states (Entergy, supra), the Southern system provides electric service to customers in portions of four states (Southern Co., HCAR No. 24579 (Feb. 12, 1988)), and the principal integrated system of NCE covers portions of five states (with all of its electric operations serving customers in six states) and operates in two reliability councils (New Century Energies supra (citation omitted)). Other registered holding companies also operate in multiple states. For example, the Allegheny Energy, Inc. system provides electricity to customers in parts of five states (Filings under the Public Utility Holding Company Act of 1935, HCAR No. 26846 (March 20, 1998)). As early as 1945, the Commission found that AEP's operations in seven states were confined to a single region or area. American Gas and Electric Co., HCAR No. 6333 (Dec. 26, 1945). In addition, in light of the present state of the industry, other utility systems, although they are not registered utility holding companies, span multiple states.(23) For example, the PacifiCorp system covers portions of seven states (Annual Report of PacifiCorp on Form 10-K for the year ended December 31, 1997), and the UtiliCorp system covers portions of nine states (Form U-1 filed as of July 2, 1998). In addition to not specifying an absolute size for an "area" or "region," the 1935 Act likewise does not provide any specific parameters with respect to the term "single" in the "single area or region" test. In considering distance, the Commission has found that the combining systems need not be contiguous in order for the requirement to be met. See, e.g., Conectiv, supra; cf. New Century Energies, supra (finding that electric utilities located in two different power pools, in two different reliability councils, in both the Eastern and Western Interconnects, and with a physical separation of 300 miles were in same area or region); Electric Energy, Inc., - ------------------------- (21) NIPSCO, supra (in analyzing the single area or region requirement for gas utility properties, the Commission noted that the acquisition would not have "an adverse effect upon localized management, efficient operation or effective operation."); accord, Sempra, supra. (22) In fact, as discussed in note 11 above, Applicants submit that the integrated utility system requirement could be interpreted to involve only a three-part test, with the last two tests read as one. (23) In this regard, Applicants believe that the continued economic viability of large utility holding company systems suggests their efficient operation and, accordingly, these systems should be evaluated on the same basis as comparably large utility systems not regulated as registered utility holding companies under the 1935 Act. 73 74 HCAR No. 13781 (Nov. 28, 1958) (utility assets were within the same area or region as the acquirer's service area despite a distance of 100 miles crossing two states); Mississippi Valley Generating Co., HCAR No. 12794 (Feb. 9, 1955) (single area or region test met where generating station was located 150 air miles from the territory served by the acquiring company). In tandem with not specifying the absolute size of an "area" or "region," the 1935 Act makes no reference to a set of pre-defined regions with specific boundaries. It follows that the concept of region is not constrained by geographical boundaries such as rivers or mountains; nor is it constrained by regional designations which are part of the common vocabulary (e.g., northeast, southwest, or midwest). The Commission's determination of whether the requirement is met is made in light of "the existing state of the art of generation and transmission and the demonstrated economic advantages of the proposed arrangement." Connecticut Yankee Atomic Power Co., HCAR No. 14968 (Nov. 15, 1963); see also, Vermont Yankee Nuclear Power Corp., HCAR No. 15958 (Feb. 6, 1968), rev'd and remanded on other grounds, Municipal Elec. Ass'n v. SEC., 413 F.2d 1052 (D.C. Cir. 1969). The Commission has applied flexibly the requirement based on the facts and circumstances involved and the practicalities of the situation at hand. See, e.g., Yankee Atomic, supra. The Division has recommended that the Commission "interpret the 'single area or region' requirement flexibly, recognizing technological advances, consistent with the purposes and provisions of the Act" and that the Commission place "more emphasis on whether an acquisition will be economical." 1995 Report at 66, 69. The Division has recognized that "recent institutional, legal and technological changes . . . have reduced the relative importance of . . . geographical limitations by permitting greater control, coordination and efficiencies" and "have expanded the means for achieving the interconnection and economic operation and coordination of utilities with non-contiguous service territories." 1995 Report at 69. It has also recognized that the concept of "geographic integration" has been affected by "technological advances on the ability to transmit electric energy economically over longer distances, and other developments in the industry, such as brokers and marketers." Id. Such advances and developments are breaking down traditional boundaries and concepts of regions. The Commission has confirmed its support for the Division's study, citing, in particular, the Division's recommendation that the Commission "continue to interpret the 'single area or region' requirement of [the 1935 Act] to take into account technological advances." NIPSCO, supra; accord, Sempra, supra. Prior to the Merger, the AEP System and the CSW System will be separated by only 150 miles at their closest point, a distance which the Commission has previously found acceptable under the single area or region test. The Combined Company will operate in eleven contiguous states located in the mid-America region of the United States, connected in the middle by the states of Arkansas and Tennessee.(24) - ------------------------- (24) The concept of a geographic region, which includes the states in which AEP and CSW are based (Ohio and Texas), exists within the electric industry. In 1956, state regulators from 14 states, including Ohio and Texas, formed the Mid-America Regulatory Conference. See Mid-America Regulatory Conference, A History, 1956-1995. 74 75 Moreover, that the Combined Company meets the single region test is further supported by adopting a definition of region used by the Commission for purposes of its size analysis under Section 10(b)(1). In Entergy, supra, the Commission adopted the applicants' definition of the relevant region for Section 10(b)(1) purposes to include themselves and those electric utilities directly interconnected with either or both. In today's increasingly competitive world, AEP and CSW do not operate as isolated companies and their geographic region should be analyzed in terms of their most accessible markets -- the Interconnected Utilities. The service territories of these Interconnected Utilities surround the Combined System and effectively close the distance between the former AEP and CSW, bringing them even closer together. The Merger represents a logical extension of the AEP System's existing service territory in light of contemporary circumstances. As the Commission has recognized, the concept of area or region is not a static one and must be refashioned to take into account the present realities of the electric industry, consistent with the purposes of the 1935 Act. These present realities have effectively shrunk the world in which the industry operates and support a finding that the concept of a region can encompass four additional states more than 50 years after the Commission's finding that the current seven-state AEP System operates within an area or region. As the restructuring of the electric industry progresses, traditional boundaries will become more blurred and the contours of regional markets will change. Structural changes in a closely-related industry subject to similar regulatory regimes, the natural gas industry, are influencing the restructuring of the electricity industry and further breaking down traditional boundaries.(25) Natural gas marketers, a new participant in the gas industry, broke up old pipeline customer networks and demanded open access conditions, fueling the industry's restructuring. See "Restructuring Energy Industries: Lessons from Natural Gas," Energy Information Administration, Natural Gas Monthly, May 1997 [hereinafter "Natural Gas Monthly"]. With the restructuring of the gas industry, regional markets have become "interrelated" and the "stages and operations of the natural gas industry have been integrated to an unprecedented degree across North America." Natural Gas 1996 at 97. One of the most recent innovations in the natural gas marketplace is the development of market centers and hubs. Id. at x. At least 39 such centers were operating in the United States and Canada by 1996, providing numerous interconnections and routes to move gas from production areas to markets. Id. These market centers have "made it easier for buyers to access the least expensive source of supply and helped - ------------------------- (25) Restructuring of the natural gas industry started more than 10 years ago, introducing competitive market forces into the industry's operations. See Energy Information Administration, Office of Oil and Gas, Department of Energy, Natural Gas 1996: Issues and Trends (December 1996) at xiii [hereinafter "Natural Gas 1996"]. With the unbundling of pipeline company transportation and sale services and the decontrol of natural gas wellhead prices over the last 20 years, the gas industry has responded by entering into new contractual relationships, developing new services and new tools for managing risk and creating a new participant -- the natural gas marketer. Id. at 1. Regulatory restraints have been increasingly removed from the sale and transport of natural gas, increasing the choices of participants in the natural gas industry, from suppliers to consumers. Id. at ix. Energy markets for natural gas have become increasingly competitive. Id. Regulatory changes seen in the interstate market are being brought to the level of local distribution as state regulators promote consumer choice in retail gas markets. Id. at 1, 113. 75 76 sellers to allocate gas to the highest bidding buyer." Id. at 78. Although it is "probably premature . . . to conclude that a true North American market for natural gas has emerged," market integration is improving and "regional clusters of markets across certain broad areas seem to be highly competitive, even between U.S. and Canadian markets." Id. at xii. Developments in the natural gas industry which are eroding traditional boundaries are being applied to the electricity industry. Many gas marketers are moving into the new electricity markets, and the development of financial instruments used in the gas industry, such as spot, forward, futures, and options contracts, are being imported into the electricity industry. Natural Gas 1996 at xiii. More than 100 energy marketing companies have registered with the FERC to market electric power on a wholesale basis. Natural Gas Monthly. These companies will be marketing retail power to retail power markets as well. Moreover, the developments in electric and gas industries "may imply a close relationship in the future for both industries." Natural Gas 1996 at xiii. Not only are gas marketers entering the electricity markets, but "gas and electric companies are forming mergers and strategic alliances to give customers menus that allow buyers to bridge the differences between the industries." Id. And the development of financial markets "may help to integrate the energy markets." Id. In short, the concept of "area or region" should be interpreted flexibly to keep pace with the current state of the industry.(26) Given the proximity of the AEP System to the CSW System and the present technological ability to economically transmit power over longer distances, and given that the Combined System will be economically operated as a single integrated and coordinated system as described in Item 1.B.3, the Combined Company satisfies the 1935 Act's requirement with respect to operating in a "single area or region." The demonstrated economic advantages of the Merger resulting in nearly $2 billion in net non-production savings and $98 million in net fuel-related savings (as described below) also support the finding that the single area or region test is met, consistent with the Commission's tradition of balancing the various objectives of the 1935 Act. As discussed immediately below, the size of the area or region in which the Combined Company will operate will not result in the evils which the 1935 Act was meant to eliminate; namely, it does not impair the advantages of localized management, efficient operation or effective regulation. - ------------------------- (26) The breakdown of traditional boundaries is also seen in industries beyond the utility industry. Technological advances, regulatory and legal changes facilitating nationwide holding company acquisitions and nationwide branching, and the entrance of nonbank providers of financial services have lead to structural changes in the banking industry resulting in a trend toward consolidation. In 1997, the number of interstate bank-to-bank mergers totaled 189. Bank Mergers: Hearings Before the House Banking and Financial Services Comm., 105th Cong. 18-21 (1998) (statement of John D. Hawke, Jr., Treasury Department Under Secretary for Domestic Finance). Similarly, the procompetitive, deregulatory framework established by Congress in the Telecommunication Act of 1996 has removed the legal and economic barriers to the entry of telecommunications firms into many markets. The Bell Atlantic-NYNEX merger approved under the Telecommunications Act by the FCC resulted in Bell Atlantic serving 13 states. The Effects of Consolidation on the State of Competition in the Telecommunications Industry: Oversight Hearings Before the House Judiciary Comm., 105th Cong. 1-2 (1998) (submitted statement of Susan Ness, Commissioner of the Federal Communication Commission). 76 77 (iv) Localized Management, Efficient Operation and Effective Regulation Section 2(a)(29)(A), like Section 10(b)(1) discussed above, requires the Commission to consider the size of the combined system. Section 2(a)(29)(A) has been interpreted to require that the combined system must not be so large as to impair (considering the state of the art and the area or region affected) the advantages of localized management, efficient operation, and the effectiveness of regulation. As the Commission stated in AEP, supra: [N]either section can be said to impose any precise limits on holding company growth. Both sections are couched in discretionary terms. They require the Commission to exercise its best judgment as to the maximum size of a holding company in a particular area, considering the state of the art and the area or region affected. In exercising its discretion, the Commission must balance the various objectives of the 1935 Act. The Commission stated in Commonwealth & Southern Corp., HCAR No. 7615 (Aug. 1, 1947): We do not, in applying particular size standards, lose sight of the objectives of other criteria. There must be a reconciliation of all objectives to the end of accomplishing a satisfactory administration of the [1935] Act. Thus we do not disregard operating efficiency in our determination of whether size is excessive from the viewpoint of localized management or effectiveness of regulation. As will be discussed below, difficult balancing decisions need not be made because each prong of this standard is easily met. The size of the Combined System does not impair the advantages of localized management, efficient operation or the effectiveness of regulation. The Merger actually increases the efficiency of operations. - Localized Management The Commission has found that an acquisition does not impair the advantages of localized management where the new holding company's "management [would be] drawn from the present management" (Centerior, supra), or where the acquired company's management would remain substantially intact (AEP, supra). The Commission has noted that the distance of corporate headquarters from local management was a "less important factor in determining what is in the public interest" given the "present-day ease of communication and transportation." AEP, supra. The Commission also evaluates localized management in terms of whether a merged system will be "responsive to local needs." AEP, supra. The management of the Combined Company will be drawn primarily from the existing management of AEP and CSW and their subsidiaries. AEP will continue to maintain its system headquarters in Columbus, Ohio and will maintain the management structure of its combined subsidiary companies (including the electric operating and other subsidiary companies of CSW) essentially intact. CSW and AEP have operated with virtual service company management which has located management personnel in a number of operating locations throughout the service territories. In 1996, AEP reorganized into a centralized management structure with localized management remaining essentially in place, with the exception of the electric utility subsidiary headquarters operating management teams being realigned into either the Power Generation, Nuclear 77 78 Generation, and Energy Delivery and Customer Relations business units. CSW completed a similar reorganization process in 1994. For example, at AEP, the subsidiary companies' generation operations were realigned into the Power Generation and Nuclear Generation business units while the transmission and distribution operations were realigned into the Energy Delivery business unit. As part of this realignment, transmission operations were structured with a centralized management and engineering organization which oversees three transmission operating regions. The distribution operations were structured with a centralized management and engineering structure which oversees 30 distribution districts which report to one of eight distribution regions. Customer services functions were also realigned under the Energy Delivery and Customer Relations business unit into a regional structure with four customer call centers, a single customer information system and centralized management of the customer service operations. As part of these individual reorganization efforts, the electric utility subsidiaries of AEP began doing business under the AEP brand without altering their separate legal identities, assets and liabilities, franchises and certificates of public convenience and necessity. Likewise, the electric utility subsidiaries of CSW retained their separate corporate identities, assets and liabilities, franchises and certificates of public convenience and necessity. Although the Applicants have just recently launched transition teams that are studying how the various components of the two organizations will be combined, the Applicants expect that the impact of the Merger will be predominantly confined to the merging of CSWS into AEPSC and the establishment of a business unit and management structure which looks very much like the existing structures of AEP and CSW. The electric utility subsidiaries will continue to operate through the regional offices with local service personnel and line crews available to respond to customers needs. The Combined Company will preserve the well established delegations of authority -- currently in place at AEP and CSW -- which permit the local, district and regional management teams to budget for, operate and maintain the electric distribution system, to procure materials and supplies and to schedule work forces in order to continue to provide the high quality of service which the customers of AEP and CSW have enjoyed in the past. The orders of the Oklahoma Commission, the Arkansas Commission, the Indiana Commission and the Kentucky Commission approving the Merger impose an extensive list of service quality standards on the utility operating companies operating within their states. In Oklahoma, the Oklahoma Commission established standards with respect to (i) customer service center calls, (ii) responses to requests for service, (iii) billing adjustments, (iv) customer satisfaction, and (v) reliability performance. The Louisiana Commission, in a service quality inquiry proceeding, has recently established customer service, staffing, and tree standards for SWEPCO. In Arkansas, Louisiana, Indiana, and Kentucky, the state commissions required that the Combined Company maintain or improve historical reliability performance levels. Moreover, the Texas Commission and the Louisiana Commission have recently been active in promoting utilities' responsiveness to customers and are expected to closely monitor the Combined 78 79 Company's performance in this regard. See, e.g., Public Utility Commission of Texas Substantive Rule 25.21 et seq.; Louisiana Public Service Commission General Order of April 30, 1998. Likewise, the settlement with the staff of the Texas Commission contains service quality standards and provisions to ensure the continuity of CSW's local management and organizational structure following the Merger. For example, in Texas Applicants have agreed to (i) freeze CSW operating company field positions and customer service jobs until October of 2000, (ii) maintain a bargaining and decision-making presence in the CSW region with authority to enter binding agreements with wholesale customers up to at least $3 million, (iii) designate an employee who will act as a contact to the Texas Commission and consumer advocates seeking information regarding affiliate transactions and personnel transfers, and (iv) designate an employee or agent in Texas who will act as a contact for retail consumers regarding service and reliability concerns. In short, the customer service and field operations management structures of AEP and CSW, which are responsive to local needs, will be left essentially intact after the Merger. Accordingly, the advantages of localized management will not be impaired. - Efficient Operation As discussed above in the analysis of Section 10(b)(1), the size of the Combined Company will not impede efficient operation; rather, the Merger will result in significant economies and efficiencies as described in Item 3.B.2 below. Economic dispatch (as described in Item 1.B.3) is more efficiently performed on a centralized basis because of economies of scale, standardized operating and maintenance practices and closer coordination of system-wide matters. Both AEP and CSW have efficient generating facilities that were recently noted by Public Utilities Fortnightly as being the fourth and sixth most efficient in the utility industry (September 1, 1998 report). In addition, AEP and CSW have consistently been rated in the top five utilities in the American Society for Quality and The University of Michigan Business Schools American Customer Satisfaction Index (ACSI). In the 1997 ACSI survey results which were published in the February 16, 1998 issue of Fortune Magazine, CSW tied for second place and AEP tied for third place, out of more than 20 utilities surveyed. Because the Merger is expected to have little impact on field personnel in either power generation or transmission and distribution, AEP and CSW expect that the Combined Company will to continue to perform at these high efficiency levels. The divestiture of the Texas and Oklahoma generating assets will not adversely affect the Combined Company's ability to operate on an efficient basis. The Combined Company will coordinate the economic dispatch of generating units under its control, make economic purchases of power, and supply power to its customers. The fact that certain 79 80 generating capacity will no longer be controlled by the Combined Company will not change the centrally coordinated, least-cost approach to operating the combined system.(27) - Effective Regulation The Merger will not impair the effectiveness of regulation at either the federal or state level. On the federal level, the Combined Company will continue to be regulated by the Commission. The electric utility subsidiaries of the Combined Company will continue to be regulated by the FERC with respect to interstate electric sales for resale and transmission services, by the NRC with respect to the operation of nuclear facilities, and by the FCC with respect to certain communications licenses. The jurisdiction of other federal regulators is also not affected. FERC declined to set the issue of effectiveness of regulation for hearing. Indeed, the FERC concluded that Applicants had adequately addressed the FERC's concerns about its own jurisdiction and that state commissions could "impose in their own proceedings appropriate conditions to ensure that there is no impairment of effective regulation at the state level." 85 FERC at 61,821-822. Thus, FERC has already concluded that the Merger will not impair the effectiveness of regulation and that the issue does not merit further investigation. On the state level, the Commission has found that the effectiveness of regulation is not impaired where the same state regulators have jurisdiction both before and after a merger. See, e.g., Conectiv, supra; GPU, supra. In finding that regulation is not impaired, the Commission has also emphasized that the various state regulators have approved the combination. Entergy, supra. The electric utility subsidiaries of CSW will continue to be regulated by the state commissions of Arkansas, Louisiana, Oklahoma and Texas with respect to retail rates, service and related matters. The electric utility subsidiaries of AEP will continue to be regulated by the state commissions of Indiana, Kentucky, Michigan, Ohio, Tennessee, Virginia, and West Virginia with respect to retail rates, service and related matters.(28) - ------------------------- (27) In fact, under the Texas Settlement, most of the generating capacity being divested will be subject to recall by the Combined Company during peak months to ensure that adequate capacity is available to serve native load. See Texas Settlement Sec. 6.D-F. (28) The AEP and CSW management structures are designed to facilitate communications and relationships with state regulators. Each company has established State offices which have responsibility for regulatory, environmental, and corporate communications and have other external relations purposes. These state offices provide a single point of contact with each of the state regulatory and environmental offices and have the responsibility for handling all regulatory contacts, including making regulatory filings and answering customer inquiries to the regulatory commissions. It is expected that these offices will be left essentially intact after the Merger. 80 81 The FERC's conclusion that the states will take appropriate action to protect their jurisdiction was correct.(29) The best evidence of this is that none of the state commissions which regulate the AEP and CSW utility subsidiaries has raised as an objection impairment of its ability to regulate the Combined Company after the Merger, or any other objection, in submissions to the Commission. In fact, the recent settlement in the Texas proceeding contains several provisions designed to ensure the effectiveness of the Texas Commission's regulatory authority over the Combined Company's operations in Texas. Among other things, these provisions include (i) a requirement that the Combined Company continue to comply with the Texas Commission's transmission pricing rules in ERCOT, (ii) a commitment by the Combined Company not to withdraw from either ERCOT or the SPP without the Texas Commission's prior approval, and (iii) a commitment that the Combined Company will not contend in any forum that the jurisdiction of the Texas Commission over any of CSW's operating companies located in Texas changed as a result of the Merger. Thus, rather than impairing the Texas Commission's regulatory authority, the settlement is specifically designed to safeguard that authority. Moreover, the Merger Agreement requires approvals from all regulatory authorities having jurisdiction over the Merger as a condition to the consummation of the Merger. The Merger has been approved by the state commissions in Oklahoma, Arkansas, Louisiana, Indiana and Kentucky. Applicants are working closely with other regulators (both state and federal) to obtain the remaining approvals (as described below in Item 4). b. Section 11(b)(1) (Acquisition of Non-Utility Interests) Section 11(b)(1) of the 1935 Act also requires that a registered holding company limit its operations to a single integrated public utility system and "such other businesses as are reasonably incidental, or economically necessary or appropriate to the operations of such integrated public-utility system." Each of CSW's non-utility business interests conforms to the "other business" standards of the 1935 Act as previously determined by the Commission. The indirect acquisition by AEP of CSW's non-utility businesses in no way affects the functional relationship of these businesses to the Combined Company's core electric business following the Merger. See Item 3.F below for a detailed discussion on the acquisition by AEP of CSW's non-utility businesses. c. Section 11(b)(2) Section 11(b)(2) of the 1935 Act directs the Commission "to ensure that the corporate structure or continued existence of any company in the holding-company system does not unduly - -------- (29) The Oklahoma, Kentucky, Arkansas, and Indiana Commissions conditioned the approval of the Merger on Applicants' agreement not to assert in proceedings before that state commission, or in court proceedings involving orders of that state commission, that the authority of the Commission as interpreted in Ohio Power v. F.E.R.C., 554 F.2d 779 (D.C. Cir. 1992) cert. denied, 498 U.S. 73 (1992) impairs that state commission's ability to examine the reasonableness of non-power affiliate costs to be passed through to that state's retail consumers. The Texas settlement contains a similar provision. 81 82 or unnecessarily complicate the structure, or unfairly or inequitably distribute voting power among security holders, of such holding-company system." The Merger is consistent with Section 11(b)(2). The resulting capital structure is not unduly complicated as discussed in Item 3.A.3 above. See, e.g., Sierra Pacific Resources, HCAR No. 24566 (Jan. 28, 1988), aff'd Environmental Action, Inc., 895 F.2d 1255 (D.C. Cir. 1990) (Commission incorporates its Section 10(b)(3) capital structure analysis into its Section 11(b)(2) corporate structure analysis). Voting power is equitably and fairly distributed among the security holders of each of AEP and CSW and their current subsidiaries, all of which have been approved by the Commission in previous proceedings. The shareholders of AEP and CSW, respectively, have overwhelmingly approved the shareholder actions necessary to effect the Merger or the Merger itself. Immediately following the Merger, AEP will be a registered holding company with respect to CSW, which, in turn, will be a registered holding company with respect to the electric utility subsidiaries and other subsidiaries it currently owns (with the exception of CSWS, which will be merged into AEPSC, and CSW Credit, which will be directly held by the Combined Company). See Exhibit E-6. Although it is intended that these interests will be restructured, the final ownership structure has not yet been determined. Accordingly, Applicants request that CSW survive as a holding company interposed between AEP and the electric utility subsidiaries and a portion of the other subsidiaries it currently owns for a period of up to eight years following the closing of the Merger. Applicants have determined that the proposed transitional corporate structure of the Combined Company following the Merger will be in the best interests of the Combined Company's shareholders and ratepayers. The continued existence of CSW as an intermediate holding company will result in AEP having a tax basis in CSW equal to the aggregate tax basis of the CSW shareholders in CSW prior to the Merger. This tax basis would be lost if CSW were not retained as an intermediate holding company. See Exhibit J for an explanation of certain relevant tax basis issues. Retaining the appropriate tax basis in CSW will allow AEP to realize significant tax savings in the event that AEP were to divest CSW assets in a future taxable transaction (although AEP does not at present have any plan to divest CSW assets). Because the costs and complications associated with the survival of CSW as an intermediate holding company are minimal, AEP and CSW management have determined that the transitional structure will contribute to the positive future financial condition of the Combined Company and will maximize shareholder value. Although CSW will have an important economic purpose following the Merger, CSW will have minimal operational functions. As an intermediate holding company, CSW largely will be a conduit between AEP and its subsidiaries with respect to capital contributions, if any, and dividends. The future management of the Combined Company does not anticipate that CSW will be involved in any intra-system financing other than maintaining its current guarantees on the debts of its subsidiaries and participating in the Money Pool (as previously authorized by the Commission) during the transitional period after the Merger to the extent necessary. Moreover, the future management of the Combined Company does not anticipate that CSW will engage in securities transactions (except as noted in the previous sentence); acquire securities, utility assets or other interests; or enter into or take any step in the performance of any service, sales, or construction contract. CSW will continue to make, keep and preserve accounts and records and make any required reports to the Commission and other appropriate agencies. 82 83 Under Section 10(c)(1) of the 1935 Act, the Commission must ensure that a proposed acquisition subject to the Act will not be 'detrimental to the carrying out of the provisions of Section 11.' Section 11(b)(2) mandates a simple corporate structure for a registered holding company system. See, e.g., TUC Holding Co., HCAR No. 26749, n. 20 (Aug. 1, 1997). Section 11(b)(2) includes two principal restrictions. First, the Section requires registered holding companies to take such action as the Commission finds necessary to ensure that registered holding company systems ultimately are restructured to include no more than two tiers of holding companies. Second, the Section directs the Commission to evaluate the facts and circumstances 'to ensure that the corporate structure or continued existence of any company in the holding-company system does not unduly or unnecessarily complicate the structure . . . of such holding-company system.' As discussed below, the transitional corporate structure of the Combined Company, in which AEP and CSW will survive as first and second tier holding companies, respectively, in the Combined Company's holding company system, will be consistent with the requirements of Section 11(b)(2).(30) Corporate structures including two tiers of holding companies are specifically envisioned under the 1935 Act and its Rules, and, in this case, the existence of two registered holding companies in one system will not result in unnecessary or undue complications. To the contrary, the minimal complications that may be introduced by the continued existence of CSW are necessary and appropriate in serving the interests of the Combined Company, its shareholders and ratepayers. (i) The Existence of Two Tiers of Registered Holding Companies in a Single Integrated Public-Utility System Is Not Prohibited under the 1935 Act The 1935 Act was passed, in large part, to curb abuses identified by Congress arising out of 'the utilization of highly-pyramided and complex holding company systems as a means of controlling and exploiting utility operating companies, as well as companies in non-utility fields . . . .' Vermont Yankee Nuclear Power Corp., HCAR No. 15958 (Feb. 6, 1968), rev'd and remanded on other grounds, Municipal Elec. Ass'n v. SEC, 413 F.2d 1052 (D.C. Cir. 1969) [hereinafter 'Vermont Yankee']. Holding companies 'piled on top of holding companies result[ed] in highly leveraged corporate structures of extraordinary complexity.' AEP. In addressing these perceived abuses, however, Congress did not prohibit holding companies entirely. Rather, it required the Commission to take such action as necessary to ensure that each registered holding company system be restructured to include no more than two - --------------- (30) Applicants note that SWEPCO, a wholly owned electric public-utility operating subsidiary of CSW, is technically a registered holding company under the 1935 Act by virtue of its 47.6% ownership interest in a company (which technically is an 'electric utility company' under the 1935 Act) whose assets at the end of 1997 accounted for approximately .02% of SWEPCO's total assets (based on SWEPCO's and its subsidiary's total assets at year-end December 31, 1997, and November 30, 1997, respectively). Applicants acknowledge that questions could be raised under Section 11(b)(2) if SWEPCO were to remain a holding company within the Combined Company following the Merger. Accordingly, Applicants hereby commit to take appropriate action to eliminate SWEPCO's holding company status following the Merger. 83 84 tiers of holding companies through the 'great-grandfather clause' of Section 11(b)(2).(31) The legislative history of the 1935 Act confirms that Congress's express authorization of two tiers of holding companies in a registered holding company system was consistent with its intent in passing the 1935 Act. While the version of the 1935 Act originally passed by the Senate contained a provision, Section 11(b)(3), that required that within five years all holding companies should cease to be holding companies unless the equivalent of a certificate of convenience and necessity were obtained from the Federal Power Commission, see American Power & Light Co. v. SEC, 329 U.S. 90, 146, 147 (1946) (citing to S. 2796, 74th Cong., 1st Sess.), the bill that became law replaced this section with the 'great-grandfather clause' of Section 11(b)(2). See 79 Cong. Rec. 14620 (August 24, 1935). The 1935 Act is silent regarding whether a registered holding company system with two tiers of holding companies is limited to one registered holding company. However, the Commission's Rules promulgated under the 1935 Act expressly envision a holding company system with more than one registered holding company. Rule 1(c) provides that 'where any holding company system includes more than one registered holding company, the annual report shall be filed by the top registered holding company in such system.' Similarly, the instructions to Form U5S (relating to holding company annual reports) track the requirements of Rule 1(c), defining 'holding company system' to mean 'the parent registered holding company together with all its subsidiary companies, including all subsidiary registered holding companies.'(32) See also, Rule 87(c) (providing that, in the context of service, sales, and construction contracts, it is Rule 85, as opposed to Rule 87, that is applicable to a 'subsidiary which is itself a registered holding company'). In summary, the transitional corporate structure of the Combined Company, which includes AEP as the top registered holding company and CSW as a subsidiary registered holding company, satisfies the first requirement of Section 11(b)(2). - ---------------- (31) The 'great-grandfather clause' of Section 11(b)(2) provides that 'the Commission shall require each registered holding company (and any company in the same holding-company system with such holding company) to take such action as the Commission shall find necessary in order that such holding company shall cease to be a holding company with respect to each of its subsidiary companies which itself has a subsidiary company which is a holding company.' See also, Entergy, supra, ('Section 11(b)(2) allows three tiers of companies in a registered holding company system.'). (32) Rule 1, adopted in 1941, was amended in 1951 to include the current formulation of subsection (c). HCAR No. 10432 (Mar. 12, 1951). Prior to 1951, each registered holding company in a holding company system was required to file its own separate annual report on Form U5S. Id. The current formulation of Rule 1(c) was adopted one year before the Commission 'largely completed' its task of 'simplifying and reorganizing the complex financial and corporate structures of holding company systems as required by section 11.' See 1995 Report at viii. Since 1951, the Commission has amended Rule 1 twice, without altering the language of Rule 1(c). See HCAR No. 17435 (Jan. 25, 1972) (imposing a filing fee for Form U5S); HCAR No. 26575 (Sept. 17, 1996) (removing the filing fee). As late as 1984, the Commission, in adopting amendments to Form U5S, specifically recognized the existence of Rule 1(c) and its requirement that the 'annual report be signed by each registered holding company in the system.' HCAR No. 23214 (Feb. 2, 1984) (emphasis added) (amending Form U5S to clarify that an exempt subsidiary holding company, as opposed to a registered subsidiary holding company, need not sign the annual report.). 84 85 (ii) The Existence of CSW Will Not Unduly or Unnecessarily Complicate the Structure of the Holding Company System The second prong of Section 11(b)(2) requires that the Commission ensure that 'the corporate structure or continued existence of any company in the holding-company system does not unduly or unnecessarily complicate the structure . . . of such holding-company system.' The existence of a subsidiary holding company does not run afoul of Section 11(b)(2) merely because it causes the structure of the holding company system to be more complicated. Rather, the existence of a company violates Section 11(b)(2) only if it causes unnecessary or undue complications. The Commission has interpreted Section 11(b)(2) to require the elimination of any holding company that serves no useful purpose or economic function. See, e.g., WPL Holdings, Inc., HCAR No. 25377 (Sept. 18, 1991); Peoples Gas Light and Coke Co., HCAR No. 15929 (Dec. 22, 1967); Voting Trustees of Granite City Generating Co., HCAR No. 14739 (Nov. 5, 1962). In prior proceedings, the Commission has determined that the existence of a second tier holding company satisfies the Section 11(b)(2) test. See, e.g., Entergy, supra (the Commission found that the addition of an exempt sub-holding company to a registered holding company system did not create an undue or unnecessary corporate complexity); Cinergy Corp, HCAR No. 26146 (Oct. 21, 1994) (the Commission approved a merger where a registered holding company would be the parent of an exempt holding company). Moreover, the Commission has in other circumstances allowed a holding company system with two tiers of registered holding companies. See Annual Report on U5S of Central and South West Corporation and Southwestern Electric Power Company for year ended December 31, 1997 (Central and South West Corporation and its wholly owned subsidiary, Southwestern Electric Power Company, are both registered holding companies); Citizens Utilities Company, HCAR No. 25331 (June 14, 1991) (Louisiana General Services, Inc. and its wholly owned subsidiary, LGS Pipeline, Inc., were both exempt, registered holding companies prior to a merger). In this case, the temporary survival of CSW as a holding company will result in minimal complications. CSW will not perform any significant operational functions. Although it will continue to guarantee the indebtedness of its subsidiaries and make borrowings to fund the Money Pool and for other subsidiaries as previously authorized by the Commission to the extent necessary during the transitional period following the Merger, it will largely function as a conduit between the Combined Company and the CSW subsidiaries. The Applicants anticipate that CSW will not engage in securities transactions (except as noted in the previous sentence); acquire securities, utility assets or other interests; or enter into or take any step in the performance of any service, sales, or construction contract. One of the complications that might have arisen, the need to file two annual reports, has been eliminated by Rule 1(c). These minimal complications are neither 'unnecessary' nor 'undue.' To the contrary, any minor complications, and any negligible expenses resulting therefrom, are necessary to assure appropriate tax and accounting treatment and to preserve the potential for significant tax savings. The survival of CSW will benefit the Combined Company's shareholders and its ratepayers. The 85 86 transitional structure certainly will not result in a 'highly-pyramided and complex holding company system' at odds with the purposes of the 1935 Act.(33) Vermont Yankee, supra. In sum, the 1935 Act itself and the Rules thereunder, the policies behind the Act, and the basic Commission interpretations of Section 11(b)(2), all point to an obvious conclusion: the transitional survival of CSW is consistent with the standards of Section 11(b)(2). Nevertheless, additional discussion of the role of tax considerations under the Commission's interpretation of the 1935 Act is helpful in light of several cases decided by the Commission in the early-1950s and before. Not only are these cases distinguishable from the case at hand, but other cases serve to support the conclusion that the Applicants meet the standards of Section 11(b)(2). (iii) CSW Will Perform a Useful Economic Purpose by Preserving Appropriate Tax Treatment Resulting from the Merger, and its Survival for Such Purpose Does Not Delay or Disrupt the Commission's Administration of the 1935 Act The structuring of business activities for tax planning purposes is not inimical to public policy considerations and is a legitimate goal under the 1935 Act. As the Commission has held, the realization of tax savings through a transaction often helps to satisfy the requirements of the 1935 Act. See, e.g., Columbia Gas System, HCAR No. 26536 (June 25, 1996) (Commission noted that the applicants expected the merger to produce economies and efficiencies, including the realization of state tax benefits); TransTok, HCAR No. 26421 (Nov. 30, 1995) (Commission noted that the benefits and efficiencies of the merger included annual tax savings); New England Power Association, 1 SEC 473 (May 16, 1936) (Commission noted that the acquisition should result in tax and other economies). The Commission has authorized the acquisition of subsidiaries organized, among other things, 'as a part of tax planning in order to limit [a registered holding company's] exposure to U.S. and foreign taxes.' Cinergy, HCAR No. 26376 (Sept. 21, 1995); see also, Allegheny Power System, HCAR No. 26401 (Oct. 27, 1995). The Commission has found that an entity can serve a useful purpose or function through its ability to provide shareholders with tax advantages. See Standard Power and Light Corporation, HCAR No. 13101 (Feb. 16, 1956), enforced, United States District Court for - -------------- (33) The Commission has in recent years recognized that registered holding companies may organize subsidiaries, including intermediate subsidiaries, for various business and legal purposes. See, e.g., Exemption of Acquisition by Registered Public-Utility Holding Companies, HCAR No. 26667 (Feb. 14, 1997) (modifying proposed Rule 58 to allow a registered holding company system to use an intermediate subsidiary to invest in energy-related companies, noting that use of such an intermediate subsidiary "could further insulate the holding company and its other subsidiaries . . . from any direct losses that could occur with respect to Rule 58 investments"); 1995 Report at 94 (noting that in the 1980s and 1990s, registered holding companies expanded their use of separate subsidiaries to engage in other activities, including the formation of EWGs and FUCOs); Cinergy, HCAR No. 26376 (Sept. 21, 1995) (authorizing the acquisition of subsidiaries organized, in part, for tax planning purposes). Similarly, Applicants' proposal to retain CSW as an intermediate holding company is for a legitimate business purpose, to preserve appropriate tax treatment of certain corporate transactions that may occur in the future. 86 87 District of Delaware (Order, Mar. 13, 1956) (the Commission modified its order directing a registered holding company to liquidate and dissolve, where the holding company could transform itself into an investment company and serve a useful purpose by providing shareholders with tax advantages). Moreover, the Commission has implied that a useful purpose for a holding company is to facilitate tax advantages by citing the lack of tax advantages as a factor in its determination that a holding company should be dissolved. United Light & Power Company, HCAR No. 6603 (Apr. 30, 1946) (the Commission found that 'there [wa]s no need for the continued existence' of a registered holding company, in part, because the holding company's existence no longer offered tax advantages due to changes in the tax laws). The Commission has 'recognized the importance of tax considerations' under Section 11 and has 'sought to cooperate in achieving that type of rearrangement [under Section 11] which imposes the least tax burden on the company and the security holders, so long as the choice does not result in frustrating the Act or in delaying the attainment of its objectives.' Engineers Public Service Co., HCAR No. 7041 (Dec. 19, 1946); cf. Standard Power & Light, HCAR No. 12208 (Nov. 9, 1953) (Commission allowed holding company, subject to a liquidation and divestment order, to divest itself of only a portion of the interests in its subsidiary to preserve tax advantages because such a plan did not, under the circumstances, delay or interfere with compliance with the 1935 Act). The existence of tax savings is a compelling reason to maintain a given structure under Section 11(b)(2), provided that 'the continued existence of this [security] structure will not be detrimental to the public interest or the interest of investors or consumers.' Community Gas and Power Company, HCAR No. 4915 (Mar. 4, 1944). The continued existence of CSW will serve a useful function in the holding company system by facilitating appropriate tax treatment and by preserving potentially significant tax savings. These savings are a compelling reason for the transitional survival of the CSW holding company, and the existence of CSW will not be detrimental to the public interest, the interest of investors or consumers, or the Commission's administration of the 1935 Act. Finally, it should be noted that in a few proceedings in the 1940's to early-1950's, the Commission determined that potential tax benefits (to only or potentially only a portion of the shareholders and, in one case, where the benefits could be achieved by other means), taken alone, were not sufficient to justify relief from dissolution findings and orders or commitments that had been made in the early stages of implementation of the 1935 Act. See Engineers Public Service Company, HCAR No. 7041 (Dec. 19, 1946); Electric Bond and Share Company, HCAR No. 11004 (Feb. 6, 1952); International Hydro-Electric System, HCAR No. 9535 (Dec. 6, 1949), aff'd sub nom., Protective Committee For Class A Stockholders v. SEC, 184 F.2d 646 (2nd Cir. 1950).(34) These decisions are not apposite here, however, where the Commission has - ------------- (34) In Portland Electric Power Company, HCAR No. 6365 (Jan. 14, 1946), supplemented on other grounds, 24 SEC 423 (1946), approved by, United States District Court for District of Oregon (Order, June 29, 1946), aff'd, 162 F.2d 618 (9th Cir. 1947), the Commission, reviewing proposed plans of reorganization under Section 11(f), found that the continued existence of a shell holding company solely for the purpose of seeking tax advantages not then available under applicable law was inimical to the standards of Section 11(b)(2). Here, by contrast, the economic and tax benefits sought by the retention of CSW as a sub-holding company will accrue under the presently existing tax laws. 87 88 not identified any unnecessary or undue complication that would result from the post-Merger transition structure the potential tax savings would inure to the Combined Company itself for the benefit of all shareholders alike. The temporary survival of CSW as a registered holding company to further the interests of the Combined Company, its shareholders and ratepayers, will meet all of the standards of the 1935 Act. The transitional corporate structure will not create unnecessary or undue complications under Section 11(b)(2), and the significant, potential tax savings outweigh any negligible complications and costs associated with CSW's survival. 2. Section 10(c)(2) Section 10(c)(2) requires that the Commission approve a proposed transaction if it will serve the public interest by tending towards the economical and efficient development of an integrated public utility system. For the reasons discussed above, the Combined System will be integrated. The Merger will also tend towards the economic and efficient development of the Combined System. This Section 10(c)(2) standard is met where the likely benefits of the acquisition exceed its likely costs. City of Holyoke, supra. Economic efficiency is the driving force behind the Merger; its purpose is to create an entity well situated to compete effectively in an increasingly active market. Applicants project $1,966 million of net non-fuel cost savings over the ten-year period immediately following consummation of the Merger. These savings will be passed on to shareholders and customers of the Combined Company. Based upon the resolution of issues related to the allocation of Merger-related savings between customers and shareholders of the Combined Company in the states which have approved the Merger, Applicants have guaranteed that approximately 55% of the projected savings from the Merger will be passed through to the respective customers of each of the Combined Company's utility operating companies, regardless of whether these actual merger-related savings are achieved. Applicants also anticipate net fuel-related savings of approximately $98 million over this same period that will be passed on to customers. Thus, the Merger will allow the Combined Company to realize the "opportunities for economies of scale, the elimination of duplicate facilities and activities, the sharing of production capacity and reserves and generally more efficient operations" described by the Commission in AEP, supra. The nonproduction cost savings resulting from the Merger are set forth in the testimony of Thomas J. Flaherty before the Texas Commission, a copy of which is included in Exhibit D-5.1 and incorporated by reference. As explained by Mr. Flaherty, the Combined Company is expected to achieve the following nonproduction costs savings:
Savings Category Millions Elimination of Duplicate Corporate and Operations Support Staffing $ 996 Elimination of Duplicate Corporate and Administrative Programs 1,044 Purchasing Economies (Not Fuel-related) 367 Total Savings 2,407 Less: Costs to Achieve (a) (248) Premerger Initiatives (193)
88 89 Net Savings $1,966
(a) Does not include contingent change in control payments. Assuming a March 31, 1999 closing, AEP and CSW estimate available synergies and cost savings resulting from the Merger, net of costs necessary to achieve these reductions, for each of the first ten years following the Merger of approximately $17 million (9 months), $102 million, $135 million, $162 million, $181 million, $243 million, $255 million, $259 million, $267 million, $275 million and $70 million (3 months), respectively, for a total of $1,966 million. The savings in the first five years are expected to be lower than in the later years due to the costs incurred to achieve the savings. Of the $1,966 million in total anticipated net savings, Applicants estimate that approximately $713 million of the total savings will be allocated to the pre-Merger CSW and approximately $1,253 million will be allocated to pre-Merger AEP. Moreover, even though the savings are shown over 10 years only, it is expected that some of these savings will continue to be realized over a much longer period. See Testimony of Thomas J. Flaherty included in Exhibit D-5.1. The Applicants' estimates of Merger savings have been provided to the staffs of all eleven state commissions which will have retail rate jurisdiction over the Combined Company (Arkansas, Indiana, Kentucky, Ohio, West Virginia, Michigan, Tennessee, Virginia, Louisiana, Oklahoma and Texas). In each of those states, the Applicants have responded to discovery requests from participants, and have defended the proposed level of savings as being achievable. In each of those states, the Applicants have either received state commission orders or entered into stipulations with the commission's staff (and other parties) which establish the level of savings that will be shared with ratepayers and which guarantee to consumers the savings regardless of whether they are achieved. The amount of the savings as well as Applicants' plans for allocating the savings have been approved by the state commissions of Arkansas, Louisiana, Indiana, Kentucky, and Oklahoma. Based upon the resolution of issues related to the allocation of Merger related savings between customers and shareholders of the Combined Company in the states which have approved the Merger, Applicants have guaranteed that approximately 55% of the projected savings from the Merger will be passed through to the respective customers of each of the Combined Company's utility operating companies. For example, the settlement with the staff of the Texas Commission includes rate reductions totaling $221 million over six years for CSW's three utility subsidiaries operating in the state. Similarly, the Oklahoma Commission issued an order approving the Merger as being in the "public interest," freezing base rates through 2003 and requiring 55% of Oklahoma's share of Merger-related savings to be recovered by ratepayers in Oklahoma. In addition, Applicants have agreed to make a $5,000,000 reduction to the revenue requirement otherwise determined by the Oklahoma Commission to be reasonable in the event they seek a rate review any time after January 1, 2003 through the end of the fifth year after the effective date of the Merger. The Arkansas Commission issued an order approving the Merger as being in the "public interest" and providing a total rate cut of $6 million over the five-year period following the Merger. 89 90 In Louisiana, Applicants agreed to a base rate freeze for 5 years and a nonfuel savings sharing mechanism ("SSM") for eight years, which is a formula-based methodology to be used to quantify merger savings. During the first 14 months following the consummation of the Merger, the Combined Company will retain 100% of the Merger savings and may use savings to reduce deferrals of the Merger costs. Beginning in the 15th month, 50% of the Merger savings as computed pursuant to the SSM will be passed through to consumers in Louisiana. The SSM will be updated annually and continue for the remainder of the eight-year period following the Merger's consummation. Applicants have estimated that the customer rate credits in Louisiana will total more than $18 million over the eight-year period. Likewise, Merger-related savings plans have been approved by the state commissions of Indiana and Kentucky. The order of the Indiana Commission provides for a credit to ratepayers of approximately 55% of the $121.2 million, or $66.6 million, of Merger savings expected to be achieved over the first eight years following the Merger. The order of the Indiana Commission further provides for an extension of an existing rate freeze to January 1, 2005. The order of the Kentucky Commission establishes merger savings of approximately $51.6 million over the first eight years following the Merger, with consumers receiving the benefit of approximately $28.4 million, or 55% of the total savings. Moreover, the order of the Kentucky Commission provides that Kentucky Power, AEP's utility subsidiary, will not request an increase in its existing base rates until the later of January 1, 2003, or three years from the effective date of the Merger. Although specific determinations of the net savings to each group in the remaining states cannot be finalized until all regulatory proceedings have been completed, it is expected that each group will realize approximately 55% of the net savings. In the states that have approved the Merger, Applicants have agreed to mechanisms for sharing the savings which utilize the Applicants' estimate and provide guaranteed net rate reduction riders for periods ranging from five to eight years. In other words, if the Applicants do not achieve the estimated level of savings, the consumers will nonetheless obtain the benefits of the estimated Merger savings. This provides the requisite incentive for Applicants to achieve the estimated Merger savings. The staffs of the Texas and Oklahoma Commissions support Applicants' divestiture of generation assets given the mitigation measures that Applicants have proposed to protect ratepayers. As part of the settlement in Texas, the Texas commission staff, the Office of Public Utility Counsel, and the other settling parties agreed to several significant provisions designed to protect consumers from the economic effects of the divestiture, including (i) a requirement that proceeds from the divestiture be used to reduce stranded costs of the Combined Company, (ii) a provision that limits any adverse impact on consumers related to the divestiture of the units, and, most significantly, and (iii) a provision that guarantees rate reductions totaling $221 million to the Combined Company's ratepayers in Texas over the six years following the Merger. In Oklahoma, as part of the stipulation approved by the Oklahoma Commission, the Applicants committed to hold Oklahoma retail consumers harmless from adverse effects related to CSW's divestiture of 300 MW of generation capacity in Oklahoma. Applicants agreed to make an "after the fact" calculation of margins both before and after the divestiture. If negative margins result, Oklahoma consumers will be held harmless from the additional costs associated with the divestiture. 90 91 Applicants estimate that the Combined Company will also realize approximately $98 million in net fuel-related savings over the same 10 year period. J. Craig Baker's testimony before the FERC (a copy of which is included in Exhibit D-1.1 and is incorporated by reference) explains that these savings will result from the central coordinated dispatch of energy by the Combined Company. These savings will be realized by customers. These expected savings exceed the anticipated savings in a number of other acquisitions approved by the Commission. See, e.g., New Century Energies, supra (expected savings of $770 million over 10 years); Entergy, supra (expected savings of $1.67 billion over ten years); Northeast I, supra (estimated savings of $837 million over 11 years); IE Industries, HCAR No. 25325 (June 3, 1991) (expected savings of $91 million over ten years); CINergy, supra (estimated savings of approximately $895 million over ten years). As the Commission has observed, with reference to the requirement of Section 10(c)(2) that a proposed combination yield economies and efficiencies, "specific dollar forecasts of future savings are not necessarily required; a demonstrated potential for economies will suffice even when these are not precisely quantifiable." Centerior, supra (citation omitted). In this regard, the Merger will result in additional benefits which, although not precisely quantifiable, are nonetheless significant. Two of these principal additional benefits relate to the Combined Company's generation mix and system reliability. The Merger will result in a more balanced generation mix that is less susceptible to fuel price volatility and supply interruptions. In addition, the Combined System will be better situated to provide more reliable electric service than is possible for AEP and CSW on a stand-alone basis. For example, the Combined System will share in a larger generating base after the Merger. As a result, the Combined System will have more generating resources to call on when units are down for maintenance or due to an unscheduled outage. In addition, each of AEP and CSW has a higher risk of unserved load than would be the case for the Combined System, since each of AEP and CSW on a stand-alone basis has access to fewer interconnections to neighboring systems for emergency support. C. SECTION 10(f) 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. Each of AEP's and CSW's obligation to consummate the Merger is conditioned, among other things, on the receipt of all requisite state regulatory approvals. State regulatory approvals have been obtained from the Oklahoma Commission, the Arkansas Commission, the Indiana Commission, and the Kentucky Commission. Applicants have also reached a settlement with the staffs of the Texas Commission and the Louisiana Commission who support the Merger as being in the public interest. See Item 4, infra, for further discussion of regulatory approvals and the 91 92 standard of review applicable to such approval. When the other approvals have been obtained, the Merger will comply with Section 10(f). D. INTRA-SYSTEM FINANCING AND OTHER COMMISSION AUTHORIZATIONS. In order to maximize the efficiencies resulting from the Merger, the Applicants seek authority for the Combined Company to reorganize, consolidate and, where necessary, restate certain of the intra-system financing and other authorizations previously issued by this Commission to each of AEP, CSW, and their respective subsidiaries, as discussed in more detail below. Applicants request approval, effective upon consummation of the Merger, to merge CSWS with and into AEPSC. Applicants request that, upon the merger of CSWS into AEPSC, AEPSC succeed to certain of the authority of CSWS as set forth in various Commission orders (which orders are summarized in Exhibit I-1 attached hereto) and that such activities with respect to CSWS include AEPSC. Certain of the non-utility businesses of CSW (each a 'CSW Non-utility Business') conduct activities that are substantially equivalent to the activities of one or more non-utility subsidiaries of AEP (each an 'AEP Non-utility Business'). Applicants request approval, as deemed appropriate by management, for the Combined Company to directly or indirectly acquire, and for CSW to transfer to the Combined Company, CSW Non-utility Businesses through: (1) merger of one or more CSW Non-utility Businesses with one or more wholly owned non-utility subsidiaries (either presently existing and performing substantially equivalent activities or to be formed, if appropriate) of the Combined Company (each a 'Combined Non-utility Business'), (2) the dividending or distribution of the common stock of one or more CSW Non-utility Businesses from CSW to the Combined Company, or (3) the acquisition of the assets or common stock of one or more CSW Non-utility Businesses by one or more Combined Non-utility Businesses. Applicants request approval, if management deems appropriate, to consolidate each CSW Non-utility Business with its corresponding AEP Non-utility Business into a single Combined Non-utility Business directly or indirectly owned by the Combined Company. Applicants request approval for the Combined Company to transfer to CSW, and CSW to acquire, any AEP Non-utility Business or to consolidate any AEP Non-utility businesses with and into any like CSW Non-utility Business consistent with the foregoing principles and authority. Applicants request that upon consolidation, each resulting Combined Non-utility Business succeed to all of the authority of each corresponding CSW Non-utility Business and AEP Non-utility Business, respectively, as set forth in previously issued Commission orders. The determination of the appropriate corporate structure of the Combined Company is the subject of currently convoked Merger transition teams. Pursuant to American Elec. Power Co., HCAR No. 26864 (Apr. 27, 1998) and American Elec. Power Co., HCAR No. 26516 (May 10, 1996), this Commission authorized AEP to issue and sell securities up to 100% of its consolidated retained earnings for investment in EWGs and FUCOs. Pursuant to Central and South West Corp. et al., HCAR No. 26653 (Jan. 24, 1997), this Commission authorized CSW to issue and sell securities up to 100% of its consolidated retained earnings for investment in EWGs and FUCOs. Applicants propose that, upon 92 93 consummation of the Merger, the authority of CSW to issue and sell securities in an amount up to 100% of its consolidated retained earnings for investment in EWGs and FUCOs as provided by Central and South West Corp. et al., HCAR No. 26653 (Jan. 24, 1997) shall cease. To the extent that AEP and CSW were authorized, pursuant to Sections 32 and 33 of the 1935 Act and the rules thereunder, to invest up to 100% of their consolidated retained earnings in EWG and FUCO interests, the Combined Company should also be authorized to invest up to 100% of its combined consolidated retained earnings in EWG and FUCO interests. Applicants therefore propose that, upon consummation of the Merger, the authority of the Combined Company to issue and sell securities in an amount up to 100% of its consolidated retained earnings for investment in EWGs and FUCOs shall be the same as that provided by American Elec. Power Co., HCAR No. 26864 (Apr. 27, 1998) and American Elec. Power Co., HCAR No. 26516 (May 10, 1996), except that for purposes of determining the amount of consolidated retained earnings as contemplated by American Elec. Power Co., HCAR No. 26864 (Apr. 27, 1998) and American Elec. Power Co., HCAR No. 26516 (May 10, 1996), 'consolidated retained earnings' shall consist of the consolidated retained earnings of the Combined Company. Currently, the CSW System uses short-term debt, primarily commercial paper, to meet working capital requirements and other interim capital needs. In addition, to improve efficiency, CSW has established a system money pool (the 'Money Pool') to coordinate short-term borrowings for CSW, its U.S. electric utility subsidiary companies and CSWS, as set forth in various Commission orders (which orders are summarized in Exhibit I-2 attached hereto). AEP has no equivalent to the Money Pool. Applicants hereby request authorization, upon consummation of the Merger and on the same terms and conditions as set forth in the orders summarized in Exhibit I-2, to permit: (1) the Combined Company, AEP's U.S. electric subsidiary companies and AEPSC to participate in the Money Pool, and (2) the Combined Company to manage and to fund the Money Pool. Exhibit I-2 summarizes the existing authority associated with the Money Pool and states the additional authority requested for the Money Pool upon consummation of the Merger. Applicants request that following the Merger, both the Combined Company and CSW (for a transitional period) will have in aggregate the authority that CSW has with respect to those orders summarized in Exhibit I-2. CSW Credit purchases, without recourse, the accounts receivable of CSW's U.S. electric utility subsidiary companies and certain non-affiliated utility companies. The sale of accounts receivable provides CSW's U.S. electric utility subsidiary companies with cash immediately, thereby reducing working capital needs and revenue requirements. In addition, because CSW Credit's capital structure is more highly leveraged than that of the CSW U.S. electric utility subsidiaries and due to CSW Credit's higher short-term debt ratings, CSW's overall cost of capital is lower. CSW Credit issues commercial paper to meet its financing needs. Applicants hereby request approval, effective upon consummation of the Merger, for the Combined Company to directly acquire, and for CSW to transfer to the Combined Company, the business of CSW Credit through: (1) the merger of CSW Credit with a subsidiary of the Combined Company to be formed, if appropriate, (2) the dividending or distribution of the common stock of CSW Credit from CSW to the Combined Company, or (3) the acquisition of the assets or common stock of CSW Credit by a subsidiary of the Combined Company to be formed, if appropriate. Applicants request that, upon the acquisition of the business of CSW Credit by the Combined Company, the resulting company ('New Credit') succeed to all of the authority of CSW Credit as set forth in various Commission orders (which orders are summarized in Exhibit 93 94 I-3 attached hereto). Exhibit I-3 summarizes the existing authority of CSW Credit and states the authority requested for New Credit. CSW has supported the financing and other activities of its subsidiaries through obtaining Commission approval to issue and guarantee certain indebtedness. After the Merger it may be more efficient or even commercially necessary for the Combined Company to support certain of the financing arrangements and business activity previously supported by CSW. Applicants hereby request approval for the Combined Company, upon consummation of the Merger, to support those financing and other activities presently supported by CSW, including the issuance and guaranteeing of indebtedness, pursuant to those orders of the Commission summarized in Exhibit I-4. Exhibit I-4 describes the existing authority of CSW which Applicants seek to duplicate in favor of the Combined Company. It is Applicants' intention that, following the Merger, both the Combined Company and CSW will simultaneously have in aggregate the authority that CSW currently has with respect to those orders summarized in Exhibit I-4. The Combined Company does not seek to widen such authority which will necessarily remain limited to the orders described in Exhibit I-4. The practical effect of this approval would be to insert the Combined Company alongside CSW in virtually all instances where CSW is mentioned in such orders. Pursuant to Central and South West Corp., HCAR No. 26616 (Nov. 27, 1996), this Commission confirmed previous authority and granted additional authority such that CSW was authorized, through December 31, 2001, to offer 10,000,000 shares of CSW Common Stock pursuant to its Dividend Reinvestment and Stock Purchase Plan, of which approximately 2,000,000 remain unissued. Pursuant to American Elec. Power Co., HCAR No. 26553 (Aug. 13, 1996) this Commission confirmed previous authority and granted additional authority such that AEP was authorized, through December 31, 2000, to offer 54,000,000 shares of AEP Common Stock pursuant to its Dividend Reinvestment and Direct Stock Purchase Plan. Applicants hereby request that, as soon as practicable upon consummation of the Merger, (1) the authority of CSW's Dividend Reinvestment and Stock Purchase Plan be terminated, and (2) the Combined Company be authorized to issue 55,200,000 shares of AEP Common Stock through December 31, 2000 pursuant to its Dividend Reinvestment and Direct Stock Purchase Plan consistent otherwise with all the terms and conditions set forth in American Elec. Power Co., HCAR No. 26553 (Aug. 13, 1996). Pursuant to Central and South West Corp., HCAR No. 26413 (Nov. 21, 1995), this Commission confirmed previous authority and granted additional authority such that CSW was authorized to issue and sell a total of 5,000,000 shares of CSW Common Stock to the trustee of the Central and South West Thrift Plan, of which approximately 4,400,000 remain unissued. Pursuant to American Elec. Power Co., HCAR No. 26786 (Dec. 1, 1997), this Commission confirmed previous authority and granted additional authority such that AEP was authorized, through December 31, 2001, to sell 8,800,000 shares of AEP Common Stock to the trustee of the American Electric Power System Employees Savings Plan. Applicants hereby request that, upon consummation of the Merger, (1) the authority of CSW to issue shares of CSW Common Stock to the Central and South West Thrift Plan be terminated, and (2) the Combined Company be authorized to issue 11,440,000 shares of AEP Common Stock through December 31, 2001 in connection with the American Electric Power System Employees Savings Plan and the Central and South West Thrift Plan (for a transitional period) consistent otherwise with all the terms and 94 95 conditions set forth in American Elec. Power Co., HCAR No. 26786 (Dec. 1, 1997) and Central and South West Corp., HCAR No. 26413 (Nov. 21, 1995), respectively. Pursuant to Central and South West Corp., HCAR No. 25511 (Apr. 7, 1992), this Commission authorized CSW to adopt the Central and South West Corporation 1992 Long Term Incentive Plan pursuant to which certain key employees would be eligible, through December 31, 2001, to receive certain performance and equity-based awards including (a) stock options, (b) stock appreciation rights, (c) performance units, (d) phantom stock, and (e) restricted shares of common stock. Applicants hereby request that, upon consummation of the Merger, the Combined Company succeed to the authority of CSW to permit it (i) to honor the awards granted by CSW prior to the consummation of the Merger, (ii) to administer the plan (subject to any necessary shareholder or regulatory approval) on a Combined Company basis and grant any remaining awards, and (iii) to reserve and issue sufficient shares of AEP Common Stock pursuant to subparagraphs (i) and (ii) above in connection with the Central and South West Corporation 1992 Long Term Incentive Plan consistent otherwise with all the terms and conditions set forth in Central and South West Corp., HCAR No. 25511 (Apr. 7, 1992). E. SERVICE AGREEMENT; APPROVAL OF METHODOLOGY FOR ALLOCATING COSTS UNDER As described in Item 1.B.1 above, AEPSC is a service company that, pursuant to service agreements with each of the subsidiary companies of AEP, provides various technical, engineering, accounting, administrative, financial, purchasing, computing, managerial, operational and legal services to each of the AEP subsidiary companies. Pursuant to the service agreements, these services are provided at cost. The Commission has previously determined that AEPSC is so organized and its business is so conducted as to meet the requirements of Section 13(b) of the 1935 Act and Rule 88 thereunder. Amer. Elec. Power Service Corp., HCAR No. 21922 (Feb. 19, 1981) (order authorizing service agreement between service company and operating subsidiaries). Similarly, CSWS is a service company which, pursuant to service agreements signed with each of the subsidiary companies of CSW, provides various technical, engineering, accounting, administrative, financial, purchasing, computing, managerial, operational and legal services to each of the CSW subsidiary companies. Pursuant to the service agreements, these services are provided at cost. The Commission has also previously determined that CSWS is so organized and its business is so conducted as to meet the requirements of Section 13(b) of the 1935 Act and Rule 88 thereunder. Central and South West Corp., HCAR No. 26293 (May 18, 1995). Upon consummation of the Merger, CSWS will be merged with AEPSC, and AEPSC will be the surviving service company for the Combined System. Applicants intend that AEPSC will enter into an amended service agreement with AEP's subsidiary companies and CSW's subsidiary companies. The proposed amended service agreement is filed as Exhibit B-2. Under the amended service agreement, AEPSC will provide the managerial, administrative, financial, technical, and other services previously provided by the two service companies, CSWS and AEPSC. The execution and performance by the respective parties of the amended service agreement is subject to Section 13(b) of the 1935 Act and the rules thereunder. To the extent not exempt under rules or otherwise under the 1935 Act, Applicants' subsidiaries will provide 95 96 services to each other at cost unless otherwise authorized by Commission orders. See, e.g., Central and South West Corp., HCAR No. 26887 (June 19, 1998), AEP Energy Services, Inc., HCAR No. 26267 (April 5, 1995) and AEP Resources, Inc., HCAR No. 26962 (Dec. 30, 1998) (authorizing certain non-regulated subsidiaries of Applicants to provide services at fair market value). The amended service agreement to be entered into between AEPSC and the utility and nonutility subsidiary companies of AEP and CSW, which, pending Commission approval, will become effective upon the consummation of the Merger, is similar to those service agreements currently in place. Under the terms of the amended service agreement, AEPSC will render services to the subsidiary companies of the Combined Company at cost. AEPSC will account for, allocate and charge its costs of the services provided on a full cost reimbursement basis under a work order system consistent with the Uniform System of Accounts for Mutual and Subsidiary Service Companies. Costs incurred in connection with services performed for a specific subsidiary company will be billed 100% to that subsidiary company. Costs incurred in connection with services performed for two or more subsidiary companies will be allocated in accordance with the attribution bases set forth in Exhibit B-3. Indirect costs incurred by AEPSC which are not directly allocable to one or more subsidiary companies will be allocated in proportion to how either direct salaries or total costs are billed to the subsidiary companies depending on the nature of the indirect costs themselves. The time AEPSC employees spend working for each subsidiary will be billed to and paid by the applicable subsidiary on a monthly basis, based upon time records. Each subsidiary company will maintain separate financial records and detailed supporting records showing AEPSC charges. Several state commissions have already approved the Merger and included codes of conduct that will govern the relationship between AEPSC, the operating companies, and other affiliated companies. For example, the orders of the Indiana, Kentucky, Louisiana and Arkansas Commissions approving the Merger all contain detailed guidelines relating to affiliate transactions. The order of the Oklahoma Commission approving the Merger grants the Oklahoma Commission and the State Attorney General access to the books and records of AEP and its affiliates and subsidiaries (including their participation in joint ventures) with respect to matters and activities that relate to Oklahoma retail rates. The settlement with the staff of the Texas Commission requires compliance with a detailed code of conduct governing activities among the Combined Company's subsidiaries. These orders and agreements, consistent with state law, generally require certain separations and safeguards between utility and nonutility affiliates to prevent cross-subsidization and preferential treatment of nonutility affiliates. Applicants hereby request that the Commission approve the amended service agreement between AEPSC and the subsidiary companies of the Combined Company and the related attribution bases listed in Exhibit B-3. The proposed attribution bases are based on cost-drivers emphasizing factors that correlate to the volume of activity that is inherent in performing certain services. The frequency at which each attribution basis will be recalculated is noted in Exhibit B-3.1. Exhibit B-3.2 compares the proposed attribution bases to the attribution bases currently used by both AEPSC and CSWS. This exhibit also includes explanations for the proposed differences. In all cases, the proposed attribution bases are based on the attribution bases 96 97 currently used by either AEPSC or CSWS with some variations. Exhibit B-3.3 identifies the scope of each of the attribution bases by class of companies. Exhibit B-3.4 describes the services that will be performed by AEPSC after the Merger and lists the attribution bases associated with each major service category. AEP currently utilizes the following principles in coordinating its work order and billing control, planning and budgeting and internal audit functions and expects that these principles will continue to govern such functions following the Merger. An AEPSC work order may be initiated by AEPSC or by a subsidiary company of AEP. Any AEPSC work order, whether for a single company or multiple companies, including the proposed cost allocation method, must be reviewed and approved by the AEPSC Corporate Accounting Department and then by a person appointed by the subsidiary company. As a result of the centralization in AEPSC of the responsibilities previously assigned to the officers of the subsidiary companies, the Corporate Planning and Budgeting Department of AEPSC has been appointed by the subsidiary companies to approve work orders. Corporate Planning and Budgeting is independent of the AEPSC work order billing process, which is maintained by the Corporate Accounting Department of AEPSC. Time records are completed by or for each employee in AEPSC and approved by work group supervisors. Charges are accumulated by the Corporate Accounting Department of AEPSC and billed to each AEP subsidiary company at the end of each month. These bills are reviewed for reasonableness and approved on behalf of the AEP subsidiary companies by Corporate Planning and Budgeting. Management has developed strategic performance measures for AEP and its subsidiary companies as a business enterprise. These measures include earnings per share, total shareholder return, competitive cost comparison, market share, customer satisfaction and loyalty, employee development, safety and productivity, and environmental performance. Management has developed targets against which to measure the performance of AEP and its subsidiaries on a consolidated basis. In addition, based upon these strategic performance measures and targets, management has developed performance measures and targets for each business group. These measures and targets focus on the business group, not on the corporate entity; however, the expected impact of proposed plans and budgets on expenses of the subsidiary companies is determined. Efficiency in business operations is important in order to achieve targets in some of the strategic performance measures, such as earnings per share and competitive cost comparison. A new planning and budgeting system, including activity based management, has been developed and implemented. This system focuses on the business process - a network of related and interdependent activities performed to achieve a specific purpose. It provides cost information quickly and allows managers to evaluate the efficiency and value of processes, including trends and internal benchmarks. Using this planning and budgeting system, an annual budget is prepared by each business unit and support organization and submitted to the Office of the Chairman for approval. The Office of the Chairman consists of the Chairman of the Board, President and Chief Executive Officer of AEP and AEPSC and the executive vice presidents of AEPSC that report to him. A majority of these officers are also directors and executive officers of each of the subsidiary 97 98 companies. The Corporate Planning and Budgeting Group assists the business units and support organizations in the planning and budgeting process and monitors expenses. It also determines and reports the expected impact of proposed plans and budgets on the expenses of the subsidiary companies. The planning and budgeting process for AEPSC is part of the overall process for the business units and support organizations and subject to approval by the Office of the Chairman. The AEPSC Internal Audits Department continuously conducts audits of the functions of AEP and its subsidiaries, including those of AEPSC, to ensure that proper internal controls exist and to determine if they are functioning as intended and are efficient and effective. As a part of the audit plan, the Internal Audits Department performs audits of the AEPSC work order system and related billings to AEP subsidiary companies. The purpose of the audits is to render an opinion on the internal controls over the work order billing process and compliance with Commission-approved cost allocation billing methodologies. The Internal Audits Department completed the latest review in 1997 and expressed an opinion that the internal controls are functioning properly and that the costs are being allocated to AEP subsidiary companies in accordance with the Commission-approved cost allocation billing methodologies. The Department will perform its next audit of the work order system and related billings in 1999 and then every two years. The Vice President of Internal Audits (the "Vice President") reports to the Chairman of the Audit Committee of the Board of Directors of AEP (the "Audit Committee"). Administratively, the Vice President reports to the Executive Vice President - Financial Services of AEPSC. The Vice President attends each meeting of the Audit Committee. In accordance with New York Stock Exchange listing requirements, the Audit Committee is comprised solely of outside directors. In December of each year, the results of the year's audit activities are reviewed with the Audit Committee and the following year's audit plan is reviewed and approved by the Audit Committee. The Audit Committee annually reviews and approves the Internal Audits Department Charter to ensure that it sufficiently allows the Vice President to carry out his duties. The Vice President meets privately with the Audit Committee several times during the year and has the addresses and telephone numbers of the Audit Committee members and is free to contact them at any time. The Vice President is reminded in these private meeting sessions that he has such freedom. F. ACQUISITION OF NON-UTILITY BUSINESSES Section 10(c)(1) provides that the Commission shall not approve an acquisition that is "detrimental to the carrying out of the provisions of Section 11." Section 11(b)(1) limits the non-utility interests of a registered holding company to those that are "reasonably incidental, or economically necessary or appropriate to the operations of such integrated public-utility system." The Commission may find that a non-utility business meets this standard when it finds that the interest in the business is "necessary or appropriate in the public interest or for the protection of investors or consumers and not detrimental to the proper functioning of such [integrated] system." CSW has a number of non-utility businesses that AEP will indirectly acquire as a result 98 99 of the Merger. CSW owns seven material non-utility subsidiaries: CSW Energy, CSW International, C3 Communications, EnerShop, CSW Energy Services, CSW Credit, and holds an 80% interest in CSW Leasing. For a description of CSW's non-utility businesses, see Item 1.B.1(b) supra. The Commission has found that CSW's non-utility businesses meet the 11(b)(1) standard (to the extent that such a finding was necessary).(35) Such businesses have an operating or functional relationship to CSW's utility operations. See, e.g., Conectiv, supra (the Commission has interpreted section 11(b)(1) "to require the existence of an operating or functional relationship between the utility operations of the registered holding company and its nonutility activities.") Upon consummation of the Merger, the non-utility businesses of CSW will become indirect subsidiaries of AEP. To the extent that Commission approval is necessary for the acquisition of CSW's non-utility businesses, the acquisitions should be approved because the indirect ownership of CSW's non-utility businesses by AEP in no way affects the functional relationship of these businesses to the Combined Company's core electric business following the Merger. Moreover, acquisition of these businesses is in the public interest and consistent with the applicable standards under the 1935 Act. G. ORGANIZATION OF MERGER SUB; ACQUISITION OF MERGER SUB COMMON STOCK Merger Sub was organized solely for the purpose of effecting the Merger and has not conducted any activities other than in connection with the Merger. Merger Sub has no subsidiaries. Each share of common stock of Merger Sub, par value $0.01 per share, to be issued to AEP and outstanding immediately before the consummation of the Merger will be converted into one share of CSW Common Stock upon consummation of the Merger. Thus, the sole purpose for Merger Sub is to serve as an acquisition subsidiary of AEP for purposes of effecting the Merger. Approval of this Application-Declaration will constitute approval of the acquisition by AEP of the common stock of Merger Sub. ITEM 4. REGULATORY APPROVAL Set forth below is a summary of the material regulatory requirements affecting the Merger. Failure to obtain any necessary regulatory approval or any adverse conditions that are imposed in connection with any necessary regulatory approval, including the failure to obtain appropriate ratemaking treatment, may affect the consummation of the Merger. - --------------- (35) A registered holding company may acquire and hold an interest in an EWG, FUCO, and an exempt telecommunications company, without the need to apply for or receive approval from the Commission (although the Commission retains jurisdiction over certain related transactions with these entities). Sections 32, 33 and 34 of the 1935 Act. Moreover, a registered holding company may acquire "energy-related" companies meeting the Rule 58 safe harbor conditions (including an investment ceiling) without the need for Commission approval. 99 100 In addition to required Commission approvals, the state utility commissions of Arkansas, Louisiana, Oklahoma, and Texas, and the FERC, the FCC, and the NRC have jurisdiction over various aspects of the transactions proposed herein.(36) Further, both AEP and CSW are required to file notification and report forms under the HSR Act with the DOJ with respect to the Merger. Additional consents from or notifications to governmental agencies may be necessary or appropriate in connection with the Merger. Applicants already have obtained regulatory approvals of the Nuclear Regulatory Commission, the Arkansas Commission, the Oklahoma Commission, the Louisiana Commission, the Kentucky Commission, and the Indiana Commission. A settlement has been reached with FERC trial staff which resolves most issues, including issues related to rates and competition. A stipulated settlement with the commission staff and key intervenor groups has been reached in the Texas proceeding, and Applicants anticipate that the FERC and the remaining state commissions asserting jurisdiction over the Merger will make similar public interest findings and issue orders approving the Merger in the near future. A. ANTITRUST CONSIDERATIONS The HSR Act and the rules and regulations thereunder provide that certain transactions (including the Merger) may not be consummated until certain information has been submitted to the Antitrust Division and the specified HSR Act waiting period has expired or been terminated. Applicants filed their respective pre-merger notification pursuant to the HSR Act in July 1999. The expiration or earlier termination of the HSR Act waiting period would not permanently preclude the Antitrust Division from challenging the Merger on antitrust grounds, but it would represent a decision by such agencies that the Merger may be consummated without challenge under Section 7 of the Clayton Act. If the Merger is not consummated within 12 months after the expiration or earlier termination of the initial HSR Act waiting period, AEP and CSW must submit new information to the Antitrust Division, and a new HSR Act waiting period must expire or be earlier terminated before the Merger may be consummated. B. ATOMIC ENERGY ACT CSW, through its wholly-owned subsidiary CPL, owns a 25.2% interest in the STP, a two-unit nuclear electric generating station. The STP is operated by STP Operating, a Texas non-profit corporation, which is jointly-owned by CPL and the other owners of the STP. CPL holds NRC licenses with respect to its ownership interests in the STP and STP Operating. Section 184 of the Atomic Energy Act provides that no license may be transferred, assigned or in any manner disposed of, directly or indirectly, through transfer of control of any license to any - ----------------- (36) AEP has U.S. electric utility subsidiaries operating in Ohio, Indiana, Kentucky, Michigan, Tennessee, Virginia, and West Virginia. AEP believes that the approval of the utility regulatory commissions in these states is not required to consummate the Merger, and that these states therefore do not have jurisdiction over this proposed transaction. Nevertheless, the Indiana Commission and the Kentucky Commission have approved the Merger, and AEP has been actively working with all of these state commissions regarding both the FERC and state regulatory impacts of the transaction. 100 101 person, unless the NRC finds that the transfer is in accordance with the provisions of the Atomic Energy Act and gives its consent in writing. On June 19, 1998, CPL sought approval from the NRC for the transfer of control of its NRC licenses as a result of the Merger. The Application for Transfers of Control Regarding Operating License No. NPF-76 and NPF-80 for the STP is filed as Exhibit D-6.1. On November 5, 1998, the NRC approved the transfer of control of CPL's NRC licenses. The NRC Order is filed as Exhibit D-6.2, and incorporated by reference. After the Merger, CPL, as an operating utility subsidiary of the Combined Company, will continue to own the identical pre-Merger interests in the STP and STP Operating. C. FEDERAL POWER ACT Section 203 of the FPA provides that no public utility may sell or otherwise dispose of its jurisdictional facilities, directly or indirectly merge or consolidate its facilities with those of any other person, or acquire any security of any other public utility, without first having obtained authorization from the FERC. On April 30, 1998, AEP and CSW filed a joint application with the FERC seeking approval of the Merger, as supplemented on January 13, 1999. See Exhibits D-1.1 and D-1.2. A procedural schedule has been adopted by FERC which directs the Administrative Law Judge to issue an Initial Decision no later than November 24, 1999. This schedule will allow FERC to issue a decision no later than March 2000. Under Section 203 of the FPA, the FERC will approve a merger if it finds the merger to be 'consistent with the public interest.' On June 24, 1999, Applicants and the FERC trial staff filed the FERC Stipulation resolving major issues related to the Merger, including all significant competition and rate issues. In addition, FERC Trial Staff agreed to support a finding that the Merger will have no adverse effect on competition. The FERC Stipulation is filed as Exhibit D-1.3. Under the terms of the FERC Stipulation, prior to the consummation of the Merger, AEP will file with the FERC a proposal whereby it would transfer certain control area functions relating principally to reliability and access to an RTO.(37) As part of the transfer, AEP agreed to transfer functions relating to transmission service, transmission security and control area responsibility to the RTO. In addition thereto, prior to December 31, 2000, AEP will file with the FERC an unconditional application to transfer the corresponding control area functions relating principally to reliability and access, controlled and/or operated by AEP and currently located in the SPP to a FERC-approved RTO directly interconnected with the facilities located outside the SPP. The FERC Stipulation also addresses rates for transmission services and ancillary services and confirms, subject to FERC guidance on the timing of divestiture, that the previously - ------------- (37) As noted in Item I.B.2.d. above, on June 3, 1999, AEP and four other utilities filed the Alliance RTO Application. CSW is participating in the ERCOT independent regional transmission plan for the portion of its system that is within ERCOT and is participating in discussions with other interested parties about the formation of an RTO that would include utility systems in the SPP. 101 102 announced generation divestiture program will satisfy the market power concerns of the FERC trial staff. In its filing with FERC, the Applicants proposed divesting ownership of 300 MW of generation capacity at CSW's Northeastern Power Station Units 3 and 4 and 250 MW of generation capacity located at the Frontera Power Plant, a merchant power plant being constructed by a CSW subsidiary near Mission, Texas. In addition to the waiver of transmission priorities that is explained in the FERC testimony of Stephen B. Jones, Applicants agreed that they will not assert the "AES/TVA" priority for any transfers of non-firm energy from AEP West to AEP East for a period of four years from the date of the consummation of the Merger. D. COMMUNICATIONS ACT CSW, itself or through one or more subsidiaries, holds various radio licenses subject to the jurisdiction of the FCC under Title III of the Communications Act. Under Section 310 of the Communications Act, no station license may be assigned or transferred, directly or indirectly, except upon application to and approval by the FCC. On July 26, 1999, Applicants filed with the FCC for authority to transfer control of licenses held by several CSW subsidiaries to AEP. See Exhibit D-9.1. E. ARKANSAS COMMISSION SWEPCO is subject to the jurisdiction of the Arkansas Commission. Pursuant to Section 23-3-306(b) of the Arkansas Statutes, and Arkansas Commission approval is required before any person may merge with or otherwise acquire control of a domestic public utility. The Arkansas Commission must approve a merger application unless it finds that one or more of five adverse circumstances would result from the transaction. The circumstances include an adverse effect on the public utility's existing obligations or quality of service, a reduction in competition for the provision of utility services within the state, and an adverse effect on the financial condition of the public utility. On June 12, 1998, AEP, CSW and SWEPCO filed an application with the Arkansas Commission seeking Arkansas Commission approval of the Merger, a copy of which is filed as Exhibit D-2.1 and incorporated by reference. On August 13, 1998, the Arkansas Commission issued an order conditionally approving the Merger, a copy of which is filed as Exhibit D-2.2 and incorporated by reference. F. LOUISIANA COMMISSION SWEPCO is subject to the jurisdiction of the Louisiana Commission. Pursuant to Louisiana Statutes Section 45:1164, the Louisiana Commission is granted general supervisory authority over public utilities operating in the state and, under this authority, the Louisiana Commission has held that its approval or non-opposition is required prior to the sale, lease, merger, consolidation, stock transfer, or any other change of control or ownership of a public utility subject to its jurisdiction. The Louisiana Commission reviews merger applications pursuant to an 18 factor test that generally relates to the impact of the transaction on competition, the financial condition of the utility, quality of service, public health and safety, employment, and other similar "public interest" matters. 102 103 On May 15, 1998, AEP, CSW and SWEPCO filed an application seeking Louisiana Commission approval of, or non-opposition to, the Merger, a copy of which is filed as Exhibit D-3.1 and incorporated by reference. On July 29, 1999, the Louisiana Commission voted to issue an order conditionally approving the Merger, a copy of which is filed as Exhibit D-3.2 and incorporated by reference. G. OKLAHOMA COMMISSION PSO is subject to the jurisdiction of the Oklahoma Commission. The Oklahoma Statutes concerning mergers and acquisitions of public utilities are substantially identical to the sections of the Arkansas Statutes discussed above. Oklahoma Commission approval is required before any person may merge with or otherwise acquire control of an Oklahoma public utility. On August 14, 1998, AEP, CSW and PSO filed an application with the Oklahoma Commission seeking approval of the Merger, a copy of which is filed as Exhibit D-4.1 and incorporated by reference. On May 4, 1999, an administrative law judge recommended that the Oklahoma Commission approve the Merger subject to certain conditions. Those conditions included the recommendation that Applicants participate in an SPP study of the impacts of the effect of the Merger on the transmission system of OG&E at its Fort Smith, Arkansas substation. On May 11, 1999, the Oklahoma Commission issued an order conditionally approving the Merger, a copy of which is filed as Exhibit D-4.2 and incorporated by reference. The order of the Oklahoma Commission is currently the subject of an appeal. H. TEXAS COMMISSION CPL, SWEPCO, and WTU are subject to the jurisdiction of the Texas Commission. Pursuant to Section 14.101 of the Texas Utilities Code, each transaction involving the sale of at least 50 percent of the stock of a public utility must be reported to the Texas Commission within a reasonable time. On April 30, 1998, AEP, CSW, CPL, SWEPCO and WTU reported the Merger to the Texas Commission for its review, as supplemented on January 15, 1999. See Exhibits D-5.1 and D-5.2. In reviewing a transaction involving the sale of at least 50 percent of the stock of a Texas utility, the Texas Commission is required to determine whether the action is consistent with the public interest, taking into consideration factors such as the reasonable value of the property, facilities, or securities to be acquired, disposed of, merged, transferred, or consolidated, and whether the transaction will adversely affect the health or safety of customers or employees, result in the transfer of jobs of Texas citizens to workers domiciled outside of Texas, or result in the decline of service. If the Texas Commission determines that a transaction is not in the public interest, it may take the effect of the transaction into consideration in ratemaking proceedings and disallow the effect of such transaction if such transaction will unreasonably affect rates or service. In the proceedings before the Texas Commission, Applicants reached a settlement with the Public Utility Commission of Texas General Counsel, the State of Texas (in its capacity as a consumer of electricity), the Texas Industrial Energy Consumers, Low Income Intervenors, the Office of Public Utility Counsel, and the Steering Committee of the Cities of McAllen, Corpus 103 104 Christi, Victoria, Abilene, Big Lake, Vernon and Paducah. The Texas Stipulation is filed as Exhibit D-5.3 and incorporated by reference. In addition thereto, in a letter dated July 9, 1999 to the administrative law judge in the Texas proceeding, Medina Electric Cooperative, Inc. and the City of Robstown, Texas stated that they have no objection to the Merger and will not file testimony in that proceeding. Furthermore, agreements have been reached with several wholesale customer groups including South Texas Electric Cooperative (STEC) and its member distribution cooperatives, the City of Brownsville Public Utility Board, the East Texas Cooperatives, which includes East Texas Electric Cooperative Inc., Northeast Texas Electric Cooperative, Inc., and Tex-La Electric Cooperative of Texas, Inc., and a group of transmission dependent utilities (TDUs), which includes Magic Valley Electric Cooperative, Inc. Mid-Tex Generation and Transmission Electric Cooperative, Inc. and its members and Rayburn Country Electric Cooperative. I. INDIANA COMMISSION On April 26, 1999, the Indiana Commission issued an order approving a stipulation and settlement agreement among AEP, CSW, and the staff of the Indiana Commission, a copy of which is filed as Exhibit D-8.1 and incorporated by reference. J. KENTUCKY COMMISSION On May 24, 1999, the Kentucky Commission issued an order approving the stipulation among AEP, CSW, Kentucky Industrial Customers Inc., Kentucky Industrial Steel, Inc., and the Kentucky Attorney General, a copy of which is filed as Exhibit D-7.1 and incorporated by reference. K. MISSOURI COMMISSION No regulatory authorization is required from the Missouri Commission. However, in an effort to address concerns raised by the Missouri Commission with respect to competitive impacts that may occur as a result of Applicants' use of the Contract Path, Applicants agreed that, as part of a settlement between Applicants and the Missouri Commission, the Missouri Commission may initiate, within four years of the consummation of the Merger, a review by the FERC of the Merger's effects on retail competition, assuming retail competition has been implemented in Missouri. The settlement also gives the FERC discretion to decide if mitigation measures are necessary to the extent that the review results in a finding that the Contract Path is harmful to competition. Any relief ordered by FERC cannot extend beyond six years after the consummation of the Merger. L. AFFILIATE CONTRACTS AEP, CSW and their subsidiaries intend to enter into or amend agreements related to the provision by affiliates of various services, including management, supervisory, construction, engineering, accounting, legal, financial or similar services. The approval or non-opposition of certain state regulatory commissions and the Commission is required with respect to the creation or amendment of certain inter-affiliate agreements. Applicants and their subsidiaries intend to file such agreements with the appropriate state regulatory commissions within the next few months. 104 105 ITEM 5. PROCEDURE The Commission is respectfully requested to issue and publish not later than November 20, 1998, the requisite notice under Rule 23 with respect to the filing of this Application-Declaration, such notice to specify a date not later than December 15, 1998, by which comments may be entered and a date not later than December 16, 1998, as the date after which an order of the Commission granting and permitting this Application-Declaration to become effective may be entered by the Commission. It is submitted that a recommended decision by a hearing or other responsible officer of the Commission is not needed for approval of the Merger. The Division of Investment Management may assist in the preparation of the Commission's decision. There should be no waiting period between the issuance of the Commission's order and the date on which it is to become effective. ITEM 6. EXHIBITS AND FINANCIAL STATEMENTS Exhibit Number Description *A-1 Copy of Restated Certificate of Incorporation of AEP, dated October 29, 1997 (filed as Exhibit 3(a) to the Quarterly Report on Form 10-Q for the period ended September 30, 1997 (File No. 1-3525) and incorporated herein by reference) *A-2 Second Restated Certificate of Incorporation of CSW (filed as Exhibit 3(1) to the Form 10-K for the fiscal year ended December 31, 1997 (File No. 1-1443) and incorporated herein by reference) *A-3 Certificate of Incorporation of Merger Sub *A-4 By-laws of Merger Sub *B-1 Agreement and Plan of Merger among AEP, CSW and Merger Sub, dated at December 21, 1997 (filed as Annex A to the Registration Statement on Form S-4 on April 15, 1998 (Registration No. 333-50109) and incorporated herein by reference)) *B-2 Proposed Service Agreement between AEPSC and subsidiaries of the Combined Company *B-3 Proposed Attribution basis List *B-3.1 Update Frequencies Applicable to the Proposed AEPSC Attribution Bases *B-3.2 Comparison of AEPSC and CSWS Current Attribution Bases to Proposed Post-Merger AEPSC Attribution Basis *B-3.3 Scope of the Proposed Post-Merger AEPSC Attribution Bases by Class of Companies 105 106 *B-3.4 Description of Services to be Provided by AEPSC Post-Merger and Associated Attribution bases by Category of Services *C-1 Registration Statement of AEP on Form S-4 (as amended) (filed as Registration Statement No. 333-50109 and incorporated herein by reference) *C-2 Joint Proxy Statement and Prospectus (included in Exhibit C-1) *D-1.1 Joint Application of jurisdictional subsidiaries of AEP and CSW before the FERC, together with exhibits, appendices and workpapers, dated April 30, 1998 (filed on Form SE) and consisting of: VOLUME 1 - Exhibit D-1.1 Transmittal Letter dated April 30, 1998 for Section 203 of the FPA and part 33 of the FERC's Regulations Joint Application of AEP and CSW for Authorization and Approval of Merger for Section 203 Filing Appendix 1 -Designation of the Territories Served, by States and Counties Appendix 2 -Morgan Stanley Letter to the Board of Directors concerning Merger; Opinion Letter from Salomon Smith Barney to Board of Directors dated December 21, 1997 Appendix 3 -AEP and CSW Companies Community and Franchise Expiration Date Exhibit A - Certified Copy of a Resolution of the Board of Directors of Central and South West Corporation Adopted on December 21, 1997 Exhibit B - Statement of Measures of Control of Ownership over AEP and CSW Exhibit C - Balance Sheets and Supporting Plant Schedules Exhibit D - Consolidated Statement of Contingencies and Commitments as of December 31, 1997 Exhibit E - Income Statements Exhibit F - Analysis of Retained Earnings Exhibit G - Copies of State and Federal Applications and Exhibits Exhibit H - Agreement and Plan of Merger among AEP and CSW Exhibit I - Territory Service Maps of AEP, CSW and the Ameren Interconnection VOLUME 2 - Exhibit D-1.1 106 107 Testimonies and Exhibits for Section 203 Filing of the Following Witnesses: Draper, Shockley, Munczinski, Baker, Hieronymus, Jones, Bethel and Maliszewski VOLUME 3 - Exhibit D-1.1 Workpapers of Witnesses Munczinski and Hieronymus for Section 203 Filing VOLUME 4 - Exhibit D-1.1 Transmittal Letter dated April 30, 1998 for Section 205 of the FPA and part 35 of the FERC's Regulations System Integration Agreement among AEP companies and CSW companies AEPSC Transmission Reassignment Tariff Testimony and Exhibits of J. Craig Baker in Support of the System Integration Tariff System Transmission Integration Agreement among AEP companies and CSW companies Testimony and Exhibits of Dennis W. Bethel in Support of the System Transmission Integration Agreement VOLUME 5 - Exhibit D-1.1 Transmittal Letter dated April 30, 1998 for Section 205 of the FPA Open Access Transmission Service Tariff of the AEP System VOLUME 6 - Exhibit D-1.1 AEP System Procedures for Implementation of the FERC Standards of Conduct Testimony and Exhibits of Dennis W. Bethel Testimony and Exhibits of Bruce M. Barber VOLUME 7 - Exhibit D-1.1 Workpapers of Dennis W. Bethel *D-1.2 Supplemental and Direct Testimony before the FERC, January 13, 1999 filed herewith on Form SE) and consisting of: VOLUME 1 - Exhibit D-1.2 Transmittal Letter dated January 13, 1999 Supplemental and Direct Testimonies and Exhibits for the Following Witnesses: Baker, Jones, Smith, Maliszewski, Henderson 107 108 VOLUME 2 - Exhibit D-1.2 Supplemental and Direct Testimonies and Exhibits for the Following Witnesses: Hieronymus, Zausner VOLUMES 3-6 - Exhibit D-1.2 Workpapers of Witness Henderson VOLUMES 7-71 - Exhibit D-1.2 Workpapers of Witness Hieronymus D-1.3 Stipulation of American Electric Power Company, Inc., Central and South West Corporation, and Commission Trial Staff, FERC Docket No. EC 98-40 (filed June 24, 1999). D-1.4 Stipulation of American Electric Power Company, Inc., Central and South West Corporation, and Commission Trial Staff, FERC Docket No. ER98-2770 (filed _______, 1999). *D-2.1 Joint Application of AEP, CSW and SWEPCO before the Arkansas Commission, together with exhibits, appendices, and workpapers, dated June 12, 1998 (filed on Form SE) and consisting of: VOLUME 1 - Exhibit D-2.1 Joint Application with Exhibits of AEP, SWEPCO, and CSW regarding Merger Exhibit A - AEP's Corporate Structure and Listing of Affiliate Companies and Business Engaged Exhibit B - Restated Certificate of Incorporation of AEP Exhibit C - Statement of Directors' and Officers' Qualifications Exhibit D - AEP's 1997 Summary Report to Shareholders Exhibit E - Annual Report of AEP on Form 10-K for the Year Ended December 31, 1997 (File No. 1-3525) Exhibit F - Quarterly Report of AEP on Form 10-Q for the Quarter Ended March 31, 1998 (File No. 1-3525) Exhibit G - Registration Statement of AEP on Form S-4, Amendment No. 1 (Registration No. 333-50109) Exhibit H - Notice to Customers of SWEPCO 108 109 VOLUME 2 - Exhibit D-2.1 Direct Testimony and Exhibits of the Following Witnesses: Draper, Shockley, Flaherty, Baker, Munczinski, Roberson, Davis, Hieronymus, Mitchell, Pena, Martin and Bailey VOLUME 3 - Exhibit D-2.1 Workpapers of Witness Roberson Workpapers of Witness Davis VOLUME 4 - Exhibit D-2.1 Continued Workpapers of Witness Davis Workpapers of Witness Pena Workpapers of Witness Martin Workpapers of Witness Munczinski VOLUME 5 - Exhibit D-2.1 Workpapers of Witness Flaherty VOLUME 6 - Exhibit D-2.1 Continued Workpapers of Witness Flaherty D-2.2 Order of Arkansas Commission conditionally approving the Merger, dated August 13, 1998 *D-3.1 Joint Application of AEP, CSW and SWEPCO before the Louisiana Commission, together with exhibits, appendices and workpapers, dated May 15, 1998 (filed on Form SE) and consisting of: VOLUME 1 - Exhibit D-3.1 Joint Application of SWEPCO, CSW, and AEP for Approval of Proposed Business Combination Testimony and Exhibits of the Following Witnesses: Draper, Shockley, Flaherty, Baker, Munczinski, Roberson, Davis, Hieronymus, Mitchell, Pena, Martin and Bailey VOLUME 2 - Exhibit D-3.1 Workpapers of Witness Roberson Workpapers of Witness Davis 109 110 VOLUME 3 - Exhibit D-3.1 Continued Workpapers of Witness Davis Workpapers of Witness Pena Workpapers of Witness Martin Workpapers of Witness Munczinski VOLUME 4 - Exhibit D-3.1 Workpapers of Witness Flaherty VOLUME 5 - Exhibit D-3.1 Continued Workpapers of Witness Flaherty D-3.2 Order of the Louisiana Commission conditionally approving the Merger, dated July 29, 1999 (to be filed by amendment) *D-4.1 Joint Application of AEP, CSW and PSO before the Oklahoma Commission, together with exhibits, appendices and workpapers, dated August 14, 1998 (filed on Form SE) and consisting of: VOLUME 1 - Exhibit D-4.1 Joint Application of AEP, PSO and CSW regarding Proposed Merger Appendix 1-Statement Required by 17 O.S. sec. 191.3 Appendix 2 -Notice of Hearing Exhibit A - AEP's Corporate Structure and Listing of Affiliate Companies and Business Engaged Exhibit B - Restated Certificate of Incorporation of AEP Exhibit C - Statement of Directors' and Officers' Qualifications Exhibit D - 1997 Summary Report to Shareholders of AEP Exhibit E - Annual Report of AEP on Form 10-K for the Year Ended December 31, 1997 (File No. 1-3525) Exhibit F - Quarterly Report of AEP on Form 10-Q for the Quarter Ended March 31, 1998 (File No. 1-3525) 110 111 Exhibit G - Registration Statement of AEP on Form S-4, Amendment No. 1 (Registration No. 333-50109) VOLUME 2 - Exhibit D-4.1 Direct Testimony and Exhibits of the Following Witnesses: Draper, Shockley, Flaherty, Baker, Munczinski, Roberson, Davis, Hieronymus, Mitchell, Pena, Evans and Bailey VOLUME 3 - Exhibit D-4.1 Workpapers of Witness Flaherty VOLUME 4 - Exhibit D-4.1 Continued Workpapers of Witness Flaherty Workpapers of Witness Munczinski Workpapers of Witness Roberson VOLUME 5 - Exhibit D-4.1 Workpapers of Witness Davis VOLUME 6 - Exhibit D-4.1 Continued Workpapers of Witness Davis Workpapers of Witness Pena Workpapers of Witness Evans D-4.2 Order of Oklahoma Commission conditionally approving the Merger, dated May 11, 1999 *D-5.1 Joint Application of AEP, CSW and PSO before the Texas Commission, together with exhibits, appendices and workpapers, dated April 30, 1998 (filed on Form SE) and consisting of: VOLUME 1 - Exhibit D-5.1 Petition of CSW and AEP Direct Testimony and Exhibits of the Following Witnesses: Draper, Shockley, Flaherty, Baker, Munczinski, Roberson, Davis, Hieronymus, Mitchell, Pena, Evans and Bailey VOLUME 2 - Exhibit D-5.1 Workpapers of Witness Flaherty 111 112 VOLUME 3 - Exhibit D-5.1 Workpapers of Witness Roberson Workpapers of Witness Davis Workpapers of Witness Pena Workpapers of Witness Evans *D-5.2 Direct Testimony, Supplemental Direct Testimony and Second Supplemental Direct Testimony before the Texas Commission, January 15, 1999 (filed herewith on Form SE) and consisting of: Transmittal Letter dated January 15, 1999 Supplemental and Direct Testimonies and Exhibits of the Following Witnesses: Hieronymus, Jones, Mitchell, Roberson D-5.3 Stipulation and Agreement between the Public Utility Commission of Texas General Counsel, the State of Texas (in its capacity as a consumer of electricity), the Texas Industrial Energy Consumers, Low Income Intervenors, the Office of Public Utility Counsel, and the Steering Committee of the Cities of McAllen, Corpus Christi, Victoria, Abilene, Big Lake, Vernon and Paducah. *D-6.1 Application for Transfers of Control Regarding Operating License No. NPF-76 and NPF-80 for the South Texas Project, dated June 19, 1998 D-6.2 Order Approving Application for Transfers of Control Regarding Operating License No. NPF-76 and NPF-80 for the South Texas Project, Docket Nos. 50-498, 499 (issued Nov. 5, 1998). D-7.1 Order of Kentucky Commission conditionally approving the Merger, dated May 24, 1999 D-8.1 Order of Indiana Commission conditionally approving the Merger, dated April 26, 1999 D-9.1 Application for Transfer of License, dated July 29, 1999 (to be filed by amendment) *E-1 Map of AEP service area, major transmission lines and interconnection points (filed on Form SE) *E-2 Map of CSW service area, major transmission lines and interconnection points (filed on Form SE) *E-3 Map of transmission lines showing the 250 MW Contract Path linking the Combined System (filed on Form SE) *E-4 AEP corporate chart (filed on Form SE) 112 113 *E-5 CSW corporate chart (filed on Form SE) *E-6 Combined Company corporate chart after the Merger (filed on Form SE) F-1 Opinion of Counsel (to be filed by amendment) F-2 Opinion of Counsel (to be filed by amendment) F-1-1 Past-tense Opinion of Counsel (to be filed by amendment) F-2-1 Past-tense Opinion of Counsel (to be filed by amendment) *G-1 Annual Report of AEP on Form 10-K for the year ended December 31, 1997, as amended, (File No. 1-3525) and incorporated herein by reference *G-2 Quarterly Report of AEP on Form 10-Q for the quarter ended March 31, 1998 (File No. 1-3525) and incorporated herein by reference *G-3 Quarterly Report of AEP on Form 10-Q for the quarter ended June 30, 1998 (File No. 1-3525) and incorporated herein by reference *G-4 Annual Report of CSW on Form 10-K for the year ended December 31, 1997 (File No. 1-1443) and incorporated herein by reference *G-5 Quarterly Report of CSW on Form 10-Q for the quarter ended March 31, 1998 (File No. 1-1443) and incorporated herein by reference *G-6 Quarterly Report of CSW on Form 10-Q for the quarter ended June 30, 1998 (File No. 1-1443) and incorporated herein by reference *G-7 AEP Consolidated Balance Sheet as of June 30, 1998 (incorporated by reference to the Quarterly Report on Form 10-Q of AEP for the quarterly period ended June 30, 1998 (File No. 1-3525) *G-8 Combined Company Unaudited Pro Forma Combined Balance Sheet at June 30, 1998 *G-9 AEP Statement of Income for the period ended June 30, 1998 (incorporated by reference to the Quarterly Report on Form 10-Q of AEP for the quarterly period ended June 30, 1998 (File No. 1-3525) *G-10 Combined Company Unaudited Pro Forma Combined Statement of Income for the twelve-month period ended June 30, 1998 *G-11 Combined Company Unaudited Pro Forma Combined Statement of Retained Earnings for the twelve-month period ended June 30, 1998 *G-12 CSW Consolidated Balance Sheet as of June 30, 1998 (incorporated by reference to the Quarterly Report on Form 10-Q of CSW for the quarterly period ended June 30, 1998 (File No. 1-1443) 113 114 *G-13 CSW Consolidated Statement of Income as of June 30, 1998 (incorporated by reference to the Quarterly Report on Form 10-Q of CSW for the quarterly period ended June 30, 1998) (File No. 1-1443) *G-14 CSW Consolidated Statement of Income for the fiscal years ended December 31, 1997, 1996 and 1995 (incorporated herein by reference to the Annual Report of CSW on Form 10-K for the year ended December 31, 1997 (File No. 1-1443) G-15 Annual Report of AEP on Form 10-K for the year ended December 31, 1998 (File No. 1-3525) and incorporated herein by reference G-16 Quarterly Report of AEP on Form 10-Q for the quarter ended March 31, 1999 (File No. 1-3525) and incorporated herein by reference G-17 Annual Report of CSW on Form 10-K for the year ended December 31, 1998 (File No. 1-1443) and incorporated herein by reference G-18 Quarterly Report of CSW on Form 10-Q for the quarter ended March 31, 1999 (File No. 1-1443) and incorporated herein by reference *H Proposed Form of Notice *I-1 CSWS Authorizations *I-2 Short-Term Borrowing Program *I-3 CSW Credit Authorizations *I-4 CSW Guarantee Authorizations *J Tax Basis Discussion K Agreement between Applicants and International Brotherhood of Electrical Workers * Previously filed. ITEM 7. INFORMATION AS TO ENVIRONMENTAL EFFECTS The Merger neither involves "major federal actions" nor "significantly [affects] the quality of the human environment" as those terms are used in Section (2)(C) of the National Environmental Policy Act, 42 U.S.C. Sec. 4332. The only federal actions related to the Merger pertain to the Commission's declaration of the effectiveness of the Registration Statement, the approvals and actions described under Item 4 and Commission approval of this Application-Declaration. Consummation of the Merger will not result in significant changes in the operations of public utilities of the AEP or CSW Systems or have any significant impact on the environment. Apart from the Application for Transfers of Control Regarding Operating License No. NPF-76 and NPF-80 in connection with the STP, no federal agency is preparing an environmental impact statement with respect to this matter. 114 115 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. By: /s/ A. A. Pena ------------------------------------------- Treasurer CENTRAL AND SOUTH WEST CORPORATION By: /s/ Wendy G. Hargus ------------------------------------------- Treasurer Dated: August 19, 1999 115 EX-99.D.1.3 2 STIPULATION OF AMERICAN ELECTRIC POWER CO. 1 Exhibit D-1.3 UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION American Electric Power Company, Inc. ) Docket Nos. EC98-40-000 And ) ER98-2770-000 Central and South West Corporation ) ER98-2786-00 STIPULATION OF AMERICAN ELECTRIC POWER COMPANY, INC. CENTRAL AND SOUTH WEST CORPORATION AND COMMISSION TRIAL STAFF For the purposes of evaluating the justness and reasonableness of the System Integration Agreement, the Transmission Reassignment Tariff and the System Transmission Integration Agreement proposed by American Electric Power Company, Inc. ("AEP") and Central and South West Corporation ("CSW")(collectively "Applicants"), the Applicants and the Trial Staff hereby enter into this Stipulation. This Stipulation resolves all issues between Applicants and the Trial Staff regarding the System Integration Agreement, the Transmission Reassignment Tariff and the System Transmission Integration Agreement in the above-referenced consolidated dockets ("this proceeding"), except the pricing of system energy exchanges under the System Integration Agreement. Applicants and the Trial Staff stipulate and agree as follows: I. SYSTEM INTEGRATION AGREEMENT (SIA) A. ARTICLE 7.3 OF THE SYSTEM INTEGRATION AGREEMENT WILL BE MODIFIED TO READ AS FOLLOWS: Whenever either the AEP East Zone or the AEP West Zone has surplus capacity relative to is 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. 2 B. THE FOLLOWING DEFINITIONS WILL BE ADDED TO THE SYSTEM INTEGRATION AGREEMENT: 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. 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. Owned General 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. C. THE FOLLOWING PROVISION WILL BE ADDED TO THE TEXT AT THE END OF PARAGRAPH A2 OF SERVICE SCHEDULE A: 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 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. D. ALLOCATION OF TRADING MARKET REALIZATIONS Add as the last two sentences to Service Schedule D, Paragraph D3 -- Allocation of Trading and Marketing Realizations, the following language: "This allocation of trading market realization shall be in effect until the last day of the fifth full calendar year following the consummation of the merger. At least sixty days prior to the day specified in the preceding sentence, Agent shall file with the -2- 3 FERC under Section 205 of the Federal Power Act the methodology to allocate trading market realizations thereafter, supported by evidence demonstrating the justness and reasonableness of the filed methodology." E. PRICING OF SYSTEM ENERGY EXCHANGES Applicants and Trial Staff agree that the issue of pricing for system energy exchanges pursuant to Service Schedule C would be most efficiently addressed as a policy issue briefed directly to the Commission. Accordingly, it is the intention of Applicants and Trial Staff that each will present their position on this aspect of the System Integration Agreement directly to the Commission for resolution and that the issue need not be addressed by the Presiding Judge. II. TRANSMISSION REASSIGNMENT TARIFF (TRT) A. TERMINATION PROVISIONS The words "in accordance with Commission regulations" will be added after the word "Agreement" in the first line of Section 3.3 of the Form of Service Agreement. B. REFUNDS FOR RECALLED TRANSMISSION CAPACITY Article III.D. shall be modified to include the following sentence at the end: The availability of refunds for service sold under this Transmission Reassignment Tariff shall be covered in the Service Agreement, or, for short-term transactions, in the umbrella Service Agreement, between AEP and the Eligible Customer purchasing the reassigned transmission capacity. C. EFFECT OF TARIFF TERMINATION Amend Section IV.C of the Transmission Reassignment Tariff by adding this sentence to the end: "A notice of termination of this tariff by Reseller shall 1) terminate Reseller's obligation to provide service under any new Service Agreement or provide new transactions under an umbrella Service Agreement immediately and 2) eliminate all tariff obligations at the time that the last remaining service arrangement initiated prior to the notice of termination is completed." III. SYSTEM TRANSMISSION INTEGRATION AGREEMENT (STIA) The following sentence from Part A2 of Service Schedule A in the System Transmission Integration Agreement, When new Transmission Facilities are acquired or installed after the effective date of the Agreement to meet the Combined System's requirements, the associated costs shall be allocated between the AEP East Zone and AEP West Zone in -3- 4 proportion to the amount of new Transmission Facilities required in each zone, as determined by the Agent. will be deleted and replaced by: Likewise, the operating companies in the AEP East Zone and the operating companies in the AEP West Zone each shall have full responsibility for all costs relating to new Transmission Facilities they may acquire or install in their respective zones after the effective date of the Agreement which do not create a direct linkage between the AEP East and West Zones. When new Transmission Facilities are acquired or installed after the effective date of the Agreement to further integrate the AEP East and West Zones, the associated costs shall be allocated equally between the AEP East Zone and AEP West Zone. IV. GENERAL PROVISIONS Applicants and the Trial Staff shall support this Stipulation in all proceedings before this Commission, and based on this Stipulation, Applicants and the Trial Staff shall support a finding that the above-mentioned agreements, as modified by this stipulation, are just and reasonable. Applicants and the Trial Staff further agree that neither will challenge any presentation by a signatory to this stipulation with respect to the matters at issue in this proceeding, so long as such presentation is in accord with this Stipulation, and that each will support this Stipulation as a resolution of the matters addressed herein as consistent with the requirements of the Federal Power Act. Each party shall be free to argue, in response to challenges by other parties, that this Stipulation is justified as a compromise of more favorable positions or principles that such party supported, but neither party may ask the Commission to vary from this Stipulation for purpose of this proceeding. This Stipulation is not intended to bind any party that is not a signatory hereto, and is not intended to set a precedent for future cases or to bind any party in any further proceeding with respect to any matter set forth herein. No term in this Stipulation may be modified without the express written consent of all signatories. /s/ James A. Pepper /s/ J.A. Bouknight James A. Pepper J.A. Bouknight, Jr. Commission Trial Staff Counsel for American Electric Power Company, Inc. /s/ Clark Evans Downs Clark Evans Downs Counsel for Central and South West Corporation -4- 5 UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION American Electric Power Company, Inc. ) Docket Nos. EC98-40-000 And ) ER98-2770-000 Central and South West Corporation ) ER98-2786-000 STIPULATION OF AMERICAN POWER COMPANY, INC., CENTRAL AND SOUTH WEST CORPORATION AND COMMISSION TRIAL STAFF For the purposes of evaluating the consistency of the merger proposed by American Electric Power Company, Inc. ("AEP") and Central and South West Corporation ("CSW")(collectively "Applicants") with the public interest and for evaluating the rates proposed by the Applicants for transmission and ancillary services for post merger operations, Applicants and the Trial Staff hereby enter into this Stipulation. This Stipulation resolves all issues between Applicants and the Trial Staff regarding the matters set for hearing in the above-referenced consolidated dockets ("this proceeding") except for the issues pertaining to system integration agreements and ratepayer protection. In addition, a question related to the timing of divestiture will be resolved by direct presentation to the Commission, as described below. Applicants and the Trial Staff stipulate and agree as follows: I. RATES The rates identified in Attachment A to this Stipulation shall be placed into effect as of the date on which the merger is consummated. Notwithstanding the foregoing, the Applicants shall have the right to tender for filing pursuant to section 205 of the Federal Power Act changes in any or all of 6 the rates identified in Attachment A and to seek an effective date on or after the date on which the merger is consummated. II. REGIONAL TRANSMISSION ORGANIZATION A. Prior to consummation of the merger AEP will file with the Federal Energy Regulatory Commission ("FERC") a proposal to transfer to a regional transmission organization ("RTO") the operation and control of bulk transmission facilities owned, controlled, and/or operated by AEP in Indiana, Michigan, Kentucky, Ohio, Tennessee, Virginia and West Virginia ("AEP East"). In addition, Applicants reconfirm the commitments made in paragraph 7A of the Stipulation and Agreement attached to the order of the Indiana Utility Regulatory Commission dated April 26, 1999 in Cause No. 41210, which paragraph is reproduced in Attachment B to this Stipulation and incorporated herein. B. Prior to December 31, 2000, AEP will file with the FERC an unconditional application to transfer the operation and control of bulk transmission facilities owned, controlled and/or operated by AEP and currently located in the Southwest Power Pool ("AEP West") to a FERC-approved RTO directly interconnected with the AEP West transmission facilities. Such transfer of operations shall be consistent with the applicable RTO. The above date shall be extended, if necessary, to 75 days after FERC issues an order on an RTO to which AEP is a signatory that is filed before June 30, 2000. C. If AEP meets its commitments pursuant to provision A in a manner other than joining the Midwest ISO, the provisions of the following paragraphs C.1., C.2., C.3. shall 7 apply. If AEP meets its commitments pursuant to provision A by joining the Midwest ISO, then only paragraph C.2. shall apply. 1. For AEP East, AEP will provide generation dispatch information necessary for the Midwest ISO to monitor the effect of such dispatch on the loading of the Midwest ISO's constrained transmission facilities. The Midwest ISO, in consultation with AEP, shall determine the format, quantity, and timing of the data submissions necessary to perform such monitoring. The information provided by AEP shall be subject to appropriate confidentiality provisions. AEP's obligation to submit such data shall be effective at such time as the Midwest ISO has procedures in place to assure that there is no disclosure of company-specific information or contemporaneous data. 2. For AEP East, AEP agrees to transfer functions relating to transmission service, transmission security and control area responsibility, as described in Attachment C, to the FERC-approved RTO to which it transfers operation and control of its bulk transmission facilities pursuant to provision A. AEP will transfer these functions by leasing and/or selling the present AEP System Control Center ("SCC") site and facilities to the RTO, and providing the present SCC employees the opportunity to transfer to the RTO with all the financial conditions necessary to create independence from AEP. AEP's transfer of such functions shall be conditional on: a) the RTO, in consultation with AEP, determining that the RTO has the capability to accept responsibility for these functions; 8 b) systems being in place for AEP to retain economic dispatch and automatic general control ("AGC") functions and allow separation for wholesale transaction billing; c) the RTO, in consultation with AEP, developing guidelines and procedures whereby the Area Control Error ("ACE") values calculated and communicated by the RTO to AEP are combined with AEP's own economic dispatch values to permit AEP to directly pulse its generating units under AGC; and d) transmission functions other than those listed in Attachment C to this Stipulation being transferred to other AEP regional facilities. 3. AEP commits to participate in ancillary services and balancing markets developed by the RTO or an RTO-authorized Regional Power Exchange. AEP will bid to redispatch generators consistent with bidding requirements established by the RTO for all parties that control the dispatch of generating facilities taking service from the RTO. 9 III. INTERIM TRANSMISSION PROVISION A. It is AEP's position that it currently is, and at all times has been, in compliance with all applicable requirements with respect to the provision of transmission service, including its open access transmission tariff. AEP's agreement to the following conditions shall not be construed as evidence of or an admission that its current or historical practices are or have been in violation of any such applicable requirement. 1. AEP will file for a declaratory order that its "flexible point-to-point" service is permitted under AEP's Open Access Tariff or other transmission service agreements on file with the Commission. 2. AEP will post on OASIS the status of all AEP East transmission facilities, including planned maintenance, for the period of the ATC postings. B. AEP will follow ECAR Security Coordinator procedures for posting transmission loading relief ("TLR") logs. IV. DIVESTITURE Applicants and Trail Staff agree that the Applicants will divest the Frontera and Northeastern Units 3 and 4 as proposed in the testimony of Witness Stephen B. Jones, with a buy-back condition and the presentation of one reserved issue. The divestiture requirement must not infringe upon AEP-West's ability to serve native load. The divestiture proposal should include a buy-back clause such that AEP West can purchase the firm power it needs to serve native load. 10 The reserved issue will be presented directly to the Commission for decision based on the comments on this settlement submitted by the participants in this proceeding. Specifically, the Commission's Trial Staff, the Applicants, and other parties shall have the right to address in comments whether the Commission should order an immediate divestiture of these facilities or whether the divestiture should occur under both the conditions stated in Witness Jones' testimony and the additional conditions incorporated in the stipulation entered into in the proceeding before the Oklahoma Corporation Commission, Cause No. PUD 980000444, dated April 16, 1999 and attached as Attachment D to this Stipulation. These additional conditions are contained in Section 7, third paragraph of the stipulation and require an informational filing before the Oklahoma Corporation Commission should the conditions proposed by the Applicants in this FERC proceeding be changed. Trial Staff and the Applicants agree that the question of whether immediate divestiture should be required should be presented to the Commission in light of two questions. The first question is whether it is appropriate to permit the timing of the divestiture to occur so as to assure that pooling of interests accounting not be jeopardized. The second question is whether a change in the timing for the divestiture for Northeastern Units 3 and 4 is consistent with the deference that the Commission should provide to the Oklahoma Corporation Commission's determination as to the conditions necessary to protect the interests of Applicants' Oklahoma retail customers. Trial Staff and Applicants further agree to limit their comments in support of their position on this reserved issue to the two questions stated in this paragraph. Applicants reserve the right to address other arguments raised in the comments of other parties that assert other bases to accelerate the timing of the divestiture of the Frontera and Northeastern Units 3 and 4. 11 Applicants agree that the conditions of sale for Northeastern Units 3 and 4 will provide that the purchaser(s) of the units shall be guaranteed that planned (maintenance) outage schedules shall be made only with the mutual consent of the merged company and the purchaser(s). V. APPLICANTS' WAIVER OF TRANSMISSION PRIORITY In addition to the waiver of transmission priorities otherwise available to Applicants that is contained in the testimony of Witness Stephen B. Jones, Applicants further agree that they will not assert the "AES/TVA" priority for any transfers of energy from AEP West to AEP East for a period of four years from the date of the consummation of the merger. VI. LOSSES AND LOSS COMPENSATION SERVICE A. The Real Power Loss Factor stated in Sections 15.7 and 28.5 of the post merger AEP open access transmission tariff ("Tariff") shall be 3.3% for AEP East and shall be 2.9% for AEP West. B. The following sentence shall be added after the second sentence of SCHEDULE 20 of the Tariff regarding Loss Compensation Service: "Charges for Loss Compensation Service shall be pursuant to rates negotiated between the Transmission Customer and the Transmission Provider." C. The following sentence shall be added after the first sentence of SCHEDULES 7 and 8 of the Tariff regarding Firm and Non-Firm Point-to-Point Transmission Service: "Capacity Reservations at the Point(s) of Receipt will be inclusive of transmission losses, unless the Transmission Customer opts to deliver energy to compensate for losses at a different point pursuant to another capacity reservation." 12 VII. GENERAL PROVISIONS Applicants and Trial Staff shall support this Stipulation in all proceedings before this Commission, and based on this Stipulation, Trial Staff shall support a finding that the merger will have no adverse effect on competition. Applicants and the Trial Staff further agree that neither will challenge the other party's presentation with respect to the matters at issue in this proceeding, so long as such presentation is in accord with this Stipulation, and that each will support this Stipulation as a resolution of the matters addressed herein as consistent with the requirements of the Federal Power Act. Each party shall be free to argue, in response to challenges by other parties, that this Stipulation is justified as a compromise of more favorable positions or principles that such party supported, but neither party may ask the Commission to vary from this Stipulation for purpose of this proceeding. This Stipulation is not intended to bind any party that is not a signatory hereto, and is not intended to set a precedent for future cases or to bind any party in any further proceeding with respect to any matter set forth herein. No term in this Stipulation may be modified without the express written consent of both parties. /s/James A. Pepper /s/J.A. Bouknight - ------------------- ------------------------ James A. Pepper J.A. Bouknight, Jr. Commission Trial Staff Counsel for American Electric Power Company, Inc. /s/Clark Evans Downs -------------------------- Clark Evans Downs Counsel for Central and South West Corporation
May 24, 1999 13 ATTACHMENT A Settlement Rates ---------------- Transmission and Ancillary Services ----------------------------------- All values in $/MW-mo. unless otherwise stated AEP East - -------- Transmission: Point to Point Firm $1,420.00 Network $349,712,000 Net Annual Revenue Requirement Rolling 12 CP Load Ratio Share
Ancillary Services Purch.% Gen. Unit Cap. Rate Monthly Rates - ------------------ ------- ------------------- ------------- Sch. 1 $57.71 Sch. 2 $73.00 Sch. 3 1.0% $5,300 $53.00 Sch. 5 1.5% $5,300 $79.50 Sch. 6 1.5% $5,300 $79.50
AEP West - -------- Transmission Point to Point Firm $1,050.00 Network $162,036,000 Net Annual Revenue Requirement Summer 4CP Load Ratio Share
Ancillary Services Purch.% Gen. Unit Cap. Rate Monthly Rates - ------------------ ------- ------------------- ------------- Sch. 1 $ 30.00 Sch. 2 $ 48.05 Sch. 3A SPP 1.2% $2,609 $ 31.31 EROCT 1.1% $2,445 $ 26.90 Sch. 3B SPP * $2,609 ERCOT * $2,445 Sch. 5 SPP 2.1% $3,482 $ 73.12 ERCOT 5.9% $3,121 $184.14 Sch. 6 SPP 2.1% $3,487 $ 72.80 ERCOT 5.9% $3,121 $164.14
* Load Following Purchase Obligation equals the difference between actual load measured on 15-minute intervals and the hourly scheduled delivery. 14 AEP and CSW Companies Term Sheet on Settlement Rates ER98-2766-000
REACTIVE REGULATION SPINNING SUPPLEMENTAL TRANSMISSION SCHEDULING SUPPLY SERVICE RESERVE RES. DESCRIPTION SERVICE SCHEDULE 1 SCHEDULE 2 SCHEDULE 3 SCHEDULE 5 SCHEDULE 6 - ---------------------------------------------------------------------------------------------------------------------------- AEP EAST ZONE AREA: - ---------------------------------------------------------------------------------------------------------------------------- Net Annual Revenue Requirement $349,712,000 $14,212,586 $17,978,148 - ---------------------------------------------------------------------------------------------------------------------------- Monthly Service Rate ?????? Mo. 1,420.00 67.71 73.00 63.00 79.50 79.50 - ---------------------------------------------------------------------------------------------------------------------------- Weekly Service Rate $???? 326.79 13.26 16.90 12.20 18.30 18.30 - ---------------------------------------------------------------------------------------------------------------------------- Daily On-Peak Service Rate 65.35 1.69 3.30 2.44 3.66 3.66 - ---------------------------------------------------------------------------------------------------------------------------- Hourly On-Peak Service Rate $?? 4.09 0.08 0.21 0.15 0.23 0.23 - ---------------------------------------------------------------------------------------------------------------------------- Daily-Off Peak Service Rate $??? DAY 49.68 1.89 2.40 1.74 2.61 2.61 - ---------------------------------------------------------------------------------------------------------------------------- Hourly Off-Peak Service Rate $??? 1.95 0.08 0.10 0.07 0.11 0.11 - ---------------------------------------------------------------------------------------------------------------------------- Cost of Generating Capacity $??? Mo. 5,300.00 5,300.00 5,300.00 - ---------------------------------------------------------------------------------------------------------------------------- Requirement per MW of load(1) 1.0% 1.5% 1.5% - ---------------------------------------------------------------------------------------------------------------------------- AEP WEST ZONE Spp-Reg. & 1F Spinning Res. Supplemental Res. - ---------------------------------------------------------------------------------------------------------------------------- Net Annual Revenue Requirement $162,005,000 4,629,600 1,415,076 - ---------------------------------------------------------------------------------------------------------------------------- Monthly Service Rate $????-Mo. 1,050.00 30.00 48.05 31.31 73.12 72.60 - ---------------------------------------------------------------------------------------------------------------------------- Weekly Service Rate $?????-Wk. 241.94 0.90 11.08 7.20 16.83 16.75 - ---------------------------------------------------------------------------------------------------------------------------- Annual Service Rate $?????-Yr. 48.33 0.99 2.21 1.44 3.37 3.85 - ---------------------------------------------------------------------------------------------------------------------------- Hourly On-Peak Service Rate $?? 3.02 0.04 0.14 0.39 0.21 0.21 - ---------------------------------------------------------------------------------------------------------------------------- Daily Off-Peak Service Rate $???-Day 34.52 0.99 1.50 1.02 2.40 2.39 - ---------------------------------------------------------------------------------------------------------------------------- Hourly Off-Peak Service Rate$? 1.44 0.04 0.07 0.04 0.10 0.10 - ---------------------------------------------------------------------------------------------------------------------------- Cost of Generating Capacity $???-Mo. Sch 3-A&B 2,609.00 3,482.00 3,467.00 - ---------------------------------------------------------------------------------------------------------------------------- Requirement per MW of Loan(1) 3A=1.2% 2.1% 2.1% - ----------------------------------------------------------------------------------------------------------------------------
15
$8=15min AEP WEST ZONE ERCOT - REG. RESPONSE R ADD 1 RESP. RES. Monthly Service Rates $????-Mo. 26.90 154.14 184.14 Weekly Service Rates $????-Wk. 6.19 42.38 42.38 Daily On-Peak Service Rate $???-Day 1.24 8.48 8.48 Hourly On-Peak Service $???? 0.08 0.53 0.53 Daily Off-Peak Service Rate $???-Day 0.58 6.05 6.06 Hourly Off-Peak Service Rate $? 0.4 0.25 0.25 Cost of Generating Capacity $/??-Mo. Sch.3-A&B 3,121.00 3,121.00 2,446.00 Requirement per MW of load(1) 3A=1.1%, 5.9% 5.9% 3B=15 min.
(1) Purchase Obligation in % of reserved capacity for Schedules 3A, 5 & 6. Schedules 3B in SPP and ERCOT defines Load Following billing determined as the largest difference between the maximum load each hour, measured over 15-minute intervals, and the hourly scheduled delivery. 16 ATTACHMENT B 7. REGIONAL TRANSMISSION ORGANIZATION. A. Prior to December 31, 2000, AEP will file with the FERC an unconditional application, consistent with the RTO agreement and tariff to transfer the operation and control of its bulk transmission facilities in Indiana, Michigan, Kentucky, Ohio, Tennessee, Virginia and West Virginia owned, controlled and/or operated by AEP to the Midwest Independent Transmission System Operator, Inc. or another FERC-approved Regional Transmission Organization directly interconnected with AEP transmission facilities. Provided that, if, by June 30, 2000, there is pending before the FERC for approval an RTO to which AEP is a signatory that includes two or more directly interconnected control areas, at least one of which is not affiliated with AEP, the December 31, 2000 date shall be extended to the date that is 75 days after the date on which the FERC issues an order either approving or disapproving the RTO. 17 ATTACHMENT C 1. TRANSMISSION SERVICE FUNCTIONS A. The RTO will administer AEP's Open Access Transmission Tariff and any succeeding RTO Tariff as follows: 1. When the RTO, in consultation with AEP, determines that it is capable of centrally calculating ATCs on data partially or totally developed by the RTO it will calculate and post ATCs on OASIS. 2. The RTO will assume responsibility for transmission service contracts. 3. When the RTO determines, in consultation with AEP, that it is capable of performing the function, the RTO will manage the single OASIS site for the AEP System. 4. When the RTO determines, in consultation with AEP, that it is capable of performing the function, it will have the sole authority to receive, evaluate, and approve or deny all transmission service requests on the AEP System. 5. The RTO will offer to provide losses and ancillary services and verify customer self-provision of such services. 6. The RTO will perform settlement/billing for transmission service and ancillary services. B. The RTO will return revenues to AEP, and/or allocate revenue to AEP and other RTO transmission owners, as applicable. II. TRANSMISSION SECURITY FUNCTIONS A. The RTO will perform the role of NERC Security Coordinator. 18 B. The RTO will perform congestion management. C. The RTO will approve transmission maintenance requests and outages. III. CONTROL AREA FUNCTIONS A. When the RTO, in consultation with AEP, determines that it is capable of performing the function, the RTO will be the single entity with responsibility to schedule energy transactions over approved transmission reservation paths. B. The RTO will coordinate and participate in time corrections. C. The RTO will assure the maintenance of NERC/ECAR operating reserves. D. The RTO will maintain load-generator balances (Control Area Regulation) by sending ACE signals to generating companies or independent generators that have contracted to provide regulation. E. The RTO will perform check out (after-the-fact) of energy MWH transactions with other control areas, and perform inadvertent accounting. 19 ATTACHMENT D SECTION 7. MITIGATION. To mitigate any perceived impacts of the merger on the Applicants' market power, the Applicants have proposed in their FERC merger application a mitigation plan which includes the following: (1) Divestiture of 300 megawatts of coal-fired generating capacity at the Northeastern generating plant after such plant is no longer required to meet PSO's native load demand requirements subsequent to industry restructuring in Oklahoma. (2) Sale of 300 megawatts per hour of energy on an interim basis prior to the divestiture of the Northeastern capacity. (3) Waiver of PSO's priority to the use of CSW interfaces with other transmission systems to import centrally dispatched energy from the existing AEP system in excess of 250 megawatts. (4) Waiver of PSO's priority to the use of CSW interfaces to import non-firm energy from non-affiliates. (5) Schedule CSW's use of the two high voltage direct current (HVDC) ties between ERCOT and the SPP on a first-in-time basis for certain transactions. The Applicants commit to hold PSO Oklahoma retail customers harmless from adverse impacts from these transactions. Attachment 4 to this agreement describes the methodology that the Applicants will follow in order to hold PSO Oklahoma retail customers harmless from adverse effects of the interim mitigation sale. EX-99.D.2.2 3 ORDER OF AR APPROVING THE MERGER 1 Exhibit D-2.2 ARKANSAS PUBLIC SERVICE COMMISSION IN THE MATTER OF THE JOINT APPLICATION OF ) AMERICAN ELECTRIC POWER COMPANY, INC., ) SOUTHWESTERN ELECTRIC POWER COMPANY, ) AND CENTRAL AND SOUTH WEST ) DOCKET NO. 98-172-U CORPORATION FOR APPROVAL OF MERGER ) ORDER NO. 9 ORDER On June 12, 1998, American Electric Power Company, Inc. ("AEP"), Central and South West Corp. ("CSW"), and Southwestern Electric Power Company ("SWEPCO") (collectively, "Applicants") filed an application in this docket for approval of a proposed merger of AEP and CSW, the holding company which owns SWEPCO. In connection with the merger, Applicants requested approval of their proposed regulatory plan ("PRP"), which would set forth the regulatory and rate treatment of merger-related benefits and costs for SWEPCO in Arkansas. The application was supported by the pre-filed Direct Testimony and Exhibits of Applicants' witnesses Richard E. Munczinski, J. Craig Baker, Thomas J. Flaherty, R. Russell Davis, Armando A. Pena, Thomas V. Shockley, Thomas E. Mitchell, William H. Hieronymus, Mark A. Bailey, Karen C. Martin, Mark D. Roberson, and Dr. E. Linn Draper. On June 12, 1998, the Commission issued Order No. 1 in this docket establishing a procedural schedule, with a hearing date of July 13, 1998. On June 26, 1998, Applicants and the General Staff of the Commission ("Staff") filed their Joint Motion to Defer Consideration of the Regulatory Plan and to Establish a Procedural Schedule. The Commission granted the joint motion by its Order No. 4, dated July 1, 1998. The procedural schedule was subsequently amended by Order No. 7, dated September 9, 1998. 2 DOCKET NO. 98-172-U PAGE 2 On August 13, 1998, the Commission issued its Order No. 5, approving the merger subject to certain conditions, including the Commission's findings and orders with respect to the PRP. Order No. 6, dated August 19, 1998, corrected certain errors in Order No. 5. In accordance with the procedural schedule established in Order No. 7, Staff filed on October 23, 1998, the Testimony and Exhibits of Alice D. Wright, J. Bret Franks, and Mark Witkowski addressing certain aspects of the PRP. On November 3, 1998, Applicants and Staff filed a Regulatory Plan Stipulation and Agreement ("RSPA") executed by Applicants and Staff and a Joint Motion to Accept the Regulatory Plan Stipulation and Agreement and to Cancel the Remaining Testimony Filing Dates. On November 4, 1998, Order No. 8 canceled the remaining testimony filing dates and directed that the RSPA be considered at the public hearing previously scheduled for December 1, 1998. The Commission further ordered the parties to file testimony in [TEXT MISSING] On December 1, 1998, a public hearing was held to consider the RPSA. Although invited, no public comment was offered. The testimony and exhibits of Applicants' witnesses Munczinski, Baker, Flaherty, and Davis were entered into the record, as were the testimony and exhibits of Staff witnesses Witkowski, Wright and Franks. In support of the RPSA, Mr. Munczinski testified that the RPSA, together with the stipulation approved by Orders No. 5 and 6, provides a fair sharing of the merger's benefits between SWEPCO's Arkansas customers and the Applicants. Mr. Munczinski noted that the RPSA provides for five years of annual rate reductions as well as a direct pass-through of merger-related fuel savings. He additionally noted that the RPSA does not preclude the Commission from pursuing other rate actions it may deem appropriate or affect the terms and conditions of the stipulation approved in Orders No. 5 and 6. Finally, Mr. Munczinski testified 3 DOCKET NO. 98-172-U PAGE 3 that the RPSA holds Arkansas retail customers harmless from unforeseen events that materially diminish the estimated benefits of the merger and from major deviations from those estimates, including any negative effects of merger-related market power mitigation measures. In response to questions from Staff counsel, Mr. Munczinski provided further details of his understanding of the Applicants' commitments to SWEPCO's Arkansas retail customers T. 219-24. Staff witness Mr. Witkowski also testified in support of the RPSA. Mr. Witkowski pointed out that the RPSA provided specific rate benefits through its rate reduction rider. Those benefits will continue for at least five years and potentially beyond that period. The rate reduction will begin at $685,000 in the first year and increase each year to $1,541,000 in year five. Mr. Witkowski testified that the RPSA provides a better match of merger savings with costs than would the PRP and noted that the RPSA also insulates Arkansas ratepayers from certain merger-related costs. He added that Paragraph 7 of the stipulation approved by Orders No. 5 and 6 provided additional protection to Arkansas ratepayers by requiring that they receive any additional benefits or conditions imposed by order of any other jurisdiction. Mr. Witkowski concluded that the RPSA, in conjunction with the conditions imposed by Orders No. 5 and 6 adequately protect ratepayers and provide equitable merger benefits for ratepayers and shareholders. The Commission finds that the RPSA represents a fair and reasonable sharing of merger benefits and costs between Arkansas' SWEPCO customers and Applicants' shareholders and is in the public interest. This finding is based on the evidence discussed above, including, specifically, the testimony of Mr. Munczinski in response to questions from Staff counsel and the condition that Applicants accept the representations therein. In conjunction with the conditions specified in Orders No. 5 and 6 and the agreement approved therein, the RPSA should provide 4 DOCKET NO. 98-172-U PAGE 4 adequate protection to Arkansas ratepayers from the potential for merger-related detriment. Nevertheless, there remains the possibility of adverse merger-related effects resulting from decisions in other jurisdictions, particularly at the federal level. The RPSA is thus conditionally approved, pending final action by other relevant authorities. Applicants are directed to continue to file with this Commission copies of all final, non-appealable orders from other jurisdictions related to their proposed merger. BY ORDER OF THE COMMISSION This 17th day of December, 1998. /s/ Lavenski R. Smith, Chairman /s/ Sam I. Bratton, Jr., Commissioner /s/ Julius D. Kearney, Commissioner /s/ Bill Mathis (acting) Jan Sanders Secretary of the Commission 5 BEFORE THE ARKANSAS PUBLIC SERVICE COMMISSION IN THE MATTER OF THE JOINT APPLICATION OF ) AMERICAN ELECTRIC POWER COMPANY, INC., ) SOUTHWESTERN ELECTRIC POWER COMPANY, ) AND CENTRAL AND SOUTH WEST ) DOCKET NO. 98-172-U CORPORATION FOR APPROVAL OF MERGER ) REGULATORY PLAN STIPULATION AND AGREEMENT American Electric Power Company, Inc. ("AEP"), Southwestern Electric Power Company ("SWEPCO"), and Central and South West Corporation ("CSW") (collectively referred to as the "Applicants"), and the General Staff of the Arkansas Public Service Commission ("Staff"), jointly referred to as the "Parties", respectfully submit this Joint Motion stating: 1. The Applicants commit and agree to implement the rate freeze as proposed in their Application and supporting testimony. 2. SWEPCO will implement a net merger savings rider in Arkansas that will reduce rates to customers by the annual amounts shown in Attachment A beginning with the first revenue month after the effective date of the merger. Each individual year's rate reduction will apply for a twelve month period, with the year five reduction continuing to apply in years following the end of year five until new base rates for SWEPCO become effective. The annual rate reduction amounts shown in Attachment A will be allocated to rate classes based upon revenue requirements to be determined in the pending earnings review. At the end of the five year period, cost amortization and shareholder saving imputations shall terminate. 6 DOCKET NO. 98-172-U PAGE 2 3. Costs to achieve the merger are those costs incurred to consummate the merger and combine the operations of AEP and CSW. These costs include, but are not limited to investment banking fees; consulting and legal services incurred in connection with obtaining regulatory and shareholder approvals; transition planning and development costs; employee separation costs including severance costs, change-in-control payments and retraining costs; systems integration costs; operations integration costs including telecommunication costs; and facilities consolidation costs. The costs to achieve the merger are to be recovered through merger savings. For Arkansas retail jurisdictional ratemaking purposes, SWEPCO will defer its share of the lesser of the estimated or actual costs to achieve as incurred over a five year period. These costs will be amortized over a five year period beginning with the effective date of the merger. The amortized cost for each year shall be proportionate to the net merger savings amount reflected in Attachment A for the corresponding year. 4. If changes in retail base rates of SWEPCO in Arkansas occur within the first five years after the effective date of the merger, the following rate treatments will be reflected: (a) Estimated non-fuel operation and maintenance expense merger savings net of costs-to-achieve will be included in cost of service as an allowable expense. The amount to be included in the cost of service shall be based upon the test year period. (b) Amortization costs to achieve will be included in cost of service as an allowable expense. The amount to be included in the cost of service shall be based upon the test year period. The unamortized balance of costs to achieve will not be included in rate base and no return will be allowed on the unamortized balance of costs to achieve. 7 DOCKET NO. 98-172-U PAGE 3 (c) The merger savings rate reduction rider will continue as described in Paragraph 2 above. (d) It is the intent of the Parties that the provisions of this Paragraph 4 relating to cost amortizations and shareholder savings imputation in the event of a base rate proceeding will terminate five years after the effective date of the merger. (e) Attachment B is an example of the retail base rate treatment described in this section. 5. If the electric utility industry in Arkansas is restructured prior to the end of the fifth year after the effective date of the merger, the rider benefits, cost amortization, and shareholder savings imputation should be reduced consistent with the functional segregation of unbundled restructured rates. It is the intent of the Parties that the cost amortizations and shareholder savings imputations would continue for the five year term for those functions subject to continued rate of return regulation. It is also the intent of the Parties that the benefits would continue for the period of time in which the net merger savings rider set forth in Paragraph 2 remains in effect for those functions subject to continued rate of return regulation. 6. All fuel savings shall be passed through to Arkansas retail customers in accordance with SWEPCO's fuel adjustment clause. After consummation of the merger, the Applicants agree to report to the Arkansas Public Service Commission in the monthly full report the amount of energy savings based on a combined joint dispatch. These savings will be the internal economies for energy transfers from the East to West Zones within the AEP system. 7. The Applicants agree to hold harmless the retail customers of SWEPCO from unforeseen events that materially diminish the estimated benefits of the merger and from major 8 DOCKET NO. 98-172-U PAGE 4 deviations from the Applicants' stated representations of estimated merger benefits. The Applicants also agree to hold harmless the retail customers of SWEPCO from any negative economic effects of market power mitigation plans implemented as a part of the merger as determined on a calendar year basis. 8. This Regulatory Plan Stipulation and Agreement supplements the conditions reflected in Orders No. 5 and No. 6 in this Docket, dated August 13, 1998 and August 19, 1998, respectively. The Parties specifically agree that the provisions of Paragraph 7 of the July 10, 1998 Stipulation and Agreement shall apply to this Regulatory Plan Stipulation and Agreement. 9. In furtherance of the provisions of Paragraph No. 3 of the Stipulation and Agreement entered into by the Parties and filed of record July 10, 1998, the Applicants agree to work with the General Staff to address the issue raised in the Quality of Service Evaluation dated August 11, 1998. 10. This Regulatory Plan Stipulation and Agreement is expressly contingent upon receipt of an order by the APSC approving the regulatory plan as reflected herein, and is contingent upon the completion of the merger. 11. The Parties agree that this Regulatory Plan Stipulation and Agreement with regard to the Proposed Regulatory Plan is in the public interest and should be approved in its entirety by the Commission. 12. In the event the Commission does not accept, adopt, and approve this Regulatory Plan Stipulation and Agreement in its entirety and without modification, the Parties agree that this Regulatory Plan Stipulation and Agreement shall be void and of no effect. In the event, the Parties agree that no Party shall be bound by any of the provisions or agreements contained herein, all Parties shall be deemed to have reserved all their respective rights and remedies in this 9 DOCKET NO. 98-172-U PAGE 5 proceeding, and no Party shall introduce this Regulatory Plan Stipulation and Agreement or writings, discussions, negotiations, or other communications of any type related to this Regulatory Plan Stipulation and Agreement in any proceeding. Agreed to this 3rd day of November, 1998. /s/ Illegible_____________________________ Counsel for American Electric Power Company, Inc. /s/ Illegible_____________________________ Counsel for Central and South West Corporation and Southwestern Electric Power Company /s/ Susan E. D'Auteuil____________________ Counsel for the General Staff of the Arkansas Public Service Commission 10 Attachment A AEP/CSW MERGER NET ANNUAL MERGER SAVINGS AND ARKANSAS CUSTOMER RATE REDUCTIONS ($000)
(1) (2) (3) (4) Net Customer Rate Shareholder Period Merger Savings Reduction Savings ------ -------------- --------- ------- Year 1 1,235 685 550 Year 2 1,899 1,054 845 Year 3 2,278 1,264 1,014 Year 4 2,574 1,428 1,146 Year 5 2,777 1,541 1,236
*The Year 5 amount will continue until the effective date of the first base rate change after Year 5. 11 Attachment B AEP/CSW MERGER EXAMPLE OF BASE RATE CASE TREATMENT BASED ON YEAR 3 ($000) CREDIT PER RIDER CONTINUES (1,264) INCLUDED IN TEST YEAR: (3,284) GROSS MERGER SAVINGS CHANGE IN CONTROL AMORTIZATION 250 OTHER CTA AMORTIZATION 756 ------------- TOTAL CTA AMORTIZATION 1,006 ----------- NET MERGER SAVINGS IN TEST YEAR (2,278) ADD BACK TO TEST YEAR COST OF SERVICE: CUSTOMER SHARE (Attachment A - Year 3, Col. 3) 1,264 SHAREHOLDER PORTION (Attachment A - Year 3, Col. 4) 1,014 -------------- 2,278 ----------- NET BASE RATE REDUCTION 0 ----------- CUSTOMER RATE REDUCTION (1,264) ==========
EX-99.D.3.2 4 PROPOSED STIPULATION AND SETTLEMENT 1 Exhibit D-3.2 EXHIBIT REM-1 Page 1 PROPOSED STIPULATION AND SETTLEMENT MERGER CONDITIONS/REGULATORY PLAN 1. SWEPCO shall function under a base rate ceiling set at the level of current rates for a period of 5 years after the merger closes. This base rate ceiling is not applicable solely under the following conditions: a. Changes in statutory federal income tax provisions that result in more than a $16,000,000 net impact on the earnings (income) of SWEPCO; b. A catastrophic "act of God" that has an extreme and long-term impact on the earnings and operations of SWEPCO-La.; c. An increase in the Consumer Price Index - Urban of 10% or more for 2 consecutive years; d. Applicants may file a request with the Commission for changes to the base rates of SWEPCO-La. upon the mandated restructuring or unbundling of electric utility services; e. This condition does not preclude the implementation of a surcharge authorized by statute, Commission decision or as a result of any remand to the Commission from a court proceeding. f. If the purchased power costs incurred by SWEPCO-La. to serve its native load customers during or after the 2001 summer cooling season would, absent this ceiling, cause SWEPCO-La. to seek an increase in its base rates, then the Company may seek relief from this rate ceiling. The Commission's analysis of such a request shall include consideration of all offsets to the requested rate increase, whether such offsets are in the form of lower revenue requirements or cost of capital needs, and these offsets may be used to reduce the need for rate relief. 2. SWEPCO shall implement a nonfuel savings sharing mechanism (SSM) that assures ratepayers will receive timely rate reduction benefits from merger-related cost reductions. See attached, Exhibit A. 3. In connection with the operation of the SSM, SWEPCO shall submit to and pay for an audit by the Commission which shall include an examination of affiliate transactions. 2 EXHIBIT REM-1 Page 2 The cost of the audit shall be reflected in SWEPCO'S cost of service in the appropriate test year. The audit shall be conducted no less than 6 months and no more than 18 months after the merger is consummated. 4. The Applicants shall be allowed to defer merger costs associated with transaction costs and other costs to achieve net of associated savings prior to the operation of the SSM. Ratemaking recovery of the deferred costs will not be allowed other than through SWEPCO's retained savings computed through the SSM. 5. SWEPCO shall flow through all Louisiana jurisdictional fuel savings from the combined operation of the AEP/CSW systems. 6. SWEPCO ratepayers shall be held harmless from any increases in fuel costs that result from the merger for a period of 10 years. To ensure that fuel and purchase power costs shall not increase as a result of the merger, the Applicants commit that the current CSW System Operating Agreement shall be continued by the Applicants, subject to the right to seek FERC-approved modification and subject to the provisions of paragraph 12 of the Affiliate Transaction Conditions. The West Zone (CSW) shall be economically dispatched, and the Applicant's proposed System Integration Agreement shall operate to allow for economic exchanges between the East and West Zones to lower fuel and purchased power costs for the West Zone. Applicants agree that they will not dispatch their system in a manner that will cause increased fuel costs to SWEPCO retail ratepayers as a result of the merger. This provision shall function in connection with the hold harmless provision related to any mitigation sale as described in Paragraph 9 of the Merger Conditions/Regulatory Plan of this Stipulation and Settlement. If AEP changes its 3 EXHIBIT REM-1 Page 3 System Integration Agreement, the notice provisions contained in Paragraph 12 of the Affiliate Transaction Conditions of this Stipulation and Settlement shall apply. To allow the Commission to monitor the fuel costs of SWEPCO-La. to ensure that ratepayers do not pay Merger fuel costs as a result of the merger and/or any mitigation, measures undertaken by the Applicants, the Applicants assume that for a period of 10 years following consummation of the merger, SWEPCO shall file yearly fuel and purchase power cost reports with the Commission. These reports shall provide the following information: a. Calendar year fuel and purchase power cost for SWEPCO and SWEPCO-La. b. A detailed explanation (including detailed workpapers) of how the annual fuel and purchase power costs were derived. c. A detailed explanation with supporting calculations showing how the Applicants incorporated the two hold-harmless merger conditions relating to any mitigation sale. The hold-harmless conditions include (1) the effect of any call-back provision; and (2) the effect on fuel and purchased power costs from any change in system dispatch from the operation of the mitigation sale. d. The annual savings attributable to power interchanges with the East Zone, including detailed workpapers supporting the savings calculation. If fuel and purchase power costs increased due to power interchanges with the East Zone, this calculation shall be shown along with detailed supporting workpapers. e. A sworn statement, consistent with current Commission requirements, with a supporting explanation, by a qualified representative of AEP stating that the fuel and purchase power costs of SWEPCO-La. did not increase as a result of the merger during the calendar year being reported. 7. SWEPCO shall continue to flow through the Louisiana jurisdictional portion of off-system sales margins to ratepayers in accordance with the following terms and conditions: a. 100% of Louisiana-jurisdictional off-system sales margins up to $874,000 shall be credited to customers. 85% of off-system sales margins between $874,000 and $1,314,000 shall be flowed through to customers, with the remaining 15% to be retained by shareholders. The off-system sales margins of SWEPCO-La. above 4 EXHIBIT REM-1 Page 4 $1,314,000 shall be shared equally between ratepayers and shareholders. These dollar figures shall apply on a calendar-year basis and shall include margins associated with mitigation sales. b. All off-system sales margins to be credited to the ratepayers of SWEPCO-LA. under this subsection shall be made in the form of credits to the fuel adjustment clause of SWEPCO-La. c. AEP shall report annually to the Commission the capital and operating costs allocable or assigned (directly or indirectly) to SWEPCO-La. of the AEP energy trading organization or operations, based upon the most recent composite allocation factor calculated. This report shall include, without limitation, the total AEP operating and capital costs for the energy trading organization and operations, allocation factors, and all supporting documentation and workpapers. To the extent that the Applicants deem any of this information to be confidential and/or proprietary, they shall so mark the information and those documents shall be treated as such in accordance with the Commission's General Orders, and Rules of Practice and Procedure. The Commission reserves the right to disallow for ratemaking purposes the costs associated with AEP's energy trading function, if the Commission finds these costs excessive in relation to the benefit received by ratepayers. 8. The Applicants commit and agree that the cost of capital as reflected in SWEPCO's rates shall not be adversely affected as a result of AEP's acquisition of CSW. The Applicants also agree that subsequent to the completion of the merger, the cost of capital for SWEPCO should be set commensurate with the risk of SWEPCO and should not be affected by the merger. Applicants agree that they will not oppose, in either a regulatory proceeding or an appeal of a decision by the LPSC, the application of the principle that the determination of the cost of capital can be based on the risk attendant to the regulated operations of SWEPCO. 9. SWEPCO's Louisiana ratepayers shall be held harmless from any net cost increases resulting from the Applicants mitigation plan (as approved or ordered by the FERC) as measured on a calendar year basis. 5 EXHIBIT REM-1 Page 5 10. SWEPCO and AEP shall commit to maintain and improving service quality in the Louisiana jurisdiction in accordance with the Commission's April 30, 1998 General Order In re: Ensuring Reliable Electric Service Quality and as required by the Commission in the Service Quality Improvement Program resulting from the Commission's previously established investigation into SWEPCO's service quality. 11. SWEPCO and the merged company commit and agree that any stranded cost that SWEPCO may seek to recover will be on a stand-alone basis, and will be limited to ownership and contractual interests of SWEPCO in its respective assets and obligations. The Applicants and merged company agree not to seek or recover any stranded costs associated with the existing AEP system from Louisiana customers. The Commission will not propose the allocation of any stranded costs associated with the CSW system to customers of the existing AEP operating companies. 12. Applicants agree not to assert in proceedings before the LPSC or in appeals of LPSC orders, that the authority of the SEC, as interpreted in Ohio Power Co. v. FERC, 954 F.2d 779 (D.C. Cir. 1992) cert. denied, 498 U.S. 73 (1992) impairs the ability, of the LPSC to examine and determine the prudence, reasonableness and necessity of non-power affiliate transaction costs of SWEPCO. The parties agree that this Agreement does not include a waiver of any arguments that Applicants may have with respect to the reasonableness of SEC approved cost allocations, as opposed to the reasonableness of the costs themselves. 13. Commission merger approval shall be final, unless the Commission rules, within 45 days of the receipt by the Commission of an order of the FERC approving the merger, that Commission approval of the merger is rescinded, modified or will be reconsidered. If the Commission does not have a B&E meeting within 45 days of receipt of the FERC order 6 EXHIBIT REM-1 Page 6 approving the merger, then the 45 day time period will begin to run on the day following the first B&E meeting after the Commission receives the FERC's merger order. The applicable time periods for seeking rehearing and/or review of the Commission Order will begin to run upon the earlier of the expiration of the 45 day time period or the issuance of a final Commission order. 14. The Applicants and the merged company commit and agree that upon issuance of final and non-appealable order from the FERC, SEC, or any state or federal commission addressing the merger, through stipulation or otherwise, providing any benefits to ratepayers of any jurisdiction or imposing any conditions on Applicants or the merged Company that would benefit the ratepayers of any jurisdiction, such net benefits and conditions will be extended to Louisiana retail customers to the extent necessary to achieve equivalent net benefits and conditions to Louisiana retail customers, provided the proposed merger is ultimately consummated. AFFILIATE TRANSACTION CONDITIONS CONFIDENTIAL DATA: WHEN THE FOLLOWING OBLIGATIONS REQUIRE THE COMPANY TO PRODUCE COMPETITIVELY SENSITIVE INFORMATION, UPON REQUEST OF THE COMPANY, THAT INFORMATION SHALL BE MAINTAINED AS CONFIDENTIAL IN ACCORDANCE WITH THE COMMISSION'S RULES OF PRACTICE AND PROCEDURE AND APPLICABLE GENERAL ORDERS. 1. CSW's domestic electric companies, including SWEPCO, will be core businesses for AEP. The Applicants commit, as part of their obligation to serve, to continue to meet the needs of SWEPCO's domestic regulated customers, including, capital requirements as long as SWEPCO is provided an opportunity to earn a fair return on its regulated investment in assets to provide service to customers, in accordance with regulatory precedent and applicable law. 7 EXHIBIT REM-1 Page 7 2. AEP and SWEPCO will provide the Louisiana Commission access to their books and records, and to any records of their subsidiaries and affiliates that reasonably relate to regulatory concerns and that affect SWFPCO's cost of service and/or revenue requirement. 3. AEP will cooperate with audits ordered by the Louisiana Commission of affiliate transactions between SWEPCO and other AEP affiliates, including timely access to books and records and to persons knowledgeable regarding affiliate transactions, and will authorize and utilize its best efforts to obtain cooperation from its external auditor to make available the audit workpapers covering areas that affect the costs and pricing of affiliate transactions. 4. a. Assets with a net book value in excess of $1 million per transaction, purchased by or transferred to the regulated electric utility (SWEPCO) from an unregulated affiliate either directly or indirectly (through another affiliate), must be valued for purposes of the Louisiana retail rate base (but not necessarily for book accounting purposes) at the lesser of the cost to the originating entity and the affiliated group (CSW or AEP) or the fair market value, unless otherwise authorized by applicable Commission rules, Orders or other Commission requirements. b. Assets with a net book value in excess of $1 million per transaction, sold by or transferred from the regulated electric utility (SWEPCO) to an unregulated affiliate either directly or indirectly (through another affiliate), with the exception of accounts receivable sold by SWEPCO to CSW Credit, must be valued for purposes of the Louisiana retail rate base (but not necessarily for book accounting purposes) at the greater of the cost to SWEPCO or the fair market value, unless 8 EXHIBIT REM-1 Page 8 otherwise authorized by applicable Commission rules, Orders or other Commission requirements. 5. The Company shall comply with all requirements contained in the Commission's March, 1994 General Order (and any superseding General Order) regarding mergers, acquisitions and transfers of ownership and control regarding regulated utilities and their assets. 6. The Company shall notify the Commission in writing at least 90 days in advance of a proposed purchase, sale or transfer of assets with a net book value in excess of $1 million if such proposed purchase, sale or transfer is expected at least 90 days before the anticipated effective date of the transaction. With the notice, the Company shall provide such information as may be necessary to enable the Commission Staff to review the proposed transaction, including, without limitation, the identity of the asset to be transferred, the proposed transferor and transferee, the value at which the asset will be transferred, the net book value of the asset, and the anticipated effect on Louisiana retail customers. When such a transaction requires approval of a federal agency under no circumstances shall such notification be less than 60 days in advance or such longer advance period as the applicable federal agency may from time to time prescribe. If not provided with the initial notice, the Company will provide the Commission with a copy of its federal filing at the same time it is submitted to the federal agency. 7. Consistent with applicable Commission and legal precedents and Commission General Orders, the Company shall have the burden of proof in any subsequent ratemaking, proceeding to demonstrate that such purchase, sale or transfer of assets satisfies the requirements of applicable Commission and legal precedent and Commission General Orders, and will not harm retail ratepayers. 9 EXHIBIT REM-1 Page 9 8. The Commission reserves the right, in accordance with Commission and legal precedents and Commission General Orders, to determine the ratemaking treatment of any gains or losses from the sale or transfer of assets to affiliates. 9. For goods and services, including lease costs, sold by SWEPCO to unregulated affiliates either directly or indirectly (through another affiliate), SWEPCO agrees that it will reflect the higher of cost or fair market value in operating income (or as an offset to operating expenses) for ratemaking purposes, unless otherwise authorized by applicable Commission rules, Orders or other Commission requirements (e.g., Commission-approved tariffed rates). 10. With the exception of transactions between SWEPCO and CSW Credit, Inc. and AEPSC, for goods and services, including lease costs, purchased by SWEPCO from unregulated affiliates either directly or indirectly (through another affiliate), SWEPCO agrees that it will reflect the lower of cost or fair market value in operating expenses for ratemaking purposes, unless otherwise authorized by applicable Commission rules, Orders or other Commission requirements. 11. For ratemaking and regulatory reporting purposes, SWEPCO shall reflect the costs assigned or allocated from affiliate service companies on the same basis as if SWEPCO had incurred the costs directly. This condition shall not apply to book accounting for affiliate transactions. 12. The Company shall submit in writing to the Commission any changes it proposes to the System Agreement, the System Integration Agreement and any other affiliate cost allocation agreements or methodologies that affect the allocation or assignment of costs to SWEPCO. The written submission to the Commission shall include a description of 10 EXHIBIT REM-1 Page 10 the changes, the reasons for such changes, and an estimate of the impact, on an annual basis, of such changes on SWEPCO's regulated costs. To the extent any such changes are filed with the SEC or FERC, the Company agrees to utilize its best efforts to notify the Commission at least 30 days prior to those filings, and at least 90 days prior to the proposed effective date of those changes or as early as reasonably practicable, to allow the Commission a timely opportunity to respond to such filings. If the documents to be filed with the SEC or the FERC are not finalized 30 days prior to the filing, the information required above may be provided by letter to the Commission with a copy of the SEC or FERC filing to be provided as soon as it is prepared. The filing by the Company of this information with the Commission shall not constitute acceptance of the proposed changes, the allocation or assignment methodologies, or the quantifications for ratemaking purposes. 13. SWEPCO or AEPSC on behalf of SWEPCO may not make any non-emergency procurement in excess of $1 million per transaction from an unregulated affiliate other than from AEPSC except through a competitive bidding process or as otherwise authorized by this Commission. Transactions involving the Company and CSW Credit, Inc. (or its successor) for the financing of accounts receivables are exempt from this condition. Records of all such affiliate transactions must be maintained until the Company's next comprehensive retail rate review. In addition, at the time of the next comprehensive rate review, all such affiliate transactions that were not competitively bid shall be separately identified for the Commission by the Company. This identification shall include all transactions between the Company and AEPSC in which AEPSC acquired the goods or services from another unregulated affiliate. 11 EXHIBIT REM-1 Page 11 14. If an unregulated business markets a product or service that was developed by SWEPCO or paid for by SWEPCO directly or through an affiliate, and the product or service is actually used by SWEPCO, all profits on the sale of such product or service (based on Louisiana retail jurisdiction) shall be split evenly between SWEPCO, which was responsible for or shared the cost of developing the product, and the unregulated business responsible for marketing the product or service to third parties, after deducting all incremental costs associated with making such product or service available for sale, including the direct cost of marketing such product or service. However, in the event that such a product or service developed by SWEPCO to be used in its utility business is not actually so used, and subsequently is marketed by the unregulated business to third parties, SWEPCO shall be entitled to recover all of its costs to develop such product or service before any such net profits derived from its marketing shall be so divided. If SWEPCO jointly develops such product or service and shares the development with other entities, then the profits to be so divided shall be SWEPCO's pro rata share of such net profits based on SWEPCO's contribution to the development costs. 15. Subject to the provisions of Paragraph 6 of the Merger Conditions (fuel hold harmless), SWEPCO shall continue to purchase, treat, and allocate its fuel costs consistently with the Commission General Order dated November 6, 1997, In re: Development of Standards Governing the Treatment and Allocation of Fuel Costs by Electric Utility Companies, including any future amendments to this Order. 16. In the event of the implementation of electric generation open access for Commission-jurisdictional electric utilities, any miles, regulations or orders of general applicability adopted by the Commission regarding generation assets in an open access environment 12 EXHIBIT REM-1 Page 12 will apply to the company and, to the extent inconsistent with provisions of this Order, will govern. No later than six months prior to the mandated open access date, the company shall file with the Commission any proposed modifications to this Order to address any such inconsistencies. 17. If retail access for SWEPCO-La. is mandated by the Commission, or through action by the Federal Energy Regulatory Commission or federal legislation, then SWEPCO-La. shall have the right to petition the Commission for modifications to the terms of this settlement, including the affiliate transaction conditions, that are made necessary by the mandating of retail access and its likely impact on the retail rates at SWEPCO-La. Any such petition must establish the necessity of the proposed modifications and provide appropriate protections to ensure that the benefits of this merger are presented for SWEPCO-La. regulated customers, including merger savings and the hold harmless provisions set forth herein. The Commission will act upon the petition in accordance with its normal rules and procedures. This paragraph is not intended to limit SWEPCO's right to petition the Commission in the event that electric utility unbundling or retail access is ordered by a state commission regulating SWEPCO's retail rates, provided that SWEPCO must comply with the requirements set forth above in any such petition. 13 EXHIBIT REM-1 Page 13 SAVINGS SHARING MECHANISM (SSM) The savings in nonfuel operation and maintenance (O&M) expense resulting from the merger between CSW and AEP will be quantified in accordance with a formula based methodology, the SSM, and shared equally between customers and shareholders. The Louisiana retail jurisdictional share of nonfuel O&M savings quantified in accordance with the SSM will be flowed through to customers through an annual surcredit effective initially and for the period beginning on the first day of the fifteenth month after the consummation of the merger. The nonfuel savings quantification through the SSM and the surcredit will be updated for current information on each twelve month anniversary for a total of eight filings. The surcredit in effect after the eighth filing will remain in effect unless and until the Commission issues an order in a base rate proceeding. The annual surcredit will be computed and applied as a uniform percentage of base revenues. After the base rate cap expires, the Company will be allowed to file a claim for a base rate revenue deficiency as an offset to the SSM savings surcredit, which will be subject to an expedited six month review by the Commission. However, the surcredit may only be reduced prospectively after the Commission determines and approves a revenue requirement offset. After the Company's base rate cap expires, but only through the effective dates of the Company's last required SSM filing, or in a base rate proceeding initiated by this Commission after the effective date of the merger, the Company may include its retained savings, computed pursuant to the SSM, as a cost of service expense in its revenue requirement filed in conjunction with a comprehensive base rate proceeding. The Company may not include its retained share of savings, computed pursuant to the SSM, as a cost of service item in any revenue requirement filing to offset the SSM. In any base revenue requirement filing through the effective date of the Company's last required SSM filing, the Company will exclude the test year amount of the SSM surcredit from its per books and pro forma revenues. I. MERGER COSTS TO ACHIEVE, TRANSACTION COSTS, AND CHANGE IN CONTROL PAYMENTS. The Company is authorized to defer its merger costs to achieve, transaction costs, and change in control payments as these terms have been defined in the testimony of the 14 EXHIBIT REM-1 Page 14 Applicants' witnesses in this proceeding. The Commission will allow the Company to retain its share of the SSM savings in order to amortize its deferred costs. During the first fourteen months following the consummation of the merger, the Company will retain 100% of the merger savings and may utilize these savings to reduce the deferrals of its merger costs. Commencing in the fifteenth months following the consummation of the merger, the Company will retain 50% of the merger savings, computed pursuant to the SSM, and may utilize these savings or any portion of these savings to reduce the deferrals of its merger costs. II. SAVINGS SHARING MECHANISM FORMULA. The SSM surcredit and the Company's retained share of merger savings will be computed in accordance with the SSM formula. The SSM formula compares the Company's future year normalized O&M expense (FYNE) to the 1998 base year normalized O&M expense (BYNE) escalated for inflation and reduced for productivity improvements. The 1998 base year normalized O&M expense, prior to the inflation and productivity adjustments, is based upon the actual pre-merger level of the Company's nonfuel O&M expense adjusted to reflect certain ratemaking adjustments., to remove operating lease costs, and to remove certain nonrecurring expenses (specifically identifiable and in excess of $1 million during the twelve-month period), including all merger costs. The derivation of the 1998 base year normalized O&M expense is detailed on Attachment A. For each year subsequent to 1998, the base year normalized O&M will be escalated by an inflation factor reflecting the annual increase in the Consumer Price Index - Urban (CPI-U) less a 1.1% annual productivity adjustment. For each subsequent year, the CYCPI-U will be for the month representing the midpoint of the twelve month future year period as published on the Consumer Price Indexes home page (http://stats.bls.gov/cpihome.htm). The future year normalized O&M expense will be based upon the actual post merger level of the Company's nonfuel O&M expenses adjusted to reflect certain ratemaking adjustments, to remove operating lease costs, and to remove certain nonrecurring expenses (specifically identifiable and in excess of $1 million during the twelve-month 15 EXHIBIT REM-1 Page 15 period), including all merger related costs and amortizations, in a manner similar to that of the base year normalized O&M. The formula for the future year normalized O&M is detailed on Attachment B. Merger savings will be computed as the difference between the future year normalized O&M and the base year normalized O&M, adjusted for inflation and productivity improvements as previously described. The mercer savings then will be allocated to the Louisiana retail jurisdiction (LJA). The merger savings for the Louisiana retail jurisdiction under the SSM will be computed in accordance with the following formula, consistent with the preceding description. Merger Savings = (FYNE - BYNE) * LJA where: FYNE = Future Year Normalized O&M, Computed According to Attachment B BYNE = Base Year Normalized O&M, Computed According to Attachment A, escalated for inflation and reduced for productivity improvement in accordance with the following formula: BYNE = 1998 BYNE O&M * (CYCPI-U/BYCPI-U) - ((1 +.011) to the power of (n - 1) where: CYCPI-U = Current Year CPI-U (as of the month representing the mid-point of 12-month future year period) BYCPI-U = 1998 Base Year CPI-U (as of June 1998) n = number of years (stated as a decimal to reflect partial years) computed as mid-point of current year less the mid-point of 1998. LJA Louisiana retail jurisdiction allocation percentage based upon the most recent calendar year cost of service Savings computed pursuant to the SSM formula beginning with the fifteenth month after the effective date of the merger will be allocated 50% to customers through the SSM surcredit mechanism and retained 50% by the Company. Attachment C provides an example of the calculation of the SSM and the allocation of savings to customers through the surcredit and the savings retained by the Company. 16 EXHIBIT REM-1 Page 16 III. TIMING OF SSM STIRCREDIT REDUCTIONS TO CUSTOMERS AND COMMISSION REVIEW. The first twelve month (year) period for the computation of SSM savings will begin on the first day of the first calendar month after the consummation of the merger. Subsequent periods for the computation of SSM savings will follow the same twelve month cycle as the first period. SWEPCO will make the first SSM filing within the Merger Docket U-23327 and pursuant to the Merger Order in Docket U-23327 within 60 days after the completion of the first twelve month period (within fourteen months of the consummation of the merger). The first surcredit rate reductions will commence on the first day of the fifteenth month following the consummation of the merger, subject to the Commission's subsequent review and approval. Likewise, the subsequent surcredit rate reductions will commence on the twelve month anniversaries of the first surcredit rate reductions, subject to the Commission's subsequent review and approval. To implement the surcredit rate reductions, the Company's annual filings will include a tariff that will go into effect with no further action by the Commission, subject to the Commission's subsequent review and approval. Copies of the SSM filings will be provided to the Commission's consultants and Special Counsel for review, analysis and recommendations to the Commission. In the event that the Commission ultimately determines that a larger surcredit rate reduction than the one filed by the Company is required, that additional reduction shall be effective as of the date the original filing became effective. The Company shall make such additional refunds or credit customer bills to reflect this effective date. In conjunction with the second SSM filing, but within 120 days of the end of the second SSM period, the Company also will file detailed financial information typically utilized in a revenue requirement filing, including a jurisdictional cost of service study. The filings of this detailed financial information also will be within the Merger Docket U-23327 and pursuant to the Merger Order in Docket U-23327. The detailed financial information will be for the most recent twelve months ending concurrent with the second SSM savings period. The detailed financial information will be provided in the format specified in Attachment D. However, the Company and other parties agree that the schedules filed pursuant to this provision will not be determinative for ratemaking 17 EXHIBIT REM-1 Page 17 purposes. Copies of the detailed financial information will be provided to the Commission's consultants and Special Counsel for review, analysis and recommendations to the Commission. The Company agrees to cooperate with the Commission's consultants and Special Counsel and to provide timely, accurate and comprehensive responses to discovery. 18 EXHIBIT REM-1 Page 18 Attachment A BASE YEAR NORMALIZED (BYNE) OPERATION AND MAINTENANCE EXPENSE SWEPCO SAVINGS SHARING MECHANISM (000)
Twelve Months Ended December 31, 1998 ----------------- I. Total Actual 1998 Non-Fuel O&M Expense $191,833 (Excluding Account Nos. 501, 518, 536, 547 and 555) II. Less: A. Transmission Fees (Account 565) (7,292) B. Merger Costs(Costs to Achieve, Transaction Costs, Separation Payments) C. Costs of Early Retirement or Other Cost Reductions 0 D. Operating Lease Expense* 0 (1,770) III. Other: Add/(Subtract) A. SFAS 106 Expense in Excess of Cash Pay-As-You-Go (194) B. Other Non-Recurring Adjustments (13,870) -------- IV. Total Base Year Normalized $168,707 ========
- -------------------------------- *FERC Accounts 507, 525, 540, 550, 567, 589, and 931. 19 EXHIBIT REM-1 Page 19 Attachment B FUTURE YEAR NORMALIZED (FYNE) OPERATION AND MAINTENANCE EXPENSE SWEPCO SAVINGS SHARING MECHANISM (000)
Twelve Months Ended MM, DD, YY ---------- I. Total Actual 1998 Non-Fuel O&M Expense (Excluding Account Nos. 501, 518, 536, 547 and 555) $ II. Less: A. Transmission Fees (Account 565) B. Merger Costs (Costs to Achieve, Transaction Costs, Separation Payments) and Amortizations C. Costs of Early Retirement or Other Cost Reductions D. Operating Lease Expense** III. Other: (Add/(Subtract) A. SFAS No. 106 Expense in Excess of Cash Pay-As-You-Go B. Other Non-Recurring Adjustments IV. Total Future Year Normalized $
- ----------------------------- *FERC Accounts 501, 525, 540, 550, 567, 589, and 931. 20 EXHIBIT REM-1 Page 20 Attachment C ILLUSTRATION OF OPERATION OF SWEPCO MERGER SAVINGS SHARING MECHANISM
YEAR 1 YEAR 2 YEAR 3 YEAR 4 YEAR 5 YEAR 6 ------ ------ ------ ------ ------ ------ DESCRIPTION Base Year O&M Expenses $100,000 $100,000 $100,000 $100,000 $100,000 $100,000 Future Year CPI-U 103,000 106,090 109,273 112,551 115,927 119,405 Base Year CPI-U 100,000 100,000 100,000 100,000 100,000 100,000 Future Year CPI-U/Base Year CPI-U 1.030 1.061 1.093 1.126 1.159 1.194 Productivity Factor Offset -0.011 -0.022 -0.033 -0.045 -0.056 -0.068 SSM Base Year Escalation Factor 1.019 1.039 1.059 1.081 1.103 1.126 Base Year Normalized Expense, Esc & Prod Offset $101,900 $103,878 $105,938 $108,078 $110,305 $12,621 Future Year Normalized Expenses $101,000 $102,010 $103,080 $104,060 $105,101 $106,152 Total Company Savings (FYNE-BYNE) ($900) ($1,868) ($2,906) $(4,017) ($5,204) ($6,469) Louisiana Jurisdictional Factor 40.00% 40.00% 40.00% 40.00% 40.00% 40.00% Louisiana Jurisdictional Merger Savings ($360) ($747) ($1,162) ($1,607) ($2,082) ($2,588) Customers Allocation of Savings @50% ($180) ($374) ($581) ($803) ($1,041) ($1,294)
YEAR 7 YEAR 8 ------ ------ DESCRIPTION Base Year O&M Expenses $100,000 $100,000 Future Year CPI-U 122,987 126,677 Base Year CPI-U 100,000 100,000 Future Year CPI-U/Base Year CPI-U 1.230 1.267 Productivity Factor Offset -0.080 -0.091 SSM Base Year Escalation Factor 1.150 1.175 Base Year Normalized Expense, Esc & Prod Offset $115,029 $117,531 Future Year Normalized Expenses $107,214 $108,286 Total Company Savings (FYNE-BYNE) ($7,815) ($9,245) Louisiana Jurisdictional Factor 40.00% 40.00% Louisiana Jurisdictional Merger Savings ($3,126) ($3,698) Customers Allocation of Savings @50% ($1,563) ($1,849)
NOTE: Years in the column headings refers to the twelve month implementation periods commencing on the first day of the fifteenth month following consummation of the merger. 21 EXHIBIT REM-1 Page 21 Attachment D SOUTHWESTERN ELECTRIC POWER COMPANY RATE BASE/RATE OF RETURN FOR THE TEST YEAR ENDED DECEMBER 31, 1997
(1) (2) (3) (4) (5) Total Company Line Schedule Total Company Pro Forma No. Description Reference Per Books Adjustments Balance --- ----------- --------- --------- ----------- ------- 1 Plant in service: 2 Plant in service W/P B-2 $ 3,005,002,647 (40,121,808) 2,964,880,839 3 Construction work in progress W/P B-2 51,665,071 (8,281,517) 43,383,554 4 Plant acquisition adjustment W/P B-2 18,043,976 0 18,043,976 5 Plant held for future use W/P B-2 80,704 (80,704) 0 --------------- ------------- --------------- 6 Gross Plant $ 3,074,792,398 $ (48,484,029) $ 3,026,308,369 7 Accumulated depreciation W/P B-3 (1,225,864,541) 14,267,639 (1,211,596,902) --------------- ------------- --------------- 8 Net Plant $ 1,848,927,857 $ (34,216,390) $ 1,814,711,467 9 10 Working capital: 11 Cash working capital W/P B-9 (90,078,456) 0 (90,078,456) 12 Prepayments W/P B-6 38,498,880 (23,698,126) 14,800,754 13 Operating materials and supplies W/P B-7 27,132,307 (2,840,083) 24,292,225 14 Fuel inventories W/P B-8 26,415,233 30,699,587 57,114,820 15 Additions and deductions: 16 Customer deposits W/P B-13 (14,358,583) 0 (14,358,583) 17 Deferred credits W/P B-11 (4,015,924) 1,939,285 (2,076,639) 18 Additional rate base items W/P B-10 25,523,062 32,374,843 57,897,905 0 --------------- ----------- --------------- 19 Net total investment $ 1,858,044,376 $ 4,259,116 $ 1,862,303,492 20 Accumulated deferred income taxes W/P B-12 (410,575,785) 5,079,396 (405,496,389) 21 Deferred investment tax credit - pre 1971 W/P B-12 (345,089) 0 (345,089) --------------- ------------- --------------- 22 Rate Base $ 1,447,123,502 $ 9,338,512 $ 1,456,462,014 =============== =========== =============== 23 Net operating income (current prices) 145,540,459 (28,706,042) 116,834,417 24 Rate of return (current prices) 10.057% 8.022%
22 EXHIBIT REM-1 Page 22 Attachment D Southwestern Electric Power Company Electric Utility Plant For the Test Year Ending December 31, 1997
Pro Forma Total FERC Total Company Company Line Account Balance Balance No. Description Number Dec. 31, 1997 Adjustments Dec. 31, 1997 --- ----------- ------ ------------- ----------- ------------- 1 Electric Plant in Service 101,106 2 Intangible Plant 3 Organization 301 12,201 12,201 4 Miscellaneous Intangible Plant 303 28,926,874 28,926,874 ------------- ------------ ------------- 5 Total Miscellaneous Intangible Plant 28,939,075 0 28,939,075 ------------- ------------ ------------- 6 PRODUCTION 7 Stearn Production Plant - Coal & Lignite 8 Land and Land Rights 310 9,186,653 9,186,653 9 Structures and improvements 311 226,605,778 226,605,778 10 Coal Unit Railroads 311 1,792,037 1,792,037 11 Boiler Plant Equipment 312 692,076,017 692,076,017 12 Rail Cars 312 31,947,035 31,947,035 13 Engines and Engine Driven Gener. 313 0 0 14 Turbogenerator Units 314 177,789,455 177,789,455 15 Accessory Electric Equipment 315 47,309,527 47,309,527 16 Misc. Power Equipment 316 34,084,763 34,084,763 17 AFUDC Rate Adjustment W/P B-4 0 (38,201,579) (38,201,579) ------------- ------------ ------------- 18 Total Steam Production Plant 1,220,791,265 (38,201,579) 1,182,589,686 ------------- ------------ ------------- 19 Steam production Plant - Gas & Oil 20 Land and Land Rights 310 743,582 743,582 21 Structures and improvements 311 21,809,310 21,809,310 22 Boiler Plant Equipment 312 72,031,354 72,031,354 23 Gas Unit Pipelines 312 1,259,681 1,259,681 24 Engines and Engine Driven Gener. 313 0 0 25 Turbogenerator Units 314 56,144,494 56,144,494 26 Accessory Electric Equipment 315 7,162,215 7,162,215 27 Misc. Power Equipment 316 4,983,273 4,983,273 ------------- ------------ ------------- 28 Total Steam Production Plant 164,113,909 0 164,113,909 ------------- ------------ ------------- 29 TRANSMISSION PLANT 30 Land and Land Rights 350 1,147,105 1,147,105 31 Land and Land Rights 350.2 23,906,233 23,906,233 32 Structure and Improvements 352 7,411,953 7,411,953 33 Station Equipment 353 178,456,520 178,456,520 34 Towers and Fixtures 354 36,124,941 36,124,941 35 Poles and Fixtures 355 92,882,931 92,882,931 36 Overhead Conductors and Devices 356 115,893,914 115,893,914 37 Underground Conduits 357 0 0 38 Underground Conductors and 358 Devices 295 295 39 Roads and Trails 359 132,266 132,266 40 AFUDC Rate Adjustment W/P B-4 0 (1,893,630) (1,893,630) ------------- ------------ ------------- 41 Total Transmission Plant 455,956,158 (1,893,630) 454,062,528 ------------- ------------ -------------
23 EXHIBIT REM-1 Page 23 Attachment D Southwestern Electric Power Company Electric Utility Plant For the Test Year Ending December 31, 1997
Pro Forma Total Company Total FERC Balance Company Line Account Dec. 31, Balance No. Description Number 1997 Adjustments Dec. 31, 1997 --- ----------- ------ ---- ----------- ------------- 42 DISTRIBUTION PLANT 43 Land and Land Rights 360 1,574,190 1,574,190 44 Land and Land Rights 360.2 2,283,509 2,283,509 45 Structures and Improvements 361 2,693,807 2,693,807 46 Station Equipment 362 113,398,298 113,398,298 47 Storage Battery Equipment 363 0 0 48 Poles, Tower, and Fixtures 364 182,418,283 182,418,283 49 Overhead Conductors and Devices 365 73,085,051 73,085,051 50 Underground Conduit 4355 17,860,530 17,860,530 51 Underground Conductors and Devices 367 73,085,051 73,085,051 52 Line Transformers 368 184,224,384 184,224,384 53 Services 369 24,482,183 24,482,183 54 Meters 370 53,226,081 53,226,081 55 Installations on Customer Premises 371 28,904,132 28,904,132 56 Leased Property on Customer Premises 372 0 0 57 Street Lighting and Signal Systems 373 22,247,734 22,247,734 58 AFUDC Rate Adjustment W/P B-4 0 132,282 132,282 ------------ ------------ ------------ 59 Total Distribution Plant 861,365,663 132,282 861,497,945 ------------ ------------ ------------ 1 GENERAL PLANT 2 Land and Land Rights 389 4,459,415 4,459,415 3 Structures and Improvements 390 84,430,237 84,430,237 4 Office Furniture and Equipment 391 14,130,237 14,130,237 5 Computer Equipment 391 12,458,854 12,458,854 6 Transportation Equipment 392 27,873,033 27,873,033 7 Stores Equipment 393 1,720,571 1,720,571 8 Tools, Shop and Garage Equipment 394 6,395,189 6,395,189 9 Laboratory Equipment 395 5,126,472 5,126,472 10 Powered Operated Equipment 396 1,950,016 1,950,016 11 Communication Equipment 397 47,175,608 47,175,608 12 Miscellaneous Equipment 398 861,098 861,098 Other Tangible Property (Fuel) 399 67,256,045 67,256,045 AFUDC Rate Adjustment - Fu W/P B-4 0 (1,052,872) (1,052,872) 13 AFUDC Rate Adjustment W/P B-4 0 893,991 893,991 ------------ ------------ ------------ 14 Total General Plant 273,836,577 (158,881) 273,677,696 ------------ ------------ ------------ 15 TOTAL ACCOUNT 101 AND 106 3,005,002,647 (40,121,808) 2.,964,880,839 16 Plant Held for Future Use 105 80,704 (80,704) 0 17 Construction Work in Progress 107 51,665,071 (8,281,517) 43,383,554 18 Plant Acquisition Adjustment 114 18,043,976 18,043,976 ------------ ------------ ------------ 19 TOTAL ELECTRIC PLANT 3,074,792,398 (48,484,029) 3,026,308,369 ============= =========== =============
24 EXHIBIT REM-1 Page 24 Attachment D Southwestern Electric Power Company Accumulated Provision for Depreciation, Amortization and Depletion For the Test Year Ending December 31, 1997
FERC Total Company W/P B-3 & Pro Forma Line Account Balance Dec. 31, W/P B-4 Balance No. Description Number 1997 Adjustments Dec. 31, 1997 --- ----------- ------ ---- ----------- ------------- 1 Accumulated Provision for 2 Depreciation 108 3 Production - Steam $ 694,173,999 $ 23,172,551 $ 717,346,550 4 Transmission 152,328,547 (13,707,722) 138,620,825 5 Distribution 306,109,948 (20,700,365) 285,409,583 6 General 26,819,051 (3,032,103) 23,786,948 7 Lignite Depletion 20,496,682 20,496,682 8 Transportation 17,145,521 17,145,521 9 Retirement Work In Progress (4,472,945) (4,472,945) -------------- ------------ -------------- $1,212,600,803 $(14,267,639) $1,198,333,164 10 Accumulated Amortization for 11 Intangible Plant 111 8,457,094 8,457,094 12 Accumulated Amortization for 13 Plant Acquisition Adjustment 115 4,806,644 4,806,644 -------------- ------------ -------------- 14 Total Accumulated Provision for 15 Depreciation and Amortization $1,225,864,541 $ (14,267,639) $ 1,211,596,902 ============== ============= ===============
25 EXHIBIT REM-1 Page 25 Attachment D SWEPCO CASH WORKING CAPITAL FOR THE TEST YEAR ENDED DECEMBER 31, 1997
(1) (2) (3) (4) (5) (6) (7) Total Adjusted Line Company Pro Forma Test Year Revenue No. Description Ref. Per Books Adjustment Amount Lag Days Ref. --- ----------- ---- --------- ---------- ------ -------- ---- 1 Fuel 383,007,632 (1,799,003) 381,228,629 3.93 2 Deferred Fuel (603,883) 603,883 - 3.93 3 Purchased Power 25,927,920 - 25,927,920 3.93 4 Total Fuel and Purchase Power 408,331,669 (1,175,120) 407,156,549 3.93 5 Total Oper & maint 191,665,267 1,886,414 193,551,681 3.93 6 Taxes other than income A/C #4081 55,952,213 (358,497) 55,603,716 3.93 7 Federal Income Tax-Current 45,158,544 (11,602,231) 33,556,313 3.93 8 Federal Income Tax-Deferred (6,646,437) (5,932,359) (12,578,796) 3.93 9 State Income Tax-Current 4,764,450 (1,786,899) 2,977,551 3.93 11 Depreciation and Amortization 43,276,557 95,228,017 27,211,431 122,439,448 3.93 12 Gain on Sale of Emission Allowance (135,568) - (135,568) 3.93 13 3.93 ----------- ------------- ------------ 14 Subtotal 794,328,156 8,242,738 802,570,894 15 Interest on Long-Term Debt A/C #427-429 49,971,270 4,830,123 54,801,393 3.93 16 Preferred Stock Dividend A/C #437 2,466,627 (107,566) 2,359,051 3.93 17 Return on common equity 59,673,958 6 59,673,964 3.93 ---------- ------------ ----------- 18 Net operating income 112,111,855 4,772,563 116,834,417 =========== ============= ============ 19 Working Capital Requirement for Cost of 906,440,010 12,965,301 919,405,311 Service =========== ============= ============ 20 Sales and Use Taxes B-9 Pg 2 21 Minimum Bank Balances A/C #1350.9000 22 Net Working Capital Requirement
(8) (9) (10) (11) Line Expenses Net Lag CWC CWC No. Description Lead Days Days Factor Requirement --- ----------- --------- ---- ------ ----------- 1 Fuel 32.77 (28.84) -0.07881 (30,043,522) 2 Deferred Fuel 3.93 0.01073 - 3 Purchased Power 38.61 (34.69) -0.09478 (2,457,394) 4 Total Fuel and Purchase Power 5 Total Oper & maint 40.58 (36.65) -0.10014 (19,382,129) 6 Taxes other than income 122.92 (119.00) -0.32513 (18,078,299) 7 Federal Income Tax-Current 84.05 (80.12) -0.21891 (7,345,863) 8 Federal Income Tax-Deferred 3.93 0.01073 (134,938) 9 State Income Tax-Current 24.26 (20.33) -0.05555 (165,416) 11 Depreciation and Amortization 3.93 0.01073 1,313,458 12 Gain on Sale of Emission Allowance 3.93 0.01073 (1,454) 13 3.93 14 Subtotal 15 Interest on Long-Term Debt 90.31 (86.38) -0.23602 (12,934,429) 16 Preferred Stock Dividend 46.32 (42.40) 0.11584 (273,281) 17 Return on common equity 3.93 0.01073 640,147 18 Net operating income - ----------- 19 Working Capital Requirement for Cost of (88,863,122) Service 20 Sales and Use Taxes (1,402,362) 21 Minimum Bank Balances 187,028 ----------- 22 Net Working Capital Requirement (90,078,458) ============
26 EXHIBIT REM-1 Page 26 Attachment D SWEPCO CASH WORKING CAPITAL FOR FUEL, O&M AND OTHER TAXES FOR THE TEST YEAR ENDED DECEMBER 31, 1997
(1) (2) (3) (4) (5) (6) (7) Line Total Company Pro Forma Adjusted Test Revenue No. Description Ref. Per Books Adjustment Year Amount Lag Days Ref. --- ----------- ---- --------- ---------- ----------- -------- ---- 1 GAS 85,995,697 (400,194) 85,595,503 3.93 2 COAL 218,213,811 (1,015,491) 217,198,320 3.93 3 LIGNITE 76,983,477 (358,254) 76,625,223 3.93 4 OIL 1,088,162 (5,064) 1,083,098 3.93 5 FUEL - CSWS 724,628 - 724,628 3.93 6 OTHER FUEL - OIL - - - 3.93 7 OTHER FUEL - DIESEL 1,857 - 1,857 3.93 8 OTHER FUEL - GAS - - - 3.93 ------------ ------------ ------------ ---- 9 TOTAL FUEL 383,007,532 (1,779,003) 381,228,629 3.93 10 PURCHASED POWER - AFFILIATE 7,836,057 - 7,836,057 3.93 11 PURCHASED POWER - OTHER 18,091,863 - 18,091,863 3.93 ------------ ------------ ------------ ---- 12 TOTAL PURCHASED POWER 25,927,920 - 25,927,920 3.93 13 PAYROLL 55,023,443 (2,609,272) 52,414,171 3.93 14 O&M - CSWS 43,923,851 648,827 44,572,678 3.93 15 CSW CREDIT FACTORING - 9,327,765 9,327,765 3.93 16 OTHER O&M 92,717,973 (3,520,461) 89,197,512 3.93 ------------ ------------ ------------ ---- 17 TOTAL O&M 191,665,267 1,886,414 195,512,126 3.93 18 AD VALOREM TAX 33,204,298 (928,572) 32,275,726 3.93 19 FUTA (36,654) (36,654) 3.93 20 SUTA 77,345 77,345 3.93 21 FICA 4,297,246 (276,425) 4,020,821 3.93 22 PAYROLL TAXES - CSWS 1,724,550 1,724,550 3.93 23 PUC ASSESSMENTS 923,559 166,696 1,090,255 3.93 24 OCCUPATIONAL TAX 47,756 47,756 3.93 25 TEXAS FRANCHISE TAX 1,800,000 810,824 2,610,824 3.93 26 OTHER STATE FRANCHISE TAX 2,422,886 (499,074) 1,923,812 3.93 27 CITY FRANCHISE FEES 8,435,125 135,520 8,570,645 3.93 28 TEXAS CROSS RECEIPTS TAX 3,353,282 (54,965) 3,298,317 3.93 SUPERFUND TAXES (Note 1) (287,500) 287,500 - 3.93 29 FEDERAL HIGHWAY USE TAX 320 - 320 3.93 ------------ ------------ ------------ ---- 30 TOTAL TAXES OTHER THAN INCOME 55,962,213 (358,497) 55,603,716 3.93 31 SALES & USE TAX - BY WIRE 21,199,353 21,199,353 3.93 32 SALES & USE TAX - BY CHECK 578,432 578,432 3.93 ------------ ------------ ------------ ---- 33 TOTAL SALES AND USE TAX 21,777,784 - 21,777,784 3.93 (8) (9) (10) (11) Expenses Line Lead Net Lag CWC CWC No. Description Days Days Days Requirement --- ----------- ---- ---- ---- ----------- 1 GAS 51.76 (47.83) -0.13105 (11,217,667) 2 COAL 21.86 (17.93) -0.04913 (10,670,718) 3 LIGNITE 41.93 (36.00) -0.10412 (7,977,942) 4 OIL 48.13 (44.20) -0.12110 (131,159) 5 FUEL - CSWS 26.96 (23.03) -0.06311 (45,730) 6 OTHER FUEL - OIL 3.93 0.01076 - 7 OTHER FUEL - DIESEL 65.28 (61.35) -0.16808 (312) 8 OTHER FUEL - GAS - 3.93 0.01076 - ------- ------- -------- ------------ 9 TOTAL FUEL 32.77 (28.84) -0.07881 (30,043,522) 10 PURCHASED POWER - AFFILIATE 37.85 (33.92) -0.09294 (728,319) 11 PURCHASED POWER - OTHER 38.81 (34.88) -0.09557 (1,729,075) ------- ------- -------- ------------ 12 TOTAL PURCHASED POWER 38.61 (34.69) -0.09478 (2,457,394) 13 PAYROLL 26.41 (22.48) -0.06160 (3,228,553) 14 O&M - CSWS 26.96 (23.03) -0.06311 (2,812,899) 15 CSW CREDIT FACTORING 3.93 - 0.00000 - 16 OTHER O&M 59.32 (55.39) 0.15176 (13,536,995) ------- ------- -------- ------------ 17 TOTAL O&M 40.58 (36.65) -0.10014 (19,578,447) 18 AD VALOREM TAX 191.33 (187.40) -0.51343 (16,571,257) 19 FUTA 74.12 (70.19) -0.19230 7,049 20 SUTA 63.11 (59.19) -0.16215 (12,542) 21 FICA 18.28 (14.35) -0.03932 (158,097) 22 PAYROLL TAXES - CSWS 26.96 (23.03) -0.06311 (108,833) 23 PUC ASSESSMENTS 6.09 (2.16) -0.00592 (6,454) 24 OCCUPATIONAL TAX (112.73) 116.66 0.31962 15,264 25 TEXAS FRANCHISE TAX 64.62) 68.55 0.18780 490,315 26 OTHER STATE FRANCHISE TAX (118.53) 122.46 0.33550 645,437 27 CITY FRANCHISE FEES 77.16 (73.24) -0.20065 (1,719,698) 28 TEXAS CROSS RECEIPTS TAX 76.92 (72.99) -0.19998 (659,588) SUPERFUND TAXES (Note 1) - 3.93 0.01076 - ------- ------- -------- ------------ 29 FEDERAL HIGHWAY USE TAX (115.55) 119.48 0.32733 105 30 TOTAL TAXES OTHER THAN INCOME 122.92 (119.00) -0.32513 (18,078,299) 31 SALES & USE TAX - BY WIRE 27.03 (23.10) -0.06330 (1,341,926) 32 SALES & USE TAX - BY CHECK 42.06 (38.14) -0.10448 (60,436) ------- ------- -------- ------------ 33 TOTAL SALES AND USE TAX 27.49 (23.57) -0.06439 (1,402,362)
Note 1: Correction entries to reverse 1996 expenses. No cash receipts or payments 27 EXHIBIT REM-1 Page 27 Attachment D SOUTHWESTERN ELECTRIC POWER COMPANY PREPAYMENTS FOR THE TWELVE MONTHS ENDED DECEMBER 31, 1997
(1) (2) (3) (4) (5) Line Schedule Total Company Pro Forma Total Company No. Description Reference Per Books Adjustments Pro Forma --- ----------- --------- --------- ----------- --------- 1 Monthly Balances: 2 December, 1996 $ 13,394,706 $ - $ 13,394,706 3 January, 1997 14,285,043 - 14,285,043 4 February, 1997 14,851,119 - 14,851,119 5 March, 1997 15,252,090 - 15,252,090 6 April, 1997 15,401,590 - 15,401,590 7 May, 1997 15,250,326 - 15,250,326 8 June, 1997 14,304,151 - 14,304,151 9 July, 1997 15,101,264 - 15,101,264 10 August, 1997 15,939,930 - 15,939,930 11 September, 1997 15,870,908 - 15,870,908 12 October, 1997 15,528,589 - 15,526,589 13 November, 1997 13,554,370 - 13,554,370 14 December, 1997 13,677,712 - 13,677,712 ------------- ------------- ------------ 15 13 Month Average 14,800,754 0 14,800,754 16 Prepaid Pension Asset - 13 Month Average 23,698,126 (23,698,126) 0 ------------- ------------- ------------ 17 Total Prepayments-A/C 1650 - 13 Month Average 38,498,880 (23,698,126) 14,800,754 ============= ============= ============
28 EXHIBIT REM-1 Page 28 Attachment D SOUTHWESTERN ELECTRIC POWER COMPANY MATERIALS AND SUPPLIES FOR THE TWELVE MONTHS ENDED DECEMBER 31, 1997
(1) (2) (3) (4) (5) Line Schedule Total Company Pro Forma Total Company No. Description Reference Per Books Adjustments Pro Forma --- ----------- --------- --------- ----------- --------- 1 Monthly Balances: 2 December, 1996 $ 29,265,405 $ (2,980,061) $26,305,344 3 January, 1997 29,429,091 (2,952,801) 26,476,289 4 February, 1997 29,021,578 (2,911,519) 25,110,059 5 March, 1997 28,659,213 (2,904,994) 25,754,219 6 April, 1997 28,052,400 (2,975,724) 25,076,676 7 May, 1997 27,433,626 (2,941,392) 24,492,234 8 June, 1997 27,433,626 (2,957,154) 24,874,795 9 July, 1997 26,782,924 (2,936,799) 23,846,125 10 August, 1997 26,468,390 (2,895,251) 23,573,139 11 September, 1997 25,401,974 (2,863,676) 22,538,298 12 October, 1997 25,099,605 (2,955,520) 22,144,085 13 November, 1997 24,751,493 (2,886,700) 21,864,793 14 December, 1997 24,522,348 (1,779,483) 22,742,865 15 13 Month Average $ 27,132,307 $ (2,840,0831) $24,292,225 ============= ============== ===========
Purpose of adjustment - The adjustment is to remove the portion of materials and supplies associated with AECC's ownership portion of Flint Creek Power Plant. These materials and supplies are recorded on SWEPCO's books. 29 EXHIBIT REM-1 Page 29 Attachment D SOUTHWESTERN ELECTRIC POWER COMPANY FUEL INVENTORIES FOR THE TEST YEAR ENDING DECEMBER 31, 1997
Book Physical Inv. Ownership Optimal Level Pro Forma Description Balance Adjustment Adjustment Adjustment Balance ----------- ------- ---------- ---------- ---------- ------- Oil Lieberman Power Plan 662,928 - - - 662,928 Knox Lee Power Plant 381,320 - - - 381,320 Lone Star Power Plant 33,150 - - - 33,150 Wilkes Power Plant 274,691 - - - 274,691 Welsh Power Plant 250,999 - - - 250,999 Flint Creek Power Plant 444,367 - - - 444,367 Pirkey Power Plant - - - - Coal Welsh Power Plant 12,593,561 - - 24,047,174 2,629,794 Flint Creek Power Plant 5,538,390 1,605,614 (6,101,085) 7,946,486 8,989,405 Lignite Pirkey Power Plant 2,680,873 - (430,383) 379,304 2,629,794 Dolet Hills Power Plant 3,554,954 - (1,652,164) 4,904,668 6,807,457 Total Fuel Inventory 26,415,233 1,605,614 (8,183,633) 37,277,605 57,114,820 26,415,233 30,699,587 57,114,820
Purpose: The purpose of the optimal level adjustment is to increase fuel inventory for each coal power plant to 60 days of inventory and the Pirkey and Dolet Hills Lignite plants to 21 and 30 days of inventory, respectively. - -------------------------------------------------------------------------------
INVENTORY LEVEL ADJUSTMENT Optimal 12/31/97 Price Pro Forma Ownership Pro Forma Tons Per Ton Ending Bal. Adjustment Ending Bal. ---- ------- ----------- ---------- ----------- Welsh Power Plant 1,460,371 $ 25.09 36,640,708 36,640,708 Flint Creek Power Plant 486,790 $ 31.00 15,090,490 (2) (6,101,085) 8,989,405 Pirkey Power Plant 264,036 $ 11.59 3,060,177 (1) (430,383) 2,629,794 Dolet Hills Power Plant 384,179 $ 22.02 8,459,622 (1) (1,652,164) 6,807,457
PHYSICAL INVENTORY ADJUSTMENT
Optimal 12/31/97 Price Pro Forma Tons Per Ton Ending Bal. ---- ------- ----------- Flint Creek Power Plant 51,794 $ 31.00 1,605,614
(1) Pirkey Power Plant and Dolet Hills Power Plant are adjusted by their ownership percentages of total optimal time. (2) Flint Creek Power Plant is adjusted by AECC's portion of MWH's generated of the total optimal tons. 30 EXHIBIT REM-1 Page 30 Attachment D SOUTHWESTERN ELECTRIC POWER COMPANY CUSTOMER DEPOSITS FOR THE TWELVE MONTHS ENDED DECEMBER 31, 1997
(1) (2) (3) (4) (5) Line Schedule Total Company Pro Forma Total Company No. Description Reference Per Books Adjustment Pro Forma --- ----------- --------- --------- ---------- --------- 1 Monthly Balances: 2 December, 1996 $ 10,497,074 - $10,497,074 3 January, 1997 10,471,669 - 10,471,669 4 February, 1997 10,424,773 - 10,424,773 5 March, 1997 10,368,557 - 10,368,557 6 April, 1997 10,372,330 - 10,372,330 7 May, 1997 10,362,815 - 10,382,815 8 June, 1997 10,361,001 - 10,361,001 9 July, 1997 10,424,381 - 10,424,381 10 August, 1997 10,564,757 - 10,564,757 11 September, 1997 10,735,824 - 10,735,824 12 October, 1997 10,960,745 - 10,960,745 13 November, 1997 11,056,367 - 11,056,367 ------------- ----------- 14 December, 1997 11,353,235 - 11,353,235 ------------- ----------- TRANSMISSION SERVICES DEPOSITS 1 Monthly Balances: December, 1996 $ - $ - January, 1997 - - February, 1997 - - March, 1997 - - April, 1997 - - May, 1997 - - 16 June, 1997 645,419 - 645,419 17 July, 1997 1,315,314 - 1,315,314 18 August, 1997 1,128,219.74 - 1,315,314 19 September, 1997 1,259,137 - 1,259,137 20 October, 1997 2,103,977 - 2,103,977 21 November, 1997 3,115,623 - 3,115,623 ------------- --------- ----------- 22 December, 1997 3,005,348 - 3,005,348 ------------- --------- ----------- 23 TOTAL DECEMBER CUSTOMER DEPOSITS 14,358,583 0 14,358,583 ------------- --------- -----------
31 EXHIBIT REM-1 Page 31 Attachment D
Southwestern Electric Power Company Additional Deductions to Rate Base - Deferred Credits For the Test Year Ending December 31, 1997 Pro Forma Line Balance Balance No. Description 31-Dec-97 Adjustments 31-Dec-97 ---- ----------- --------- ----------- --------- 1 Miscellaneous Deposits 2,000 2,000 2 Bremco Liability 1,849,639 1,849,639 3 Property Salvage Proceeds 225,000 225,000 4 Non Rate Base 1,939,285 (1,939,285) 0 --------- ---------- -------- 4,015,924 (1,939,285) 2,076,639 ========= ========== =========
32 EXHIBIT REM-1 Page 32 Attachment D
Southwestern Electric Power Company Additional Rate Base Items For the Twelve Months Ending December 31, 1997 Total Company Total Company Pro Forma Line Balance Balance No. Description Dec. 31, 1997 Adjustments Dec. 31, 1997 ---- ----------- ------------- ----------- ------------- 1 Regulatory Assets: 2 AMAX Coal Contract 15,709,474 (1,963,684) 13,745,790 3 Ft. Davis R&D Project 2,473,338 0 2,473,338 4 South Tie Asset Costs 0 10,226,802 10,226,802 5 Severance Costs - W/P D-1-35 0 2,558,583 2,558,583 6 Fuel Litigation & Consulting Costs 0 18,488,452 18,488,452 7 Deferred Charges: 8 Deferred DSM Costs 0 5,097,942 5,097,942 9 Accum. Amort. Of Deferred DSM Costs 0 (933,053) (933,053) 10 Cajun Merger Costs Deferred 5,200,027 (5,200,027) 0 11 Deliberative Polling - TX 2,140,223 0 2,140,223 12 Rate Case Expenses - Estimated 0 2,950,000 2,950,000 13 Recoverable Inventory - W/P D-1-16 0 1,149,828 1,149,828 ---------- ---------- ---------- 14 Total 25,523,062 32,374,843 57,897,905 ========== ========== ==========
33 EXHIBIT REM-1 Page 33 Attachment D
SOUTHWESTERN ELECTRIC POWER COMPANY ACCUMULATED DEFERRED INCOME TAXES FOR THE TEST YEAR ENDED DECEMBER 31, 1997 Total Company Total Company Pro Forma Pro Forma Per Books Adjustments Balance ------------- ----------- ------------ ADIT Account 2820.xxxx (410,312,903) 9,516,867 (400,796,036) 2830.xxxx (74,840,339) 2,813,490 (72,026,849) 1900.xxxx 84,649,850 (7,250,961) 77,398,889 ------------ ---------- ------------ (400,503,392) 5,079,396 (395,423,996) ------------ ---------- ------------ Net reg asset/liability 2540.xxxx (114,668,688) - (114,668,688) 1823.xxxx 104,596,295 - 104,596,295 ------------ ---------- ------------ (10,072,393) - (10,072,393) Total - ADIT (410,575,785) 5,079,396 (405,496,389) ============ ========== ============ ITC Account 2550 Pre-71 (345,089) - (345,089) Post 70 (66,499,892) - (66,499,892) ------------ ---------- ------------ Total (66,844,981) - (66,844,981) ============ ========== ============
34 EXHIBIT REM-1 Page 34 EXHIBIT C Attachment D
SOUTHWESTERN ELECTRIC POWER COMPANY COMPONENTS OF CAPITAL FOR THE TEST YEAR ENDED DECEMBER 31, 1997 (1) (2) (3) (4) (5) Line Schedule Capital Pro-Forma Adjusted No. Description Reference Per Books Adjustments Capital ---- ----------- --------- --------- ----------- ------- 1 Long-Term Debt C-1 $ 639,524,230 $ -- $ 639,524,230 2 Preferred Stock C-2 34,312,853 (3,972,926) 30,339,927 3 Common Equity 702,235,261 3,972,926 706,208,187 --------------- ------------- ------------- 4 Total Capital $ 1,376,072,344 $ -- $1,376,072,344 =============== ============= ==============
SOUTHWESTERN ELECTRIC POWER COMPANY COMPONENTS OF CAPITAL FOR THE TEST YEAR ENDED DECEMBER 31, 1 (1) (6) (7) (8) Weighted Line Capital Cost Average No. Description Ratio Rate Cost ---- ----------- ------- ---- -------- 1 Long-Term Debt 46.47460817% 8.09611592% 3.76263800% 2 Preferred Stock 2.20482064% 7.34628663% 0.16197200% 3 Common Equity 51.32057119% 7.98351560% 4.09718600% ----------- ---------- ---------- 4 Total Capital 100.00% 8.02179600% ====== ==========
35 EXHIBIT REM-1 Page 35 Attachment D
SOUTHWESTERN ELECTRIC POWER COMPANY STATEMENT OF OPERATING INCOME FOR THE TEST PERIOD ENDING DECEMBER 31, 1997 Total Company Total Company Pro Forma Dec. 31, 1997 Adjustments Dec. 31, 1997 --------------- ----------------- ----------------- REVENUES Total Electric Operating Revenues $ 939,868,615 (20,463,304) $ 919,405,311 Fuel $ 383,007,632 (1,779,003) $ 381,228,629 Deferred Fuel (603,883) 603,883 0 Purchased Power 25,927,920 0 25,927,920 --------------- ----------------- ----------------- Total Fuel and Purchased Power $ 408,331,670 (1,175,120) $ 407,156,550 --------------- ----------------- ----------------- Operations Expense $ 147,627,296 (5,633,248) $ 141,994,048 Maintenance Expense 44,037,971 7,519,662 51,557,633 Depreciation Expense $ 91,093,281 17,179,415 $ 108,272,696 Amortization Expense 4,134,736 10,032,016 14,166,752 Other Taxes 55,962,212 (358,497) 55,603,716 Gain on Sale of Emission Allowances (135,568) 0 (135,568) --------------- ----------------- ----------------- Operating Expenses Before Income Taxes 342,719,928 28,739,348 371,459,277 --------------- ----------------- ----------------- Federal Income Taxes 43,174,551 (18,400,860) 24,773,691 Deferred Investment Tax Credit (4,662,444) 790,877 (3,871,567) State Income Taxes 4,764,450 (1,711,507) 3,052,943 --------------- ----------------- ----------------- Total Income Taxes 43,276,557 (19,321,490) 23,955,067 --------------- ----------------- ----------------- Net Operating Income $ 145,540,459 (28,706,042) $ 116,834,417 =============== ================= ================= Rate Base $ 1,447,123,502 $ 9,338,512 $ 1,456,462,014 Rate of Return 10.06% 8.02%
36 EXHIBIT REM-1 Page 36 Attachment D SOUTHWESTERN ELECTRIC POWER COMPANY ADJUSTMENTS TO OPERATING INCOME STATEMENT FOR THE TEST YEAR ENDED DECEMBER 31, 1997
WP D-1-2 WP D-1-3 WP D-1-4 WP D-1-5 WP D-1-1 Customer Adjust Auto OPEBS Total Company Factoring Deposit Depreciation & Purchase SFAS 106 Per Books Expenses Interest Amortization Assistance Adjustment Revenues Residential Sales $ 289,723,381 Commercial Sales 192,115,273 Industrial Sales 263,206,856 Pub St. & Highway Lighting 15,139,937 Other Sales to Public Authorities 12,084,316 ------------- ------------- ----------- ------------- ------------- ------------- $ 772,269,763 $ -- $ -- $ -- $ -- $ -- Off System Sales 146,915,557 Forfeited Discounts & Service Rev 3,073,881 Rent From Electric Property 1,958,632 Other Electric Revenue 15,650,781 Required Adjustment for Rate Filing 0 ------------- ------------- ----------- ------------- ------------- ------------- Total Electric Operating Revenues $ 939,868,615 $ -- $ -- $ -- $ -- $ -- Fuel $ 383,007,632 Deferred Fuel (603,883) Purchased Power 25,927,920 ------------- ------------- ----------- ------------- ------------- ------------- Total Fuel and Purchased Power $ 408,331,670 $ -- $ -- $ -- $ -- $ -- ------------- ------------- ----------- ------------- ------------- ------------- Operations Expense $ 147,627,296 9,327,765 846,680 (804,000) (783,931) Maintenance Expense 44,037,971 Depreciation Expense 91,093,281 17,179,415 Amortization Expense 4,134,736 2,062,072 Other Taxes 55,962,212 Gain on Sale of Emission Allowances (135,568) ------------- ------------- ----------- ------------- ------------- ------------- Operating Expenses Before Income Taxes $ 342,719,928 $ 9,327,765 $ 846,680 $ 19,241,487 $ (804,000) $ (783,931) ------------- ------------- ----------- ------------- ------------- ------------- Operating Income Before Income Taxes $ 188,817,016 $ (9,327,765) $ (845,680) $ (19,241,487) $ (804,000) $ (783,931) Federal Income Taxes $ 43,174,551 Deferred Investment Tax Credit (4,662,444) State Income Taxes 4,764,450 ------------- ------------- ----------- ------------- ------------- ------------- Total Income Taxes $ 43,276,557 $ -- $ -- $ -- $ -- $ -- ------------- ------------- ----------- ------------- ------------- ------------- Net Operating Income $ 145,540,459 $ (9,327,765) $ (845,680) $ (19,241,487) $ 804,000 $ 783,931 ============= ============= =========== ============= ============= =============
37 EXHIBIT REM-1 Page 37 Attachment D
WP D-1-6 WP D-1-7 WP D-1-8 WP D-1-9 WP D-1-10 WP D-1-11 Pension DSM Reclass Recognize Reverse Dues SFAS 87 Amortization Cr. Line and South Tie Central Lab Recorded Above Adjustment Adjustment Filing Fees Costs Revenues The Line ---------- ------------ ------------ --------- ----------- -------------- Revenues Residential Sales Commercial Sales Industrial Sales Pub St & Highway Lighting Other Sales to Public Authorities ----------- -------------- ---------- ------------- -------- ---------- $ -- $ -- $ -- $ -- $ -- $ -- Off System Sales Forfeited Discounts & Service Rev Rent From Electric Property Other Electric Revenue 2,842 Required Adjustment for Rate Filing Total Electric Operating Revenues ----------- -------------- ---------- ------------- -------- ---------- $ -- $ -- $ -- $ -- $ 2,842 $ -- Fuel Deferred Fuel Purchased Power ----------- -------------- ---------- ------------- -------- ---------- Total Fuel and Purchased Power $ -- $ -- $ -- $ -- $ -- $ -- ----------- -------------- ---------- ------------- -------- ---------- Operations Expense 2,057,720 (4,552,851) 145,693 (10,226,802) (70,714) Maintenance Expense Depreciation Expense Amortization Expense 832,978 2,045,360 Other Taxes Gain on Sale of Emission Allowances Operating Expenses Before Income ----------- -------------- ---------- ------------- -------- ---------- Taxes $ 2,057,720 $ (3,719,873) $ (145,693) $ (8,181,442) $ $ (70,714) ----------- -------------- ---------- ------------- ---------- Operating Income Before Income Taxes $(2,057,720) $ (3,719,873) $ (145,693) $ (8,181,442) $ 2,842 $ 70,714 Federal Income Taxes Deferred Investment Tax Credit State Income Taxes Total Income Taxes ----------- -------------- ---------- ------------- -------- ---------- $ $ $ $ $ $ ----------- -------------- ---------- ------------- -------- ---------- Net Operating Income $(2,057,720) $ 3,719,873 $ (145,693) $ 8,181,442 $ 2,842 $ 70,714 =========== ============== ========== ============= ======== ==========
38 EXHIBIT REM-1 Page 38 Attachment D
WP D-1-13 WP D-1-16 WP D-1-12 Amortization WP D-1-14 WP D-1-15 Reverse WP-D-1-1 of Litigation Inventor Fed. & State and Amortization Write-off & Increase Income Tax Consulting of Rate Reverse Allow Distribution Adjustments Costs Case Expense Laredo Expense Amortization C Expense ------------ ------------- ------------- -------------- ------------ ------------ Revenues Residential Sales Commercial Sales Industrial Sales Pub St. & Highway Lighting Other Sales to Public Authorities ____________ _____________ _____________ _____________ _____________ _____________ $ - $ - $ - $ - $ - $ - Off System Sales Forfeited Discounts & Service Rev. Rent From Electric Property Other Electric Revenue Required Adjustment for Rate Filing _____________ _____________ _____________ _____________ _____________ _____________ Total Electric Operating Revenues $ - $ - $ - $ - $ - $ - Fuel Deferred Fuel Purchased Power _____________ _____________ _____________ _____________ _____________ _____________ Total Fuel and Purchased Power $ - $ - $ - $ - $ - $ - _____________ _____________ _____________ _____________ _____________ _____________ Operations Expense (1,090,376) (1,149,828) Maintenance Expense 7,993,000 Depreciation Expense Amortization Expense 2,312,038 983,333 229,966 Other Taxes Gain on Sale of Emission Allowances _____________ _____________ _____________ _____________ _____________ _____________ Operating Expenses Before Income Taxes $ - $ 2,312,038 $ 983,333 $ (1,090,376) $ (919,862) $ 7,993,000 _____________ _____________ _____________ _____________ _____________ _____________ Operating Income Before Income Taxes $ - $ (2,312,038) $ (983,333) $ 1,090,376 $ 919,862 $ (7,993,000) Federal Income Taxes (18,400,860) Deferred Investment Tax Credit 790,877 State Income Taxes (1,711,507) _____________ _____________ _____________ _____________ _____________ _____________ Total Income Taxes $ (19,321,490) $ - $ - $ - $ - $ - _____________ _____________ _____________ _____________ _____________ _____________ Net Operating Income $ 19,321,490 $ (2,312,038) $ (983,333) $ 1,090,376 $ 919,862 $ (7,993,000) ============= ============= ============= ============= ============= =============
39 EXHIBIT REM-1 Page 39 Attachment D
WP D-1-20 WP D-1-18 WP D-1-19 Adjust WP D-1-21 WP D-1-23 Customer Other Property Fuel Adjust SFAS 112 Annualization Taxes Insurance Revenue Expense to Adjustment Adjustment Expense Adjustment "Pay-As-You-Go" ------------- --------- ---------- --------- -------------- Revenues Residential Sales 5,965,768 (15,167,323) Commercial Sales Industrial Sales Pub St & Highway Lighting Other Sales to Public Authorities ____________ _____________ _____________ _____________ _____________ $ 5,965,768 $ - $ - $ (15,167,323) $ - Off System Sales Forfeited Discounts & Service Rev. Rent From Electric Property Other Electric Revenue 266,408 Required Adjustment for Rate Filing _____________ ____________ _____________ _____________ _____________ Total Electric Operating Revenues $ 8,017,298 $ - $ - $ (15,167,323) $ - Fuel Deferred Fuel Purchased Power _____________ _____________ _____________ _____________ _____________ Total Fuel and Purchased Power $ - $ - $ - $ - $ - _____________ _____________ _____________ _____________ _____________ Operations Expense 655,615 473,500 Maintenance Expense Depreciation Expense Amortization Expense 0 Other Taxes (358,497) Gain on Sale of Emission Allowances _____________ _____________ _____________ _____________ _____________ Operating Expenses Before Income Taxes $ - $ (358,497) $ 655,615 $ $ 473,500 _____________ _____________ _____________ _____________ _____________ Operating Income Before Income Taxes $ 8,017,298 $ 358,497 $ (655,615) $ (15,167,323) $ (473,500) Federal Income Taxes Deferred Investment Tax Credit State Income Taxes _____________ _____________ _____________ _____________ _____________ Total Income Taxes $ - $ - $ - $ - $ - _____________ _____________ _____________ _____________ _____________ Net Operating Income $ 8,017,298 $ 358,497 $ (655,615) $ (15,167,323) $ (473,500) ============= ============= ============= ============= =============
40 EXHIBIT REM-1 Page 40 Attachment D
WP D-1-28 WP D-1-24 WP D-1-25 WP D-1-26 WP D-1-27 Amortization Adjustment Open Unbilled TFO of of CSWS Access Revenue Expense Deliberative Billings Adjustment Adjustment Adjustment Polling ---------- ------------ ----------- ---------- ------------ Revenues Residential Sales Commercial Sales Industrial Sales Pub St. & Highway Lighting Other Sales to Public Authorities ____________ _____________ _____________ _____________ _____________ $ - $ - $ - $ - $ - Off System Sales Forfeited Discounts & Service Rev. Rent From Electric Property Other Electric Revenue (169,000) Required Adjustment for Rate Filing _____________ ____________ _____________ _____________ _____________ Total Electric Operating Revenues $ - $ - $ (169,000) $ - $ - Fuel Deferred Fuel Purchased Power _____________ _____________ _____________ _____________ _____________ Total Fuel and Purchased Power $ $ $ $ $ _____________ _____________ _____________ _____________ _____________ Operations Expense (682,611) 6,290,574 (5,005,286) Maintenance Expense Depreciation Expense Amortization Expense 713,408 Other Taxes (358,497) Gain on Sale of Emission Allowances _____________ _____________ _____________ _____________ _____________ Operating Expenses Before Income Taxes $ (682,611) $ 6,290,574 $ - $ (5,005,286) $ 713,408 _____________ _____________ _____________ _____________ _____________ Operating Income Before Income Taxes $ 682,611 $ (6,290,574) $ (169,000) $ 5,005,286 $ (713,408) Federal Income Taxes Deferred Investment Tax Credit Sate Income Taxes _____________ _____________ _____________ _____________ _____________ Total Income Taxes $ - $ - $ - $ - $ - _____________ _____________ _____________ _____________ _____________ Net Operating Income $ 682,611 $ (6,290,574) $ (169,000) $ 5,005,286 $ (713,408) ============== ============== ============== ============== =============
41 EXHIBIT REM-1 Page 41 Attachment D
WP D-1-29 Reduce Fuel WP D-1-30 WP D-1-31 WP D-1-32 WP D-1-33 Exp. for Adjustment to RTP & STOU Eliminate Payroll Time of Use Mine Closing Revenue Walker Co. Annualization Sales Expense Adjustment Revenue Adjustment ----------- ------------- ---------- ---------- ------------- Revenues Residential Sales (2,561,349) Commercial Sales Industrial Sales Pub St. & Highway Lighting Other Sales to Public Authorities ____________ _____________ _____________ ____________ _____________ $ - $ - $ (2,561,349) $ - $ - Off System Sales Forfeited Discounts & Service Rev. Rent From Electric Property Other Electric Revenue (320,167) Required Adjustment for Rate Filing Total Electric Operating Revenues _____________ _____________ _____________ _____________ _____________ $ - $ - $ (2,561,349) $ (320,167) $ - _____________ _____________ _____________ _____________ _____________
42 EXHIBIT REM-1 Page 42 Attachment D
WP D-1-34 WP D-1-36 WP D-1-37 WP D-1-38 CSWS Payroll WP D-1-35 Wholesale Pro Forma Facilities Annualization Severance Refund Revenue Charges Adjustment Adjustment Adjustment Adjustment Adjustment ------------- ---------- ---------- ---------- ---------- Revenues - ----------------------------------- Residential Sales (35,052) (1,071,116) Commercial Sales Industrial Sales Pub St & Highway Lighting Other Sales to Public Authorities _____________ _____________ _____________ _____________ _____________ $ - $ - $ - $ (35,052) $ (1,071,116) Off System Sales (7,479,430) (88,990) Forfeited Discounts & Service Rev. Rent From Electric Property Other Electric Revenue 1,160,106 Required Adjustment for Rate Filing _____________ ____________ _____________ _____________ _____________ Total Electric Operating Revenues $ - $ - $ (7,479,430) $ (35,052) $ - Fuel 17,126 Deferred Fuel Purchased Power _____________ _____________ _____________ _____________ _____________ Total Fuel and Purchased Power $ 17,126 $ - $ - $ - $ - _____________ _____________ _____________ _____________ _____________ Operations Expense 642,156 (1,055,322) Maintenance Expense 6,671 Depreciation Expense Amortization Expense 852,861 Other Taxes Gain on Sale of Emission Allowances _____________ _____________ _____________ _____________ _____________ Operating Expenses Before Income Taxes $ 648,827 $ (202,461) $ - $ - $ - _____________ _____________ _____________ _____________ _____________ Operating Income Before Income Taxes $ (665,953) $ 202,461 $ (7,479,430) $ (35,052) $ - Federal Income Taxes Deferred Investment Tax Credit State Income Taxes _____________ _____________ _____________ _____________ _____________ Total Income Taxes $ - $ - $ - $ - $ - _____________ _____________ _____________ _____________ _____________ Net Operating Income $ (665,953) $ 202,461 $ (7,479,430) $ (35,052) $ ============= ============= ============== ============== =============
43 EXHIBIT REM-1 Page 43 Attachment D
WP D-1-39 Economic WP D-1-40 Development Deferred Rider Fuel Total Total Company Adjustment Adjustment Adjustments Pro Forma ----------- ---------- ----------- ------------- Revenues - ----------------------------------- Residential Sales 537,781 (3,288,904) (15,620,195) 274,103,185 Commercial Sales 0 192,115,273 Industrial Sales 0 263,206,856 Pub St. & Highway Lighting 0 15,139,937 Other Sales to Public Authorities 0 12,084,316 _____________ ____________ ____________ _____________ $ 537,781 $ (3,288,904) $(15,620,195) $ 756,649,568 Off System Sales (5,783,298) 141,132,259 Forfeited Discounts & Service Rev. 0 3,073,881 Rent From Electric Property 0 1,958,632 Other Electric Revenue 940,189 16,590,971 Required Adjustment for Rate Filing 0 0 _____________ ____________ ____________ _____________ Total Electric Operating Revenues $ 537,781 $ (3,288,904) $(20,463,304) $ 919,405,311 Fuel (1,779,003) 381,228,629 Deferred Fuel 603,883 603,883 0 Purchased Power 0 25,927,920 _____________ ____________ ____________ _____________ Total Fuel and Purchased Power $ - $ 603,883 $ (1,175,120) $ 407,156,550 _____________ ____________ ____________ _____________ Operations Expense 537,781 $ (5,633,248) $ 141,994,048 Maintenance Expense 7,519,662 51,557,633 Depreciation Expense 17,179,415 108,272,696 Amortization Expense 10,032,016 14,166,752 Other Taxes (358,497) 55,603,716 Gain on Sale of Emission Allowances 0 (135,568) _____________ ____________ ____________ _____________ Operating Expenses Before Income Taxes $ 537,781 $ - $ 28,739,348 $ 371,459,277 _____________ ____________ ____________ _____________ Operating Income Before Income Taxes $ - $ (3,892,787) $ (48,027,532) $ 140,789,484 Federal Income Taxes $ (18,400,860) 24,773,691 Deferred Investment Tax Credit 790,877 (3,871,567) State Income Taxes $ (1,711,507) $ 3,052,943 _____________ ____________ ____________ _____________ Total Income Taxes $ - $ - $ (19,321,490) $ 23,955,067 _____________ ____________ ____________ _____________ Net Operating Income $ $ (3,892,787) $ (28,706,042) $ 116,834,417 ============= ============= ============= =============
EX-99.D.4.2 5 ORDER OF OK APPROVING THE MERGER 1 Exhibit D-4.2 BEFORE THE CORPORATION COMMISSION OF THE STATE OF OKLAHOMA JOINT APPLICATION OF AMERICAN ) ELECTRIC POWER COMPANY, INC., ) PUBLIC SERVICE COMPANY OF ) OKLAHOMA AND CENTRAL AND SOUTH ) CAUSE NO. PUD 980000444 WEST CORPORATION REGARDING ) PROPOSED MERGER ) ORDER NO. 432267 HEARING: April 19, 20 and 21, 1999 Before Robert E. Goldfield, Administrative Law Judge May 11, 1999, before the Commission en banc APPEARANCES: Cody L. Graves, Attorney for American Electric Power Company, Inc. Jack P. Fite, Clark Evans Downs and Jay M. Gait, Attorneys for Public Service Company of Oklahoma and Central and South West Corporation Deborah Jacobson, Assistance General Counsel for the Public Utility Division of the Oklahoma Corporation Commission Marchi C. McCartney and Jeffrey P. Southwick. Staff Counsel for Consumer Services Division of the Oklahoma Corporation Commission Deborah R. Morgan, Assistant Attorney General. Counsel for the Office of the Attorney General Patrick D. Shore. Attorney for the Oklahoma Association of Electric Cooperatives C. Max Speegle. Attorney for Municipal Electric Systems of Oklahoma Robert D. Steward, Jr. and Harry H. Selph, II. Attorneys for Oklahoma Gas and Electric Company 2 FINAL ORDER BY THE COMMISSION The Corporation Commission of the State of Oklahoma ("Commission"), being regularly in session, and the undersigned Commissioners being present and participating, there comes on for consideration and action the report of the Administrative Law Judge in the above-entitled Cause and the appeals thereto. The procedural history in this Cause is set forth at pages 2 and 3 of the Report and Recommendations of the Administrative Law Judge ("Report") and is incorporated herein as if fully set forth. SUMMARY OF EVIDENCE The Summary of Evidence found on pages 7 through 58 of the Report is adopted as the Summary of Evidence of the Commission. Oklahoma Association of Electric Cooperatives ("OAEC") and Municipal Electric Systems of Oklahoma ("MESO") filed appeals to the Report and argued that 17 O.S. Section 191.5 does not authorize or allow the exercise of "conditional approval" by the Commission of a merger. They argued that the statute provides that a merger application shall be approved unless one of the five conditions is found, in which case the merger shall be disapproved. They argued that the ALJ found that market power would exist and competition in Oklahoma would be harmed, and therefore the ALJ's "conditional approval" was beyond the jurisdiction of the Commission. (See the Report, at page 58.) OAEC and MESO further argued that as a result of this finding, under the above statute, the Commission was without discretion, and must deny the merger. 2 3 OG&E argued that if the Commission determined, as a matter of law, that it does not have the authority to approve the merger with conditions, the request for approval of the merger should be rejected. In the alternative, if the Commission found as a matter of law that the Oklahoma merger statute (17 O.S. Sections 191.1 et seq.) did permit approval by the Commission of a merger subject to conditions. OG&E suggested various conditions. OG&E stated that if the merger should go forward, that the market and public interest should be protected from any negative impact of the merger. OG&E also noted its disagreement with the ALJ as to the recommendation regarding line loss being exclusively a Federal Energy Regulatory Commission jurisdictional issue. It is the position of OG&E that this Commission does have jurisdiction over the line loss issue. OG&E counsel stated that an OG&E witness, Stephen Heibson, quantified the line loss issue to be worth at least $15 million over a 10 year period, as a direct result of the merger and, OG&E's customers should not have to bear the cost of that loss. OG&E stated that the Southwest Power Pool ("SWPP") should be recognized as the final arbitrator as to the mitigation of the congestion issue, and requested that the Commission direct the parties to go to the SWPP to establish appropriate mitigation measures. OG&E recommended that the Merger be denied for now, without prejudice, until the Applicants could show that the conditions recommended by this Commission are met and then, upon a showing by the Applicants that the conditions have been met, the merger could go forward without harm. The Joint Applicants' Brief in Support of the ALJ's Report and arguments before the Commission, disputed characterization of the ALJ's Report made by MESO and OAEG. Specifically, the ALJ did not find the existence of the statutory standard that "substantial" harm 3 4 would be caused to competition. The ALJ further found that the impact of the merger which would lessen competition was "negated" by the Joint Applicants' commitment to engage in joint planning. Specifically, the ALJ's Report states as follows on page 58: "The primary areas of inquiry raised by Intervenor OG&E and others, relating to whether the merger would lessen competition in the furnishing of public utility service in the state, is negated by the Joint Applicants' commitment to engage in joint planning and the involvement of the Southwest Power Pool." (emphasis supplied) The Joint Applicants argued that the ALJ had not found any of the conditions existed which would require the Commission to deny the merger. The Joint Applicants argued that the order issued in the Southwestern Public Service Company ("SPS") Public Service Company of Colorado ("PSO") merger approval case (PUD 960000231) was a similar order as that recommended by the ALJ. The Commission's order, Order No. 405423, approved a Stipulation which required studies of the proposed interconnection between SPS and PSCO to be performed. Alternatives to the proposed interconnection, including using existing high-voltage, direct current interconnections, were to be examined. Another required study was to examine the options and the cost of expanding import and export capability between SPS's system and the Southwest Power Pool. By following the recommendations of the ALJ, it was argued the Commission is stating that none of the conditions exist if the Stipulation is approved and the Southwest Power Pool is engaged. MESO and OAEC argued it was error for the ALJ to strike a portion of Dr. Sinclair's testimony as being outside of the parameters of the study guidelines approved for use 4 5 in this case by Order No. 430244. The essence of their argument is that only the Joint Applicants were subject to the guidelines approved in Order No. 430244. Further, it was presented that the testimony was relevant and should be given an appropriate weight by the Court. The Commission finds this argument unpersuasive. All parties agreed to the guidelines, and it was the testimony of OG&E's witness that OG&E felt bound by the Commission's order. It is the Commission's decision that all parties were bound by the guidelines contained in Order No. 430244. (Attached as Attachment B for reference.) FINDINGS OF FACT AND CONCLUSIONS OF LAW After considering the Report of the Administrative Law Judge and the arguments made during the hearing on exceptions, the Commission makes the following findings of fact and conclusions of law: The Commission finds that it has jurisdiction over this merger and the authority to issue this order pursuant to 17 O.S. Section 191.1 et seq. and OAC 165:5-7-57. Further, this Commission has jurisdiction over Public Service Company of Oklahoma regarding retail rates, and the effect that the merger might have on those rates, pursuant to 17 O.S. Section 152.153 and Okla. Const. Art. 9, Section 18. Based upon the argument of counsel and an examination of the ALJ's findings and recommendations, the Commission finds that the adoption of the ALJ's Report and the recommendations contained therein is within this Commission's jurisdiction. This Commission issues many orders which contain directives. It is not unusual for this Commission to allow an applicant permission to perform some activity (such as in oil and gas orders) and to take other actions such as implementing a new tariff if certain directives are followed. This case is no different. All parties except OAEC and MESO stated that this Commission had the authority to 5 6 issue an order which would contain directives. This Commission is of the opinion that its order in the SPS case was proper and that an order in this Cause adopting the ALJ's Report is within the jurisdiction of this Commission. The Commission further finds that the ALJ acted within the scope of his authority to limit the testimony to the agreed upon study parameters which were found in Order No. 430244. The Commission further finds that although competition would be lessened as a result of this merger, it does not meet the level required under Section 191.5(A)(2), that competition would be "substantially" lessened, and therefore, the Commission finds that the condition contemplated under the statute does not exist. This Commission further finds that the safeguards are present and that it will continue to have jurisdiction over retail electric competition in this state. The Attorney General for the State of Oklahoma ("Attorney General") recommended to the Commission that the ALJ Report be adopted as a fair and reasonable balance of the interests of the parties involved. The Attorney General further noted that the SWPP is a forum in which both the Applicants and OG&E are members, and as such, should receive fair consideration. Staff recommended that the ALJ Report be adopted as the order of this Commission. The Staff believes that congestion does exist on the system, and recommends further study on this issue. Staff noted that the Applicants is to divest certain assets to address some market power concerns. Certain mitigation measures are addressed (see page 7, Section 7 of the Stipulation, Attachment A) which are designed with the intention to allow entry into the competitive market. The Applicants commit to hold the current jurisdictional customers 6 7 harmless and identify that the merger does not create any stranded costs. The Applicants also have committed to regional planning, either through an Independent System Operator ("ISO") or a Regional Transmission Organization ("RTO"). The Commission having considered the record in this Cause and the Appeals to the Report, adopts the Findings of Fact and Conclusions of Law contained within the Report of the Administrative Law Judge as the findings of fact and conclusions of law of the Commission. The Commission therefore finds that the merger should be approved, consistent with the recommendations of the ALJ's report. ORDER IT IS THEREFORE THE ORDER OF THE CORPORATION COMMISSION OF THE STATE OF OKLAHOMA that the findings of the Administrative Law Judge be adopted as the Findings and Conclusions of this Commission. IT IS FURTHER ORDERED that the recommendations of the Administrative Law Judge, including the Stipulation attached thereto, are hereby adopted by the Commission. Said Report is attached to this order as "Attachment A". IT IS FURTHER ORDERED that the merger between American Electric Power Company, Inc., Public Service Company of Oklahoma and Center & Southwest Corporation is hereby approved consistent with the Report of the Administrative Law Judge. CORPORATION COMMISSION OF OKLAHOMA /s/ED APPLE, Chairman /s/BOB ANTHONY, Vice-Chairman /s/DENISE A. BODE, Commissioner Done and performed this 17th day of May, 1999. 7 8 BY ORDER OF THE COMMISSION: /s/CHARLOTTE W. FLANAGAN, Secretary 8 9 BEFORE THE CORPORATION COMMISSION OF THE STATE OF OKLAHOMA JOINT APPLICATION OF AMERICAN ) ELECTRIC POWER COMPANY, INC., ) PUBLIC SERVICE COMPANY OF ) OKLAHOMA AND CENTRAL AND ) CAUSE NO. PUD 98 0044 SOUTH WEST CORPORATION ) REGARDING PROPOSED MERGER ) HEARING: April 19, 20 and 21, 1999 Before Robert E. Goldfield, Administrative Law Judge APPEARANCES: Cody L. Graves, Attorney for American Electric Power Company, Inc. Jack P. Fite, Clark Evans Downs and Jay M. Galt, Attorneys for Public Service Company of Oklahoma and Central and South West Corporation Deborah Jacobson, Assistant General Counsel for the Public Utility Division of the Oklahoma Corporation Commission Marchi C. McCartney and Jeffrey P. Southwick, Counsel for Consumer Services Division of the Oklahoma Corporation Commission Deborah R. Morgan, Assistant Attorney General, Counsel for the Office of the Attorney General Patrick D. Shore, Attorney for the Oklahoma Association of Electric Cooperatives C. Max Speegle, Attorney for Municipal Electric Systems of Oklahoma Robert D. Stewart, Jr. and Harry H. Selph, II, Attorneys for Oklahoma Gas and Electric Company 10 REPORT AND RECOMMENDATIONS The following is the Report and Recommendations of the Administrative Law Judge ("ALJ") regarding the Joint Application of American Electric Power Company, Inc. ("AEP"), Public Service Company of Oklahoma ("PSO") and Central and South West Corporation ("CSW") regarding a proposed merger. I. PROCEDURAL HISTORY On August 14, 1998, AEP, PSO and CSW ("Applicants" or "Joint Applicants") filed a Joint Application and Statement requesting this Commission approve a proposed business combination in which CSW operating companies and subsidiaries, including PSO, would become operating companies and subsidiaries of AEP. The Office of the Attorney General ("AG"), Oklahoma Association of Electric Cooperatives ("OAEC"), Municipal Electric Systems of Oklahoma, Inc. ("MESO"), International Brotherhood of Electrical Workers ("IBEW"), Oklahoma Gas and Electric Company ("OG&E"), the Consumer Services Division ("CSD") of the Oklahoma Corporation Commission ("OCC") and the Public Utility Division of the OCC ("PUD" or "Staff") were granted intervention. On September 25, l998, OG&E filed a Motion to Compel or Dismiss Application. Also on that date OAEC filed a Motion to Strike Testimony or Dismiss the Application. The Joint Applicants filed a Motion to Withdraw Statement filed October 15, 1998. By agreement of the parties, the Motion was presented to the ALJ on October 20, 1998. The parties objected to the Commission granting the Motion as amended by the Joint Applicants. The Commission thereafter issued Order No. 427699 granting the Motion to Withdraw Statement and holding in suspense the time frame contained within 17 O.S. Section 191.2 and ordering that a new 2 11 time would commence on the filing of a new Statement upon which the Joint Applicants would rely for their relief requested in the Cause. On October 26, 1998, this Commission issued Order No. 427700 (Order Regarding Discovery) which stated that the Joint Applicants could file a new Statement as required by 17 O.S. Section 191.2 which was to include a retail market study and load flow analysis as described in the Order after which the statutory time limits contained within 17 O.S. Section 19l.5(b) would commence. On November 30, 1998, this Commission issued Order No. 428530 (Amended Scheduling Order) which was superceded by Order No. 429667, which granted the AG's Motion to Hold the Hearing in Abeyance. On February 25, 1999, the Joint Applicants filed its Amended Statement and Application after which a Second Amended Scheduling Order (Order No. 430719) was issued March 9, 1999. On April 1, 1999, the Joint Applicants filed a Motion to Strike the Testimony of Dr. Sinclair as being contrary to the directives of Order No. 430244, issued February 16, 1999. Based upon the argument of counsel the ALJ struck page 30, line 25 through page 33, line 2 and Exhibit RAS-2. An exception to this ruling was noted to MESO and the OAEC. On April 15, 1999, OG&E filed a Motion to Strike the Rebuttal Testimony of Raymond M. Maliszewski. The oral arguments were held on April 19, 1999, prior to the taking of testimony. Based upon the arguments of counsel, the ALJ struck page 14, beginning with line 8 through page 16, line 13 and page 23, line 11 (the word "Furthermore") through line 15 (the end of the sentence with the word "occur") and Exhibits RMM-4 and RMM-5 of Mr. Maliszewski's testimony. An exception was noted for the Joint Applicants. 3 12 The trial on the merits was held before the ALJ on April 19, 20 and 21, 1999. II. SUMMARY OF STIPULATION The Joint Applicants, PUD, CSD, and AG announced that a stipulation had been reached on various issues between the parties. Mr. David Carpenter testified on behalf of the Joint Applicants in support of the Stipulation (Exhibit No. 209, attached to this Report). DAVID G. CARPENTER Mr. Carpenter testified that the Stipulation provides for net non-fuel and non-purchase power O & M savings to be shared through a net merger savings rate rider over the next five years after the effective date of the merger. Attachment 1 of the Stipulation, column 5, reflected the annual amount of rate reduction which would be reflected in the rate reduction rider over the next five years. In the sixth year after the effective date of the merger, the customer rate reduction rider would increase to $9,409,000 until the next base rate proceeding after the end of the fifth year at which time the net merger savings rate reduction rider will be terminated [pp. 176-177]. Mr. Carpenter further testified that the Stipulation provided that the cost to achieve the merger would be deferred and amortized. Costs to achieve the merger are those costs which are incurred within the time period ending two years after the effective date of the merger. Those costs will be deferred and amortized over a five-year period of time. Attachment 2 sets forth the allocation of the net merger savings rider between customer classes. Attachment 3 contains an example of how merger savings will be treated in future base rate cases. The example used was based upon year three after the effective date of the merger. Mr. Carpenter explained how the net merger savings for the test year were arrived at, and then how the add-back to the test year cost of service of the Oklahoma customer rate reduction would be $5,878,000. 4 13 Mr. Carpenter also gave an example if the merger savings were $5 million higher than predicted and how the formula worked so that retail customers received all of the additional merger savings over and above those set forth in Attachment 1. In the event that the electric utility industry in Oklahoma is restructured, and the services provided by PSO are unbundled into regulated and unregulated services, the merger savings and associated amortization and shareholder imputation will continue. Therefore, customers will continue to receive the full level of merger savings on the regulated portion of the rates. In the event that a general rate proceeding is initiated by a party other than PSO, subsequent to industry restructuring and prior to the end of the fifth year, then the rider benefits, cost amortization, and shareholder net savings amputations shall be reduced proportionally to the rates of the unregulated, unbundled services. Fuel and purchase power expense savings derived from the merger will be flowed through the fuel adjustment clause to customers in accordance with the current practice. Other provisions of the Stipulation provide for the Staff and AG to have access to copies of books and records of AEP and its affiliates as necessary to review the transactions of PSO. The Joint Applicants have also agreed that stranded costs, if any that PSO may seek to recover in the future will be on a stand-alone basis and that PSO does not have any stranded costs currently. Further, the merger does not create any stranded costs. Mr. Carpenter testified that the agreement holds harmless Oklahoma retail customers from any adverse effects of the mitigation plan filed at the FERC. Section 8 of the Stipulation states that the Joint Applicants will not seek to increase base rates prior to January 1, 2003, except for certain Force Majeure provisions. If a review is sought by the Joint Applicants from January 1, 2003 through the end of the fifth year after the effective 5 14 date of the merger, then the Joint Applicants will make a $5 million reduction to a revenue requirement otherwise determined to be reasonable by the Commission. The Force Majeure provisions found in Section 9 provide that PSO will have the burden of proving that its request for relief is a good faith request, that the event or occurrence was not directly or indirectly caused by PSO, that the occurrence has at least an annual impact of $6 million, and that PSO has no direct or indirect control over the event or occurrence. The agreement also has provisions regarding a hold harmless for PSO's cost of capital, a commitment to comply with quality of service standards which were set forth in Attachment 5, a most favored nations provision which provides that Oklahoma retail customers will receive the same equivalent net benefits and conditions as any other state related to settlements of the merger case or orders related to the merger. In addition, a hold harmless provision for retail customers from any unforeseen events that materially diminished the estimated benefits of the merger is contained in the Stipulation. The Stipulation at Section 15 contains an agreement that states that if the merger is not consummated, PSO would not seek to recover merger-related transition, transaction, or termination fees from Oklahoma retail customers. Section 16 states that PSO will not incur any debt or pledge the stock of PSO in a manner that, upon an affiliate's default, would permit a creditor to have recourse against the regulated assets of PSO. Section 17 is a commitment by the Joint Applicants to join a regional transmission authority by the latter of six months prior to retail customer choice or December 31, 2001. 6 15 The agreement also provides for Joint Applicants to notify the Commission at the time the merger is closed and the agreement becomes effective. Further, the agreement is to not be precedential for other proceedings in the future. Mr. Carpenter recommended that the Stipulation be approved. Pursuant to a question from the Attorney General's office, Mr. Carpenter stated that if a rate case takes place after year five from the effective date of the closing, Section 3(d) provides there will be no estimated non-fuel operation and maintenance expense savings included in the cost of service. There will be no amortization of costs to achieve included in the cost of service and the merger savings rate reduction rider will terminate. In essence, everything will be the same in setting rates as before the merger. At the conclusion of Mr. Carpenter's testimony the Joint Applicants moved into the record the pre-filed testimonies of Mr. Mark Bailey (Exhibit Nos. 21 and 78); Mr. David Carpenter (Exhibit No. 120); Mr. Russell Davis (Exhibit Nos. 16 and 121); Dr. Linn Draper (Exhibit No. 10); Mr. Bruce Evans (Exhibit Nos. 20 and 77); Mr. Richard Munczinski (Exhibit Nos. 14, 74, 118, 133 and 195); Mr. Thomas Mitchell (Exhibit Nos. 18 and 122); Mr. Armando Pena (Exhibit 19); Mr. Thomas Shockley (Exhibit No. 11); and Mr. Eric Zausner (Exhibit No. 138). The Joint Applicants submitted the testimony as support for the Stipulation and there were no objections to allowing the testimony to be submitted into the record and relied upon by the ALJ with all parties waiving cross-examination of those particular witnesses. The following witnesses pre-filed testimony in this Cause regarding issues that were settled in the Stipulation: Mr. Bill Burnett (Exhibit No. 111) on behalf of CSD; Ms. Evelyn H. Francik (Exhibit No. 58), Ms. Roya Z. Soltani (Exhibit No. 57) and Mr. Robert C. Thompson (Exhibit No. 113) on behalf of PUD; and Mr. Michael L. Brosch (Exhibit Nos. 114 and 170) on 7 16 behalf of the AG. Cross-examination of these witnesses was waived and since their testimony was filed prior to an agreement being reach, their testimony should be conformed to the Stipulation. III. SUMMARY OF EVIDENCE THOMAS J. FLAHERTY Mr. Thomas J. Flaherty, the National Partner - Energy Consulting and a partner in the Deloitte & Touche Consulting Group LLC (Deloitte Consulting) testified on behalf of the Joint Applicants. Mr. Flaherty's testimony contained within Exhibits 12 and 119 was accepted into the record without objection. According to Mr. Flaherty, the merger of the Joint Applicants is anticipated to result in cost savings that should permit rates in the future to be below the level that otherwise would have been necessary on a stand-alone basis for either AEP or CSW operating companies. The merger is estimated to produce approximately $2.4 billion of nonproduction cost savings, before approximately $248 million of out-of-pocket costs to achieve these savings, and $193 million of cost cutting measures planned or initiated by each of the Companies prior to the merger ("premerger initiatives"), and is expected by management of AEP and CSW to provide an opportunity to benefit all stakeholders, including customers, shareholders and employees, and result in a stronger, more competitive company. The estimated nonproduction cost savings reflect the potential creation of cost reduction or cost avoidance opportunities through the ability to consolidate separate, stand-alone operations into a single entity. This consolidation and integration thus may enable duplicative functions and positions to be eliminated, similar corporate activities to be combined, avoided or reduced in scope, external purchases of commodities and services to be aggregated, and capital expenditures to be avoided. The savings, by category, were identified as follows: 8 17 Total Nonproduction Cost Savings
1999 - 2009 Savings Category ($ Millions) -------------------------------------------------------------- Corporate and Operations Support Staffing 996 Corporate and Administrative Programs 1,044 Purchasing Economies (Nonfuel) 367 ----- Total Savings 2,407 Less: Costs to Achieve (248) Premerger Initiatives (193) ----- Net Savings 1,966 =====
Recent utility mergers and acquisitions in other states have produced substantial benefits to customers in the form of operational synergies and cost savings that reduce rates or slow the rate of growth in rates. Benefits to customers, however, will not materialize without costs being incurred and risks being assumed. In merger transactions, shareholders assume the risk that the merged entity will achieve the strategic, financial, and operational benefits set forth as the rationale for the proposed combination. To the extent these objectives are not attained (e.g., failing to realize cost savings), shareholders suffer from eroded equity value and/or lower returns. It is a well established regulatory principle that, to compensate for these risks and to reflect the shareholders' willingness to fund the costs necessary to realize potential cost savings, the costs to achieve both these savings and the underlying transaction should be fully recovered and the resulting net cost savings should be equitably shared with shareholders. Mr. Flaherty testified that based on his experience in other mergers, and on his direct involvement with the identification, evaluation, and quantification efforts related to estimated cost savings in this and other transactions, the process utilized by the Joint Applicants for estimating potential merger cost savings was consistent with the process utilized by other companies in previous merger transactions. Consequently, Mr. Flaherty believes that the level of 9 18 merger savings identified by the Joint Applicants is reasonably attainable provided that management of the combined company executes its integration plans in a manner consistent with its intent and how other utilities have pursued similar opportunities. In response to questions from Mr. Shore, Mr. Flaherty testified that he had done studies in other merger cases where the companies were physically separated [p. 20]. Those included Public Service Company of Colorado and Southwestern Public Service Company, Wisconsin Power and Light, Iowa Electric Light and Power and, Interstate Power, and, Washington Water Power and Sierra Pacific Resources [p. 19]. Mr. Flaherty further testified that as a general proposition, there arc more synergies for saving money when two merging companies are similarly-sized entities. AEP and CSW are not similarly-sized utilities. Mr. Flaherty further testified that studies regarding possible merger benefits had been conducted on two prior occasions in 1997, and that the results in those undertakings were similar in total amounts as the work which was performed subsequent to the announcement of the merger [p. 25]. In answering questions from Mr. Stewart, Mr. Flaherty testified that the total savings were approximately S2 billion [p. 28]. In calculating proposed merger savings, Mr. Flaherty used 3% for general inflation, 4% for wages and salaries, and 5% for certain other professional services category as escalation factors. The escalation factors reflected the Joint Applicants' stand-alone forecast assumptions as well as from the Conference Board Group, which includes some 50 economists [p. 34]. WILLIAM HIERONYMOUS Dr. William Hieronymous, Senior Vice-President of PHB-Hagler Bailly, testified on behalf of the Joint Applicants. Dr. Hieronymous' testimony contained in Exhibits 17, 80, 137 10 19 and 193 was accepted into the record without objections. Dr. Hieronymous prepared the Applicants' analysis of the competitive effects of the merger, and sponsored both direct and rebuttal testimony for this proceeding. Dr. Hieronymous' testimony was based on the FERC's requirements and this Commission's order relating to the effect of the merger on retail competition in Oklahoma. His fundamental conclusion is that the merger has no substantial negative impact on competition. The analysis conducted according to FERC requirements showed no negative impact on any Oklahoma market when the Applicants' proposed mitigation measures are taken into account. Sensitivities were conducted that assumed greater transmission capability, lower transmission rates and AEP joining the Midwest ISO. These showed a similar lack of impact on competition. His analysis demonstrates that the merger will not turn CSW and PSO into significantly more powerful competitors in Oklahoma. AEP historically has made no sales whatsoever into Oklahoma. According to Dr. Hieronymous, AEP is not a competitor in the Oklahoma market today, nor is it likely to become one because it has more lucrative markets elsewhere. The 250 MW transmission path that CSW has reserved to implement the System Integration Agreement does have a small competitive impact on the market. By bringing 250 MW of low cost AEP power into CSW, irrespective of whether AEP has better alternatives elsewhere, the merger creates savings for Oklahoma consumers. It also increases Applicants' market share. To mitigate the impact of the 250 MW transfer, Applicants have offered to sell 550 MW of capacity to competitors which helps deconcentrate those markets in Oklahoma and Texas in which CSW was the largest seller. Pursuant to this Commission's Order No. 427700, his direct testimony also includes an analysis of the impacts of loop flow on market power. The transfer of AEP energy through 11 20 Ameren causes somewhat greater loop flow effects than the imports it replaces. This results in an increase in concentration in some third-party markets in some time periods. Applicants' share of these markets is small and, indeed, smaller than CSW's share was before the merger. Any increase in concentration is due to the increased market share of the incumbent in that market, not CSW. His rebuttal testimony addresses the supposed harm that the merger causes to competition in these non-CSW areas. The Applicants do not gain market power. According to Dr. Hieronymous, no intervenor has presented evidence to demonstrate that the merger of CSW with AEP will cause CSW to have increased market power. The supposed harm from the merger is that it caused Applicants to reserve transmission that no other party wanted to reserve. Applicants have mitigated any increase in their own market share that results. He rejected OG&E's position that Applicants must also mitigate the increase in OG&E's market share. The idea that a party that contracts for firm transmission service must compensate any other party that is adversely affected by resulting loop flows is directly contrary to FERC policy. The fact that the contract was related to a merger does not clothe unintended and minor effects of loop flow on third parties with any market power significance. The other market power issue raised by Intervenors is whether Applicants' mitigation effectively transfers control to the buyer of the interim contract of the divested capacity. The interim contract fully transfers the economic interest in the contracted power. This reduction in Applicants' share of the market is the purpose of the mitigation. Because Applicants must deliver on the contract under all foreseen circumstances, the fact that they have not transferred direct ownership in any specific plant does not matter. 12 21 Concerning the divestiture of the Northeastern capacity, Intervenors' complaint is that PSO will continue to be the plant operator and will control the timing of scheduled outages. Abuse of such control would require scheduling outages when prices are predictably high. Even if one ignores the regulatory response to this action, the fact is that the owner of the divested capacity would have grounds to sue CSW and have every prospect of collecting damages. On cross-examination by Mr. Selph, Dr. Hieronymous testified that his firm developed a competitive analysis screening model designed to address issues and analysis that are required by Appendix A of the FERC Merger Policy Statement which his firm used in regard to this merger [p. 45, ls. 10-17]. The model provided a method to identify whether the merger presents market power concerns [p. 45, ls. 18-21]. In the Merger Policy Statement, FERC adopted the Department of Justice/Federal Trade Commission Merger Guidelines which are intended to evaluate the competitive effects of a proposed merger on competition [p. 45, ls. 24-25 and p. 46, ls. 1-9]. The Guidelines set out steps for merger analysis to assess, among other things, market concentration by use of the Herfindahl-Hirschman Index ("HHI") [p. 46, ls. 10-21]. Dr. Hieronymous testified that in regard to the AEP-CSW merger, his firm's screening model for economic capacity before mitigation identified five (5) screen failures outside of CSW, four of which occurred in the State of Oklahoma [p. 46, ls. 22-25 and p. 47, ls. 1-4]. He stated that the model showed an HHI change for the summer peak period of 66 points relating to OG&E and 57 points relating to Western Farmers Electric Cooperative ("Western Farmers") [p. 47, Is. 20-22 and p. 48, ls. 4-9]. He also stated that the model showed an HHI change for the summer off-peak period of 175 points relating to OG&E and 70 points relating to Western Farmers [p. 47, ls. 23-25 and p. 48, ls. 10-11]. He stated that under the Guidelines, for a highly concentrated market, if the HHI change exceeds 50, the Guidelines provide that the merger potentially raises 13 22 significant competitive concerns and if the change in HHI exceeds 100, it is presumed that the merger is likely to create or enhance market power, absent mitigation [p. 48, ls. 12-19]. Dr. Hieronymous stated that the Applicants' merger proposal includes mitigation so he is principally looking at the results of the merger inclusive of the proposed mitigation [p. 48, l. 25 and p. 49, ls. 1-3]. Dr. Hieronymous accepted the assertion that the Applicants' 250 megawatts reservation results in the reduction in import capability into some of the Oklahoma destination markets [p. 49, ls. 18-25 and p. 50, l. 1]. He also stated that the reservation does have some adverse impacts on the availability of transmission into Oklahoma [p. 50, ls. 5-11]. On redirect examination, Dr. Hieronymous testified that his studies pointed out that, after mitigation, the summer peak and summer off-peak periods in terms of the concentrating effect of the transfer on OG&E's and Western Farmers' markets showed a change in HHI of -5 points and -23 points, respectively, as to OG&E and -47 points and -48 points, respectively, as to Western Farmers, and thus, he stated the mitigation, coupled with the transfer, deconcentrates those markets [p. 52, ls. 12-25 and p. 53, ls. 1-15]. MARK D. ROBERSON Mr. Mark D. Roberson, Vice President - Regulatory Affairs for CSW, testified on behalf of the Joint Applicants. Mr. Roberson's testimony contained in Exhibits 15, 75, 134 and 194 were accepted into the record without objections. According to Mr. Roberson, during the first ten years following closing, the proposed AEP/CSW merger is anticipated to provide net non-fuel savings of approximately $152 million and fuel savings of approximately $11.8 million to PSO's Oklahoma retail jurisdiction. It was Mr. Roberson's opinion that the proposed merger will not impair retail competition in Oklahoma or adversely affect PSO's ability to fulfill its contractual commitments. The companies will integrate their system operations according to the terms of the System Integration 14 23 Agreement, which has been presented for approval at the FERC. In addition to various state regulatory filings, approvals are being requested from the FERC, the Securities and Exchange Commission under the Public Utility Holding Company Act of 1935, the Federal Trade Commission and Department of Justice under the Hart-Scott-Rodino Act, the Nuclear Regulatory Commission and the Federal Communications Commission. Mr. Roberson's testimony was given before the parties to the Stipulation had reached an agreement. Therefore, portions of Mr. Roberson's pre-filed testimony appear to be inconsistent with the Stipulation. CSW and AEP are willing to protect customers from any changes in PSO's stranded costs arising from the merger, and will not oppose a Commission order approving the merger which contains a merger condition limiting the basis of PSO's stranded costs to PSO's assets and obligations. Further, it is not necessary to perform additional production cost modeling of different power interchange levels between AEP and CSW to find that the merger is not detrimental to the public interest. The production cost studies performed based upon the interchange levels which have been secured show that the merger does produce fuel cost benefits for customers. Mr. Roberson also committed that AEP and CSW are willing to protect PSO customers from any adverse impacts from cost changes which arise due to implementation of the proposed market power mitigation plan. In explaining the mitigation plan, Mr. Roberson testified the Joint Applicants had committed at the FERC to divest 300 megawatts (MW) of capacity at PSO's Northeastern Plant (Units 3 and 4) in the Southwest Power Pool (SPP) and 250 MW of capacity at CSW Energy's Frontera Plant in the Electric Reliability Council of Texas ("ERCOT") upon the fulfillment of 15 24 certain conditions to mitigate potential market power concerns. In the time between the merger's closing and the fulfillment of the specified conditions, interim energy sales will be used to mitigate market power concerns. In the SPP, the sales will be interim system sales totaling 300 MW that are available all hours of the year, but which are subject to repurchase by AEP/CSW in the case of a system emergency. If the company recalls generation capacity, in the event of a system emergency pursuant to SPP operating rules or the CSW System Operating Agreement, it will make energy sold in the interim financially firm to the buyers affected. In ERCOT, the interim sale will be a unit sale for 250 MW of energy from CSWE's Frontera Plant. The interim sales will cease when the capacity is divested [pp. 57-58]. The sales revenues and incremental costs from the interim system sales in the SPP transactions will be treated for ratemaking purposes like all other off-system sales transactions. The Joint Applicants have committed to hold customers harmless from negative net margins (revenues, less incremental costs of energy and repurchased power) that might occur on an annual basis from the interim system sale in the SPP. For the Northeastern Units owned by PSO, divestiture would not occur until after implementation of retail competition in Oklahoma (which is now targeted for July 1, 2002). The Joint Applicants have developed a procedure for measurement of margins arising from the proposed 300 MW mitigation interim sale, and for crediting the customer share of margins on an annual basis, which will be sold from the CSW System and delivered in the Southwest Power Pool. The buyer will be responsible for paying $14/MWh for energy delivered, and will make a fixed payment, determined by auction, for the right to receive the low-cost energy. The Joint Applicants will incur incremental costs for fuel to produce the energy, for repurchase of energy at market prices when required to serve native load, and for 16 25 hedges to manage fuel and gas price risks associated with the transaction. Each of these cost components must be accurately measured to determine the economic benefit resulting from the transaction. An hourly calculation of the incremental cost is required to ensure that the fuel cost incurred to serve retail customers is based on the lowest reasonable cost from available sources of generation, referred to as Regulatory Mitigation Reconstruction. An hourly redispatch process is necessary to allocate lower cost sources of generation to native load, and then to allocate the higher cost resources for off-system transactions, such as the mitigation sale. By performing an hourly calculation, the procedure ensures that ratepayers are charged the lower-cost resources, and that off-system transactions are charged the higher-cost resources. All costs and revenues from the transaction will be added together to determine the margin. Since the incremental unit dispatched for PSO is often natural gas, the incremental dispatch costs will frequently exceed the S14/MWh energy revenues. The revenues from the auction payment from the buyer must be reflected in the determination by the margin. Buyers will base their payment upon their estimates of market prices, which are expected to be significantly higher than $14/MWh on an annual basis. Positive net gains will be flowed through to customers consistent with the sharing procedures in effect for off-system sale gains. If a negative gain occurred for a twelve-month period, it would be absorbed by shareholders. The Regulatory Mitigation Reconstruction cost procedure will provide a reliable mechanism for a meaningful "hold harmless" protection for customers from the impacts of the market power mitigation transaction. An annual sharing mechanism for the benefits of the mitigation sale will most fairly capture all of the cost changes arising from the sale and share the net benefits with customers. 17 26 Regarding the proposed divestiture of Northeastern capacity, such mitigation is not planned until generation prices are no longer subject to regulation in Oklahoma, and therefore hold harmless protections are not required from the effects of divestiture. However, if the Joint Applicants' plan for divestiture changes, and divestiture is required earlier, hold harmless provisions could be required, and the Joint Applicants are willing to propose appropriate provisions for OCC approval. Applicants are willing to accept fair hold harmless conditions for the mitigation sale as a condition of merger approval [p. 61]. In response to questions from Mr. Speegle, Mr. Roberson stated that the purchaser of the Northeastern Units would be required to enter into an operating agreement which would set forth the terms and conditions of the joint owners' participation in the plant [p. 62]. Further, Mr. Roberson was not aware of any draft operating agreements in existence for the divestiture. It was further generally contemplated that PSO would retain certain management rights and the right to operate the plant [p. 63]. Mr. Shore inquired regarding the proposed estimated $11.8 million in fuel savings to be realized by customers of PSO over a ten-year period. According to Mr. Roberson, the savings are derived from PSO customers receiving AEP's coal generation which in general had a lower variable cost than CSW companies' incremental gas generation [p. 65]. In response to questions regarding the mitigation proposal, Mr. Roberson testified that two conditions had to be satisfied prior to divestiture of 300 MW at Northeastern. Those conditions were that a pooling of interest accounting had to be satisfied for the merger as a whole and PSO would not have an obligation to serve at least 300 MW of native load [p. 68]. The interim sale would continue until those conditions would be satisfied [p. 70]. It is contemplated that a bidding process would be used for the interim sale [p. 70]. 18 27 In response to questions from Mr. Stewart, Mr. Roberson stated that the $11.8 million in fuel savings will not arise from the sale of capacity but from the energy exchanges that occur hour-to-hour [p. 72]. Mr. Roberson describes the interim sale as a sale of firm energy [p. 72]. In describing when PSO could repurchase in the event of a system emergency, Mr. Roberson explained that this event would only be triggered when PSO would not have other resources available either internally or through the points of interconnection that PSO has with others [p. 74]. Although the party purchasing the energy will lose that energy, that party will still receive the market price benefit associated with that energy [p. 74]. Whether or not the purchasing party would be able to secure electricity elsewhere, Mr. Roberson stated would depend on where the buyer was located and where the buyer was trying to deliver the power [p. 75]. In response to questions from Ms. Morgan, Mr. Roberson stated that any gains from the interim sale of the 300 MW should be treated as off-system sales are currently, i.e., 25% to shareholders and 75% to customers. In response to questions from Ms. Jacobson, Mr. Roberson testified that under the current system of regulation in Oklahoma, PSO would have no stranded costs and the merger does not create any stranded costs [p. 89]. On cross-examination by Mr. Stewart, Mr. Roberson said that the interim sale of energy under Applicants' mitigation plan is "firm" except for the need for PSO to recall the energy to serve its native load and then only when PSO is physically unable to acquire resources from the market [p. 72, ls. 1-4 and 20-24]. If the energy were recalled by PSO, Mr. Roberson stated it is possible, depending on where the owner was located, that there might not be any power to replace that energy [p. 73, ls. 15-24]. He also stated he would not be able to speculate as to 19 28 whether the buyer could replace the resources [p. 75, ls. 6-8]. The buyer of that energy would then be entitled to receive as compensation for the inability to replace the power, the market price of the energy according to a published index [p. 74, ls. 21-24 and p. 75, ls. 1 - 2]. This situation could cause the buyer of the energy to have physical problems which Mr. Roberson characterized as load shedding or interruptible customer shedding [p. 76, ls. 7-13]. Mr. Roberson also testified under cross-examination that the $11.8 million savings for PSO customers relates to hour-to-hour electricity exchanges from AEP to CSW [p. 70, ls. 21-25 and p. 71, ls. 1-11]. He had previously testified that the savings related to a ten-year period [p. 55, Is. 8-10]. Mr. Roberson explained that because of the lower costs structure of AEP with respect to variable costs, because coal is cheaper than gas, the Applicants' studies show that the predominant power flow direction is east to west [p. 71, ls. 11-18], although the agreement provides go either way. Concerning the portion of the Applicants' mitigation measures relating to the sale of capacity, Mr. Roberson testified that the terms of such a sale have not yet been worked out but that AEP might want some provision providing for a right of first refusal for AEP should the buyer of that capacity decide to sell its interest [p. 78, ls. 23-25 and p. 79, ls. 1-9]. He testified that AEP does have some agreements today for existing joint units that have right of first refusal provisions. He did not know whether such a provision would be part of a future agreement [p. 80, Is. 9-13]. STEPHEN B. JONES Mr. Stephen B. Jones, the Director of Issues Management for CSW, testified on behalf of the Joint Applicants. Mr. Jones' testimony contained in Exhibit 135 was accepted into the record without objection. Mr. Jones explained the market power mitigation measures proposed by the 20 29 Joint Applicants in their application for approval of the merger at the FERC. He attached his FERC testimony as an exhibit. The mitigation plan proposes the divestiture of ownership interests in two CSW plants. The Frontera plant located in the Electric Reliability Council of Texas (ERCOT) and the Northeastern plant located in the Southwest Power Pool (SPP). The Frontera plant is under construction and owned by CSW Energy, Inc. When completed, the facility will be an exempt wholesale generator merchant plant. The Northeastern plant is located in Oklahoma and serves PSO. Joint Applicants will divest an ownership interest in 300 MW of the Northeastern plant in two equal lots of 150 MW from Unit 3 and Unit 4 through an auction process devised to obtain the greatest possible value for the sale. No buyer can purchase both lots, and the divestiture cannot cause violations of the post-merger Herfindahl-Hirschman Index ("HHIs") in any CSW/SPP destination market or contiguous destination market. PSO will maintain operational control of the Northeastern plant through an operating agreement with the purchasers, who will have the right to capacity at any time and to the extent that the units are available for operation. In addition, at any time the units are available and PSO is not fully scheduling PSO's interests in the units, the purchasers will have the right to purchase at marginal cost any energy available. PSO will have a reciprocal right. The operating agreement will also provide for mutually agreed upon maintenance schedules and coordination on other operating matters. This divestiture cannot happen unless both of the following have occurred: - two years have passed since consummation of the merger as required by pooling of interest accounting; and 21 30 - retail access and entry by alternate suppliers in Oklahoma has caused a reduction in PSO's native load obligations to where the 300 MW of divested capacity is no longer required to satisfy SPP reliability criteria. The divestiture of the Northeastern units was selected because these units have the location and price characteristics necessary to provide effective mitigation in the CSW/SPP region and Oklahoma has set a statutory goal of full consumer choice by July 1, 2002. Consequently, the introduction of retail competitors into Oklahoma will allow the divestiture of these units without undermining PSO's ability to fulfill its native load obligation. Mr. Jones testified the OCC should find that the merger will not have an adverse impact on wholesale and retail competition within the state, and that the mitigation proposal will not have an adverse impact on customers served by PSO. In response to questions from Mr. Speegle, Mr. Jones testified he was familiar with how jointly owned plants are operated and he assumed that PSO personnel would continue to operate the Northeast Plant [p. 98]. Further, the operating agreement would include how the plant was going to be scheduled, O& M costs, the governing structure, and when capital additions are made to the plant [p. 100]. The right of first refusal would not be contained within the operating agreement if it would ruin the mitigation purpose of the divestiture [p. 101]. In response to questions from Mr. Shore, Mr. Jones testified that the reason for having two purchasers of 150 MW blocks is to avoid creating a market power problem [p. 102]. Mr. Jones further testified that if the Oklahoma Legislature passes a statute in the next session, or sometime before 2002, that says all generation shall be unregulated and electric utilities will have no obligation to native load, then one of the conditions for divestiture will have been met. However, if the Legislature says that there shall be a transition period where default customers will be supplied by PSO, even though it is unbundled as part of the restructuring process, then 22 31 the condition might not be met. However, whenever PSO has 300 MW or more of capacity in excess of those obligations then the divestiture can occur [pp. 103-104]. In response to questions from Mr. Stewart, Mr. Jones testified that AEP companies would not be allowed to purchase the capacity, nor a company which would possess market power after the purchase of the capacity [p. 105]. Mr. Jones further testified that there is no problem with OG&E bidding on the capacity [p. 106]. Pursuant to re-direct, Mr. Jones testified that as part of the condition of the offer of sale that HHI violations do not occur as a result of the sale [p. 111]. It would be more difficult for OG&E to bid on Northeastern and not exceed the market power test than an entity remote to Oklahoma [p. 112, ls. 2-6]. RAYMOND M. MALISZEWSKI Mr. Raymond M. Maliszewski testified on behalf of the Joint Applicants. Mr. Maliszewski's testimony contained in Exhibits 136 and 192 was accepted into the record without objections. The participants in this case agreed that the Applicants would conduct a system performance analysis of the bulk transmission networks in Oklahoma to determine the impact of the proposed 250 MW power transfer from AEP to CSW. Applicants evaluated load flow performance of the Oklahoma systems for the summer, spring/fall and winter seasons of 1999 with and without the AEP to CSW power transfer. Applicants compared the results of with and without cases to evaluate system performance and provide an indication of the AEP to CSW transfer impact. The Applicants' analysis examined: a) the incremental impact of the 250 MW transfer on flows on all the bulk transmission lines in Oklahoma as well as the rest of the interconnected network; b) the ability of the Oklahoma transmission networks to support single contingency operations, i.e., the outage of each transmission line; and 23 32 c) the impact that the power transfer would have on the power transfer capabilities of the other Oklahoma utilities with each of the directly connected neighboring systems. According to Mr. Maliszewski, the parties agreed that the Applicants would perform a conventional linear load flow analysis. The Applicants also agreed to verify these results with an AC load flow analysis as required to take into account the voltage performance considerations of the Oklahoma systems if they are significant. The Applicants' results are documented in Exhibit RMM-5. According to Mr. Maliszewski, the analysis showed: - The 250 MW AEP to CSW power transfer causes small changes in incremental power flows on the Oklahoma bulk transmission facilities that are widely distributed throughout the network, ranging from 0 MW to about 30 MW on 345 kV lines in Oklahoma. Considering that the 345 kV lines typically carry several hundred MW and have thermal capacity of at least 1000 to 1200 MW, these are relatively small changes. In some cases there will be no change, in others, a small amount of reduction, and in still others a slight increase. - The system is capable of supporting transmission outages with the 250 MW power transfer. Thus, the reliability of power supply to Oklahoma customers is not undermined by the 250 MW power transfer. - The AEP/CSW power transfer will have no more impact on Oklahoma line flow patterns and the ability of Oklahoma utilities to import and export energy than power transfers made by any other Oklahoma system. Any change in generation dispatch or power transfer in any Oklahoma system will result in a change in power flow patterns on every other Oklahoma system, some of which will be an addition to base power flows, while others will be a subtraction. - In general, over the entire year, spring, fall, winter and summer, there will continue to be significant levels of ATC available to the other Oklahoma systems. In those situations where no transfer capability existed to begin with, due to some existing inherent limitation, this condition cannot change. 24 33 Overall, it was Mr. Maliszewski' s conclusion that these studies clearly demonstrate that the AEP to CSW 250 MW power transfer will not have a material detrimental impact on the Oklahoma bulk transmission network. OG&E claimed that Applicants' study was flawed because Applicants had used an incorrect transformer rating that OG&E had supplied. In his rebuttal testimony, Mr. Maliszewski described a revised study of OG&E's ability to import power from the systems to which OG&E is interconnected. That revised study showed that the conclusions drawn from Applicants' original analysis were not affected by the change in the transformer rating. In particular, Applicants' earlier finding that even before the AEP/CSW transfer OG&E would be unable to import energy from the Entergy system was still true even with the higher rating on the OG&E transformer at the Fort Smith station. OG&E's transformers at Fort Smith already operate very near their emergency ratings in contingency conditions, and had little margin remaining to accommodate load growth or contingency conditions. OG&E also claimed that it would suffer significantly increased losses due to the AEP to CSW transfer. Mr. Maliszewski explained the flaws in OG&E's analysis [p. 117,l. 24]. Based on its flawed analyses, OG&E made claim to compensation for the cost of adding a new transformer at Fort Smith and to cover the cost of increased losses. Mr. Maliszewski testified that such remedies are at odds with established industry practice, and that granting the requested relief would have the effect of inhibiting the competition that Oklahoma and the federal government are seeking to foster. In response to questions from Mr. Speegle, Mr. Maliszewski testified that transmission service is requested from transmission owners through the processes that have been established 25 34 by the FERC, including using the OASIS. Once the reservation has been granted it is filed before the FERC and not at the Oklahoma Corporation Commission [p. 122]. In response to questions from Mr. Shore, Mr. Maliszewski testified that the parties had agreed that Applicants should perform an all encompassing study of the interconnected network between and including the AEP service area and the CSW and other Oklahoma systems. Mr. Maliszewski further explained that the parties had discussed how the study was to be carried out, what base cases were to be used, the source of the base case information, the load levels that would be studied and the kinds of system performance analyses that the Applicants would undertake [pp. 123-125]. Mr. Maliszewski testified that Applicants agreed to the performance of the interconnected network for the outage of every key transmission element within the interconnected network to determine whether there would be any detrimental impacts resulting from the 250 MW transaction. Applicants also undertook to examine the transfer capability between each directly connected utility within Oklahoma, with and without the 250 MW transaction, in order to determine whether the transaction had any impact on those transfer capabilities [pp. 128-129]. In a February 4, 1999 technical conference, of the parties' engineers, OG&E had requested that the Joint Applicants also examine what effect the proposed 300 MW divestiture of capacity at the Northeastern plant would have on the Oklahoma systems. The Joint Applicants were of the opinion that it was not appropriate to make such a study using a base case year of 1999 when the proposed divestiture would not occur earlier than 2002. However, the Joint Applicants agreed to carry out an analysis, which was discussed in Mr. Maliszewski's testimony [p. 129]. 26 35 In response to questions from Mr. Stewart, Mr. Maliszewski stated that the conduct of load flow studies is a well-established industry practice [p. 133, ls. 9-10]. According to Mr. Maliszewski, the agreement among the parties contemplated a basic DC analysis, which does not consider certain system characteristics but allows expeditious analysis of hundreds of system contingencies and in most cases produces accurate results. Applicants used the same software and study process that the Southwest Power Pool uses in making similar studies. Mr. Maliszewski testified that the agreement among the parties also contemplated that the DC analysis would be supplemented by AC analysis, which does consider system characteristics such as resistance and voltage levels, as required [p. 135, ls. 14-24]. [p. 7, 1.9 of rebuttal] in his rebuttal testimony, Mr. Maliszewski explained that, contrary to the claim of OG&E witness Kuebeck, the Applicants had performed the required AC analyses [pp. 135-140]. According to Mr. Maliszewski the agreement reached between the parties at the technical conference called for a DC Analysis because a conventional linear load flow analysis was simply an alternative terminology for a DC Analysis. DC Analysis is by its very nature a linear analysis, so that when one says a conventional linear analysis, it was understood by all engineers that DC load flow analysis would be used [p. 135, ls. 8-13]. In response to questions from Ms. Jacobson, Mr. Maliszewski testified that he had seen no evidence that the merger would burden the Oklahoma transmission network to an extent that would require transmission system reinforcement [p. 167, ls. 12-16]. On cross-examination by Mr. Stewart, Mr. Maliszewski testified that the six base cases studied by the Applicants were full-blown legitimate AC load flow base cases [p. 135, ls. 14-17]. Mr. Maliszewski testified that the determination of whether to use an AC or DC analysis is a 27 36 function of the purpose of the study to begin with and the judgment of the engineer who is reviewing the result to determine whether the study results are sufficient for his purposes [p. 138, ls. 19-23]. He stated that in its calculation procedure the DC analysis does not capture resistance, reactive aspects or voltage variations, that you would expect to see on the AC solution [p. 140, ls. 6-10]. It was for that reason that relative to the conventional load flow analysis that a supplemental AC analysis to evaluate voltage performance was performed [p. 140, ls. 12-16]. On cross-examination by Mrs. Jacobson, Mr. Maliszewski testified that line losses cannot be prevented. He said they are a natural phenomena. He stated that whenever current flows in a transmission line the current produces flows through a resistance, and losses are simply the heating of that resistance or that transmission line [p. 162, ls. 11-20]. He stated line losses are a natural consequence of system operation. He stated, whenever power flows from a transmission line, losses are going to occur [p. 165, ls. 3-9]. In response to a question from the Court, Mr. Maliszewski stated that if the merger in its implementation resulted in a definitive overload condition at the Fort Smith station which did not exist before, then it appears one solution would be for a reinforcement at Fort Smith [p. 170, ls. 7-11]. Mr. Maliszewski stated in his rebuttal testimony filed on April 12, 1999 (Exhibit 192) that prior to the merger, the Fort Smith transformer does have a small amount of capacity to accommodate load growth and other system conditions [Exhibit 192 at p. 22, ls. 18-20]. CRAIG BAKER Mr. Craig Baker, Vice - President - Transmission Policy for AEP, testified on behalf of the Joint Applicants. Mr. Baker's testimony contained in Exhibits 13, 76 and 196 was accepted into the record without objections. Mr. Baker described the System Integration Agreement (SIA) through which the companies will integrate their power supply resources, explained the central 28 37 economic dispatch of the merged company's generating units and the production-related benefits that will accrue as a result of the post-merger operations of AEP and CSW. The SIA provides for the distribution of power supply costs and benefits between the two zones, the east zone (presently AEP's system) and the west zone (presently CSW's system). The existing intra-system agreements will continue to govern the distribution of costs and benefits within the zones. It is the intent of the Applicants to centrally dispatch the combined system and eventually to combine the control area functions of the east and west zones. However, generation dispatch priorities will be the same as pre-merger, i.e., each zone's most economic generation will be used to serve its native load and previously committed firm load contracts. Under the SIA, the price in the purchasing zone will be one-half of the sum of the foregone opportunity cost to sell capacity in the supplier zone and the decremental capacity purchase cost in the purchasing zone. For example, if PSO needs to purchase capacity and the price of capacity is $4.00 in the CSW zone and $2.00 in the AEP zone, PSO would purchase at a price of $3.00 (The $2.00 AEP zone price plus one-half the difference between the CSW zone price of $4.00 and the AEP zone price of $2.00). If the situation is reversed, i.e., the CSW zone price is less than the AEP zone price, then PSO would make the purchase in the CSW zone since it is cheaper, thereby paying the same price they would have paid absent the merger. Energy works in the same manner. For energy the price is the lower of CSW's decremental cost or one-half of the sum of AEP's out-of-pocket costs and CSW's zone decremental cost. Mr. Baker also estimated the production-related benefits and costs associated with the post-merger operations of the combined company. Production-related benefits will result from the economic transfer of energy among the east and west zone companies to displace relatively 29 38 higher cost generation in one zone with relatively lower cost generation from the other zone. The net production-related savings are as follows: Gross Production Savings $198 million Transmission Wheeling Costs ($39 million) Net Fuel Related Savings $159 million) Foregone Net Revenue ($61 million) ------------- Net Production Related Savings $ 98 million ============
According to Mr. Baker, the merger affords the opportunity for production-related savings through the economic dispatch and transfer of energy between zones in a real-time manner benefiting CSW's and AEP's customers. Mr. Baker submitted rebuttal testimony to respond to the recommendations of Staff witness Crosslin that Applicants join an Independent System Operator ("ISO"). He also provided documentation related to affiliate purchases of capacity and energy. In response to Mr. Crosslin's recommendation that Applicants be required to join an ISO at their earliest opportunity to further mitigate transmission market power concerns, Mr. Baker stated the Applicants are willing to join a properly organized ISO of large geographic scope with a truly independent governance structure, broad authority over transmission pricing and reliability, and appropriate configuration and fair provisions for transmission pricing and revenue distribution. According to Mr. Baker, AEP has not joined the Midwest ISO (MISO) because it has a number of flaws including that MISO covers too narrow a geographic area. The decision of other utilities to the north and east of AEP not to join MISO undermines the ability of MISO to facilitate access to major power markets and MISO does not have an efficient pricing mechanism or fair revenue distribution. AEP is working with a group of utilities, called the Alliance, to either form a separate ISO or to join a reformed MISO. In Oklahoma, CSW's has been active in working with the Oklahoma staff and other utilities toward an ISO in the SPP. 30 39 Mr. Baker testified that the Staff's concern that affiliate sales of capacity or energy under the proposed System Integration Agreement ("SIA") will cause Oklahoma ratepayers to pay a higher price for electricity than they would have paid absent the merger was unfounded. The merger will not effect the price or the need for capacity by PSO, but will afford an additional opportunity for PSO to purchase AEP capacity. Under the SIA, the price in the purchasing zone will be one-half of the sum of the foregone opportunity cost to sell capacity in the supplier zone and the decremental capacity purchase cost in the purchasing zone. For example, if PSO needs to purchase capacity and the price of capacity is $4.00 in the CSW zone and $2.00 in the AEP zone, PSO would purchase at a price of $3.00 (The $2.00 AEP zone price plus one-half the difference between the CSW zone price of $4.00 and the AEP zone price of $2.00). If the situation is reversed, i.e. CSW zone price is less than the AEP zone price, then PSO would make the purchase in the CSW zone since it is cheaper, thereby paying the same price they would have paid absent the merger. Energy works in the same manner. For energy the price is the lower of CSW's decremental cost or one-half of the sum of AEP's out-of-pocket costs and the CSW's zone decremental cost. Mr. Baker testified that the Applicants are committed to participation in an Independent System Operator (ISO) or other RTO arrangement. Since April 1998, AEP has participated in discussions regarding the development of the Alliance RTO and, as described below, the process is currently expected to lead to a Federal Energy Regulatory Commission ("FERC") filing this year. Beginning July 1, 1998, CSW/Southwest Power Pool ("CSW/SPP") has participated in the Southwest Power Pool short-term tariff, under which SPP controls access to the SPP members systems, including the CSW/SPP system, for short-term transactions. In addition, in 31 40 December 1998, the SPP filed with the FERC an enhanced regional transmission tariff, which provides control and access for long-term transmission service. CSW/SPP has also been an active participant in the development of an SPP-RTO. Currently, the SPP has a regional tariff that applies to short-term (less than a year) transactions. Under that tariff, the SPP determines transmission access for purposes of those transactions and is directly responsible for maintaining the node of the SPP. RTO membership provides a number of public benefits. Two of the most important are: (1) further assistance of non-discrimination in the offering of open access transmission; and (2) the broadening of energy markets. Applicants' RTO activities are designed to achieve both of these benefits in the near term. In response to a question from the ALJ as to whether his testimony regarding ISO's/RTO's was tempered by the stipulation, Mr. Baker indicated the Applicants had committed to join an RTO by a date certain [pp. 15-16]. In response to cross-examination from Mr. Stewart, Mr. Baker explained that the System Integration Agreement, which deals with generation production costs, and the System Transmission Integration Agreement, which deals with transmission facilities, provide a basis for maintaining the costs and benefits to each zone within the zone and to share benefits that are achieved through the merger among the zones [pp. 18-19]. He also testified that these agreements require FERC approval [p. 20]. Mr. Baker further testified that as contemplated under the agreement, AEP Service Company would take over the functions of CSW Service Company after the merger is consummated [p. 22]. He additionally testified that the applicants would not enter into a transaction that would impose more costs on PSO's customers [pp. 24-24]. 32 41 Mr. Baker further testified on cross-examination by Mr. Stewart, that the System Transmission Integration Agreement and System Integration Agreement between AEP and CSW are for a term of five years with the ability for them to roll-over for additional periods unless terminated [p. 18, ls. 5-9 and p. 19, ls. 18-24]. Mr. Baker also testified that it is projected that PSO will be short of capacity in the years 1999 and 2000 [p. 23, ls. 10-19]. He stated that the shortage that PSO will need to supply would be to meet the combination of load and reserves requirements [p. 23, ls. 20-25]. Mr. Baker testified that consideration was given by AEP to the losses that would occur on the Ameren system associated with the transfer of power from AEP to CSW but AEP did not do an independent loss study with respect to losses on the CSW system for that transfer [p. 25, ls. 13-25 and p. 26, ls. 1-9]. The analysis that was done held the losses constant in both systems [p. 26, Ls. 3-4]. In response to questions from Ms. Jacobson, Mr. Baker testified as to the relative timelines for FERC approval of ISO/RTO applications [pp. 26-28]. On re-direct Mr. Baker reiterated that sales to CSW of up to 250 MW would be required if savings to CSW would result [p. 29]. ROBERT A. SINCLAIR Dr. Robert A. Sinclair testified on behalf of the Municipal Electric Systems of Oklahoma and the Oklahoma Association of Electric Cooperatives to address economic matters that arise out of the merger between AEP and CSW, collectively ("the Applicants"). According to Dr. Sinclair, the basic competitive problem with this merger lies in two facts. First, both Applicants are large regional utilities with control over vast generating resources and transmission facilities. Second, the merger is taking place in a region of the country where generation supply has become a critical problem whereby generating capacity has not kept up with the growth in demand and transmission capacity has not been adequately 33 42 expanded. This has led to drastic price increases as recently as last summer. These prevailing conditions certainly heighten the competitive impact of the merger, especially given the large size of both companies and their geographic location at the northern and southern ends of the Midwest. While Mr. Sinclair's testimony, as stricken does not contain empirical market share calculations that would illustrate the competitive impact of the merger, his testimony does contain a thorough description of the competitive problems that the merger entails. Dr. Sinclair examined a number of market structure variables to assess the merger's competitive effects. These other variables include: (1) the potential of the merger to give rise to anticompetitive effects; (2) entry conditions; (3) efficiencies; and (4) whether one of the firms is likely to exit the market with its assets because of financial stress. In examining each of these four factors, the conclusion is that the merger, (1) will facilitate the exercise of unilateral market power; (2) is likely to enhance conspiratorial market power and tacit collusion; (3) will create adverse competitive effects related to the control of the regional transmission system; (4) will create market power that is not likely to be undercut by free and easy entry; (5) will not create cost savings that are remarkable by industry standards (and, indeed, evidence suggests that costs are lower in smaller utilities); and (6) is not initiated to save one of the merger partners from exiting the market with its assets because of financial stress. Consequently, the merger would provide the merged entity with increased market power, unmitigated by other economic factors. In addition to his market power analysis, he also analyzed the proposed mitigation measures and found that they were inadequate. The Applicants propose two main mitigation measures. The first is to "divest" about 300 MW of capacity in the SPP and about 150 MW in the Electric Reliability Council of Texas ("ERCOT"). The second measure is a promise not to invoke priority rights (the AES-TVA priority) affecting transmission usage from power transfers 34 43 from AEP to CSW. The idea behind both of these measures is an attempt at diminishing the increased concentration that results from the merger. The "divestiture" proposal is supposed to reduce the post-merger concentration to a level that is comparable to the concentration level pre-merger. But in addition to being of inadequate magnitude to reduce concentration to pre-merger levels, the scheme does not really release the capacity from CSW's control. And the interim measure to make energy sales is unsatisfactory because such sales are non-firm and, thus, would not be of sufficient quality to serve retail demands. The Applicants promise not to invoke certain priority rights also will not mitigate the increased concentration resulting from the merger. The basic competitive problem is that, as a result of the merger, AEP will gain control of the bulk of low-cost capacity that can be delivered to CSW's SPP ("CSW-SPP") control area by controlling access to the transmission capacity into CSW-SPP from the east. Currently, a large number of firms have somewhat equal access to this transmission capacity. After the merger, because of certain operational advantages, AEP will be able to gain priority in using the scarce transmission capacity into CSW from the east. In an effort to alleviate this problem, the Applicants propose to reduce the priority at which they can make transfers from AEP to CSW. This measure is not sufficient to ensure the preemption of other suppliers because the new Company will still have advantages in obtaining available transmission capacity over other suppliers. Dr. Sinclair also rebuts the Applicants' economic analysis. The rebuttal is in two parts. First, he explains why the market concentration analysis of Applicants' economic witness Hieronymous is not an adequate basis from which to draw conclusions about the competitive impact of the merger. Basically, Dr. Hieronymous did not consider certain important market 35 44 supply conditions in the Midwest that are likely to have a determinative effect on market power. The second part of Dr. Sinclair's rebuttal involves an examination of the mitigation measures proposed by the Applicants. As noted above, these measures are not sufficient to ameliorate the severe competitive consequences of the merger. Dr. Sinclair's main recommendation is that the merger should not be approved. However, if it is nonetheless approved, generation divestiture should be required to address market power problems. Significant amounts of CSW's generation should be divested to multiple entities in order to address the market power problems in this case. Along with this, the Commission should require that the Applicants join a functional, Independent System Operator ("ISO") before the merger is approved. On cross-examination by Ms. Jacobson, Dr. Sinclair testified that he was familiar with FERC Order No. 592 and that his mitigation recommendations of divestiture and a requirement to join an ISO were consistent with the requirements of that order. He also testified on cross-examination by Ms. Jacobson that Order No. 592 also provides that expansion of the transmission system could also be a mitigation measure [pp. 37-38]. On cross-examination by Mr. Downs, Dr. Sinclair testified it was practically feasible for American Electric Power to deliver power into Oklahoma but that such power would have to be bundled with ancillary services in the SPP to assure reliable service [p. 39, ls. 5-14]. It was Dr. Sinclair's opinion this had not been done in the past because AEP's resources were committed to serving AEP's retail customers [pp. 39-40]. Dr. Sinclair testified on cross-examination that he would modify the delivered price test to take into account anticipated or historical equilibrium conditions for analyzing the effects of the merger. When asked whether such a model left a lot of room for the exercise of judgment or 36 45 even bias, Dr. Sinclair responded that all economic models require judgment and there could be bias injected [p. 41, ls. 18-23]. Dr. Sinclair testified the adjustments he made to the models were in an attempt to reveal market power [p. 42]. Dr. Sinclair admitted on cross-examination that the transfer capacity from the Ameren system under summer peak to CSW is 760 MW [p. 44, ls. 5-11]. He stated that in his model, he used 1,260 MW as an ATC on the Ameren-CSW path. Dr. Sinclair stated that this figure had no empirical basis but was used in an attempt to model transmission conditions, which he expected to prevail in the future under certain new transmission institutions, such as an ISO. Dr. Sinclair stated the level he chose was to test the sensitivity of the model and was based upon his informed judgment as an economist [pp. 43-45]. On further cross-examination by Mr. Downs, Dr. Sinclair discussed his conclusion that, in order to mitigate market power increases that result from the merger, Applicants should divest 2,000 MW of capacity. Dr. Sinclair admitted that 2000 MW was an amount larger than the 1260 MW path from Ameren to CSW that he expected to be available in the future. Regarding the accuracy of his estimates, Dr. Sinclair stated that his recommendation for divestiture had no empirical basis but it was better over estimate rather than under estimate [p. 50,Il. 20 - p. 51, 1-8]. On redirect examination, Dr. Sinclair testified that all economists need to rely on informed judgment in making an analysis. He further stated that Dr. Hieronymous delivered price tests required certain judgments be made. He testified that, in an appendix to his FERC testimony, Dr. Hieronymous argues a number of points about the methodology to be used in the FERC delivered price test. Dr. Sinclair stated he applied his informed judgment based upon 37 46 certain market realities of events which have either transpired in recent months or that are forecast in the future based on generation supply [pp. 54-55]. Finally, Dr. Sinclair testified that, he had heard statements that AEP has not limited itself to the 250 MW firm transfer to the CSW system. In fact, Dr. Sinclair said he had heard that Applicants had reserved the right to apply to the FERC for non-firm transfers above the 250 MW level [p. 56, ls. 7-12]. MELVIN H. PERKINS, JR. Melvin H. Perkins, Jr. was called as the first witness for Oklahoma Gas and Electric Company ("OG&E"). Mr. Perkins has been employed by OG&E since 1972 in Transmission and distribution engineering and operations. He is presently Manager of Operations in the Power Delivery business unit and is responsible for the OG&E system transmission operations, substation construction, operations and maintenance and metering. This includes responsibility for transmission system security and tariff administration including compliance with FERC Orders 888 and 889. Mr. Perkins received a BS degree in Electrical Engineering from the University of Oklahoma in 1972. His Responsive Direct Testimony filed on March 29, 1999 (Exhibit 165), and the summary of his testimony dated April 19, 1999 (Exhibit 212) were accepted into the record [p. 64, ls. 12-13]. Mr. Perkins testified that the capability to import power into Oklahoma will be significantly impacted by the energy transfer proposed in the merger of American Electric Power Company, Inc. ("AEP") and Central and South West Corporation ("CSW"). His testimony was offered to show that Available Transmission Capability ("ATC") is significantly reduced and he urged the Commission to deny the merger application at this time and to encourage the Applicants to come forward with a joint planning initiative to restore the Oklahoma transmission system to pre-merger conditions. 38 47 Mr. Perkins testified that the OG&E system is comprised of 4300 miles of transmission interconnected with other companies at 43 points. The bulk 345kv system began with joint planning between OG&E and Public Service Company of Oklahoma ("PSO") and resulted in several joint ownership lines. He stated that this highly integrated system of transmission facilities relies on close coordination between utility companies to ensure continued reliability and market efficiency. He testified that this coordination could include daily communication regarding maintenance, service restoration, and other issues. Mr. Perkins stated that ATC is an indicator of import and export capacity with each of the companies interconnected with OG&E. Among other factors, ATC includes a margin for reliability. He said that this reliability margin is reserved for generation in one transmission area that provides a backup supply for another area. He stated that ATC is calculated by running complex computer models of the system. These models contain thousands of transmission system elements that have information about each element. He testified that OG&E has assigned an incorrect rating to one of these elements, a large power transformer in the OG&E Fort Smith Substation, and that caused the ATC to be understated. This rating was changed as a result of reviewing the Applicants' study and the original study was rerun by OG&E producing results found in Mr. Perkins' pre-filed testimony. He testified that these new results actually reflect a higher ATC from Entergy to OG&E; however, he asserted that the transfer proposed by the Applicants in this case still significantly lowers ATC values. Mr. Perkins testified that ATC is lowered by approximately 94% from Entergy to OG&E due to the proposed transfer. Chart 1 in Mr. Perkins' pre-filed testimony (Exhibit 165, p. 4) shows that the import capability from Western Resources is lowered by approximately 73% and the import capability from CSW will be lowered by 65%. One possible 39 48 mitigation OG&E identified through the testimony of Mr. Perkins is to upgrade the Fort Smith Substation transformer at a cost of approximately $10,900,000. Mr. Perkins testified that with the time limitations under the merger, OG&E did not make any in-depth investigation to determine if any other upgrade might be a solution to the problems caused by the transfer of power in accordance with the merger. [p. 64, ls. 18-23]. He stated that joint planning with OG&E, CSW, and other transmission owners in the region would be necessary to determine if the Fort Smith Substation transformer upgrade is the best solution. Mr. Perkins testified that OG&E does not expressly oppose the merger but initiated its intervention for due diligence reasons. He stated that there are certain conditions created by the merger that are clearly not acceptable and not in the best interest of Oklahoma customers. He said that OG&E remains ready to work with the Applicants to determine the extent of necessary mitigation measures so that the merger can go forward and pre-merger conditions can be retained. Mr. Perkins said that OG&E requests that the merger application be denied and that the Applicants be ordered to engage in joint planning with costs to restore pre-merger conditions to be paid by the Applicants. Mr. Perkins testified on cross-examination that the joint planning requested by OG&E will require the parties to study the problems caused and agree on a set of parameters for a computer model [p. 65, ls. 14-17 and p. 77, ls. 23, 24] and then look at what mitigation measures are necessary to restore the pre-merger conditions [p. 78, ls. 3-4]. The computer model must include the flows that are on the system along with those related to the merger transaction [p. 78, ls. 12-17]. On cross-examination, Mr. Perkins admitted that he had no experience in transmission planning, as distinguished from operations [p. 84, ls. 4-6]. He did not know what an annual load 40 49 factor was [p. 82, ls. 20-21]. He stated the head of the OG&E transmission planning function was probably more knowledgeable about the status of OG&E's transmission system than he was [p. 9 1, ls. 1-3]. He was not able to testify regarding the models used by the Southwest Power Pool for its databases in preparing its own computer model to analyze the transmission system and did not know how many points of interconnection OG&E had with Entergy [p. 86, ls. 16-19 and p. 91, 1.23 - p. 92, 1.3]. With regard to many of these matters, Mr. Perkins said that Mr. Kuebeck would be the best person to ask [p. 82, l. 20 - p. 89, l. 20 and p. 94, ls. 1-2]. Mr. Perkins further stated that OG&E's study showed that there is no pre-existing condition that would cause congestion on the OG&E system [p. 78, ls. 23-25 and p. 79, ls. 1-4]. Mr. Perkins further testified that OG&E had submitted a five-year transmission construction plan to the Southwest Power Pool and that such plan did not contemplate any system upgrade designed to address overloads at or in relation to OG&E's Fort Smith station [p. 86, l. 20 - p. 87, 1. 4]. Mr. Perkins agreed that the Southwest Power Pool had adopted Coordinated Planning Procedures, which were an attachment to the SPP Regional Open Access Transmission Tariff. He explained that under such procedures, the SPP conducts seasonal assessments of the expected performance of the regional transmission network and notifies transmission owners of violations of reliability criteria. It is then the responsibility of the transmission owner either to explain why the violation finding is not valid or to identify alterations to the transmission system that would correct the violation. Mr. Perkins agreed that, under the procedures, the SPP staff would participate in the conduct of studies needed to study any such violation and that the procedures make provision for sharing of the costs of a system upgrade among those who benefit from the upgrade [p. 87, .l 5 - p. 88, l.5]. 41 50 Mr. Perkins testified that the merger related study conducted by OG&E showed that the transformer upgrade for the Fort Smith Substation will resolve the constraints on the OG&E transmission system [p. 107, ls. 21-24, p. 112, ls. 22-24 and p. 113, ls. 2-4]. On cross-examination Mr. Perkins admitted that OG&E had posted on the SPP OASIS a zero Available Transfer Capability for imports from Entergy for the summer of 1999. He explained that the zero ATC was based on notification from the SPP that loop flow from transactions by other utilities had impacted OG&E's import capability. Mr. Perkins stated that the zero ATC posting had been made in April and that the transactions referred to by the SPP as impacting OG&E did not include any transfer from AEP to CSW. Mr. Perkins testified that OG&E had retained an outside consulting firm, PCA, to analyze the impact on OG&E's system of transfers from AEP to CSW. He further stated that he had seen the results of PCA's studies but claimed not to be familiar with Table 1 to PCA's study report and referred all questions about the report to Mr. Kuebeck [p. 99, ls. 12-13 and p. 101, ls. 7-16]. Mr. Perkins further testified that, while OMPA and WFEC had firm transmission reservations on the OG&E system, he did not know how OMPA or WFEC used those reservations or where their power supply resources were located. Mr. Perkins testified that according to OG&E's answers to the Applicants' data request (Exhibit 213) that OMPA had no firm transmission reservation of the Entergy system for imports into OG&E's control area [p. 102, l. 11 - p. 105, l. 19]. However, on redirect examination, Mr. Perkins explained that the Applicants' data request related to "use" of firm transmissions and does not reflect the reservations that OMPA has on the system [p. 113, ls. 6-22]. On redirect examination Mr. Perkins stated that AEP would not be required to pay for services under the SPP tariff with respect to the merger transaction [p. 112, ls. 12-14]. He also 42 51 stated that AEP would not have any financial obligation under the SPP tariff to pay for upgrades caused by the merger transaction because AEP has not requested transmission service through the SPP [p. 112, ls. 16-21]. PETER P. KUEBECK OG&E's next witness was Peter P. Kuebeck. Mr. Kuebeck is employed by OG&E as Supervisor of Transmission Scheduling. His Responsive Direct Testimony, filed on March 29, 1999 (Exhibit 164), the volume two of two volumes, which Mr. Kuebeck sponsored and which contains the work papers relating to the studies performed by OG&E in this case and was also filed on March 29, 1999 (Exhibit 168) and the summary of Mr. Kuebeck's testimony, as redacted, dated April 19, 1999 (Exhibit 214), were accepted into the record [p. 131, ls. 15-21]. Mr. Kuebeck testified that Applicants, AEP and CSW propose a multi-year arrangement by which a large transfer of electric energy will be sent cross country from Ohio to Texas. He stated that, this transfer, which he referred to as the Merger Transaction, involves a vast distance, broadly distributed flows and impacts across multiple states and control areas. Mr. Kuebeck testified that Applicants were asked to perform a transfer study [p. 117, ls. 4 and 5]. The parameters for the study were agreed upon by the parties in this case and became a part of an Order of this Commission. Mr. Kuebeck takes issue with the study performed by the Applicants in the following respects: 1. The transmission system study performed by the Applicants demonstrates that the proposed merger and transfer of 250 megawatts of energy from AEP to CSW, the Merger Transaction, cannot be accommodated without negatively affecting import Available Transfer Capability ("ATC") on the existing transmission grid in Oklahoma. The proposed Merger Transaction will impose a significant limitation on electric energy import capability to the State of Oklahoma. The Applicants insist that there is no ATC from Entergy to OG&E, yet conclude 43 52 that their own transaction along this same path can be accommodated. He testified, however, that the Applicants' Merger Transaction is the incremental transaction that takes away virtually all of the ability of the Fort Smith substation to carry any other imports of power and reduces import capability across the transmission system serving Oklahoma [p. 117, ls. 16-18]. 2. The studies that Mr. Kuebeck performed with data provided by the Applicants demonstrate that transfer considerations were overlooked in the Applicants' study. Specifically, Applicants failed to perform a meaningful Linear Transfer Analysis by AC solutions, and Applicants ignored the Transmission Reliability Margin for each studied contingency. a. Linear Transfer Analysis is used to determine the level of reliable transfer capability from one area to another. The studies Mr. Kuebeck performed for OG&E utilized an AC methodology that is inherently more accurate than the DC studies used by the Applicants. An AC analysis considers transformer tap settings, generator MVAR limits, shunt devices, transmission line MVAR loading, and voltage performance of the network. Energy transfers across vast distances require complete AC analysis for accurate determination of network performance. b. Transmission Reliability Margin ("TRM") is that amount of transmission capacity used in this region to supply generation resources from adjacent utility systems to maintain generation reliability in the event of generator forced outages. Applicants failed to consider TRM in their analysis. The Applicants failed to recognize the absolute Available Transfer Capability at the points of interconnection. The Merger Transaction reduces ATC severely at all north and east import points for the purchase of energy outside Oklahoma. The Applicants insist that TRM of other companies is inconsequential to the AEP to CSW transfer of energy. That aside, the Applicants have 44 53 reported that there is a decrease in First Contingency Incremental Transfer Capability ("FCITC") into OG&E after subtracting the 250 megawatt transfer. Applicants' own study shows there is a significant reduction in import capability to Oklahoma. 3. Mr. Kuebeck performed a Loss Study for OG&E using the load flow data submitted by Applicants. The study revealed increased losses for OG&E as energy flows on parallel paths through the OG&E system to CSW SPP and CSW ERCOT. Losses appear as loads to generators, requiring the generators to produce more power and use more fuel. The additional fuel cost for the losses caused by the Merger Transaction will be paid for by all OG&E customers. Mr. Hiebsch provides quantitative cost estimates for this impact in his responsive direct testimony. Mr. Kuebeck further testified that Applicants were asked by this Commission to perform and submit a study that would identify transmission constraints that might result from this merger. Using the Applicants' data Mr. Kuebeck performed studies to verify the conclusions reached by the Applicants. According to Mr. Kuebeck, while all of these studies reflect a decrease in import capability into the State of Oklahoma as a result of the Merger Transaction, Applicants suggest that these results should be ignored. Mr. Kuebeck stated that the studies he performed clearly demonstrate harm to Oklahoma's electric consumers, and Applicants should propose and agree to implement mitigation measures that will eliminate that harm. Mr. Kuebeck criticizes Applicants for relying too heavily on DC transfer studies rather than relying on the more accurate AC studies. Out of the estimated 2,000 to 3,000 cases studied by the Applicants, only 12 of the studies were done with an AC solution to verify the DC transfer study [p. 128, ls. 17-24 and p. 129, ls. 2-12]. 45 54 Mr. Kuebeck testified that the OG&E transmission line losses were calculated using the winter 1999 case provided by the Applicants [p. 129, ls. 16-17]. Although an hour by hour computation of the line losses throughout the entire year would yield a more precise calculation, Mr. Kuebeck is comfortable that the figures on the exhibit he sponsored are representative of what would be the annual loss on OG&E's system [p. 130, ls. 5-20]. He explained that there are two types of power on OG&E's system negatively impacted by the merger: real power measured in megawatts [p. 132, Is. 12-23] and reactive power measured in MVARs [p. 133, ls. 1-8]. Mr. Kuebeck estimates that the merger will increase line losses on OG&E's transmission system by 5 megawatts in real power [p. 130, ls. 23-25] and by 44 MVARs of reactive power [p. 133, ls. 13-17, Exhibit PPK-1]. Mr. Kuebeck explained that as the transmission system becomes loaded, it is necessary to supply more capacity MVARs to the system to maintain the voltage [p. 133, ls. 18-24 and p. 134, ln. 2]. Mr. Kuebeck testified that he is familiar with the SPP coordinated planning procedures. The seasonal assessments that the SPP does as contemplated by those procedures is done to point to violations in reliability. Mr. Kuebeck testified that SPP has not advised OG&E that any of its facilities are in violation of the SPP reliability criteria [p. 153, ls. 5-15]. In response to cross-examination, Mr. Kuebeck admitted that OG&E's OASIS postings were at variance with the chart in Mr. Perkins' testimony that purported to list OG&E's Available Transfer Capabilities for imports from OG&E's interconnected neighbors. In particular, where Mr. Perkins' chart had shown that before the AEP/CSW merger OG&E would have an ATC from Entergy of 139 MW the OG&E OASIS posting showed zero ATC. Mr. Kuebeck testified that Entergy had similarly posted a zero ATC value for imports into OG&E from Entergy, which Mr. Kuebeck said was appropriate [p. 142, l 22 - p. 144, l. 21]. 46 55 Where Mr. Perkins' chart had shown a pre-merger ATC from GRDA. of 417 MW and a post-merger ATC of 392 MW, Mr. Kuebeck stated that the OG&E OASIS posting showed only 231 MW of ATC available from GRDA. prior to the merger [p. 144, l. 21 - p. 145, l. 5]. Mr. Kuebeck further admitted that OG&E's OASIS postings showed that OG&E had provided for no Transmission Reserve Margin (TRM) in relation to its import capabilities from any of its interconnected neighbors other than Entergy [p. 166, l. 13 - p. 167, l. 7]. Mr. Kuebeck testified that he was comfortable with OG&E's OASIS postings [p. 144, l. 21 p. 148, l. 12]. Mr. Kuebeck also admitted that DC analyses were customarily used to study the performance of the transmission network under contingency conditions to expedite the analysis of hundreds of different contingency conditions and that the study process that Applicants followed in this case mirrored the process that the Southwest Power Pool ordinarily follows [p. 150, l. 4 p. 151, l. 22]. Mr. Kuebeck agreed that, contrary to his prefiled testimony, Applicants had performed AC studies to confirm the reasonableness of their DC studies [p. 128, l. 14 - p. 129, l. 3] and that in all but one instance the AC results were consistent with the DC results [p. 167, ls. 4-6]. Mr. Kuebeck agreed that linear load flow analyses involve a systematic evaluation of the loss of individual bulk power system elements on other elements of the interconnected network but that his study of the effect of the AEP to CSW transfer on OG&E's import capabilities was based on an assessment of only 31 contingencies [p. 155. Is. 8-12; p. 161, ls. 14-16 and p. 186, ls. 18-20]. Mr. Kuebeck said that it was important to select the appropriate outages to study where you know they can make a difference. It was for this reason that he studied outages of Fort Smith station because it has a history of outages including four outages in the last three years. Mr. Kuebeck pointed to Fort Smith as an example of where operating judgment and 47 56 system knowledge helps in selecting the appropriate contingencies to study [p. 154, l. 17 - p. 155, l. 3]. Mr. Kuebeck admitted that originally if any studies were put forward in this proceeding by OG&E, PCA would do the studies [p. 160, ls. 8-13]. However, in the last days of March, OG&E decided that it should perform its own studies [p. 160, ls. 8-13]. Mr. Kuebeck stated that based on the information provided by OG&E, it was reasonable for the Applicants to assume that the Fort Smith transformer limit is a pre-existing condition [p. 169, ls. 14-23]. Mr. Kuebeck admitted that Table 1 to the PCA study showed that the Fort Smith 161/500 MVA transformer, even when modeled at its correct emergency rating, overloaded when the Fort Smith 161/345 MVA transformer was out of service even before the AEP to CSW transaction, but that the SPP had not informed OG&E of any reliability violation. Mr. Kuebeck had earlier corrected his testimony on direct examination by stating that the AEP to CSW transfer would affect loadings on Fort Smith by less than 5%, not 20% [p. 115, ls. 11-12 and [p. 169, l. 11 - p. 170, l. 10]. Table 1 to PCA's study report showed that a transmission line on the Entergy system would be the element that would limit to zero firm power transfers from Entergy to OG&E [p. 174, ls. 6-16]. When asked about this, Mr. Kuebeck contended that the consultant's analysis was not reliable because neither OG&E nor its consultant had confirmed with Entergy that transmission lines on Entergy's system would actually respond to contingencies as indicated in the PCA study. Mr. Kuebeck testified that OG&E had made no recent effort to engage in coordinated planning with Entergy [p. 169, ls. 6-14]. After rejecting PCA's original results, which were based on a full-blown contingency analysis which studied the outage of 9000 interconnected system facilities [p. 178, l. 86], PCA was asked to do a different study. Mr. Kuebeck explained that the second PCA study produced 48 57 no equivalent to Table 1 to the first PCA study and that the second study was based on a different set of transfers and may include different modeling of generation changes [p. 186, ls. 3-14]. When asked why he had stated in direct testimony that the PCA studies were consistent with the studies Mr. Kuebeck had done, Mr. Kuebeck stated that they were generally because they both examined the effects of the AEP to CSW transfer [p. 191, l. 19 - p. 192, l. 1]. When asked about the loss study that he had done, Mr. Kuebeck agreed that he had used a winter season base case prepared by the SPP in January 1998 rather than the SPP base cases that Applicants and OG&E had used for determining the loop flow effects of the AEP to CSW transfer, which were prepared by the SPP in December 1998 [p. 193, l. 10 - p. 194, l. 4]. Mr. Kuebeck agreed that the PCA study, which was based on the Summer 1999 base case prepared in December 1998, showed that at the summer peak additional losses resulting from the AEP to CSW transfer would be 3.1 MW not the 5.5 MW Mr. Kuebeck had found based on the older winter base case [p. 195, ls. 7-21]. Mr. Kuebeck readily admitted that his measure of incremental losses associated with the AEP to CSW transfer does overstate the amount of incremental losses that OG&E would experience on an average annual basis [p. 195, l. 23 - p. 196, l. 2]. Mr. Kuebeck was cross-examined about his Exhibit PPK-3, which shows the impacts that a number of transactions for which firm transmission reservations have been made that include service in the month of August 1999 would have on OG&E's Fort Smith station [p. 204, l. 16 - p. 205, l. 17]. Mr. Kuebeck stated that there were other long-term transactions on this list that would have an impact on Fort Smith station loadings that would be about the same or greater than the AEP to CSW transfer [p. 206, l. 1 - p. 209, l. 7]. Mr. Kuebeck further agreed that some of the uses made by Western Farmers and OMPA of the OG&E system were modeled in the base 49 58 case and would therefore not be affected by any reduction in ATC resulting from the merger [p. 211, l. 16 - p. 213, l. 4]. GUSTAVO E. BAMBERGER OG&E's next witness was Gustavo E. Bamberger, an economics consultant from Chicago, Illinois. Dr. Bamberger is a Principal and Vice President of Lexecon Inc., an economics consulting firm that specializes in the application of economics to legal and regulatory issues. He received a B.A. degree from Southwestern at Memphis, and M.B.A. and Ph.D. degrees from the University of Chicago Graduate School of Business. Responsive Direct Testimony, filed in this cause on March 29, 1999 (Exhibit 167). Exhibit 167 and the summary of Dr. Bamberger's testimony, as redacted, dated April 19, 1999 (Exhibit 216), were accepted into the record [p. 13, ls. 5-10]. Dr. Bamberger testified that Lexecon Inc. had been asked by OG&E to analyze the likely effect of the proposed merger of AEP and CSW on buyers of electricity in Oklahoma. Based on the available evidence, they reached the following conclusions: FIRST, absent additional mitigation measures, the proposed AEP/CSW merger likely will harm a substantial number of Oklahoma consumers because it will reduce available transmission capacity into Oklahoma from relatively low-cost power suppliers. SECOND, Applicants' proposed mitigation measures fail to address the merger-induced reduction in available transmission into Oklahoma. THIRD, Applicants' proposed mitigation measures do not alleviate market power concerns. Dr. Bamberger testified that the proposed merger reduces transmission into Oklahoma. He stated that as a condition of the proposed merger, Public Service of Oklahoma ("PSO"), a CSW company, has entered into transmission service agreements with Ameren and Western 50 59 Resources ("the Ameren contract"), whereby PSO purchased 250 megawatts of firm "point-to-point" transmission service for the period June 1, 1999 to May 31, 2003. If it were not for the merger, CSW was not planning to purchase firm energy from AEP; instead, CSW intended to utilize different transmission resources to reach alternate energy suppliers. Thus, Dr. Bamberger concluded that this sale is merger related. Dr. Bamberger testified that Applicants concede that CSW's use of the Ameren transmission path will affect the availability of transmission in other parts of the state because AEP/CSW's use of the Ameren path causes "loop flows" over other parts of the Oklahoma transmission system. He explained that loop flows are power flows on portions of a transmission system owned by utilities that are not involved in a particular power transaction. Dr. Bamberger stated that because less transmission will be available as a result of the merger, certain transactions between Oklahoma utilities and power suppliers likely will be precluded. That is, if the merger is completed (without additional mitigation), power purchasers in Oklahoma, like OG&E, will not be able to import as much power from outside of the state. This reduction in transmission capability also likely will affect several other entities in Oklahoma, including the Oklahoma Municipal Power Authority and Western Farmers Electric Cooperative. In effect, a reduction in the availability of transmission reduces the geographic size of the market in which an Oklahoma utility can purchase power, thus reducing OG&E's (and others') ability to import lower-cost power into Oklahoma. Dr. Bamberger concluded that such a reduction in the availability of relatively low-cost power harms Oklahoma consumers. Dr. Bamberger further testified that Applicants' proposed mitigation measures do not address the effect of the merger on transmission. He stated that Applicants concede that the proposed merger raises market power concerns. In response to these concerns, Applicants 51 60 propose certain mitigation measures. Dr. Bamberger testified, however, that Applicants' proposed mitigation measures fail to address the merger-induced reduction in the geographic size of those markets. That is, even if the proposed mitigation measures reduce concentration in Oklahoma to the pre-merger level, they do not return a transmission capability into Oklahoma to the pre-merger level because the proposed mitigation measures do not affect merger-induced loop flows. Dr. Bamberger testified that the solution to the merger-induced reduction in transmission capability is straightforward. It can be mitigated by increasing transmission capacity at points where the Ameren transaction-related loop flows would reduce the availability of transmission. Such a mitigation measure would, in effect, return the geographic size of the market to pre-merger levels. Dr. Bamberger testified that because the proposed merger affects the size of the geographic market, Applicants' use of an "HHI" analysis to evaluate the effectiveness of the proposed mitigation measures is misleading. Applicants' analysis consists of comparing pre-merger HHIs in particular geographic markets to post-merger HHIs in smaller geographic markets. In Dr. Bamberger's opinion, Applicants' economic analysis is flawed because the pre-merger and post-merger HHIs are based on markets of different geographic sizes. Dr. Bamberger testified that Applicants' proposed mitigation measures do not alleviate market power concerns. He said that even if the pre-merger extent of the geographic market were re-established by upgrading transmission capacity to offset merger-induced loop flows, Applicants' mitigation measures do not alleviate concerns that the merger will allow a merged AEP/CSW to exercise market power. Dr. Bamberger stated that Applicants claim that they will mitigate market power concerns in Oklahoma by divesting generation assets. In particular, 52 61 Applicants claim that they will "divest" 300 megawatts of generating capacity from PSO's Northeastern plant (which has a total generating capacity of about 1,500 megawatts). Dr. Bamberger stated that in general, divestiture can be a reasonable approach for mitigating market power concerns (but not loop flow concerns) because it removes the divested assets from the control of the merging parties. However, Applicants' mitigation proposal falls short of divestiture. First, Applicants concede that their proposed "divestiture" will not take place until sometime after July 1, 2002. Indeed, AEP and PSO have not committed to divest generation assets by any particular point in time. Second, the "divestiture" fails to eliminate AEP/CSW's control of the "divested" asset. In particular, AEP/CSW likely will be able to influence when outages will be scheduled at the "divested" plant. Dr. Bamberger stated that if AEP/CSW can override the objections of the owners of the "divested" 300 megawatts (or if they do not object), AEP/CSW could use its control of the Northeastern plant to exercise market power by restricting the output of the Northeastern plant at times when such a reduction in output could substantially raise electricity prices. It is Dr. Bamberger's opinion that the proposed mitigation measures may make it easier for AEP/CSW to exercise market power because it may allow the merged firm to raise market price by restricting the output of the "divested" 300 megawatts of generating capacity at no cost to AEP/CSW. Dr. Bamberger testified that under Applicants' proposed interim mitigation measures, that is, until the proposed "divestiture" of 300 megawatts takes place, CSW will conduct interim system energy sales from the Northeastern plant at a specified price. It is his understanding that under the terms of the proposed sales contracts, CSW will be able to recall the energy under certain "emergency" conditions. If it does so, CSW will be obligated to compensate the owners of the energy, at a yet-to-be specified amount. 53 62 It is Dr. Bamberger's opinion that this interim mitigation measure fails to alleviate market power concerns. First, the merged firm will maintain operational control of the to-be-divested plant during the interim period. As stated in Dr. Bamberger's testimony, Applicants may have an incentive to exercise market power by scheduling outages strategically. Second, if the amount of compensation that CSW must pay to the owners of the financially firm energy in the event of a recall is not related to the price of energy at that time, CSW may have an incentive to recall the energy, thereby profiting from the difference between market price and the amount it must pay to compensate the owners of the financially firm energy. Dr. Bamberger testified further that even if his concerns about the proposed mitigation measures were unfounded, Applicants concede that their proposed mitigation measures fail to prevent concentration levels from increasing substantially in several areas of Oklahoma, including OG&E's service area. That is, Applicants concede that, as a result of the proposed merger, concentration in several areas of Oklahoma will increase substantially. Dr. Bamberger testified that OG&E's concerns about the availability of relatively low cost power as a consequence of the merger are not overstated, contrary to the criticisms of the Applicants' consultant, Dr. Hieronymous. Dr. Bamberger noted, first of all, that Dr. Hieronymous did not deny that the merger would have an effect on such availability but only claimed that the effect would be relatively small. Dr. Bamberger testified that there is not any reason to believe that the effect will be small. He testified that the effects will likely increase into the future [p. 11, ls. 22-25 and p. 12, ls. 1-11]. Dr. Bamberger testified that the merger would harm the 60 cities represented by the Municipal Electric Systems of Oklahoma because it will cause a reduction in import capability [p. 13, ls. 14-24]. Dr. Bamberger compared this situation to a quota on the import of low priced 54 63 cars. He stated that what the loop flows, in effect, do is reduce the availability of transmission and that is like a quota on relatively low cost power. He stated that being denied access to some of this low cost power, because of the loop flows, harms anybody who would have an opportunity to buy such relatively low cost power [p. 13, l. 25 and p. 14, ls. 1-10]. Dr. Bamberger testified that the Applicants' plan of divestiture under their mitigation measures has nothing to do with the reduction of transmission and how that would increase costs to Oklahoma consumers [p. 16, ls. 9-22 and p. 17, ls. 4-9]. Dr. Bamberger also stated that some of the terms relating to the proposed mitigation measures are ambiguous, for example, the price that the owners of the financially firm energy will get making it difficult for an economist to be able to evaluate the effectiveness of the measure [p. 12, ls. 18-24 and p. 17, ls. 10-15]. Under cross-examination, Dr. Bamberger testified that he did not make an independent evaluation of the impact of the on transmission capability and that he was not competent to perform loop flow studies. Dr. Bamberger noted, however, that both Mr. Maliszewski and Dr. Hieronymous found that the merger caused negative impacts on import capability. Dr. Bamberger observed that the Appendix A analysis (under the FERC Merger Policy Statement) done by Dr. Hieronymous showed that the amount of power that can be imported into the OG&E service area is reduced [p. 19, ls. 12-25 and p. 20, ls. 1-10]. Dr. Bamberger also testified that he relied upon OG&E's engineering studies which show that loop flows would reduce transmission and Mr. Maliszewski's studies which showed the same thing, so he did not do any additional investigation beyond noting that both sides agree [p. 20, ls. 12-25 and p. 21, ls. 1-2]. Although the Applicants and OG&E disagree as to the extent transmission capabilities are reduced, Dr. Bamberger found the parties' agreement to be significant [p. 25, ls. 18-25 and p. 26, ls 1-20]. 55 64 Dr. Bamberger concluded that the effect of the merger on the availability of transmission will likely increase the cost of electricity to a substantial number of customers. This conclusion was based on his observation that absent the merger, CSW would utilize different transmission resources to reach alternative energy suppliers and that AEP was unlikely to be a supplier in Oklahoma and Texas in the future because it has more lucrative opportunities elsewhere [p. 27, is. 2-12, 23-25 and p. 28, ls. 14-17]. Dr. Bamberger cites the testimony of Mr. Maliszewski and Dr. Hieronymous to support this conclusion [p. 28, ls. 8-25 and p. 29, ls. 1-6]. Dr. Bamberger concludes that the Oklahoma Municipal Power Authority and Western Farmers Electric Cooperative will be affected by the merger-induced reductions in transmission capability because they rely on the transmission system of OG&E [p. 31, ls. 11-18]. He reaches this understanding in reliance on the testimony of Mr. Hiebsch without independent knowledge of the facts [p. 31, ls. 19-25 and p. 32, l. 4]. On further cross-examination, Dr. Bamberger was advised that Applicants' interim mitigation measures include a sale of energy from CSW's system, not just from the Northeastern plant, as Dr. Bamberger had testified. However, Dr. Bamberger stated that that fact did not make a difference in his opinions [p. 35, ls. 3-19]. STEPHEN F. HIEBSCH The final witness called on behalf of OG&E was Stephen F. Hiebsch. Mr. Hiebsch is the manager of Market Solutions for OG&E which is the research and service support group of the Marketing and Customer Care Division. Market Solutions contains traditional areas such as cost of service, revenue needs, rate making, electric forecasting for both retail and wholesale, and load research. It also includes areas such as customer research, financial analysis and market studies. Mr. Hiebsch earned his B.S. degree in business and mathematics from Southwestern College in Winfield, Kansas. He did graduate work at Wichita State University in Wichita, 56 65 Kansas, and earned a Master's Degree in Economics from Oklahoma State University. He has also completed an additional 30 hours of graduate courses in economics from Oklahoma State University. Mr. Hiebsch has previously been recognized as an expert witness before this Commission in the areas of economic forecasts, economic analysis, financial analysis and costs of capital. His Responsive Direct Testimony, filed on March 29, 1999 (Exhibit 166), and the summary of his testimony dated April 19, 1999 (Exhibit 217), were accepted into the record [p. 47, l. 19]. Mr. Hiebsch testified that the purpose of his testimony was to identify the concerns that OG&E has with the proposed merger of AEP and CSW, and its subsidiary, PSO, from a competitive and ratepayer impact perspective, and the relief OG&E seeks from the Commission. He stated that OG&E is concerned that the merger of AEP and CSW, as structured with their proposed mitigation measures, will constrict both the number of energy suppliers and the extent to which energy suppliers are able to participate in the Oklahoma marketplace. He testified that this reduction in marketplace participants has the likely effect of raising electric prices by limiting competition. Mr. Hiebsch stated it was his understanding that this merger will be approved automatically if the Commission does not affirmatively reject the merger in the time permitted under Oklahoma law. He said it was also his understanding that under Oklahoma law, the Commission should disapprove the merger if the effect of the merger substantially lessens competition in the furnishing of public utility service in this State. He stated that under the conditions that will prevail in the post-merger world, based upon Applicants' filings and OG&E's review of those filings, it leads OG&E to believe that this merger will have a significant adverse impact on competition in Oklahoma. Furthermore, any savings which might be achieved for 57 66 PSO's Oklahoma customers comes at the expense of customers of the remaining electric providers in this State. Mr. Hiebsch stated that he believes the mitigation measures of the Applicants may never occur since they are based upon Applicants' own subjective determinations of their need for capacity. He also feels that the divestiture of 300 megawatts of capacity is likely to never occur since growth in load of this size could occur in a short period of time. Mr. Hiebsch testified that there is evidence in the record that PSO is already short of capacity, referring to Exhibit SFH-3 to his Responsive Direct Testimony (Exhibit 166). Mr. Hiebsch testified that historically OG&E has had the ability to purchase power off-system for economic reasons. As an example, he stated that the Fort Smith substation is the primary interconnect to OG&E for power coming from the East. In his prefiled testimony, he discussed the various reasons for purchasing power from off system suppliers. He testified that while historically these amounts have not been large, with the changing competitive environment, economy power purchases will increase. He testified that Exhibit SFH-8 to his Responsive Direct Testimony (Exhibit 166) is an example of historic capabilities but is not an indication of the expected growth that is likely to occur. Mr. Hiebsch referred to Mr. Perkins' chart which shows OG&E's entire system is impacted by the 250 megawatts transfer. He stated that in addition to the Entergy interconnection (Fort Smith substation), major interconnection capabilities with SPA, Western Resources and CSW are also significantly reduced. Mr. Hiebsch stated that these increased system wide transmission constraints substantially lessen competition in Oklahoma after the merger. The constraints remove the opportunity to make economic power purchases on behalf of Oklahoma consumers. Also, 58 67 Economic Development will be hurt by the increased transmission constraints which limit competition. Mr. Hiebsch also stated that these constraints hurt more than just OG&E's customers. Cooperative Association members served by Western Farmers and municipal customers served by the Oklahoma Municipal Power Authority, likewise, will be hurt. He said that consumers throughout the State of Oklahoma will be affected by this reduction in import capabilities. The increased transmission constraints limit the geographic size of the marketplace which decreases the opportunity for obtaining purchased energy at a competitive price. Mr. Hiebsch concludes that this hurts all Oklahoma customers. Mr. Hiebsch stated that another negative impact of the merger is the increased transmission line losses as testified to in Mr. Kuebeck's testimony. Mr. Hiebsch testified that these increased line losses cause OG&E's Oklahoma retail and wholesale customers to pay approximately $1.5 million per year more in fuel costs as shown in Exhibit SFH-9 to his Responsive Direct Testimony (Exhibit 166). He stated that in CSW's Proxy Statement, March 5, 1999, which is Exhibit SFH-10 to his testimony (Exhibit 166), the Applicants claim that the PSO customers will receive an $11.8 million fuel cost savings over the next 10 years. By multiplying the annual increased fuel expenditure by 10, the estimated cost to OG&E's Oklahoma retail and wholesale customers attributable to line losses is $15 million over 10 years. Thus, he concludes OG&E's customers are subsidizing PSO's customers. He stated that this does not address any impact that might be placed on transmission systems other than OG&E's. Mr. Hiebsch testified that OG&E's requested litigation measures are as follows: 1. The Applicants must bear all capital expenditures necessary to return the transmission system and the Fort Smith Substation to the pre-merger conditions. He stated that 59 68 the preliminary estimate of this expenditure according to Mr. Perkins is approximately $11 million. 2. The Applicants must bear all expenditures necessary to install the equipment required to correct power factor, 3. Applicants should pay the increased $15 million in fuel costs that is related to increased line losses. 4. Contrary to past practice between PSO and OG&E, there was no effort on the part of the Applicants to conduct any joint planning for future operations. Since OG&E was not fully informed of the Applicants' plans, any conclusions drawn thus far must be considered preliminary. OG&E requests that the Applicants engage in joint planning with the other electric providers in the State to more fully understand the impacts of the merger and resulting operations will have on the State. Furthermore, OG&E requests that the Applicants and the other electric providers in the State work together to resolve issues and problems that arise from this joint planning. Mr. Hiebsch testified that OG&E and its customers must be held harmless from any required capital investments and increased operating costs caused by post-merger operations. He stated that OG&E urges the Commission to dismiss the Application at this time. Mr. Hiebsch testified that notwithstanding the comments of Dr. Hieronymous, OG&E's purchases of power at the Entergy interconnect during the summers of 1996, 1997 and 1998, which is depicted on Exhibit SFH-8 (Exhibit 166) does not overstate the amount of purchases that OG&E makes through the Entergy system. He stated that the path for the energy was actually reserved and payment for the energy was made and, at the time the power was to flow to OG&E, a determination was made, based on weather and other factors, whether OG&E needed 60 69 the power or would sell the power to other entities [p. 45, ls. 16-25 and p. 46, ls. 1-22]. On cross-examination, Mr. Hiebsch testified that Exhibit SFH-8 was introduced to show that there are availabilities to purchase energy off-system through the Fort Smith Substation for OG&E to buy economy purchases of energy so it can lower costs to its customers. He also stated the purpose was to show that this type of trading has gone on in the past and as the competitive environment grows in the future, these purchases could become much larger [p. 55, ls. 14-24]. Mr. Hiebsch testified that the megawatt hours listed on his exhibit for the days of May in 1998 showed instances where actual physical delivery of energy was made. However, he could not testify as to which of the megawatt hours for the month of May in 1998, if any, were actually delivered to OG&E [p. 56, ls. 5-20]. On cross-examination, Mr. Hiebsch admitted that he had assumed that in each hour of the year additional losses caused by transfers from AEP to CSW would be equal to the losses Mr. Kuebeck had calculated that OG&E would experience at the hour of the winter peak on OG&E's system [p. 61, l. 21 - p. 62, l. 13]. Mr. Hiebsch further admitted that he had determined the cost of additional losses caused by a 250 MW transfer from AEP to CSW by assuming that OG&E would burn additional natural gas to make up for such losses [p. 61. l. 2 - p. 63, l. 16]. Mr. Hiebsch testified that OG&E's average annual fuel cost was approximately 52% of its average annual gas cost for generating electricity [p. 60, ls. 1-5]. Mr. Hiebsch testified that he had concluded that the merger would cause OG&E to incur additional losses at a cost of $15 million over the first ten years after consummation of the AEP/CSW merger by multiplying an annual cost of $1.5 million, by 10 years. Mr. Hiebsch testified that Applicants have planned to transfer power from AEP to CSW for the length of the contract [p. 63, ls. 1-25]. 61 70 JIMMY D. CROSSLIN Mr. Jimmy D. Crosslin, Tariff and Cost of Service Coordinator for PUD, testified on behalf of Staff. Mr. Crosslin testified in support of the Stipulation, Exhibit No. 209, which was presented to the Court and accepted into the record in this Cause on April 19, 1999. Mr. Crosslin testified that the terms of the Stipulation are a fair compromise and asked the Commission to accept the Stipulation, as a balance of all interests involved. Mr. Crosslin testified that the Stipulation is fair, just and reasonable, as to the issues it addresses. Mr. Crosslin testified that the Public Utility Division also gave serious consideration, in its review of the Applicants' proposed merger, to the impact it may have on competition in Oklahoma, and the effect it will have on Oklahoma jurisdictional ratepayers. Mr. Crosslin testified that the regulatory plan as initially proposed by the Applicants should be rejected, and stated Staff has developed an alternative plan. Staff recommends that the regulatory plan ultimately approved by the Commission provide meaningful benefits to the ratepayers and that to accomplish this goal, Staff proposes the merger savings be credited against the customer's bill. Mr. Crosslin testified that Staff's proposal provides for a fair and expedient manner to flow the merger savings to ratepayers. Mr. Crosslin testified that he recommends a five-year regulatory plan be adopted to address the regulatory treatment of merger synergies and the cost to achieve the synergies. Mr. Crosslin testified Staff further recommends that each year following the merger closing, the Joint Applicants distribute 50% of the jurisdictional merger synergies to the ratepayers as shown on Attachment A of the December 19, 1998 prefiled testimony of Jimmy D. Crosslin. Mr. Crosslin testified that Staff's plan allows for the customers to receive a merger synergy credit each August following the merger approval date. Mr. Crosslin testified that the merger synergy credit rider should be effective until such time as the Applicants' base rates are adjusted through a general base rate filing. Mr. Crosslin testified that 62 71 Staff also recommends hold harmless conditions to ensure that the ratepayers are shielded from unknown and unintended consequences. Attachment B, of Jimmy D. Crosslin's December 19, 1998 Testimony, provides Staff's overall regulatory plan recommendations. Mr. Crosslin testified the Applicants propose that merger savings be credited against regulatory assets. However, Staff notes that PSO's regulatory assets were definitively addressed in PSO's last rate proceeding, Cause No. PUD 960000214. Next, the Applicants propose the merger savings be applied to depreciation expense to provide the benefit of a lower ratebase for distribution facilities. Mr. Crosslin testified that Staff cannot support the Applicants' proposal since it does not provide meaningful benefits to customers. Mr. Crosslin testified as to the Applicants' retail market power study and the load flow study. Mr. Crosslin testified that the proposed merger substantially lessens competition in a retail access environment. He stated that the Applicants propose market power mitigation measures in order to gain regulatory approval of their proposed merger. Mr. Crosslin further testified that the issue of market power becomes a major and vital concern as the State of Oklahoma moves toward allowing competition for electric utility services. Mr. Crosslin testified that the proposed merger creates market barriers on the transmission system. The proposed merger contemplates transactions from the AEP service territory to CSW. Historically, there have been no trading transactions between the merging parties. Mr. Crosslin testified that the proposed merger seeks to combine separate, distinct, geographic markets through a 250 MW transmission service reservation. Mr. Crosslin testified that the Applicants' reservation for transmission service results in additional congestion on the regional transmission grid. Mr. Crosslin testified that the Applicants' transmission reservation limits market participants' ability to enter the Oklahoma market, which has an impact on the 63 72 competitiveness of the market. Staff's specific recommendations regarding the market power issues and hold harmless conditions are provided in the recommendation portion of Mr. Crosslin's testimony. Furthermore, 17 O.S. Section 191.5 provides that the merger may be disallowed if the Commission finds: the effect of the merger or other acquisition or control would be substantially to lessen competition in the furnishing of public utility service in this state; Mr. Crosslin testified that the proposed merger presents competitive concerns in a retail access environment. Staff recommended the following changes to the Applicants' market power mitigation proposal: 1. The Applicants shall divest generation assets as necessary to address horizontal and vertical market power concerns. 2. The Applicants must provide meaningful hold harmless provisions to ensure that the customer is not negatively impacted by the merger. To date, the Applicants have not provided a meaningful hold harmless mechanism to evaluate the opportunity cost of the customers resulting from diverting cheap generation as part of the interim and divestiture market power mitigation sale. 3. The Applicants shall hold the customers harmless for the cost differential of coal versus natural gas generation resulting from the market power mitigation plan. The Applicants propose to divest coal generation capacity instead of natural gas. Staff recommends the customer be insulated from the adverse effect that might result from the __________. 64 73 4. plan for sharing the generation divestiture gains with the ratepayers. 5. Applicants should agree to a 75% - 25% sharing of the interim generation sale margins. 6. The Applicants load flow study of the transmission system identifies the congestion areas, which has an impact on the performance of Oklahoma transmission systems. Staff recommends the Applicants bear the cost of upgrading the Fort Smith transformers. 7. Finally, Staff recommends the Applicants join an ISO by a date certain to ensure that the transmission system is operated. Mr. Crosslin's prefiled testimony was accepted into the record as Exhibit Numbers 56, 112 and 172, without objection. Mr. Crosslin testified, under cross-examination, that it was his understanding that his testimony should be deemed conformed to be in compliance with the stipulation entered into on April 19, 1999. Mr. Crosslin further testified under cross-examination that an Independent System Operator ("ISO") could identify and take remedial action to remove transmission congestion and constraints through regional transmission planning [p. 84 ls. 16-21], and further stated that PSO, in the offered stipulation, agrees to participate in an ISO pursuant to the Stipulation at page 11, paragraph 17 (Exhibit 209 attached hereto). Mr. Crosslin further testified it was his understanding that the PSO customers will receive 100 percent of the jurisdictional fuel and purchase power savings resulting from the merger. Mr. Crosslin testified that the upgrade to the transformer at the Fort Smith junction is required by the Public Utility Holding Company Act, under the interconnection requirement. Therefore, the expense to upgrade the transformer is an appropriate merger cost. Mr. Crosslin testified that the upgrade is 65 74 necessary to ensure the parties are returned to pre-merger condition [p.86 ls. 12-17]. Mr. Crosslin testified that this is a traditional issue, because ideally, the members of an ISO would pay proportionately for this benefit, but he admitted "we are not there" [p.87 ls. 18-24]. He also testified that the reason the upgrade is needed is the merger transaction [p.87 ls. 24 and 25 and p. 88 l. 1) [See also p. 88 ls. 23-25 and p. 89 ls. 1-3]. Mr. Crosslin was aware that a firm reservation of 250 MW had not been made for the summer of 1999, and therefore there was not a requirement to resolve this issue immediately [p. 89, ls. 4-14]. Mr. Crosslin further reiterated his recommendation was that the Applicants be required to have the Southwest Power Pool perform a regional study to identify whether the merger would cause transmission constraints that may have a negative impact on Oklahoma utilities. The second recommendation was for the Applicants to be required to join an ISO. [p. 90, ls. 1-5 ] It was Mr. Crosslin's opinion that this issue would be resolved if the Southwest Power Pool would in fact do the study, determine if the 250 MW transfer can be performed and determine what the impact was on Oklahoma utilities. The parties should be required to accept the decision rendered by the Southwest Power Pool in this regard [p. 90, ls. 7-12]. Mr. Crosslin was also aware that PSO could accept the position taken by the Staff [p. 90, ls. 13-15]. Mr. Crosslin was also aware that the State of Arkansas in their approval of the merger had made as a condition that if SWEPCO intended on leaving the Southwest Power Pool they would come back and request the Arkansas Public Service Commission for approval [p. 90, ls. 17-22]. 66 75 KENNETH R. ZIMMERMAN Kenneth R. Zimmerman, Ph.D., Tariff & Cost of Service Coordinator for PUD, testified on behalf of Staff. Dr. Zimmerman testified that this application has been evaluated by Staff in terms of the criteria contained in 17 O.S., Section 191.5, as well as the general definitions and standards in Sections 191.1 through 191.13. Section 191.5(A), provides: The Corporation Commission shall approve any merger or other acquisition of control referred to in Section 2 of this act unless, after a public hearing thereon, it finds that one or more of the following conditions will exist if such merger or other acquisition of control is consummated, in which event it shall disapprove such merger or acquisition of control and the same shall not be consummated. The specific criteria in Section 191.5 are: 1. The acquisition of control would adversely affect the contractual obligations of the domestic public utility or of any person controlling such domestic public utility, or its ability or commitment to continue to render the same level of service to its customers that the domestic public utility is currently rendering; 2. The effect of the merger or other acquisition of control would be substantially to lessen competition in the furnishing of public utility service in this state; 3. The financial condition of any acquiring party is such as might jeopardize the financial stability of the domestic public utility or any person controlling such domestic public utility or otherwise prejudice the interest of the domestic public utility's customers; 4. The plans or proposals which an acquiring party has to liquidate the public utility or any such controlling person, sell its assets, or a substantial part thereof, or consolidate or merge it with any person, or to make any other material change in its investment policy, business or corporate structure or management, would be detrimental to the customers of the domestic public utility and not in the public interest; or 5. The competence, experience and integrity of those persons who would control the operation of the domestic public utility are such that it would not be in the interest of its customers and the public to permit the merger or other acquisition of control. Dr. Zimmerman testified that his testimony concerns two criteria in the review Staff performed in assessing the impact of the proposed merger. In addressing these criteria, Dr. Zimmerman testified that he focused on the following: 67 76 1. The PROMOD analyses performed by the applicants to assess the operational costs and characteristics of the combined AEP/CSW generation and transmission systems; and, 2. The economic impact of the proposed merger on the Tulsa Metropolitan Statistical Area (MSA) economy and the Oklahoma economy. Based on its review of the data and information provided by the Applicants and independent analysis, Dr. Zimmerman testified that Staff has reached the following overall conclusions: 1. The PROMOD analyses prepared by the Applicants indicate that the AEP and CSW generation and transmission systems can be operated in combination without significant negative impact on either the reliability or cost of power for the customers of PSO; 2. The PROMOD analyses prepared by the Applicants do not investigate how the AEP and CSW generation and transmission systems might be operated so as to minimize the cost of power to PSO's customers; 3. The economic impact of the proposed merger on the economy of the Tulsa MSA and the economy of the State of Oklahoma is unknown at this time, and for the next 3-5 years; and, 4. An appropriate and acceptable estimate of the impact of the proposed merger on the economy of the Tulsa MSA and the economy of the State of Oklahoma can be made by either the University of Oklahoma or Oklahoma State University, using state level economic modeling tools already available to those institutions. Based on these conclusions, Dr. Zimmerman testified that Staff recommends the Commission approve the proposed merger only if the hold harmless provisions outlined in Mr. Crosslin's testimony are agreed to by the Applicants. Dr. Zimmerman testified that these hold harmless provisions are essential to protect the public interest relative to a proposed merger that has so many uncertainties and potential impacts for Oklahoma. In addition, Staff recommends that the Commission order the Applicants to: 1. Perform more extensive PROMOD analyses to assess any possible operational benefits of the merger for PSO's customers; and, 68 77 2. Perform ongoing analyses to assess the impact of the merger on the economy of Tulsa MSA and the State, in conjunction with the University of Oklahoma or Oklahoma State University if possible. Dr. Zimmerman testified in an in camera proceeding on April 21, 1999, that the Applicants voluntarily had Oklahoma State University perform an analysis to assess the impact of the merger on the economy of Tulsa County, Oklahoma. He further testified regarding the results of the analysis. Dr. Zimmerman's testimony presented in the in camera proceeding on April 21, 1999, is under seal. His conclusions, however, are that additional PROMOD analyses are not needed due to information received in discovery. The economic impact of the merger is not fully known at this time. However, even a worst case scenario would not be a significant adverse economic impact on Tulsa County, considering the size of Tulsa County economy. Dr. Zimmerman's pre-filed testimony was accepted into the record as Exhibit Number 59 without objection or cross-examination. FINDINGS OF FACT AND CONCLUSIONS OF LAW The ALJ finds that this Commission has jurisdiction over the merger pursuant to 17 O.S. Section 191.1 et seq. and OAC 165:5-7-57. Further, the ALJ finds this Commission has jurisdiction over Public Service Company of Oklahoma regarding retail rates and the effect that the merger might have on those rates pursuant to 17 O.S. Section 152, 153 and Okla. Const. Art. 9, Section 18. The conditions for disapproval of a merger are set forth at 17 O.S. Section 191.5, and require the merger be approved unless one of the conditions contained within the statute would exist if the merger is consummated. The Stipulation reached by the Joint Applicants, Staff, CSD, and the AG, which sets forth various hold harmless provisions, guaranteed rate reductions, guaranteed a base rate increase moratorium, quality of service standards and a most favored nations clause, satisfies the majority of the statutory standards. The primary areas of inquiry raised by Intervenor OG&E and others, relating to whether the merger would lessen competition 69 78 in the furnishing of public utility service in the state, is negated by the Joint Applicants' commitment to engage in joint planning and the involvement of the Southwest Power Pool. The evidence tends to show that market power will indeed be impacted in Oklahoma and competition harmed because of the impact of the merger on the transmission system at the Ft. Smith transformer which may result in line losses and congestion. The evidence also tends to show that the Southwest Power Pool did not list this area of transmission (OG&E's Ft. Smith transformer) as a problem in its seasonal studies and OG&E has no plans for any upgrades for the next five years. The ALJ further finds that the Commission should direct PSO and OG&E to request the Southwest Power Pool to evaluate and identify the impact on the transmission import capability into Oklahoma at the Ft. Smith 161/500 MCA Transformer of the 250 MW transfer of power from AEP to CSW across the Ameren system and to identify what, if any, corrective action should be taken to return the Oklahoma transmission system to pre-merger condition. The ALJ further finds that the Commission should require that, after the Southwest Power Pool has made its determination, the Joint Applicants be required to reimburse OG&E for the proportionate share that the Joint Applicants contribute to any problem found to exist on the Oklahoma transmission system by making such transfers recognizing that some part of the problems caused by the merger already exist at the Ft. Smith substation that has resulted in outages and congestion. The ALJ further finds that authority over the alleged line loss issue lies with the Federal Energy Regulatory Commission. 70 79 RECOMMENDATION After careful consideration of the testimony and the Stipulation, the ALJ recommends that the Commission issue an order approving the merger based upon the conditions set forth herein: The ALJ further recommends that the Commission issue an order approving the Stipulation as being fair, just and reasonable. The ALJ further recommends that the Commission direct PSO and OG&E to request the Southwest Power Pool to evaluate the impact on OG&E's Fort Smith 161/500 MVA transformer of a 250 MW transfer of power from AEP to CSW across the Ameren system and identify what, if any, corrective action should be taken. The ALJ further recommends that the Commission require that, after the Southwest Power Pool has made its determination, the Joint Applicants be required to reimburse OG&E for the proportionate share that the Joint Applicants contribute to any problem found to exist at the Fort Smith substation by making such transfers, recognizing that a problem already exists at the Fort Smith substation that has resulted in outages and congestion. The ALJ further recommends that the Commission direct the Joint Applicants to report the results of the Southwest Power Pool evaluation to the Director of the Public Utility Division of the Oklahoma Corporation Commission no later than June 14, 1999. The ALJ further recommends that the Commission issue an order stating that the Commission lacks jurisdiction to address the question of line loss reimbursement based upon the facts presented in this Cause. 71 80 DATED this 4th day of May, 1999 /s/ ROBERT E. GOLDFIELD Administrative Law Judge 72 81 BEFORE THE CORPORATION COMMISSION OF THE STATE OF OKLAHOMA JOINT APPLICATION OF AMERICAN ) ELECTRIC POWER COMPANY, INC., ) PUBLIC SERVICE COMPANY OF ) CAUSE NO. PUD 980000444 OKLAHOMA AND CENTRAL AND SOUTH ) WEST CORPORATION REGARDING ) PROPOSED MERGER ) STIPULATION The parties to this Stipulation, dated as of April 16, 1999, are the Public Utility Division (Staff) and the Consumer Services Division (CSD) of the Oklahoma Corporation Commission (OCC or Commission); American Electric Power Company, Inc. (AEP); Central and South West Corporation (CSW); Public Service Company of Oklahoma or any successor (PSO); and, the Attorney General of the State of Oklahoma (Attorney General). The foregoing parties to this cause shall be referred to individually either as a Signatory or by the acronym assigned above, and collectively as the Signatories. The Signatories submit this Stipulation to the Commission as representing a just and reasonable disposition of the issues addressed in this Stipulation; the Signatories request approval of this Stipulation and entry of an order consistent with this Stipulation. The Signatories stipulate and agree as follows: STATEMENT OF SIGNATORIES' INTENT The purpose of the plan is to distribute net merger savings through a credit rider to retail ratepayers. The minimum life of the credit rider is five years. It is the intention of the Signatories to this Stipulation that, at a minimum, a five-year plan be implemented. The costs to achieve the merger incurred prior to the end of the first two years after the effective date of the merger will be deferred and amortized. These costs are to be amortized during the five-year period after the 82 effective date of the merger. If a general rate change proceeding changes PSO's base rates within the first five years after the effective date of the merger, the shareholder savings imputation shall be used and the credit rider will continue regardless of any changes to base rates. If a general rate change proceeding changes PSO's base rates after the first five years after the effective date of the merger, no shareholder savings imputations or deferred costs to achieve amortization shall be used and the credit rider shall terminate upon the implementation of new base rates. The Applicants commit to hold PSO Oklahoma retail customers harmless from adverse impacts of the merger. PSO commits not to seek a general base rate change prior to January 1, 2003. If PSO seeks a general rate change from January 1, 2003 through the fifth year anniversary of the effective date of the merger, the Applicants agree to a $5,000,000 reduction to PSO's revenue requirement as otherwise determined by the Commission. The parties acknowledge that there may be changes in the number of Central and South West Services, Inc. (CSWS) or PSO employees located within Oklahoma as a result of this merger and the level of such changes have not been finally determined. The economic impacts of this merger are not addressed in this partial Stipulation and remain unresolved. It is the intent of the Signatories that all five attachments to this Stipulation be incorporated as if set forth fully herein. SECTION 1. NON-OPPOSITION TO MERGER. Both the Staff and the Attorney General acknowledge that they will not oppose the merger as to the issues stipulated herein before the Federal Energy Regulatory Commission (FERC). Further, the Staff recommends that the Commission file a position statement in consolidated FERC Docket Nos. EC98-40-000; ER98-2770-000; and ER98-2786-000 indicating that it does not oppose the merger. The Staff reserves the right to litigate before FERC the impact of the merger upon the transmission system in Oklahoma, which includes the impact of the merger upon other 2 83 Oklahoma jurisdictional utilities and also includes the impact of potential line losses and potential increased congestion within Oklahoma. SECTION 2. THE PROPOSED PLAN. This Stipulation has been developed to ensure that Oklahoma retail customers of PSO receive the benefits of the merger. The proposed plan set forth below is reasonable and in the public interest. SECTION 3. SHARING OF NET NON-FUEL AND NON-PURCHASED POWER OPERATION AND MAINTENANCE EXPENSE SAVINGS. (a) PSO will implement a net merger savings (net of costs to achieve the merger as defined in Section 3(b)) rider in Oklahoma that will reduce rates to customers by the annual amount shown in Attachment 1 beginning with the first revenue month after the effective date of the merger. Each individual year's rate reduction will apply for a twelve month period as presented in Attachment 1, with a $9,409,000 annual reduction to be applied in each of the years following the end of the fifth year until new base rates for PSO become effective pursuant to a general rate change proceeding.(1) At the end of the five-year period, deferred costs to achieve amortization and shareholder savings imputations as addressed in Section 3(c) shall terminate. (b) Costs to achieve the merger ("costs to achieve") are those costs reasonably and prudently incurred within the first two years after the effective date of the close of the merger in order to consummate the merger and combine the operations of AEP and CSW. These costs include, but are not limited to, investment banking fees; consulting and legal services incurred in connection with obtaining regulatory and shareholder approvals; transition planning and development costs; employee separation costs including severance costs, change-in-control payments and retraining costs; systems integration costs; operations integration costs including - ---------- (1) The Signatories' understanding for the purpose of this Stipulation of what constitutes a general rate change proceeding is one in which the overall non-fuel base revenue requirements of the company are revised. 3 84 telecommunication costs; and facilities consolidation costs. The costs to achieve are to be recovered through merger savings. For Oklahoma retail jurisdictional ratemaking purposes, PSO will defer the lesser of estimated or actual costs to achieve incurred prior to the end of two years after the effective date of the merger. These deferred costs will be amortized over a five-year period beginning with the effective date of the merger. The amortized costs for each year shall be proportionate to the aggregate estimated merger savings for the corresponding year as seen in Attachment 1. Applicants shall credit the customer via an allocation methodology that allocates the net merger savings according to Attachment 2. (c) If changes in base rates of PSO, pursuant to a general rate change proceeding, occur within the first five years after the effective date of the merger, the following rate treatments shall be reflected: (1) Estimated non-fuel operation and maintenance expense merger savings net of costs-to-achieve will be included in cost of service as an allowable expense. The amount to be included in the cost of service shall be based upon the test year period. (2) Amortization of costs to achieve will be included in cost of service as an allowable expense. The amount to be included in the cost of service shall be based upon the test year. The unamortized balance of costs to achieve will not be included in rate base and no return will be allowed on the unamortized balance of costs to achieve. (3) The merger savings rate reduction rider as described in Paragraph (a) above shall continue. (4) The Applicants shall have the burden of proof to show that they have substantially achieved the estimated level of merger savings as shown in Attachment 1. If the Applicants cannot demonstrate in any general rate change proceeding initiated within the first five years after the effective date of the merger, that they have substantially achieved the estimated merger savings, then the shareholders' portion of net merger savings (as shown in Attachment 1) shall not be included as a cost of service expense. (5) Attachment 3 is an example of the retail base rate treatment described in this subsection. 4 85 (d) For each year following the end of the fifth year after the effective date of the merger, a $9,409,000 annual reduction will be reflected in the net merger savings rate reduction rider. In any retail base rate change proceeding after the fifth year after the effective date of the merger, the following rate treatments will be reflected: (1) No estimated non-fuel operation and maintenance expense merger savings will be included in cost of service as an allowable expense. (2) No amortization of costs to achieve will be included as an allowable expense. (3) The merger savings rate reduction rider will cease upon the effective date of the new base rates. (e) In the event the electric utility industry in Oklahoma is restructured prior to the end of the fifth year after the effective date of the merger, the then effective rider benefits, as described above in Section 3, and costs to achieve amortization pursuant to Section 3(b) shall be deemed applicable in their entirety to the rates of the unbundled services that remain regulated by the Commission. The costs to achieve amortization and rider benefits shall continue in full, and remain unaltered, for the five-year term, except in the case of a general rate change proceeding initiated by a party other than PSO. (f) In the event of any general rate change proceeding initiated by a party other than PSO subsequent to industry restructuring and prior to the end of the fifth year, the rider benefits, cost amortization, and shareholder net savings imputation shall be reduced proportionate to the rates of regulated unbundled services. It is the intent of the Signatories that the cost amortization, net merger savings rider, and shareholder savings amputations continue for the five-year term for those services subject to continued regulation by the State of Oklahoma. It is also the intent of the Signatories that the benefits would continue for the period of time in which the net merger savings rider set forth in Section 3 above remains in effect for those services subject to continued regulation by the State of Oklahoma. 5 86 SECTION 4. SHARING OF FUEL AND PURCHASED POWER EXPENSE SAVINGS. After the effective date of the merger, all jurisdictional fuel and purchased power expense savings resulting from the merger shall accrue to the benefit of the retail customers through the existing fuel cost recovery mechanism. SECTION 5. ACCESS TO BOOKS AND RECORDS. The Applicants agree that subject to regulatory authority, the OCC and Attorney General will either have access in Oklahoma to copies of books and records of AEP and its affiliates and subsidiaries (including their participation in joint ventures) with respect to matters and activities that relate to Oklahoma retail rates or AEP will pay reasonable and prudently incurred travel expenses to conduct on-site review of books and records. The OCC and Attorney General will have access to the books and records of PSO to the degree required to fully audit, examine, or otherwise investigate transactions between PSO and AEP affiliates. SECTION 6. AGREEMENT REGARDING STRANDED INVESTMENT. The Applicants commit and agree that stranded costs, if any, that PSO may seek to recover will be on a stand-alone basis, and will be limited to the ownership-interest of PSO's assets and obligations. PSO does not have any stranded costs under current Oklahoma regulation. The merger by itself does not create stranded costs. SECTION 7. MITIGATION. To mitigate any perceived impacts of the merger on the Applicants' market power, the Applicants have proposed in their FERC merger application a mitigation plan which includes the following: (1) Divestiture of 300 megawatts of coal-fired generating capacity at the Northeastern generating plant after such plant is no longer required to meet PSO's native load demand requirements subsequent to industry restructuring in Oklahoma. 6 87 (2) Sale of 300 megawatts per hour of energy on an interim basis prior to the divestiture of the Northeastern capacity. (3) Waiver of PSO's priority to the use of CSW interfaces with other transmission systems to import centrally dispatched energy from the existing AEP system in excess of 250 megawatts. (4) Waiver of PSO's priority to the use of CSW interfaces to import non-firm energy from non-affiliates. (5) Schedule CSW's use of the two high voltage direct current (HVDC) ties between ERCOT and the SPP on a first-in-time basis for certain transactions. The Applicants commit to hold PSO Oklahoma retail customers harmless from adverse impacts from these transactions. Attachment 4 to this agreement describes the methodology that the Applicants will follow in order to hold PSO Oklahoma retail customers harmless from adverse effects of the interim mitigation sale. The Applicants' market power mitigation plan is reasonable and is subject to approval at the FERC. To the extent that the market power mitigation plan is modified by a final order of the FERC, the Applicants will inform the Commission and the Attorney General of such modifications. The Applicants shall make a filing with the Commission to address such modification, so as to ensure that Oklahoma PSO retail customers are held harmless from adverse effects of such plan, and quantify and determine the regulatory treatment of gains, if any. SECTION 8. BASE RATE MORATORIUM. Applicants will commit not to seek a base rate increase over base rates as of the date of this Stipulation, subject to major Force Majeure provisions set forth below, which would become effective prior to January 1, 2003. If a rate review is sought by the Applicants after January 1, 2003 through the end of the fifth year after the effective date of the merger, the Applicants shall make a $5,000,000 reduction to the revenue requirement otherwise determined by the Commission to be reasonable. 7 88 SECTION 9. FORCE MAJEURE. Prior to January 1, 2003, if Force Majeure or events beyond the influence and/or control of PSO occur, including Oklahoma legislative action regarding industry restructuring or unbundling, PSO shall be entitled to file for a general rate review pursuant to OAC 165:70 and in such case, PSO will have the burden of proving (1) that its request for relief is a good faith request, (2) that the event or occurrence was not directly or indirectly caused by PSO, (3) the event or occurrence has at least an annual impact of $6,000,000 and (4) that PSO had no direct or indirect control over the event or occurrence. The Signatories will have the right to challenge PSO's request for rate relief. In any rate proceeding pursuant to this Section, merger costs and savings will be treated in accordance with Section 3. SECTION 10. REGULATORY AUTHORITY. Applicants agree not to assert in proceedings before this Commission, or in court proceedings related to this Commission, that the authority of the Securities and Exchange Commission ("SEC") as interpreted in Ohio Power v. FERC, 554 F.2d 779 (D.C. Cir. 1992.) cert. denied, 498 U.S. 73 (1992) impairs the Oklahoma Corporation Commission's ability to examine the reasonableness of non-power affiliate costs to be passed to PSO's retail customers. The parties agree that the Ohio Power waiver does not include waiver of any arguments that AEP/CSW may have with respect to the reasonableness of SEC approved cost allocations, as opposed to the reasonableness of the costs themselves. SECTION 11. CAPITAL COSTS. The Applicants commit and agree that the cost of capital as reflected in PSO's rates shall not be adversely affected by the result of AEP's acquisition of CSW. The Applicants al so agree that subsequent to the completion of the merger, the cost of capital from PSO should be set commensurate with the risk of PSO and should not be affected by the merger. Applicants agree 8 89 that they will not oppose, in either a regulatory proceeding or an appeal of a decision by the OCC, the application of the principal that the determination of the cost of capital can be based on the risk attendant to the regulated operations of PSO. SECTION 12. QUALITY OF SERVICE. The Applicants agree to the quality of service standards set forth in Attachment 5. SECTION 13. MOST FAVORED NATIONS. The Applicants commit and agree that upon issuance of any final and non-appealable order from the FERC, SEC, or any state or federal commission addressing the merger, through stipulation or otherwise, providing any benefits to customers of any jurisdiction or imposing any conditions on Applicants that would benefit the customers of any jurisdiction, such net benefits and conditions will be extended to PSO Oklahoma retail customers to the extent necessary to achieve equivalent net benefits and conditions to the Oklahoma PSO retail customers, provided the proposed merger is ultimately consummated. Joint Applicants will provide to the director of the Public Utility Division and the Attorney General any final and non-appealable order from the FERC, SEC, or any state or federal commission addressing the merger, through stipulation or otherwise. SECTION 14. MERGER SAVINGS HOLD HARMLESS CONDITIONS. The Applicants agree to hold harmless the retail customers of PSO from unforeseen events that materially diminish the estimated benefits of the merger and from major deviations from the Applicants' stated representations of estimated merger benefits as reflected in Column 5 of Attachment 1 in calculating the benefits to flow to retail customers. SECTION 15. COST RECOVERY. If the merger is not consummated, the Applicants commit and agree not to seek to recover transition or transaction costs, or termination fees, including but not limited to the "Out of Pocket" 9 90 and "Topping Out" fees associated with the merger described in Sections 9.5 and 9.6 of the Agreement and Plan of Merger By and Among American Electric Power Company, Inc., Augusta Acquisition Corporation and Central and South West Corporation dated December 21, 1997 (Merger Agreement) and further commit and agree not to seek to recover fees related to the merger that may be charged by Morgan Stanley. SECTION 16. NON-RECOURSE PROVISION. A PSO affiliate may not incur debt or pledge the stock of PSO in a manner that, on the affiliate's default, would permit a creditor to have recourse against the regulated assets of PSO. SECTION 17. REGIONAL TRANSMISSION ORGANIZATION. The Applicants offer the following as a condition to approval of the merger: Prior to the later of six months prior to retail customer choice, or December 31, 2001, the Applicants agree that AEP will file with the FERC an unconditional application to, consistent with the RTO agreement, transfer the operational control of bulk transmission facilities owned, controlled and/or operated by AEP currently located in the Southwest Power Pool to a FERC-approved Regional Transmission Organization directly interconnected with the AEP transmission facilities. The above date shall be extended, if necessary, to 75 days after FERC issues the order on an RTO to which AEP is a signatory that is filed before June 30, 2001. Notwithstanding any other provision of this agreement, the Joint Applicants will not be precluded from seeking recovery of costs required to implement a Regional Transmission Organization. SECTION 18. NOTICE OF CLOSING. AEP shall notify the parties of the date the merger closes promptly after the closing occurs. This notice shall be sent to the parties in care of their respective attorneys of record at the addresses shown on the service list in this docket. 10 91 SECTION 19. SUPPORT OF STIPULATION AND EFFECT OF MODIFICATION OF STIPULATION. The Signatories shall recommend that the Commission enter an order consistent with this stipulation in all material respects. If the Commission enters an order inconsistent with this stipulation, any Signatory may withdraw its consent to this Stipulation, and the withdrawing Signatory's agreement to this Stipulation shall be extinguished. The withdrawing Signatory shall not be deemed to have in any way waived or compromised any right to urge that a different result, methodology, or position be required by law or the facts. The Signatories agree that the provisions of this Stipulation are the result of extensive negotiations and that the terms and conditions of this Stipulation are interdependent. The Signatories agree that settling the issues in this Stipulation is in the public interest, and, for this reason, they have entered into this Stipulation to resolve among themselves the issues in this Stipulation. This Stipulation is a compromise and settlement among the Signatories, and no Signatory is bound beyond its obligation to support this Stipulation. This Stipulation shall not constitute nor be cited as precedent or deemed an admission by any Signatory in any other proceeding except as necessary to enforce its terms before the Commission or any state court of competent jurisdiction. The Commission's decision, if it enters an order consistent with this Stipulation, will be binding as to the matters decided regarding the issues described in this Stipulation, but the decision will not be binding with respect to similar merger plans that might arise in other proceedings. A Signatory's support of this Stipulation may differ from its position or testimony in other causes. To the extent there is a difference, the Signatories are not waiving their positions in other causes. Because this is a stipulated agreement, the Signatories are under no obligation to take the same positions as set out in this Stipulation in other dockets. 11 92 Fully and duly authorized representatives of the Signatories have signed this Stipulation as of the date first set forth above. GENERAL COUNSEL FOR THE PUBLIC UTILITY DIVISION OF THE OKLAHOMA CORPORATION COMMISSION By: /s/ Deborah Jacobson COUNSEL FOR THE CONSUMER SERVICES DIVISION OF THE OKLAHOMA CORPORATION COMMISSION By: /s/ Marchi McCartney COUNSEL FOR THE OFFICE OF THE ATTORNEY GENERAL OF THE STATE OF OKLAHOMA By: /s/ Deborah R. Morgan COUNSEL FOR AMERICAN ELECTRIC POWER COMPANY, INC. By: /s/ Cody L. Graves COUNSEL FOR CENTRAL AND SOUTH WEST CORPORATION AND PUBLIC SERVICE COMPANY OF OKLAHOMA By: /s/ Jack P. Fite 12 93 Attachment 1 AEP/CSW MERGER NET ANNUAL MERGER SAVINGS AND OKLAHOMA CUSTOMER RATE REDUCTIONS ($000)
(1) (2) (3) (4) (5) (6) Costs to Gross Merger Achieve Net Merger Customer Rate Shareholder Period Savings the Merger Savings Reduction* Savings ------ ------- ---------- ------- ---------- ------- Year 1..................... 8,255 2,524 5,731 3,179 2,552 Year 2..................... 12,648 3,868 8,780 4,871 3,909 Year 3..................... 15,264 4,668 10,596 5,878 4,718 Year 4..................... 17,355 5,307 12,048 6,684 5,364 Year 5..................... 18,817 5,754 13,063 7,247 5,816 72,339 22,121 50,218 27,859 22,359 Percent of Net Savings..... 55.5% 44.5%
- ------------- * The amount of customer rate reduction to be used after Year 5 and which will continue until the effective date of the first base rate change after Year 5 is $9,409. 1 94 Attachment 2 PUBLIC SERVICE COMPANY OF OKLAHOMA Net Merger Savings Rate Reduction Percentage Allocation of Merger Savings to Rate Class
OCC PUD 960000214 PROPOSED BASE % OF CLASS SAVINGS RATE CODE NON-FUEL REVENUES NON-FUEL REV SPREAD ---------------- RESIDENTIAL 1 Residential LURS 120 $5,885,299 3.420% 1.710% 2 Residential GCLURS 125 319,841 0.186% 0.093% 3 Residential RS 140 151,429,153 88.002% 44.001% 4 Residential GCRS 150 14,439,411 8.391% 4.196% ------------------------------------------------------- --------------------- ----------------- -------------- 5 TOTAL RESIDENTIAL 172,073,704 100.000% 50.000% ------------------------------------------------------- --------------------- ----------------- -------------- COMMERCIAL & INDUSTRIAL SER. LEVEL 5 6 C & I SL5 LUGS 575, 675, 676 33,019,230 29.439% 8.243% 7 C & I SL5 GS 5 680, 651, 685, 686, 2660 65,581,934 58,471% 16.372% 8 C & I SL5 PL5 550, 560, 650, 651, 655, 656, 2650 12,453,658 11.103% 3.109% 9 C & I SL5 GSTOD 750 157,856 0.141% 0.039% 10 C & I SL5 MP 835, 836, 837 592,526 0.528% 0.148% 11 C & I SL5 UMS 435, 436, 444 356,569 0.318% 0.069% ------------------------------------------------------- --------------------- ----------------- -------------- 12 TOTAL COMMERCIAL & INDUSTRIAL SER. 112,161,773 100.000% 28.000% LEVEL 5 ------------------------------------------------------- --------------------- ----------------- -------------- COMMERCIAL & INDUSTRIAL SER. LEVEL 4 13 C & I SL4 GS 680 3,493,596 58.842% 0.941% 14 C & I SL4 PL 640 2,337,453 39.370% 0.630% 15 C & I SL4 LUGS 574, 674 106,151 1.788% 0.029% 16 C & I SL4 GS TOD 740 0 0.000% 0.000% ------------------------------------------------------- --------------------- ----------------- -------------- 17 TOTAL COMMERCIAL & INDUSTRIAL SER. 5,937,200 100.000% 1.600% LEVEL 4 ------------------------------------------------------- --------------------- ----------------- -------------- COMMERCIAL & INDUSTRIAL SER. LEVEL 3 ------------------------------------------------------- --------------------- ----------------- -------------- 18 C & I SL 3 LPL 630, 632, 635, 637, 2630, 2635 25,665,299 100.000% 8.000% ------------------------------------------------------- --------------------- ----------------- -------------- COMMERCIAL & INDUSTRIAL SER. LEVEL 2 ------------------------------------------------------- --------------------- ----------------- -------------- 19 C & I SL2 LPL 620, 625, 2620, 2625 22,875,147 100.000% 10.000% ------------------------------------------------------- --------------------- ----------------- -------------- COMMERCIAL & INDUSTRIAL SER. LEVEL 1 ------------------------------------------------------- --------------------- ----------------- -------------- 20 C & I SL1 LPL 612, 617, 2612 2617 3,559,629 100.000% 1.800% ------------------------------------------------------- --------------------- ----------------- -------------- LIGHTING 21 Lighting GSL 833-834 4,660 0.078% 0.000% 22 Lighting OL 320-325 334,335 5.631% 0.034% 23 Lighting SL 310, 311, 330, 340, 360 4,838,557 81.498% 0.489% 24 Lighting MSL 830-832 759,466 12,792% 0.077% ------------------------------------------------------- --------------------- ----------------- -------------- 25 TOTAL LIGHTING 5,937,018 100.000% 0.600% ------------------------------------------------------- --------------------- ----------------- -------------- ------------------------------------------------------- --------------------- ----------------- -------------- 26 TOTAL RETAIL 348,209,770 100.000% ------------------------------------------------------- --------------------- ----------------- --------------
1 95 PUBLIC SERVICE COMPANY OF OKLAHOMA Net Merger Savings Rate Reduction Percentage Allocation of Merger Savings to Rate Class
Year 1 Year 2 Year 3 Year 4 ---------------- --------------- ---------------- ---------------- Annual Savings Annual Savings Annual Savings Annual Savings Rate Code $3,179,000 $4,871,000 $6,878,000 $6,664,000 ---------------- RESIDENTIAL 1 Residential LURS 120 $ 54,364 $ 83,299 $ 100,520 $ 114,384 2 Residential GCLURS 125 2,954 4,527 5,463 6,212 3 Residential RS 140 1,398,800 2,143,301 2,506,393 2,941,043 4 Residential GCRS 150 133,381 264,373 246,624 200,441 ---------------------------------------- ---------------- --------------- ---------------- ---------------- 5 TOTAL RESIDENTIAL 1,589,500 2,435,500 2,939,000 3,342,000 ---------------------------------------- ---------------- --------------- ---------------- ---------------- COMMERCIAL & INDUSTRIAL SER. LEVEL 5 6 C & I SL5 LUGS 575, 675, 676, 262,842 401,512 484,518 550,956 680 7 C & I SL5 GS 5 681, 685, 686. 2660 520,441 797,472 962,337 1,094,294 8 C & I SL5 PL5 550, 560, 650, 651, 655, 656, 98,833 151,436 183,743 207,800 2650 9 C & I SL5 GSTOD 750 1,253 1,920 2,316 2,634 10 C & I SL5 MP 835, 836, 837 4,702 7,203 8,095 9,087 11 C & I SL5 UMS 435, 426, 444 2,830 4,336 5,232 5,990 ---------------------------------------- ---------------- --------------- ---------------- ---------------- 12 TOTAL COMMERCIAL & INDUSTRIAL SER. 80,120 1,363,000 1,645,840 1,871,520 LEVEL 5 ---------------------------------------- ---------------- --------------- ---------------- ---------------- COMMERCIAL & INDUSTRIAL SER. LEVEL 4 0 0 0 0 13 C & I SL4 GS 680 29,930 43,859 35,340 62,929 14 C & I SL4 PL 640 20,025 30,083 37,826 42,163 15 C & I SL4 LUGS 574, 674 909 1,393 1,681 1,912 16 C & I SL4 GS TOD 740 0 0 0 0 ---------------------------------------- ---------------- --------------- ---------------- ---------------- 17 TOTAL COMMERCIAL & INDUSTRIAL SER. 90,864 77,936 94,848 106,944 LEVEL 4 ---------------------------------------- ---------------- --------------- ---------------- ---------------- COMMERCIAL & INDUSTRIAL SER. LEVEL 3 ---------------------------------------- ---------------- --------------- ---------------- ---------------- 18 C & I SL 3 LPL 630, 632, 635, 637, 2630, 2635 234,320 389,600 470,240 534,720 ---------------------------------------- ---------------- --------------- ---------------- ---------------- COMMERCIAL & INDUSTRIAL SER. LEVEL 2 ---------------------------------------- ---------------- --------------- ---------------- ---------------- 19 C & I SL2 LPL 620, 625, 2620, 2625 317,980 487,100 587,800 608,400 ---------------------------------------- ---------------- --------------- ---------------- ---------------- COMMERCIAL & INDUSTRIAL SER. LEVEL 1 ---------------------------------------- ---------------- --------------- ---------------- ---------------- 20 C & I SL1 LPL 617, 617, 2812, 2617 57,222 87,678 105,884 120,312 ---------------------------------------- ---------------- --------------- ---------------- ---------------- LIGHTING 21 Lighting GSL 833-834 15 23 28 31 22 Lighting OL 320-325 1,074 1,646 1,986 2,258 23 Lighting SL 310-311, 330, 15,545 23,819 28,743 32,084 340, 360 24 Lighting MSL 830-832 2,440 3,739 4,511 5,130 ---------------------------------------- ---------------- --------------- ---------------- ---------------- 25 TOTAL LIGHTING 19,074 29,226 35,268 40,104 ---------------------------------------- ---------------- --------------- ---------------- ---------------- ---------------------------------------- ---------------- --------------- ---------------- ---------------- 26 TOTAL RETAIL 3,179,000 4,871,000 5,878,000 6,684,000 ---------------------------------------- ---------------- --------------- ---------------- ---------------- Year 5 Total Rev. Year 6 --------------- ---------------- ---------------- Annual Savings 6 Yr Savings Annual Savings Rate Code $7,247,000 $27,808,000 $9,409,000 ---------------- RESIDENTIAL 1 Residential LURS 120 $ 123,932 $ 476,420 $ 168,984 2 Residential GCLURS 125 6,735 25,891 8,744 3 Residential RS 140 3,196,770 12,298,308 4,140,077 4 Residential GCRS 150 304,863 1,168,882 394,774 ---------------------------------------- --------------- ---------------- ---------------- 5 TOTAL RESIDENTIAL 3,623,500 13,929,500 4,704,500 ---------------------------------------- --------------- ---------------- ---------------- COMMERCIAL & INDUSTRIAL SER. LEVEL 5 6 C & I SL5 LUGS 575, 675, 676, 597,363 2,296,390 775,575 680 7 C & I SL5 GS 5 681, 685, 686. 2660 1,186,467 4,561,000 1,540,426 8 C & I SL5 PL5 550, 560, 650, 651, 655, 656, 225,304 866,115 292,519 2650 9 C & I SL5 GSTOD 750 2,856 10,978 3,706 10 C & I SL5 MP 835, 836, 837 10,720 41,288 13,918 11 C & I SL5 UMS 435, 426, 444 6,451 24,798 8,375 ---------------------------------------- --------------- ---------------- ---------------- 12 TOTAL COMMERCIAL & INDUSTRIAL SER. 2,829,100 7,800,520 2,634,520 LEVEL 5 ---------------------------------------- --------------- ---------------- ---------------- COMMERCIAL & INDUSTRIAL SER. LEVEL 4 0 0 0 13 C & I SL4 GS 680 68,229 262,287 88,504 14 C & I SL4 PL 640 45,658 173,488 99,200 15 C & I SL4 LUGS 574, 674 2,073 7,989 2,002 16 C & I SL4 GS TOD 740 0 0 0 ---------------------------------------- --------------- ---------------- ---------------- 17 TOTAL COMMERCIAL & INDUSTRIAL SER. 115,952 445,744 150,544 LEVEL 4 ---------------------------------------- --------------- ---------------- ---------------- COMMERCIAL & INDUSTRIAL SER. LEVEL 3 ---------------------------------------- --------------- ---------------- ---------------- 18 C & I SL 3 LPL 630, 632, 635, 637, 2630, 2635 579,760 2,228,720 732,720 ---------------------------------------- --------------- ---------------- ---------------- COMMERCIAL & INDUSTRIAL SER. LEVEL 2 ---------------------------------------- --------------- ---------------- ---------------- 19 C & I SL2 LPL 620, 625, 2620, 2625 724,700 2,785,900 948,980 ---------------------------------------- --------------- ---------------- ---------------- COMMERCIAL & INDUSTRIAL SER. LEVEL 1 ---------------------------------------- --------------- ---------------- ---------------- 20 C & I SL1 LPL 617, 617, 2812, 2617 130,446 501,462 109,362 ---------------------------------------- --------------- ---------------- ---------------- LIGHTING 21 Lighting GSL 833-834 34 131 44 22 Lighting OL 320-325 2,449 9,413 3,179 23 Lighting SL 310-311, 330, 35,437 136,227 46,009 340, 360 24 Lighting MSL 830-832 5,562 21,382 7,222 ---------------------------------------- --------------- ---------------- ---------------- 25 TOTAL LIGHTING 43,482 167,154 56,454 ---------------------------------------- --------------- ---------------- ---------------- ---------------------------------------- --------------- ---------------- ---------------- 26 TOTAL RETAIL 7,247,000 27,859,000 9,409,000 ---------------------------------------- --------------- ---------------- ----------------
2 96 Attachment 3 AEP/CSW MERGER EXAMPLE OF BASE RATE CASE TREATMENT BASED ON YEAR 3 ($000)
CREDIT PER RIDER CONTINUES (5,878) INCLUDED IN TEST YEAR: GROSS MERGER SAVINGS (15,264) CHANGE IN CONTROL AMORTIZATION 1,160 OTHER CTA AMORTIZATION 3,508 ---------------- TOTAL CTA AMORTIZATION 4,668 ----------------- NET MERGER SAVINGS IN TEST YEAR (10,596) ADD BACK TO TEST YEAR COST OF SERVICE: CUSTOMER SHARE (Attachment A1- Year 3, Col. 5) 5,878 SHAREHOLDER PORTION (Attachment A1- Year 3, Col. 6) 4,718 ---------------- 10,596 ----------------- NET RATE REDUCTION 0 --------------- OKLAHOMA CUSTOMER RATE REDUCTION (5,878) ===============
1 97 Attachment 4 MITIGATION SALE HOLD HARMLESS METHODOLOGY The following describes the methodology proposed by the Applicants to account for the margins from the Market Mitigation Sale in order to meet the Hold Harmless provisions of the agreements between the Applicants and the Arkansas, Louisiana and Oklahoma commissions. Applicants will do an "after the fact" calculation, using actual hourly data, to reconstruct the dispatch and determine margins from the mitigation sale. This calculation will be referred to as the Regulatory Mitigation Reconstruction (RMR). The RMR will not alter the methodology currently used by CSW under the CSW Operating Agreement to account for transactions by and between the CSW Operating Companies. The RMR will be used to determine if the mitigation sale resulted in negative margins, which should not be included in the retail customer eligible fuel and provide the mechanism by which the Applicants will ensure that retail customers are held harmless from this sale. The RMR will calculate the margins on a monthly basis, and any margins above credits to eligible fuel will be calculated and deferred monthly and refunded annually such that customers are protected from any negative margins on an annual basis. The RMR will reconstruct the dispatch on a hourly basis using the installed generation capacity owned by the CSW Operating Companies (both off-line and on-line) plus the firm annual purchases included in CSW's CDR. The purchases will be used as dispatchable resources at the price incurred in that hour. (Firm annual purchases will be modeled as a reduction in load. Because the purchase expense and the MW amount are held constant in both production cost cases, the model ignores the purchase price for the firm annual purchases.) The generation resources will be economically dispatched to serve the actual hourly load included in the CSW Internal Economy dispatch level of the CSW Interchange Cost Reconstruction (ICR). The program will determine the cost of production for the level of dispatch referred as the Own Load Production Cost. The Mitigation Sale (scheduled in that hour) will then be added to the load and the dispatch performed again. The resulting production costs are referred to as the Total Production Cost. The difference between Total Production Cost and the Own Load Production Cost is the Mitigation Production Cost. The energy revenues from the sale (S14/MWh) minus Mitigation Production Cost and the costs of hedges to manage fuel cost risks and any expenses due to the buy back provisions of the sale equals the Mitigation Margin. If the Mitigation Margin is positive then the margin would be treated in the same manner as any other off-system sales margin. The revenues received from the mitigation sale auction are referred to as the Mitigation Reservation Margin. These margins will be used to offset any negative Mitigation Margin calculated above. The Mitigation Margins will be deferred on a monthly basis and all gains and losses will be accumulated annually and flowed through 30 days after the end of a calendar year. Alternatively, if the Mitigation Margin is positive, the Mitigation Reservation Margin will be treated in the same manner as any other off-system sales margin. When the Mitigation Margin is negative for the month, then the Mitigation 1 98 Attachment 4 MITIGATION SALE HOLD HARMLESS METHODOLOGY Reservation Margin (calculated on an monthly basis) will be credited in an amount necessary to make the Mitigation Margin zero. If the Mitigation Margin is still negative, after giving full credit for the Mitigation Reservation Margin, this amount determines the monthly Hold Harmless credit applied to eligible fuel. The positive or negative monthly Mitigation Margin will be accrued monthly, and the Hold Harmless credits in a month may be reversed if Mitigation Reservation Margin is available in a succeeding month. The expenses and revenues associated with the Mitigation Margin will be allocated to the CSW Operating Companies based on the relative participation of their units in the sale as determined in RMR. The following is the RMR algorithm: OWN LOAD - the sum of the CSW Operating Companies native load plus firm purchase and sale obligations. OWN LOAD PRODUCTION COST (OLPC) - The cost of production to serve CSW Own Load requirement plus daily regulating and operating reserves. This is the Internal Economy dispatch level of ICR. TOTAL PRODUCTION COST (TPC) - The cost of production to serve CSW Own Load requirements plus daily regulating and operating reserves plus the Mitigation Sale. MITIGATION ENERGY SALES REVENUE (MESR) - The revenue associated with the Mitigation Energy, at $14/MWh. MITIGATION PRODUCTION COST (MPC) - the cost or producing the energy to supply the Mitigation Sale. MITIGATION MARGIN (MM) - Margin resulting from the mitigation sale. MITIGATION RESERVATION MARGIN (MRM) - The annual revenue from the reservation fees determined in the mitigation auction. The annual revenue is divided by 12 to determine a monthly MRM. ENERGY RECALL EXPENSE (ERE) - The payments made to the Mitigation Sale purchasers when CSW recalls the energy in order to serve firm native load. These payments will be calculated on an hourly basis. MPC = TPC - OLPC MM = MESR - MPC - ERE If MM is negative, an amount of M4RM will be added in an amount to make MM positive. If MM is still negative, MM equals the Hold Harmless Credit. 2 99 Attachment 4 MITIGATION SALE HOLD HARMLESS METHODOLOGY Following are two examples: one representing a Summer load case and the other representing a Spring/Fall load case. In each example, it is assumed that the MRM value = $10,512,000/12 = $876,000. SUMMER LOAD CASE
Operating Company Load Generation Production Cost $/MWh - ----------------- ---- ---------- --------------- ----- CPL 3500 MW 3709 MW $57,455.55 15.49 PSO 3000 MW 2999 MW $48,015.25 16.02 SWEPCO 3500 MW 3432 MW $43,621.21 12.71 WTU 1000 MW 861 MW $20,018.25 23.25 CSW 11000 MW 11000 MW $169,110.26 15.37 Own Load Production Cost = $169,110.26 Add 300 MW Mitigation Sale: CPL 3500 MW 3709 MW $57,455.55 15.49 PSO 3000 MW 3098 MW $49,905.25 16.11 SWEPCO 3500 MW 3632 MW $47,361.21 13.03 WTU 1000 MW 861 MW $20,018.25 23.25 CSW 11000 MW 11300 MW $174,740.26 15.46
TOTAL PRODUCTION COST = $174,740.26 WC = TPC - OLPC $174,740.26 - 169,110.26 = $5,630.00 MITIGATION PRODUCTION COST = $5,630.00 $5630/300 MWh = $18.77/MWh MM = MESR - MPC - ERE MM = $4,200.00 - $5,630.00 - 0 MM = -$1430.00 If MM is negative for the month, MRM is added as needed. Assuming MM is the same for every hour of the month (30 days x 24 hours), MM would equal 720 x -$1430 = -$1,029,600. MRM = $876,000 MM = -$1,029,600 + $876,000 = -$153,600 The whole monthly amount of MRM was applied. THE MONTHLY HOLD HARMLESS CREDIT = -$153,600 3 100 Attachment 4 MITIGATION SALE HOLD HARMLESS METHODOLOGY SPRING/FALL LOAD CASE
Operating Company Load Generation Production Cost $/MWh - ------------------ ---- ---------- --------------- ----- CPL 3000 MW 3 100 MW $45,767.23 14.76 PSO 2300 MW 2250 MW $32,358.25 14.38 SWEPCO 2750 MW 2800 MW $40,010.00 14.29 WTU 845 MW 745 MW $11,735.45 15.75 CSW 8895 MW 8895 MW $129,970.93 14.60 Own Load Production Cost = $129,870.93 Add 300 MW mitigation sale CPL 3000 MW 310OMW $45,767.23 14.76 PSO 2300 MW 2375 MW $34,203.25 14.40 SWEPCO 2750 MW 2975 MW $42,582.50 14.31 WTU 845 MW 745 MW $11,735.45 15.75 CSW 8895 MW 9195 MW $134,288.43 14.60
TOTAL PRODUCTION COST - $134,288.43 WC = TPC - OLPC $134,288.43 - 129,870.93 = $4,417.50 MITIGATION PRODUCTION COST = $4,417.50 $4417.5/300 MW = $14.73/MWh MM = MESR - MPC - ERE $4,200.00 - $4,417.50 - 0 = -$217.50 MM = -$217.50 If MM is negative for the month, MRM is added as needed. Assuming MM is the same for every hour of the month (30 days x 24 hours), MM would equal 720 x -$217.50 = -$156,600. MRM = $876,000 $156,600 of MRM is credited to MM MM = $0.00 The remaining $719,400 of MRM is treated as normal off-system sales margin. THE MONTHLY HOLD HARMLESS CREDIT = $0.00 4 101 Attachment 5 CAUSE NO. PUD 980000444 PROPOSED QUALITY OF SERVICE STANDARDS AMERICAN ELECTRIC POWER COMPANY, INC., AND CENTRAL AND SOUTH WEST CORPORATION Standards related to the Company's customer service center calls: - - On an annual basis, the customer call center's average answer time for customer calls shall not exceed fifty-five seconds. - - As used in this paragraph, "answer" means the operator, service representative, or automated system is ready to render assistance and/or accept the information necessary to process the call. - - Answer time shall be measured from the first ring at the call enter or at the point the customer begins to wait in queue, whichever comes first. - - If AEP/CSW utilizes a menu driven, automated, interactive answering, the initial recorded message presented by the system to the customer shall only identify the Company and the general options available to the customer, including the option of being transferred to a live attendant. At any time during the call, the customer shall be transferred to a live attendant if the customer fails to interact with the system for a period of ten seconds following any prompt. - - Customers shall not be delayed from reaching the queue by any promotional or merchandising material not selected by the customer. - - Performance data during a "major event" or comparable term as such is used by the electric distribution company in its emergency plan, and subject to review and acceptance by the Commission shall be excluded from the calculation of monthly minimum service values pursuant to the paragraphs above. If the Company and the Commission cannot agree on the definition of a "major event" or comparable term, Staff and /or the Company may apply, within forty-five days after the submission of the Company's proposal, to the Commission for a hearing, file a written report and/or recommendations. Standards related to the Company's response to requests for service: - - Ninety-five percent (95%) of the Company's application for new electric service, not involving a line extension or new facilities, shall be filled by the end of the next business day after the customer's location is ready for service and the customer submits a service request, excluding those orders where a later date was specifically requested by the customer. - - The Company will notify customers two days before non-emergency, temporary service interruptions required to improve or maintain performance of the Company's system, and shall meet its commitment in ninety-five percent (95%) of such instances. - - The Company shall comply with the deadlines established for meter testing, written reports on meter testing, and reconnection of service, in OAC 165:35 and any amendments thereto. 1 102 Standard related to the Company's Billing Adjustments: - - The Company shall maintain its infrastructure and customer service in such a manner that the average monthly rate of actual customer over-billing errors per 1,000 customers does not exceed ten. Estimated billings due to inclement weather, lack of access to customer premises, damaged metering equipment, and errors due to erroneous information provided from customers shall be excluded from this measurement. All of the above standards and measurements are on a PSO Company-wide, 12-month basis. The customer service standards established under this agreement shall remain in effect for a period of no more than three years following the effective date of the merger. In the event the OCC changes any of its rules concerning customer service standards, such changes shall automatically be incorporated in this agreement. Additionally, these standards can be changed during the three-year period to reflect any performance-based ratemaking plans or rules for PSO and/or the electric industry. Standard related to Customer Satisfaction: - - PSO shall provide a Customer Satisfaction Index Report to the OCC on an annual basis. This report will provide at a minimum data on: a.) the fairness and reasonableness of rates; b.) reliability/high quality service; c.) courteous and understanding employees; and, d.) quick service restoration after an outage. In addition, if a decline in the trend in the categories noted above is reported, PSO shall provide information to the OCC as to the actions being taken in order to correct such decline(s). The data to be provided in conjunction with this paragraph shall be provided (and maintained by the OCC) on a confidential basis. Standards related to Company's Reliability Performance: The merged company, AEP and CSW, commits to maintain its reliability performance for its Oklahoma retail customers as determined by the System Average Interruption Frequency Index (SAIFI) and the System Average Interruption Duration Index (SAIDI) within the range experienced during the period 1997 through 1999 (inclusive), absent a major outage event beyond the scope of any the PSO system experienced during the same period. The SAIFI and SAIDI indices are defined as shown below. PSO will provide information/substantiation of its performance for each of these measures on an annual basis by the end of May of the year following the year in question.
Year 97 98 99# ---- -- -- --- SAIFI 1.59 1.54 SAIDI* 158 178
* These numbers reflect minutes. # These numbers will be available by the time the merger is consummated. AEP/CSW RELIABILITY MEASURES 1) System Average Interruption Frequency Index (SAIFI) is defined as the number of customers interrupted divided by the number of customers served. It is calculated by the equation: 2 103 SAIFI = number of customers interrupted number of customers served 2) System Average Interruption Duration Index (SAIDI) is defined as the number of customer minutes of interruption divided by the number of customers served. It is calculated by the equation: SAIDI = sum of all customer minutes of interruption ------------------------------------------- number of customers served EX-99.D.5.3 6 STIPULATION AND AGREEMENT 1 Exhibit D-5.3 SOAH DOCKET NO. 473-98-0839 PUC DOCKET NO. 19265 APPLICATION OF CENTRAL AND BEFORE THE SOUTH WEST CORPORATION AND AMERICAN ELECTRIC POWER PUBLIC UTILITY COMMISSION COMPANY, INC. REGARDING PROPOSED BUSINESS COMBINATION OF TEXAS MOTION TO IMPLEMENT SETTLEMENT Now come the Signatories to the attached Integrated Stipulation and Agreement, Applicants American Electric Power Company, Inc. ("AEP") and Central and South West Corporation ("CSW"), the General Counsel of the Public Utility Commission of Texas, the Office of Public Utility Counsel, certain Cities served by CSW, Texas Industrial Energy Consumers, the State of Texas, and the Low-Income Intervenors, and request that the ALJ and the Commission approve and implement the Integrated Stipulation and Agreement in this Docket. I. Summary of Integrated Stipulation and Agreement The Agreement provides for the following: * Rate reductions: Total rate reductions of $221,000,000 by the CSW Texas operating companies over a period of six years, broken down as follows: - CPL: $142,840,000 - SWEPCO: $ 42,080,000 - WTU: $ 36,080,000 The Signatories agree that these rate reductions are in addition to any rate reduction provided for in legislation and will be implemented regardless of any changes to the current regulatory structure in Texas or implementation of a legislatively-mandated rate freeze. 2 * Low-income program: An expanded Low-Income Program. * Customer Education Plan: Implementation of a Customer Education Plan in the event of electric industry restructuring legislation. * ECOM amortization: An additional commitment by CPL to amortize $60,000,000 of ECOM over six years ($20,000,000 in 2000 and 2001 and $5,000,000 per year in 2002-2005). * Rate moratorium: Applicants agree to a rate moratorium until January 1, 2003, subject to certain force majeure provisions. Other Signatories (except General Counsel) agree not to initiate a base rate proceeding against the CSW Texas operating companies that would result in a change in base rates prior to January 1, 2001. * Off-system sales margins: A sharing of off-system sales margins in excess of historical levels. * Jurisdictional issues: Preservation of status quo concerning CSW operating companies' relationship with ERCOT and the SPP, absent prior Commission authorization for a change. * Affiliate standards: Applicants agree to abide by affiliate standards set out in the Agreement until new standards are enacted by rule or legislation. The standards in the Agreement include financial policies and guidelines for transactions between AEP operating companies, access to books and records, restrictions on extension of credit to affiliates, requirements for separation of employees and facilities, restrictions on information exchange, comparability requirements, provisions governing transfer of utility assets, and a requirements for biennial audits. * Market power mitigation plan: A market power mitigation plan that provides, subject to Commission approval, for divestiture of 250 MW from CSWE's Frontera Plant and 1354 MW from CPL plants, subject to certain recall provisions if necessary to supply CPL's native load and existing firm wholesale contracts. In addition, the Applicants have agreed to divest 300 MW in the SPP. * Customer service standards: Customer service standards, including service quality standards (service turn-on and upgrade, light replacement, telephone response, reporting requirements), reliability standards and financial guarantees to meet those standards, and provisions for an Office of Consumer Protection audit of service quality. 2 3 II. Request for Establishment of Procedures The Signatories also request that the ALJ expeditiously schedule a prehearing conference to establish a new procedural schedule for consideration of the Integrated Stipulation and Agreement. The Signatories propose the following schedule: Supplemental Testimony in Support of the Stipulation May 21 Discovery on Supplemental Testimony Ends June 11 Testimony of Non-Signatory Parties June 25 Motions to Strike Direct Testimony of All Parties July 2 Discovery on Testimony of Non-Signatory Parties Ends July 9 Responses to Motions to Strike Direct Testimony July 9 Rebuttal Testimony July 9 Motions to Strike Rebuttal Testimony July 15 Discovery on Rebuttal Testimony Ends July 16 Responses to Motions to Strike Rebuttal Testimony July 19 Hearing on the Merits July 19 Discovery Response Times: Signatories' Testimony on Stipulation Ten Working Days Non-Signatory Testimony Ten Working Days Signatories' Rebuttal Testimony Five Working Days Time for Filing Objections to RFIs on the Following Testimony: Signatories' Testimony on the Stipulation Five Working Days Non-Signatory Testimony Five Working Days Signatories' Rebuttal Testimony Three Working Days Time from Receipt of Objections for Filing Motions to Compel and Responses to Motions to Compel on Objections to the Following Testimony: Signatories' Testimony on the Stipulation Five Working Days Non-Signatory Testimony Three Workings Days Signatories' Rebuttal Testimony Two Working Days Wherefore, the Signatories request that the ALJ and the Commission grant the relief requested herein. 3 4 Respectfully submitted, CLARK, THOMAS & WINTERS BRACEWELL & PATTERSON, L.L.P. A Professional Corporation By: /s/ Philip F. Ricketts ---------------------- By: /s/ Walter Demond Philip F. Ricketts ----------------- Walter Demond 111 Congress Avenue, Suite 2300 P.O. Box 1148 Austin, TX 78701 Austin, TX 78767 (512) 472-7800 (512) 472-8800 (512) 472-9123 Fax (512) 474-1129 Fax BROYLES & PRATT ATTORNEYS FOR AMERICAN ELECTRIC A Professional Corporation POWER COMPANY, INC. One Northpoint Centre, Suite 250 6836 Austin Center Boulevard BUTLER, PORTER, GAY & DAY Austin, TX 78731 (512) 794-2100 Geoffrey M. Gay (512) 794-2111 Fax 1600 Shoal Creek Blvd., Suite 302 Austin, TX 78701 (512) 474-7475 ATTORNEYS FOR CENTRAL (512) 474-7443 Fax AND SOUTH WEST CORPORATION MAYOR, DAY, CALDWELL & KEETON, ATTORNEYS FOR CITIES OF ABILENE, L.L.P. CORPUS CHRISTI, MCALLEN, VICTORIA, BIG LAKE, VERNON AND PADUCAH Rex D. VanMiddlesworth C. Lane Mears LOW INCOME INTERVENORS 100 Congress Avenue, Suite 1500 Austin, TX 78701 Neish A. Carroll (512) 320-9200 Texas Legal Services Center (512) 320-9292 Fax 815 Brazos, Suite 1100 Austin, TX 78701 ATTORNEYS FOR TEXAS INDUSTRIAL (512) 477-6000 ENERGY CONSUMERS (512) 477-6576 Fax 4 5 OFFICE OF PUBLIC UTILITY COUNSEL STATE OF TEXAS James K. Rourke, Jr. Bryan L. Baker, Ass't Attorney General Assistant Public Counsel Consumer Protection Division 1701 North Congress Avenue 300 West 15th St., 9th Floor Austin, TX 78701 Austin, TX 78701 (512) 936-7500 (512) 475-4237 (512) 936-7520 (512) 322-9114 Fax PUBLIC UTILITY COMMISSION OF TEXAS Bret J. Slocum Director-Legal Division Russell Trifovesti Assistant Director - Legal Division Thomas S. Hunter Assistant General Counsel Christopher Green Assistant General Counsel 1701 North Congress Avenue (512) 936-7272 (512) 936-7268 Fax CERTIFICATE OF SERVICE I certify that a copy of this document was served on all parties of record in this proceeding on this 4th day of May, 1999, by facsimile, first-class mail or hand delivery. /s/ Walter Demond ----------------- Walter Demond 5 6 INTEGRATED STIPULATION AND AGREEMENT This Integrated Stipulation and Agreement ("Agreement") is made and entered into by and among American Electric Power Company, Inc. ("AEP") and Central and South West corporation ("CSW"), referred to jointly as "Applicants," and other entities whose authorized representatives have signed it. Applicants and such other signatories are at times referred to jointly herein as the "Signatories" (also referred to individually as "Signatory"). WHEREAS, on April 30, 1998, AEP and CSW filed an Application with the Public Utility Commission of Texas ("PUCT") pursuant to Section 14.101 of the Public Utility Regulatory Act ("PURA"), requesting that the PUCT find their proposal to combine their systems ("merger") to be consistent with the public interest ("Application"); WHEREAS, notice of the filing of the Application and the Commission's proceeding to evaluate it was published once each week for four consecutive weeks in newspapers of general circulation in each Texas county served by Central Power and Light Company ("CPL"), West Texas Utilities Company ("WTU") and Southwestern Electric Power Company ("SWEPCO"), the electric utility operating company subsidiaries owned by CSW. In addition, individual notice was given by mail to each Texas customer of CPL, WTU and SWEPCO and supplemental notice was given in accordance with Order Nos. 43 and 45; WHEREAS, the Signatories desire to resolve all outstanding merger-related issues among them; WHEREAS, this Agreement involves all issues in this proceeding in a manner the Signatories believe is consistent with the public interest, and the Signatories, along with the non-signatory parties who do not oppose the Agreement, represent diverse interests; WHEREAS, the Signatories believe that fully contested hearings in this case would be time-consuming and expensive for all parties and that the public interest will be served by adoption of an order consistent with this Stipulation; WHEREAS, the WTU rate freeze expired in October 1998; WHEREAS, there are currently pending in the Texas courts appeals of prior PUCT Docket Nos. 14965 and 17460 concerning CPL and SWEPCO, respectively; WHEREAS, the Signatories desire to resolve all issues in Docket No. 17460 and certain issues in Docket No. 14965 as part of this Agreement; WHEREAS, the PUCT is currently considering adoption of an affiliate code of conduct and has recently considered reliability and service quality issues in several proceeding; 7 WHEREAS, the Signatories desire to address affiliate code of conduct and service quality issues in response to the PUCT's stated concerns; WHEREAS, AEP and CSW previously entered into a Stipulation and Agreement with the Office of Public Utility Counsel and certain Cities served by CSW; WHEREAS, the parties to the previous Stipulation and Agreement have now reached agreement with additional parties, including the General Counsel of the Public Utility Commission of Texas, Texas Industrial Energy Consumers, the State of Texas, and the Low-Income Intervenors; WHEREAS, this subsequent agreement accomplishes the Signatories' desire to resolve as many pending and potential issues and disputes existing among them as possible; and WHEREAS, the Signatories wish to consolidate the terms of this subsequent agreement with the terms of the previous Stipulation and Agreement to produce this Integrated Stipulation and Agreement. NOW, THEREFORE, in consideration of the mutual agreements and covenants herein, the Signatories, through their undersigned representatives, agree to and recommend for PUCT approval the following provisions of this Agreement as a means of fully resolving the issues among them in Docket No. 19265 and other proceedings referenced in this Agreement: 1. Definitions The term "Merged Company" refers to post-merger AEP and its successors in interest. "Texas operating company" refers to either CPL, WTU or SWEPCO, and their respective successors in interest. "Texas operating companies" refers collectively to CPL, WTU, SWEPCO and their respective successors in interest. The term "actual native load requirements" refers to firm wholesale contractual load requirements existing as of the date of this Agreement and load requirements of firm retail customers. The term "effective date of the merger" refers to the "closing date" as defined in Annex A to the Agreement and Plan of Merger attached to Thomas V. Shockley's testimony as Exhibit TVS-4. References to CPL, WTU or SWEPCO include their respective successors in interest. 2 8 2. Support For the Merger A. The signatories hereby stipulate and agree, and urge the PUCT to issue a Final Order finding, that the Application in Docket No. 19265, as modified and contained in this Agreement, is in the public interest and otherwise consistent with the requirements of Section 14.101 of PURA. B. All Signatories agree to fully support this Agreement in all respects and to use all reasonable efforts to obtain prompt adoption of a final order in Docket No. 19265 based upon this Agreement. Further, all Signatories agree to defend the terms of this Agreement. 3. Regulatory Plan A. Texas Retail Rate Reductions. The Texas operating companies will implement net merger savings rate reduction riders which will reduce rates to customers by the annual amounts shown in Attachment A beginning with the first revenue month after the effective date of the merger. The annual rate reduction amounts shown in Attachment A will be allocated to rate classes based 50% upon a total revenues factor and 50% upon a year-end customer factor, as shown on Attachment A. Table A-1. Each individual year's rate reduction will apply for a twelve month period with the last reduction continuing to apply in years following the end of year six until base rates for the Texas operating company are changed. Notwithstanding any base rate proceeding during the six year period after the effective date of the merger, the annual amounts shown in Attachment A will remain in effect. B. The annual base rate reduction amounts are net "bottom-line" amounts not subject to any offset. C. The Texas operating companies agree to implement the above rate reductions in the manner and amounts described above notwithstanding any changes to the current regulatory structure in Texas or implementation of a legislatively-mandated rate freeze. In the event that retail electric restructuring legislation is implemented in Texas including any divestiture, unbundling or restructuring, the Texas operating companies agree to apply the regulatory plan's provisions to regulated rates of their customers. D. The Signatories agree that any legislatively mandated reductions or credits to base rates that are part of any retail electric restructuring legislation implemented in Texas shall not diminish or offset, but shall be in addition to, the base rate reductions established in this proceeding. E. The Merged Company and Texas operating companies agree not to request under currently existing law any new resource surcharge or Power Cost Recovery Factor 3 9 ("PCRF") for increase in any existing resource surcharge or PCRF that would become effective within a period of six years after the effective date of the merger or until retail electric restructuring legislation is implemented in Texas, whichever first occurs. Notwithstanding the previous sentence, the Merged Company or a Texas operating company may request a new or increased surcharge or PCRF if the requested surcharge or PCRF was authorized in Docket Nos. 18041 or 18845 or is to provide for recovery of fuel and purchased power energy savings resulting from demand-side management ("DSM") as required by the preliminary integrated source plan in Docket No. 16995. In addition, the Merged Company or a Texas operating company may request a surcharge or PCRF related to acquisition of additional short-term capacity or DSM resources required to meet the load requirements specified in subparagraphs (1) and (2) below. The following provisions will apply to any such request made by the Texas operating companies: (1) for amounts of short-term capacity or DSM resources required to meet a reserve margin based upon actual native loan requirements plus a 15% reserve margin during each annual period, the Merged Company and Texas operating companies agree that the costs which may be requested in a surcharge or PCRF will be limited to the cost of the short-term capacity or DSM less the amount of production capacity costs per kilowatt embedded in current base rates times the kilowatts of short-term capacity of DSM required to meet the actual native load requirements and 15% reserve margin. (2) For amounts of short-term capacity or DSM resources required by the PUCT to be purchased in excess of actual native load requirements plus a 15% reserve margin during each annual period, the Merged Company and Texas operating companies agree that the costs which may be requested in a surcharge or PCRF will be limited to the cost of the short-term capacity or DSM. Any PCRF implemented pursuant to this section is not subject to adjustment pursuant to Section 3.F.(3) below. The Merged Company's request for recovery of any surcharge or purchased power costs pursuant to this Section 3.E. will not be considered a base rate case and will not trigger any rate treatments illustrated on Attachment F, and the Attachments A and H rate credits will remain in place. This Agreement does not prevent any Signatory from opposing any request referenced in this Section 3.E. F. (1) Subject to subparagraph F.(3), in a proceeding to change base rates of a Texas operating company to become effective prior to the end of the six year period after the effective date of the merger, a "net merger savings" expense item, the purpose of which is to prevent ratepayers from receiving their share of merger savings twice and to ensure that the shareholders 4 10 retain their share of net merger savings attributable to the Texas operating company, will be reflected as reasonable and necessary operating expenses in the calculation of cost of service. The annual amounts of the net merger savings expense item for each of the Texas operating companies are included in Attachment B. The amount to be included in cost of service shall be based upon the test year period. (2) The Merged Company and Texas operating companies will defer and amortize their merger related costs-to-achieve over a six year period following the effective date of the merger. Costs to achieve the merger are those costs incurred to consummate the merger and combine the operations of AEP and CSW. These costs include, but are not limited to, investment banking fees; consulting and legal services incurred in connection with obtaining regulatory and shareholder approvals; transition planning and development costs; employee separation costs including severance costs, change-in-control payments and retraining costs; and facilities consolidation costs. Subject to subparagraph F. (3), in any proceeding to change base rates of a Texas operation company to become effective prior to the end of the six year period after the effective date of the merger and that is not initiated to implement electric industry restructuring legislation, the annual amount of amortization of costs to achieve the merger included in Attachment C will be reflected as a reasonable and necessary expense included in the calculation of cost of service. (3) In any proceeding initiated by a Texas operation company requesting an increase to overall base rate revenues to become effective prior to end of the six year period after the effective date of the merger: (a) The net merger savings expense item and annual amount of amortization of costs to achieve the merger will not be included in the calculation of the cost of service unless the Texas operating company demonstrates: (i) that the proposed rate increase results from circumstances not directly or indirectly related to the merger; and (ii) that the full level of achieved merger savings for the applicable year as reflected in Attachment D have been achieved; and (b) The revenue requirements otherwise determined to be reasonable and necessary will be reduced by the annual amounts included in Attachment E. (4) The Merged Company and the Texas operating companies, subject to the following force majeure provisions, agree not to initiate a base rate 5 11 proceeding seeking an overall base rate revenue increase to be effective prior to January 1, 2003 or three years from the effective date of the merger, whichever is later (the "rate moratorium"): (a) Changes in statutory Federal income tax provisions which result in a material known and measurable increase of tax expense of the Texas operating company initiating the proceeding; (b) Legislative or governmental regulatory action, other than loss of load resulting from electric industry restructuring, which has a material direct impact on the Texas operating company's non-fuel cost of providing service; (c) Other material increases in a Texas operating company's known and measurable annual non-fuel operating expenses which are outside its control; and (d) A review of the Texas operating company's rates instituted and allowed to proceed under PURA Section 36.151. For purposes of this force majeure provision, the annual levels of materiality for each Texas operating company on a Texas retail basis shall be 5% of normalized base revenues for the previous year. For example, for a force majeure event occurring in 2001, the annual level of materiality would be 5% of the normalized base revenues for the year 2000. (5) Subject to the limitations in Sections 3.B, 3.C and 3.D above, during the rate moratorium the Texas operating companies may request and support any changes to rates that they believe appropriate or desirable in connection with any filings required to implement any regulatory or legislatively-imposed restructuring or unbundling of services provided by electric companies. (6) The Texas operating companies may make filings during the rate moratorium which either: (1) modify tariffs, riders, or terms and conditions while not increasing aggregate base revenues for major rate classes (residential, commercial, industrial, municipal and lighting) or (2) add tariffs, riders, or terms and conditions to address competitive conditions or secure additional load that will not shift allocable costs under such tariffs, riders, or terms or conditions to other major rate classes. (7) The rate moratorium does not preclude the implementation of any surcharge or other rate mechanism found appropriate as a result of a remand to the PUCT from a court proceeding. (8) An illustration of the impact of this Agreement on the revenue requirements of each Texas operating company in the event a base rate 6 12 proceeding is initiated during the six-year period after the effective date of the merger is included as Attachment F. In the event of any request to change rates under subparagraph (5), (6) or (7), above, the annual rate credits shown in Attachments A and H will remain in effect. G. Off-System Sales Margins. (1) CPL off-system sales margins up to $1.75 million shall be credited to customers. For any CPL off-system sales margins between $1.75 million and $2.62 million, 85% shall be credited to customers and 15% of such margins shall be retained by the shareholders. For any CPL off-system sales margins above $2.62 million, 50% of such margins shall be credited to customers and 50% of such margins shall be retained by the shareholders. (2) SWEPCO off-system sales margins up to $1.35 million shall be credited to customers. For any SWEPCO off-system sales margins between $1.35 million and $2.03 million, 85% of such margins shall be credited to customers and 15% of such margins shall be retained by the shareholders. For any SWEPCO off-system sales margins above $2.03 million, 50% of such margins shall be credited to customers and 50% of such margins shall be retained by the shareholders. (3) WTU off-system sales margins up to $900,000 shall be credited to customers. For any WTU off-system sales margins between $900,000 and $1.35 million, 85% of such margins shall be retained by the shareholders. For any WTU off-system sales margins above $1.35 million, 50% of such margins shall be credited to customers and 50% of such margins shall be retained by the shareholders. (4) The provisions as to off-system sales margins shall be in effect for a period of five years from the effective date of the merger. (5) The dollar figures shall apply on a calendar-year basis. (6) Off-system sales margins to be credited to customers under this subsection shall be made in the form of revenue credits in fuel reconciliation proceedings. H. Fuel Savings. All reconcilable fuel and purchased power savings shall be passed through to customers in accordance with PUCT rules and proceedings for fuel factor adjustments and fuel reconciliation (consistent with the proposal of the Applicants). 7 13 4. Regulatory Jurisdiction A. The Merged Company and the Texas operating companies commit and agree that they will not contend in any forum that the jurisdiction of the PUCT over any Texas operating company is changed as a result of the merger. B. The Merged Company commits to file any allocation of the cost of the new generation of transmission facilities with the Federal Energy Regulatory Commission ("FERC") and to notify the PUCT of any such filings at the time they are made. C. The Merged Company agrees not to assist in proceedings before the PUCT or in appeals of PUCT orders that the authority of the Securities and Exchange Commission ("SEC"), as interpreted in Ohio Power Co. v. FERC, 954 F.2d 779 (D.C. Cir. 1992) cert. denied, 498 U.S. 73 (1992) impairs the ability of the PUCT to examine and determine the reasonableness and necessity of non-power affiliate transaction costs of the Texas operating companies. The Signatories agree that this agreement does not include a waiver of any arguments that the Merged Company may have with respect to the reasonableness of SEC approved costs allocations, as opposed to the reasonableness of the costs themselves. D. The Merged Company will not seek recovery of AEP mine-closing costs except to the extent that such closing costs are reflected as a component of AEP fueled costs utilized for economy energy sales under the Systems Integration Agreement. Economy energy sales will only be made under the Systems Integration Agreement when both the East and West zones will achieve coast savings. E. The Merged Company commits and agrees that any stranded costs that CPL, SWEPCO or WTU may seek to recover will be on a stand-alone basis, and will be limited to the ownership-interest of CPL, SEPCO or WTU in its respective assets and obligations. The Merged Company agrees not to seek or recover any stranded costs associated with the existing AEP system from Texas customers. The Signatories agree not to propose the allocation of any stranded costs associated with the CSW system to customers of the existing AEP operating companies. STP will be used only to serve Texas customers. F. The Merged Company will provide the PUCT with notice of filings which propose new allocation factors with the SEC or FERC. The notice will include a description of the proposed factors. G. The Merged Company agrees not to implement further connection between the Electric Reliability Council of Texas ("ERCOT") and the Southwest Power Pool ("SPP") or the Western Systems Coordinating Council ("WSCC") without providing prior notice to the PUCT and all members of ERCOT and without first obtaining a Section 211 order from the FERC. Any such interconnect proposed will comply with legal and current contractual requirements for making such interconnections. 8 14 H. Subject to due process rights to a public hearing and opportunity to present evidence in support of their position, CPL and WTU agree not to terminate their membership in ERCOT without the prior written approval of the PUCT. The Merged Company will not include CPL and the ERCOT portion of WTU in an Independent System Operator ("ISO") outside ERCOT without the prior written approval of the PUCT, with CPL and WTU afforded the right to seek this determination through the PUCT's contested case hearing process. SWEPCO will not withdraw from the SPP without first seeking approval from the PUCT. I. CPL and WTU will continue to file rates for transmission services at the FERC in accordance with ERCOT regional pricing and terms and conditions as established by the PUCT so long as CPL and WTU are members of ERCOT or until such time as ERCOT is no longer subject to the jurisdiction of the PUCT. CPL and WTU will comply with all Texas transmission statutes and rules, including Transmission Cost of Service ("TCOS") allocations. CPL and WTU commit to make TCOS filings with the PUCT in accordance with PUCT rules and procedures. The PUCT will determine CPL's and WTU's transmission costs in accordance with the PUCT's transmission rules. CPL and WTU will submit and support the results of the PUCT orders concerning TCOS for CPL and WTU in FERC transmission rate filings for intra-ERCOT transmission service. J. The Merged Company agrees that it should not double recover Direct Current ("DC") tie costs and will make all necessary or appropriate adjustments to prevent double recovery, including, but not limited to, removal of any DC tie costs included in CPL, WTU and TCOS. K. The Merged Company will comply with any Texas legislation or administrative order providing for direct retail access. This requires complying with all conditions governing such legislation and/or order, including conditions related to the recovery and quantification of stranded costs, if any. Notwithstanding the foregoing, the Merged Company does not waive any rights which it may have to challenge the legality of any legislation or administrative orders. L. The Merged Company will abide by the ultimate resolution of affiliate allocation issues in the Docket No. 14965 appeal, i.e, whether the PUCT may determine that the Company applied the wrong SEC factor to an affiliate expense. 5. Affiliate Standards The Merged Company agrees to comply with affiliate rules adopted in either restructuring legislation or in PUCT rules. The Merged Company also agrees to comply with all existing statutes and PUCT rules pertaining to affiliate transactions. Until a statute or rule governing affiliate transactions is adopted, the Merged Company agrees to comply with the affiliate standards set forth below. The following affiliate standards shall apply from the effective date of merger until the new affiliate standards imposed by state legislation or PUCT rule become effective. 9 15 A. The terms "exempt wholesale generator" and "power marketer" are defined in PURA Section 31.002. B. The financial policies and guidelines for transactions between an AEP operating company and its affiliates shall reflect the following principles: (1) An AEP operating company's retail customers shall not subsidize the activities of the operating company's non-utility affiliates or its utility affiliates. (2) An AEP operating company's costs for jurisdiction rate purposes shall reflect only those costs attributable to its jurisdiction customers. (3) The principals set forth in subparagraphs (1) and (2), above, shall be applied to prevent costs found to be just and reasonable for ratemaking purposes by the affected state commission being left unallocated or stranded between various regulatory jurisdictions, resulting in the failure of the opportunity of timely recovery of such costs by the operating company and/or its utility affiliates; provided, however, that no more than one hundred percent of such costs shall be allocated on an aggregate basis to the various regulatory jurisdictions. (4) An AEP operating company shall maintain and utilize accounting systems and records which are sufficient to identify and appropriately allocate costs between the operating company and its affiliates, consistent with these cross-subsidization principles and the financial policies and guidelines set out in this subparagraph B. C. The PUCT and other municipal regulatory authorities under PURA shall have access to the books and records of any affiliate of a Texas operating company to the same extent and in like manner that the PUCT has over a public utility operating company if the affiliate has had direct or indirect transactions with the Texas operating company. The access shall be sufficient to enable the PUCT or other regulatory authority to conduct a complete analysis and make appropriate determinations under PURA Section 36.058. Upon request of the PUCT, such employees, officers, books and records will be made available in Austin, Texas to the PUCT. Each AEP operating company shall maintain, in accordance with generally accepted accounting principles, books, records, and accounts that are separate from the books, records, and accounts of its affiliates consistent with Part 101 - Uniform System of Accounts Prescribed for Public Utilities and Licensees Subject to the Provisions of the Federal Power Act. Any objections to providing all books and records must be raised before the PUCT and the burden of showing that the request is unreasonable or unrelated to the proceeding is on the AEP operating company. The confidentiality of competitively sensitive information shall be maintained in accordance with the rules and regulations of the PUCT and the Texas Public Information Act. 10 16 D. In accordance with generally accepted accounting principles and consistent with state and federal guidelines, an AEP operating company shall record all transactions with its affiliates, whether direct or indirect. An AEP operating company and its affiliates shall maintain sufficient records to allow for an audit of the transactions involving the operating company and its affiliates. Asset transfers from an AEP operating company to a non-utility affiliate and asset transfers from a non-utility affiliate to an AEP operating company shall be at fully distributed costs for book purposes in accord with current SEC requirements or other statutory requirements of the SEC have no jurisdiction. E. An AEP operating company shall not allow a non-utility affiliate to obtain credit under any arrangement that would permit a creditor, upon default, to have recourse to the operating company's assets. The financial arrangements of an AEP operating company's affiliates are subject to the following restrictions: (1) Any indebtedness incurred by a non-utility affiliate will be without recourse to the operating company. (2) An AEP operating company shall not enter into any agreements under terms of which the operating company is obligated to commit funds in order to maintain the financial viability of a non-utility affiliate. (3) An AEP operating company shall not make any investment in a non-utility affiliate under circumstances in which the operating company would be liable for the debts and/or liabilities of the non-utility affiliate incurred as a result of acts or omissions of a non-utility affiliate. (4) An AEP operating company shall not issue any security for the purpose of financing the acquisition, ownership, or operation of a non-utility affiliate. (5) An AEP operating company shall not assume any obligation or liability as guarantor, endorse, surety, or otherwise in respect of any security of a non-utility affiliate. (6) An AEP operating company shall not pledge, mortgage or otherwise use as collateral any assets of the operating company for the benefit of a non-utility affiliate. An AEP operating company may not incur debt in a manner that, on its default, would permit a creditor to have recourse against the assets of another AEP operating company. Transactions between AEP operating companies and affiliates involving a money pool for financing the short-term funding requirements or transactions between AEP operating companies and special purpose financing entities used solely for the purpose of financing utility assets are exempt from the requirements of this paragraph. Further, provisions of this paragraph would not preclude the AEP operating companies from issuing securities or assuming obligations related to their coal subsidiaries. 11 17 F. Any good or service provided by a non-utility affiliate to an AEP operating company shall be by itemized billing statement pursuant to a written contract or written arrangement. The operating company and non-utility affiliate shall maintain and, upon request, make available for inspection in Austin, Texas by the PUCT, copies of each billing statement, contract and arrangement between the operating company and its non-utility affiliates that relates to the provision of such goods and services in accordance with applicable PUCT document retention requirements. G. Employees responsible for the day to day operations of the AEP operating companies and those of affiliated exempt wholesale generators or affiliated power marketers shall operate independently of one another. AEP shall track and document all employee movement between and among all affiliates. Such information shall be made available to the PUCT and consumer advocates upon request. Employees may transfer from one function to the other so long as the transfer does not create any unfair competitive advantage to the AEP operating company or the affiliated exempt wholesale generator or affiliated power marketer. H. An AEP operating company may not own property in common with an affiliated exempt wholesale generator or affiliated power marketer. I. No market information obtained in the conduct of utility business may be shared with an affiliated exempt wholesale generator or affiliated power marketer, except where such information has been publicly disseminated or simultaneously shared with and made available to all non-affiliated entities who have requested such information. Customer specific information shall not be made available to an affiliated exempt wholesale generator or affiliated power marketer except under the same terms as such information would be made available to a non-affiliated company, and only with the written consent of the customer specifying the information to be released. J. An affiliate may use an AEP operating company's name or logo only if, in connection with such use, the affiliate makes adequate disclosures to the effect that (i) the two entities are separate; (ii) it is not necessary to purchase the non-regulated product or service to obtain service from the operating company; and (iii) the customer will gain no advantage from the operating company by buying from the affiliate. K. An AEP operating company shall not condition or tie the provision of any product, service, pricing benefit, or waiver of associated terms or conditions, to the purchase of any good or service from its affiliated exempt wholesale generator or power marketer. 12 18 L. Except as provided in paragraph M, an affiliated exempt wholesale generator or affiliated power marketer shall not share office space, office equipment, computer systems or information systems with an AEP operating company. M. Computer systems and information systems may be shared between an AEP operating company and non-utility affiliates only to the extent necessary for the provision of corporate support services; however, the operating company shall ensure that the proper security access and other safeguards are in place to ensure full compliance with these affiliate rules. N. The provision of corporate support services shall not allow or provide a means for the transfer of confidential information from the operating company to the affiliate, create the opportunity for preferential treatment or unfair competitive advantage, create opportunities for cross-subsidization of affiliates, or otherwise provide any means to circumvent these affiliate rules. O. Except as provided in paragraph M, an AEP operating company may only make a product or service available to an affiliate exempt wholesale generator or an affiliated power marketer if the product or service is equally available to all non-affiliated exempt wholesale generators and power marketers on the same terms, conditions and prices, and at the same time. An AEP operating company shall process all requests for a product or service from affiliated and non-affiliated exempt wholesale generators and power marketers on a non-discriminatory basis. P. An AEP operating company which provides both regulated and non-regulated services or products, or an affiliate which provides services or products to an AEP operating company, shall maintain documentation in the form of written agreements, an organization chart of AEP (depicting all affiliates and AEP operating companies), accounting bulletins, procedure and work order manuals, or other related documents, which describe how costs are allocated between regulated and non-regulated services or products. Such documentation shall be available, subject to requests for confidential treatment, in a central location for review by the PUCT and municipal regulatory authorities. Q. Except as provided in the Public Utility Regulatory Act, including, but not limited to Subchapter B of Chapter 35, all transfers of utility property with a net book value of more than $1 million to unregulated affiliates must be valued at the higher of net book value or market value for ratemaking purposes, and all transfers of affiliate property with a net book value of more than $1 million to regulated utilities must be valued at the lesser of net book value or market value for ratemaking purposes. This provision shall not apply to sales of accounts receivable. R. Transfers of generation, transmission, and fuel regulated assets allowed by applicable utility industry restructuring legislation or regulatory requirements are not subject to subparagraph Q. For retail rate-making purposes, the cost 13 19 characteristics of such generation, transmission or fuel related assets shall be preserved for the duration of cost based regulation of such transferred assets. Treatment of any loss or gain from the sale of such assets will be subject to applicable accounting, regulatory and statutory requirements. S. AEP shall designate an employee who will act as a contact for the PUCT and consumer advocates seeking data and information regarding affiliate transactions and personnel transfers. Such employee shall be responsible for providing data and information requested by the PUCT for any affiliate transactions and personnel transfers which involve a jurisdictional operating company, regardless of the affiliate(s), subsidiary(is), associate(s) or AEP operating company from which the information is sought. T. AEP shall designate an employee or agent within Texas who will act as a contact for retail consumers regarding service and reliability concerns and to allow a contact for retail consumers for information, questions and assistance. Such AEP representative shall be able to deal with billing, maintenance and service reliability issues. U. AEP shall provide the PUCT a current list of employees or agents that are designated to work with the PUCT concerning state regulatory matters, including, but not limited to, rate cases and retail competition issues. V. Prior to filing any affiliate contract (including service agreements) with the SEC or the FERC, and AEP operating company shall submit to the PUCT a copy of the proposed filing. W. Any violation of the provisions of these affiliate standards is subject to the enforcement powers and penalties of the PUCT. X. AEP shall contract with an independent auditor who shall conduct biennial audits for eight years after merger consummation of affiliated transactions to determine compliance with these affiliate standards. The results of such audit shall be filed with the PUCT. Prior to the initial audit, AEP will conduct an informational meeting with the PUCT regarding how its affiliates and affiliate transactions will or have changed as a result of the proposed merger. 7. Market Power Mitigation A. System Integration Agreements. To mitigate any perceived impacts of the merger on the Merged Company's market power, the Applicants have proposed in their FERC Merger Application a mitigation plan. To protect Texas retail customers, the Merged Company agrees to hold harmless the retail customers of the Texas operating companies from adverse net costs impacts arising from the mitigation plan, as measured on a calendar year basis. 14 20 B. The Merged Company agrees to divest 1604 megawatts ("MW") of generation capacity in ERCOT (Lon Hill Units 1-4 (CPL) - 546 MW, Nueces Bay Plan (CPL) - 559 MW, Joslin Unit 1 (CPL) - 249 MW, and Frontera Plan (CSW Energy) - 250 MW (as included in Applicants' FERC mitigation plan). The divestiture shall be timed so as not to violate the criteria for pooling of interests accounting. Following execution of the Agreement, Applicants and General Counsel shall jointly seek written guidance (including appeals to the SEC, if available) from the SEC or other entity authorized by the SEC to rule on this matter, including, but not limited to, the Office of Chief Accountant, on whether the divestiture of assets before two years after consummation of the merger as proposed herein will prevent pooling of interests accounting treatment for the AEP/CSW merger. Absent the Stipulation, General Counsel would have advocated, and believed the PUCT would have ordered both the level and the timing of the divestiture included within this Stipulation. Affiliates shall be ineligible to directly purchase divested capacity, but may engage in non-firm energy transactions with parties who purchase the capacity. The Signatories agree not to oppose, consistent with any applicable electric industry restructuring legislation, inclusion of these amounts of divested capacity for purposes of compliance with future statutes or rules requiring capacity auction or divestiture. C. General Counsel and Applicants believe that current SEC guidance allows the divestiture event to begin as soon as possible after the effective date of the merger if the Merged Company can demonstrate that the divestiture was required by the PUCT and would have been ordered to occur in less than two years if not for this settlement. The Merged Company agrees to advocate this position in any meeting or proceeding before the SEC in which the pooling of interests issue is considered. If it is determined that divestiture can proceed immediately without jeopardizing pooling of interests accounting treatment for the merger, the divestiture shall begin no later than 90 days after the effective date of the merger. The Merged Company further agrees to provide regular status reports to the PUCT and all Signatory parties of the status of SEC considerations of the merger, including, but not limited to, the pooling of interests issue. If the SEC, through the issuance of a final, non-appealable order or other final, non-appealable ruling determines that the divestiture would be a pooling violation, the auction will be scheduled consistent with meeting SEC pooling of interests requirements. If the final ruling from SEC will allow the divestiture of some of the units within two years after the effective date of the merger, the General Counsel and the Merged Company will work together to determine the sequence of divestiture of those units. If the General Counsel and the Merged Company are unable to agree on the sequence of divestiture they will submit the issue to the PUCT. 15 21 D. The terms of the divestiture will detail the right of CPL to recall up to 1354 MWs of the divested capacity in accordance with the following terms: (1) CPL may recall the capacity anytime during May through September; (2) Any recall of capacity must be pre-scheduled at least 24 hours in advance with specific hours and MWs nominated; (3) Hours nominated may not exceed 20% of the hours in a year (i.e., 1752 hours); and (4) A minimum of four consecutive hours shall be nominated for each day pre-scheduled. E. If the acquirer of the divested CPL plants has to run the plant(s) more than the nominated hours on the days in which CPL preschedules or nominates energy due to operating requirements, CPL agrees to offer the acquirer the heat rate times the applicable fuel cost of such plan(s) for energy received. Such additional hours shall not count toward the limit of 1752 hours that may be nominated per year. Alternatively, the acquirer is free to sell power above the nominated amounts into the marketplace. F. CPL will pay the acquirer(s) of its divested generation for capacity during the May through September period at the level embedded in CPL's current rates less seven months of operation and maintenance expenses embedded in CPL's current rates. The Merged Company will pay for nominated energy by multiplying an agreed daily fuel market index by the heat rate of the specific plant as agreed in the contract between the acquirer(s) of the CSW plant(s) and the Merged Company. G. During the other seven months of the year (i.e., October through April). CPL may need to purchase power from the market to replace the divested capacity (up to 1354 MWs). The energy portion of the purchased power will be included in CPL's reconcilable fuel expense at a fixed heat rate of 10,000 multiplied by the applicable monthly average price paid by CPL for natural gas for each month such energy portion was purchased during the reconciliation period. The cost of replacement capacity will be subtracted from the reduction in CPL's base rate revenue requirement due to divestiture in order to determine the net reduction in revenue requirement resulting from the divestiture. This amount is identified by the following formula: A + B - C + D where: A = seven-twelfths of the operation and maintenance expense of the divested plants, as recorded in the 1998 FERC Form 1 for CPL; 16 22 B = reduction in annual depreciation and pre-tax return due to reducing the undepreciated balance of STP plant by the amount of the gain from divestiture; C = replacement capacity cost for the October through April period; D = annual net reduction in base rate revenue requirement from divestiture. One-half of any positive annual net reduction in base rate revenue requirement resulting from divestiture, as "D" is defined in the above formula, will be used to reduce the undepreciated balance of South Texas Project ("STP") plant, and the remainder will be retained by the Merged Company. H. CPL's recall right will expire once there is no longer an obligation to serve retail customers in ERCOT. The recall right will be reduced to the extent that CPL no longer remains legally obligated to serve any retail customer or group of retail customers, either existing or prospective. To the extent that CPL retains the legal obligation to serve any existing or prospective retail customer or group of retail customers, the load requirements of those customers shall be considered in determining whether the right of recall shall be reduced. An example of how this calculation will be done under currently proposed deregulation legislation is attached as Attachment G. In the event that future statutes require that the PUCT designate a provider of last resort which must offer service to all customers within all or designated portions of CPL's service area, and in the event that CPL affirmatively requests that it be so designated, the load requirements for those customers eligible for service from CPL as a provider of last resort shall not be considered as load requirements of retail customers for whom CPL retains a legal obligation to serve, solely for purposes of determining whether the right of recall shall be reduced. In the event that CPL does not affirmatively request designation as a provider of last resort within its service area but is so designated by the PUCT, the load requirements of retail customers eligible for service from CPL as a provider of last resort shall be considered as load requirements of retail customers for whom CPL retains a legal obligation to service for purposes of determining whether the right of recall shall be reduced. I. The Merged Company agrees to divest 300 MW in SPP. No further SPP divestiture is required. J. Gains from the sale of the Lon Hill, Nueces Bay and Joslin plants shall be utilized to reduce STP excess costs over market ("ECOM"), taking into account the effects of income taxes and reasonable transaction costs. The amount of such gains will be deducted from the ECOM asset determined by the Commission's Final Order on Rehearing in Docket No. 14965. At the time of CPL's next base rate proceeding, if industry restructuring legislation has not been adopted, then the parties agree that the annual amortization of ECOM will be reduced proportionately. The period over which the remaining balance of ECOM, if any, 17 23 is to be amortized remains as ordered by the Commission's Final Order on Rehearing in Docket No. 14965. K. The Merged Company and Texas operating companies agree that no ratepayer of a Texas operating company will be charged any new or increased surcharge or PCRF to recover any capacity cost resulting from divestiture provided for in Section 6 of this Agreement. This provision does not prevent the Merged Company from seeking recovery of capacity costs in accordance with subparagraph 3.E of this Agreement which may be incurred regardless of the divestiture of generating capacity required by this Agreement. L. Pursuant to the PUCT's statutory authority, CPL will submit the terms of the divestiture of its plants to the PUCT for approval. M. Prior to December 31, 2000, the Applicants agree that AEP will file with the FERC an unconditional application to, consistent with the Regional Transmission Organization ("RTO") agreement, transfer the operational control of bulk transmission facilities owned, controlled and/or operated by AEP currently located in the SPP to a FERC-approved RTO directly interconnected with the AEP transmission facilities. The above date is extended, if necessary, to 75 days after FERC issues the order on an RTO to which AEP is a signatory that is filed before June 30, 2000. Applicants agree to pursue any FERC filings made pursuant to this paragraph in good faith using their best efforts to obtain prompt FERC approval. 7. Quality of Service A. Customer Service Standards. These guidelines establish customer service performance standards that should be achieved by the Merged Company. The Merged Company shall make measurements to determine the level of service quality for each item included in these guidelines. The Merged Company shall provide the PUCT with the measurements and summaries thereof for any of the items included herein on request of the PUCT. Records of these measurements and summaries shall be retained by the Merged Company. (1) Service Turn On and Upgrades: On a quarterly basis, the Merged Company shall complete the installation of new service or upgrade of service as follows: (a) Ninety-five percent of new service installations requiring no construction of electric facilities shall: 18 24 (i) be completed within 24 hours after the customer's service location is ready for service and all necessary tariff requirements have been met; (ii) be completed by the requested installation date, when an applicant requests an installation date more than 24 hours after the customer's service location is ready for service and all necessary tariff requirements have been met. (b) Ninety percent of new service installations requiring construction of electric facilities, including the setting of the meter, and ninety percent of service upgrades, shall: (i) be completed within 10 business days after the customer's service location is ready for service and all necessary tariff and local regulation requirements have been met; (ii) be completed by the requested installation date, when an applicant or customer requests an installation date more than ten business days after the customer's service location is ready for service and all necessary tariff requirements have been met; (iii) provided that this standard shall not apply to an extension that involves the construction of non-standard facilities. Non-standard conditions for extension requirements are characterized by one of the following factors: (a) the service installation requires underground feeder construction of more than 300 feet in length or (b) the service installation requires construction of more than 1320 feet of single phase line in the service area of WTU, or more than 900 feet of single phase line in the service areas of CPL or SWEPCO. Service installation requiring line extensions that involve non-standard facilities shall be completed within ninety (90) days, unless circumstances beyond the Company's control cause unavoidable delays; (iv) provided, further, that this standard will be tolled for all requests for service for the duration of any "major event" as defined in Substantive Rule 25.52(c)(2)(D). c. If an applicant/customer complies with all pertinent tariff requirements and the electric distribution company cannot complete the requested service installation or service upgrade as 19 25 set forth above, the company shall promptly notify the applicant/customer of the delay, the reasons for the delay, the steps being taken to complete the work, and the probable completion date. If such probable completion date cannot be met, repeat notification shall be made. d. Penalty for failure to meet this standard: the Merged Company will rebate, on a quarterly basis, via bill credit $40 for each customer not connected within the time frames stated above. (2) Light Replacements. In any distribution substation service area, 95 percent of all customer reports of security and streetlight outages shall be corrected within 72 hours. Light replacement compliance will be measured on a calendar month basis. This standard will be tolled for all customer reports for the duration of any "major event," as defined in Substantive Rule 25.52(c)(2)(D). (3) Telephone Response. On an annual basis, the call center's average answer time for customer calls shall not exceed sixty seconds. a. As used in this paragraph, "answer" means the operator, service representative, or automated system is ready to render assistance and/or accept the information necessary to process the call. b. Answer time shall be measured from the first ring at the call center or at the point the customer begins to wait in queue, whichever comes first. c. If the Merged Company utilizes a menu driven, automated, interactive answering, the initial recorded message presented by the system to the customer shall only identify the company and the general options available to the customer, including the option of being transferred to a live attendant. At any time during the call, the customer shall be transferred to a live attendant if the customer fails to interact with the system for a period of ten seconds following any prompt. d. Customers shall not be delayed from reaching the queue by any promotional or merchandising material not selected by the customer. e. Performance data during a "major event" (as such term is defined in Substantive Rule 25.52(c)(2)(D)) or comparable term as such is used by the electric distribution company in its emergency plan, and subject to review and acceptance by the PUCT, shall be 20 26 excluded from the calculation of annual minimum service value pursuant to this subparagraph (3). f. Penalty for failure to meet this standard. The Merged Company will rebate, via a bill credit, on an annual basis, $20 for each verifiable customer who does not receive service within the standard's parameters, limited to one $20 credit per customer per month of service. For customers who cannot be verified, the Merged Company will contribute the $20 to a fund to benefit low-income customers. (4) Reporting requirements. a. When the Merged Company does not meet any minimum service standards concerning Response to Request for Service and Customer Service Call Center for any two months within any twelve-month period, the company shall notify the PUCT Office of Customer Protection in writing within fifteen days after internal measurements have disclosed such failure. The company shall submit a report of any remedial action taken to the Office of Customer Protection within an additional thirty days. b. The Merged Company shall conduct statistically valid customer service surveys of Texas customers annually. The results of the survey shall be compiled by the utility and reported to the PUCT Office of Customer Protection under confidential or other protected designations if required to protect sensitive information. c. The Merged Company shall submit an Annual Customer Service Report to the PUCT Office of Consumer Protection that addresses customer service issues such as number of customer complaints, performance of the call center, performance of field personnel, billing error rates, etc. d. The Merged Company shall provide an Annual Utility Scorecard to its customers that addresses issues such as number of customer complaints, performance of the call center, performance of field personnel, billing error rates, etc. e. The Merged Company shall maintain records sufficient to demonstrate compliance with these standards and shall provide such records to the PUCT upon request. B. Reliability. The intent of the reliability provisions set out below is for the Merged Company to comply with the provisions of the PUCT rules adopted in Project No. 19198. 21 27 (1) General Provisions. a. The standards are to be consistent with PUCT Substantive Rule 25.52 (Reliability and Continuity of Service). b. Reporting periods are to be consistent with PUCT Substantive Rule 25.81 (Service Quality Reports) and are to coincide with the Applicants' Electric System Service Quality Report to the PUCT. Annual evaluations will be for the 12-month period ending April 30 of each year. Initial evaluation will be for the reporting period ending April 30, 2001. c. Reliability indices are calculated for "forced interruptions" unless otherwise specified. d. The standards will be calculated and evaluated separately for the Texas operations of each CSW operating company (CPL, SWEPCO and WTU). (2) 90% Distribution Feeder Standards. The following reliability standards for System Average Interruption Frequency Index ("SAIFI") and System Average Interruption Duration Index ("SAIDI") shall be established for distribution feeders for each CSW operating company: a. Standards shall be established for the 24-month period ending April 30, 1999. The standards shall be the average of the 1998 and the 1999 reporting years for each index at the value represented by the 10% of the distribution feeders with the highest values. b. Reliability of distribution feeders performing below the standard shall be improved, resulting in 96% of the feeders performing at or better than the standard in the 2001 reporting period. (3) 2% Distribution Feeder Standards. Each CSW operating company shall manage its distribution feeders so that no distribution feeder shall sustain 12-month SAIDI or SAIFI values that are among the highest (worst) 2.0% of that company's feeders for two or more consecutive reporting years. (4) System Standards. System-wide service reliability standards shall be established for each CSW operating company as follows: a. SAIFI Standard - System Average Interruption Frequency Index Average SAIFI for 3-year reporting period 5/1/97-4/30/00. 22 28 b. SAIDI Standard - System Average Interruption Duration Index Average SAIDI for 3-year reporting period 5/1/97-4/30/00. c. As of April 30, 2001, maintain annual system-wide SAIFI and SAIDI values at or better than 105% of the standard. (5) Guarantees to Meet Reliability Standards. a. The Annual service reliability guarantees for the CSW operating companies will be as follows:
Operating Company Dollar Amount % of Total ----------------- ------------- ---------- CPL $3,000,000 71.4% SWEPCO 700,000 16.7% WTU 500,000 11.9% --------- ---------- ----- Total CSW $4,200,000 100%
b. The guarantees will be credited to customers based upon the following priorities: (i) 90% Distribution Feeder Standards; (ii) 2% Distribution Feeder Standards; (iii) System Standards. c. Terms of Guarantees: (i) 90% Distribution Feeder Standards (a) A service reliability credit of $20 shall be made to each customer on all feeders violating the 96% provision of the rule. (For example, if only 95% of the feeders perform at or better than the 90% standard, a credit will be made to customers on 5% of the feeders.) A separate credit will be made for each standard violated (SAIDI and SAIFI) such that a customer on a feeder violating both standard would be credited $40. This credit will not be made for feeders that perform at the system average times two. The sum of these credits will not exceed the maximum amount of the service reliability guarantees stated above. (b) If a CSW operating company achieves the SAIDI and/or SAIFI 90% Distribution Feeder Standards for a reporting period (i.e., 96% of the feeders perform at or better than the 90% standard), the 23 29 total amount of guarantees will be reduced in the following amounts for each standard achieved: CPL, $357,000; SWEPCO, $83,500; and WTU, $59,500 (which total $500,000) (such that the amount of the reduction will be equal to twice that amount if both standards are achieved). The reduction of guarantees will decrease the exposure the operating company may have with respect to the 90% Distribution Feeder Standards, the 2% Distribution Feeder Standards or the System Standards for that reporting year. (ii) 2% Distribution Feeder Standards. (a) A service reliability credit of $50 shall be made to each customer on a feeder violating either standard. A separate credit will be made for each standard violated (SAIDI and/or SAIFI) such that a customer on a feeder violating both standards would be credited $100. These credits will be prorated if the guarantees for this provision plus the guarantees for the 90% Distribution Feeder Standard exceed the total guarantees expressed above as calculated for each CSW operating company. (b) If a CSW operating company achieves the SAIDI and/or SAIFI 2% Distribution Feeder Standards for a reporting period (i.e., no feeders repeat on the 2% list), the total amount of guarantees will be reduced in the following respective amounts for each standard achieved: CPL, $357,000; SWEPCO, $83,500; and WTU, $59,500 (which total $500,000) (such that the amount of the reduction will be equal to twice that amount if both standards are achieved). The reduction of guarantees will decrease the exposure the operating company may have with respect to the 2% Distribution Feeder Standards or the System Standards for the reporting year. (iii) System Standards. In the event an operating company's system SAIDI and/or SAIFI values exceed the allowable limit of 105% of the 36-month standard described above, the company shall credit the guarantees proportionately among all customers on the company's Texas system as follows: 24 30 (a) SAIDI: The guarantee will be the numerical difference between the actual and allowable SAIDI values (measured in minutes) multiplied by 10,000, up to a maximum of the lower of (i) the total remaining guarantee described above for each operating company or (ii) the following amounts for each respective company: CPL, $749,700; SWEPCO, $175,350; and WTU, $124,950 (which total $1.05 million, or 25% of the total guarantee described above). (b) SAIFI: The guarantee will be the numerical difference between the actual and allowable SAIFI values multiplied by 1 million, up to a maximum of the lower of (i) the total remaining guarantee described above for each operating company or (ii) the following amounts for each respective company: CPL, $749,700; SWEPCO, $175,350; and WTU, $124,950 (which total $1.05 million, or 25% of the total guarantee described above). (c) If a CSW operating company achieves either the SAIDI or SAIFI System Standard for a reporting period (i.e., performance at or below 105% of the standard), the amount of the guarantees will be reduced in the following amounts: CPL, $357,000; SWEPCO, $83,500; and WTU, $59,500 (which total $500,000). The reduction of guarantees will decrease any exposure the operating company may have with respect to the other System Standard for that reporting year. C. PUCT Office of Customer Protection ("OCP") audit. Twenty-four months after the customer service objectives and performance standard levels are implemented by the Merged Company, and every twenty-four months thereafter, the PUCT Office of Customer Protection shall conduct an independent audit to determine whether the proposed performance standards have been implemented. The PUCT Office of Customer Protection shall file a report detailing any areas where the Merged Company did not accurately report instances where the performance standard levels were not met, or failed to accurately account for every penalty required by these guidelines. 25 31 D. Term of Standards. (1) The customer service standards established under this agreement shall remain in effect for a period of six (6) years following the effective date of the merger. Reporting periods for all standards will coincide with the Electric System Service Quality Report to the Commission. The initial evaluation will be for the reporting period ending April 30, 2001. (2) Any interested person shall have the right to petition the Commission to revise the standard and/or penalties described herein. In the event the Commission's service reliability rule (Substantive Rule 25.52) is amended, such amendments shall automatically be incorporated in this agreement. Additionally, the signatories agree that they will revisit these standards and penalties in the future in the context of any performance-based ratemaking plans or rules for CSW and/or the electric industry. 8. Low Income Program. The Merged Company commits to the Low-Income Program described below for six years, until the next base rate case of each operating company, or until the Low-Income Program is evaluated in accordance with provisions of restructuring legislation. The PUCT will have the ability to review the Low-Income Program in accordance with the next base rate case of each operating company or in accordance with the provisions of restructuring legislation and may continue such programs to the extent cost recovery is provided. A. CPL, SWEPCO and WTU commit to continue funding of low-income DSM programs at current levels for the full six-year term of the merger savings sharing plan unless otherwise revised by the PUCT. Current HomeSavers program funding commitments: CPL $1,365,000 SWEPCO 400,000 WTU $ 325,000 ------------ Total $2,090,000
Funds not utilized by the HomeSavers program during the current contract year and in future years shall be carried forward during the six-year merger savings sharing period. B. Each operating company shall conduct an annual review meeting for low-income program expenditures and to recommend any changes in program design and outreach. Representative of the PUCT, the Low-Income Intervenors and OPC will participate in the annual meeting. Interim spending reports for low-income programs shall be provided on a quarterly basis to PUCT staff, Low-Income Intervenors and OPC. 26 32 C. CPL, SWEPCO and WTU shall each commit an additional annual budget of $100,000 to unspecified low-income DSM programs approved by the Commission. Representatives of the Commission, Low Income Intervenors and OPC shall be given an opportunity to participate in formulating a list of low-income DSM programs recommended for Commission approval. These funds will be used for DSM programs to benefit low-income customers living in public housing, Section 8 multifamily housing, housing funded by Habitat for Humanity, homeless shelters, and any other energy efficiency programs that benefit low-income customers. D. CPL and SWEPCO will continue their Neighbor to Neighbor programs that provide billing assistance to low-income customers. WTU shall implement a Neighbor to Neighbor program. WTU will work with Texas Legal Services Centre to implement such a program through a third party administrator. Minimum annual funding for each Neighbor to Neighbor program shall be as follows: CPL $250,000 SWEPCO $100,000 WTU $100,000 ---------- $450,000
These minimum-funding levels will be in addition to any customer contributions to the programs. 9. Other Provisions A. Pending rate litigation will be resolved as provided in Attachment H. Each individual year's rate reduction will apply for a twelve month period following the effective date of the merger with the last decrease continuing to apply in years following the end of year six until base rates for the Texas operating company are changed. B. The Merged Company commits and agrees that: (i) upon issuance of any final and non-appealable order from the FERC, SEC, or any state or federal commission addressing the merger, through stipulation or otherwise; and (ii) upon execution of any written agreement settling merger issues, any of which provide merger benefits to ratepayers of any jurisdiction or impose merger conditions on the Merged Company that would benefit the ratepayers of any jurisdiction, such set benefits and conditions will be extended to Texas retail customers to the extent necessary to achieve equivalent net benefits and conditions to the Texas retail customers, 27 33 provided the proposed merger is ultimately consummated. The Merged Company will file with the PUCT and provide all Signatories a copy of all final orders from all jurisdictions, and serve all executed settlement agreements on General Counsel, within 10 days of execution of the same. Any action by a Signatory to enforce the most favored nations provision of this stipulation will not trigger any rate treatments illustrated in Attachment F, and the Attachments A and H rate credits will remain in place. C. Excluding positions at the three divested plants after the date of divestiture, the Merged Company will freeze operating company field positions and customer service jobs for eighteen months from April 1, 1999. The Merged Company will not make any terminations, layoffs, or reassignments, unless the reassignment is to Central and South West Services, Inc. ("CSWS") or its successor and the employee performs the same job as before the reassignment, except for CSWS or its successor rather than for the operating company. D. If electric utility restructuring legislation is adopted, the Merged Company commits to file a one-time customer Education Program with the PUCT for approval by the OCP within 90 days of the effective date of the merger or the legislation, whichever is later. The Customer Education Program will be designed to provide information about electric industry restructuring and retail competition. The program will be designed and implemented for all of the Merged Company's Texas customers. The program will include, but is not limited to, an Internet web site, mailers which include information such as frequently asked questions and answers, newspaper articles, press releases, and advertisements. The Merged Company should spend an amount up to $750,000 per year for two years on the customer Education Program. The Signatories agree not to oppose, to the extent consistent with any applicable electric industry restructuring legislation, inclusion of these amounts of customer education expenditures for purposes of compliance with future statutes or rules requiring consumer education advertising. E. This agreement is binding on the Office of the Attorney General only in its capacity as a representative of state agencies as consumers of electric service. By signing this agreement, the State of Texas is in no way waiving any of its rights or settling any potential claims pursuant to the Texas Free Enterprise and Antitrust Act of 1983, TEX. BUS. & COM. CODE Sections 15.01-.52. The approval of this Integrated Stipulation and Agreement by the Steering Committee of the Cities of Corpus Christi, McAllen, Victoria, Big Lake, Paducah and Vernon is conditioned to the right of individual cities to reconsider their prior approval of the November 3, 1998 Stipulation and Agreement and reject the Integrated Stipulation and Agreement within thirty (30) days of the execution of this document. 28 34 F. The Merged Company commits to coordinate transmission and distribution substation planning with transmission dependent utilities to provide reliable service, to maximize use of existing facilities, and to avoid expenditures for duplicative facilities. The process will include: (1) Period meetings to discuss requirements for facilities that are mutually beneficial;, (2) A commitment by the Merged Company to provide resources and information to the appropriate regional ISO or regulatory authority to assist in their evaluations of facility requirements; and (3) An opportunity to utilize alternative dispute resolution processes, as defined either by PUCT rules (within ERCOT) or SPP tariffs or procedures (within the SPP) or by the procedures of future entities which exercise operational control over the transmission systems. G. The Merged Company will maintain a bargaining and decision-making presence in the current CSW region with authority to negotiate, deal and enter into binding agreements with its present and potential Texas wholesale and transmission customers (including interconnection agreements). The threshold for such authority will be at least $3 million. H. The Merged Company and the Texas operating companies may consider increasing the level of contributions to low income programs so long as the contributions do not adversely affect the rate credits and reductions agreed to in this proceeding or result in any new surcharge or PCRF or an increase in any existing surcharge or PCRF. I. The Merged Company and Texas operating companies will create an internal accounting mechanism to reflect AEP use of existing CSW sulfur dioxide ("SO2") allowances. Such use will be valued at market value and gains and losses realized in comparison to original cost of allowances in excess of amounts included in base rates will be reflected as reconcilable fuel costs. SO2 allowance transactions among existing AEP operating companies will be as per existing agreements. J. The Merged Company commits and agrees that the cost of capital as reflected in CPL's, WTU's, and SWEPCO's rates shall not be increased or adversely affected as a result of AEP's acquisition of CSW. The Merged Company also agrees that subsequent to the completion of the merger, the cost of capital for CPL, WTU and SWEPCO should be set commensurate with the risk of those utilities and should not be affected by the merger. The Merged Company agrees that it will not oppose, in either a regulatory proceeding or an appeal, the application of the principle that the determination of the cost of capital can be based on the risk attendant to the regulated operations of CPL, WTU and SWEPCO. 29 35 K. The Merged Company has no plans to liquidate, sell, merge, or consolidate any Texas operating company or to materially change any Texas operating company's investment policy, business or corporate structure, or management. The Merged Company agrees that the Texas operating companies will continue to operate subject to the jurisdiction and regulation of the PUCT after closing of the proposed merger. The Merged Company agrees that the financial stability of the Texas operating companies will not be impaired or jeopardized by the merger and the interests of Texas customers will not be prejudiced as a result of the merger. Nothing in this agreement shall be construed to limit whatever rights the Merged Company may have under applicable Texas law to liquidate, sell, merge, or consolidate any Texas operating company or to materially change any Texas operating company's investment policy, business or corporate structure, or management subject to required regulatory approvals. L. The Merged Company shall provide written notice on the day of closing to the Signatories and non-opposing parties that the merger closing has occurred. M. Any and all exhibits and testimony submitted by Signatories in this docket will be offered for the purpose of supporting this Agreement. Signatories reserve their full rights to challenge any and all exhibits and testimony offered in this proceeding by any party for any purpose other than support of this Agreement. This includes the right to object to the admission of such evidence and the right of cross-examination. N. This Agreement is binding on each Signatory only for the purpose of settling the issues herein and for no other purpose. The Signatories acknowledge and agree that a Signatory's support of the matters contained in this Agreement may differ from its position or testimony in other dockets and cases not referenced in this Agreement. To the extent that there is a difference, a Signatory does not waive its position in such other dockets. Because this is a settlement agreement, a Signatory is under no obligation to take the same position as set out in this Agreement in other dockets not referenced in this Agreement whether those dockets present the same or a different set of circumstances. The Signatories reserve their rights in this docket to litigate all issues in this docket against parties who do not sign this Stipulation. O. This Agreement represents a compromise, settlement and accommodation among the Signatories, and all Signatories agree that the terms and conditions herein are interdependent and no Signatory shall be bound by any portion of this Agreement outside the context of the Agreement as a whole. If the PUCT does not accept this Agreement in any material respect as issued, the Signatories agree that any Signatory adversely affected by that material modification or inconsistency has the right to withdraw its consent from this Agreement, thereby becoming released from all commitments and obligations, and to proceed to hearing on all issues, present evidence, and advance any positions it desires as if it had not been a Signatory. If the PUCT does not adopt appropriate orders consistent with the material terms of this Agreement, the Signatories agree that neither oral nor 30 36 written statements made during the course of the settlement negotiations, nor the terms of this Agreement may be used as an admission or concession of any sort nor as evidence in any proceeding. This obligation shall continue and be enforceable, even if this Agreement is terminated. P. Implementation of the actions contemplated in this Agreement is subject to PUCT approval of this Agreement and consummation of the AEP/CSW merger. Q. This Agreement expires six years from the effective date of the merger. R. Nothing in this Agreement shall limit the statutory power of any regulatory authority to adjudicate a contested case brought before it. S. This written agreement contains the entire understanding and agreement of the Signatories, supersedes all other written and oral exchanges, or arrangements or negotiations among them or their representatives with respect to the subjects contained herein; and neither this Agreement, nor any of the terms of this Agreement, may be altered, amended, waived, terminated, discharged or modified, except by a writing properly executed by the Signatories. T. The Signatories mutually agree that they enter into this Agreement for their exclusive benefit and the benefit of their respective lawful successors. The Signatories agree that nothing in this Agreement shall be construed to confer any right, privilege or benefit on any person or entity other than the Signatories and their respective lawful successors. U. This Agreement assumes the legality of the treatments and methodologies set out herein. Should any treatment or methodology used be declared illegal by either the PUCT or a court, the Signatories agree to negotiate in good faith to substitute a treatment or methodology with the same economic effect of that declared illegal. V. The titles assigned to each Article are for convenience only, are not part of this Agreement and shall not be considered in the resolution of any dispute or question arising with respect to this Agreement. W. Each signing representative warrants that he or she is duly authorized to sign this Agreement on behalf of the Signatory he or she represents. Facsimile copies of signatories are valid for purposes of evidencing execution. X. The Signatories may sign individual signature pages to facilitate the circulation and filing of the original of this Agreement. 31 37 IN WITNESS WHEREOF, this Agreement has been executed, approved and agreed to by the Signatories hereto in multiple counterparts each of which shall be deemed an original, on the date indicated below by the Signatories hereto, by and through their undersigned duly authorized representatives. This Agreement shall be effective and binding, as to each Signatory, as of the date of execution of each Signatory. AMERICAN ELECTRIC POWER GENERAL COUNSEL OF THE PUBLIC COMPANY INC. UTILITY COMMISSION OF TEXAS By: /s/ Walter Demond By: /s/ Thomas S. Hunter ------------- ---------------- Walter Demond Thomas S. Hunter Title: Title: Assistant General Counsel Date: Date: CENTRAL AND SOUTH WEST STATE OF TEXAS CORPORATION By: /s/ Philip F. Ricketts By: /s/ Bryan Baker ---------------------- --------------- Philip F. Ricketts Bryan Baker Title: Title: Assistant Attorney General Date: Date: OFFICE OF PUBLIC UTILITY TEXAS INDUSTRIAL ENERGY COUNSEL CONSUMERS By: /s/ James K. Rourke, Jr. By: /s/ C. Lane Mears ------------------------ ----------------- James K. Rourke, Jr. C. Lane Mears Title: Assistant Public Counsel Title: Date: Date: 32 38 STEERING COMMITTEE OF THE LOW INCOME INTERVENORS CITIES OF MCALLEN, CORPUS CHRISTI, VICTORIA, ABILENE, BIG LAKE, VERNON, PADUCAH By: /s/ Geoffrey Gay By: /s/ Neish Carroll ---------------- ----------------- Geoffrey Gay Neish Carroll Title: Attorney Title: Attorney Date: Date: 33 39 Attachment A to Integrated Stipulation and Agreement AEP/CSW Merger Net Merger Savings Rate Reduction Rider(1) NET MERGER SAVINGS RATE REDUCTION RIDER AMOUNTS
YEAR CPL SWEPCO WTU TOTAL ---- --- ------ --- ----- (Thousands) Year 1 $ 3,663 $ 1,127 $ 1,053 $ 5,843 Year 2 6,999 2,107 2,015 11,121 Year 3 8,841 2,670 2,582 14,093 Year 4 10,212 3,110 3,040 16,362 Year 5 11,180 3,417 3,349 17,946 Year 6 11,827 3,639 3,591 19,058 ------- ------- ------- ------- Total $52,722 $16,070 $15,630 $84,423 ------- ------- ------- -------
- ------------------ (1) See Attachment J for the total allocation of rate reduction riders set out in Attachments A and H. 40 Attachment B to Integrated Stipulation and Agreement AEP/CSW Merger Net Merger Savings Expense Adjustment For Inclusion in Cost of Service NET MERGER SAVINGS EXPENSE AMOUNTS
YEAR CPL SWEPCO WTU TOTAL ---- --- ------ --- ----- (Thousands) Year 1 $ 5,982 $ 1,844 $ 1,713 $ 9,539 Year 2 12,653 3,806 3,636 20,095 Year 3 16,337 4,931 4,769 26,037 Year 4 19,080 5,811 5,686 30,577 Year 5 21,016 6,424 6,304 33,744 Year 6 22,309 6,868 6,787 35,964 -------- -------- -------- --------- Total $ 97,377 $ 29,684 $ 28,895 $ 155,956 -------- -------- -------- ---------
41 Attachment C to Integrated Stipulation and Agreement Page 1 of 2 AEP/CSW Merger Amortization of Costs to Achieve TRANSITION AND TRANSACTION COST AMORTIZATION
YEAR CPL SWEPCO WTU TOTAL ---- --- ------ --- ----- (Thousands) Year 1 $ 4,832 $ 1,470 $ 1,418 $ 7,720 Year 2 4,832 1,470 1,418 7,720 Year 3 4,832 1,470 1,418 7,720 Year 4 4,832 1,470 1,418 7,720 Year 5 4,832 1,470 1,418 7,720 Year 6 4,832 1,470 1,418 7,720 -------- ------- ------- -------- Total $ 28,992 $ 8,820 $ 8,508 $ 46,320 -------- ------- ------- --------
CHANGE-IN-CONTROL AMORTIZATION
YEAR CPL SWEPCO WTU TOTAL ---- --- ------ --- ----- (Thousands) Year 1 $1,334 $ 409 $ 394 $ 2,147 Year 2 1,334 409 394 2,147 Year 3 1,334 409 394 2,147 Year 4 1,334 409 394 2,147 Year 5 1,334 409 394 2,147 Year 6 1,334 409 394 2,147 ------ ------- ------- -------- Total $8,064 $ 2,454 $ 2,364 $ 12,882 ------ ------- ------- --------
42 Attachment C to Integrated Stipulation and Agreement Page 2 of 2 TOTAL COST TO ACHIEVE AMORTIZATION
YEAR CPL SWEPCO WTU TOTAL ---- --- ------ --- ----- (Thousands) Year 1 $ 6,176 $ 1,879 $ 1,812 $ 9,867 Year 2 6,176 1,879 1,812 9,867 Year 3 6,176 1,879 1,812 9,867 Year 4 6,176 1,879 1,812 9,867 Year 5 6,176 1,879 1,812 9,867 Year 6 6,176 1,879 1,812 9,867 -------- -------- -------- -------- Total $ 37,056 $ 11,274 $ 10,872 $ 59,202 -------- -------- -------- --------
43 Attachment E to Integrated Stipulation and Agreement AEP/CSW Merger REVENUE REQUIREMENTS CREDIT
YEAR CPL SWEPCO WTU TOTAL ---- --- ------ --- ----- (Thousands) Year 1 $ 2,319 $ 718 $ 659 $ 3,696 Year 2 5,654 1,698 1,621 8,973 Year 3 7,496 2,261 2,187 11,944 Year 4 2,554 779 771 4,104 Year 5 3,038 932 926 4,896 Year 6 3,361 1,043 1,046 5,450 -------- ------- ------- -------- Total $ 24,422 $ 7,431 $ 7,210 $ 39,063 -------- ------- ------- --------
44 Attachment D to Integrated Stipulation and Agreement American Electric Power Company, Inc. and Central and South West Corporation Texas Retail Gross Merger Savings Source: Roberson Exhibit MDR-1 Converted to Calendar Year Amounts in Dollars
Year CPL SWEPCO WTU ---- --- ------ --- Year 1 12,158,351 3,722,895 3,524,846 Year 2 18,829,238 5,684,479 5,448,585 Year 3 22,513,700 6,809,739 6,581,266 Year 4 25,256,296 7,689,677 7,498,009 Year 5 27,192,785 8,303,151 8,115,701 Year 6 28,485,394 8,747,580 8,598,207 Year 7 29,580,313 9,116,169 8,967,591 Year 8 30,061,345 9,318,729 9,189,807 Year 9 30,895,061 9,608,775 9,455,822 Year 10 31,651,550 9,880,562 9,718,245 ----------- ---------- ---------- Total 256,624,032 78,881,755 77,098,137 ----------- ---------- ----------
45
AEP/CSW Merger Attachment F to Example of Application of Rate Integrated Stipulation and Agreement Treatment of Merger Savings and Expense Page 1 of 3 Central Power and Light Company Rate Case Initiated By The Company Revenue Requirements Impact ------------------------------------------------------------------------------------------------ Net Merger Savings Net Merger Amortization Net Revenue Net Rate Savings Of Costs Revenue Requirements Base Rate Rider Achieved Expense Adj. To Achieve Requirements Credit Impact Year (Attach. A) Savings (a) (Attach. B) (Attach. C) (2)-(3)-(4) (Attach. E) (5)-(6) ---- ----------- ----------- ----------- ----------- ----------- ----------- ------- (1) (2) (3) (4) (5) (6) (7) Year 1 $ (3,663) Year 2 (6,999) Not applicable due to rate cap unless a force majeure proceeding is initiated under Sec. 3. F. Year 3 (8,841) Year 4 (10,212) (25,256) 19,080 6,176 - 2,554 (2,554) Year 5 (11,180) (27,193) 21,016 6,176 - 3,038 (3,038) Year 6 (11,827) (28,486) 22,309 6,176 - 3,361 (3,361) ----------- ------------- ------------- ------------ ------------- ------------ Total $ (52,722) $ (80,934) $ 62,405 $ 18,529 - $ 8,952 $ (8,952) ----------- ------------- ------------- ------------ ------------- ------------ ------------
Revenue Requirements Impact --------------------------------------------- Rate Rate Total Reduction Reduction Rate Rider Rider Impact Year (Table H-1) (Table H-2) (1)+(7)+(8)+(9) ---- ----------- ----------- --------------- (8) (9) (10) Year 1 $ (15,337) $ (4,807) $ (23,807) Year 2 (12,001) (4,807) (23,807) Year 3 (10,159) (4,807) (23,807) Year 4 - (4,807) (17,573) Year 5 - (4,807) (19,025) Year 6 - (4,807) (19,995) ------------ ------------ ------------ Total $ (37,497) $ (28,842) $ (128,014) ------------ ------------ ------------
Rate Case Initiated By A Signatory Other Than The Company
Revenue Requirements Impact --------------------------------------------------------------------------------------------- Merger Savings Net Merger Amortization Net Revenue Net Rate Savings Of Costs Revenue Requirements Base Rate Rider Achieved Expense Adj. To Achieve Requirements Credit Impact Year (Attach. A) Savings (a) (Attach. B) (Attach. C) (2)-(3)-(4) (Attach. E) (5)-(6) ---- ----------- ----------- ----------- ----------- ----------- ----------- ------- (1) (2) (3) (4) (5) (6) (7) Year 1 $ (3,663) Year 2 (6,999) Not applicable due to rate freeze. Year 3 (8,841) (22,514) 16,337 6,176 - - - Year 4 (10,212) (25,256) 19,080 6,176 - - - Year 5 (11,180) (27,193) 21,016 6,176 - - - Year 6 (11,827) (28,486) 22,309 6,176 - - - ----------- ------------- ------------- ------------ ------------- ------------ ------------ Total $ (52,722) $ (103,448) $ 78,742 $ 24,705 - $ - $ - ----------- ------------- ------------- ------------ ------------- ------------ ------------
Revenue Requirements Impact --------------------------------------------- Rate Rate Total Reduction Reduction Rate Rider Rider Impact Year (Table H-1) (Table H-2) (1)+(7)+(8)+(9) ---- ----------- ----------- --------------- (8) (9) (10) Year 1 $ (15,337) $ (4,807) $ (23,807) Year 2 (12,001) (4,807) (23,807) Year 3 (10,159) (4,807) (23,807) Year 4 (8,788) (4,807) (23,807) Year 5 (7,820) (4,807) (23,807) Year 6 (7,173) (4,807) (23,807) ------------ ------------ ------------ Total $ (61,278) $ (28,842) $ (142,842) ------------ ------------ ------------
Note (a) Achieved savings are the reduction in cost of service from gross merger savings as shown in Roberson Exhibit MDR-1. 46
AEP/CSW Merger Attachment F to Example of Application of Rate Integrated Stipulation and Agreement Treatment of Merger Savings and Expense Page 2 of 3 Southwestern Electric Power Company Rate Case Initiated By The Company Revenue Requirements Impact ----------------------------------------------------------------------------------------------- Net Merger Savings Net Merger Amortization Net Revenue Net Rate Savings Of Costs Revenue Requirements Base Rate Rider Achieved Expense Adj. To Achieve Requirements Credit Impact Year (Attach. A) Savings (a) (Attach. B) (Attach. C) (2)-(3)-(4) (Attach. E) (5)-(6) ---- ----------- ----------- ----------- ----------- ----------- ----------- ------- (1) (2) (3) (4) (5) (6) (7) Year 1 $ (1,127) Year 2 (2,107) Not applicable due to rate cap unless a force majeure proceeding is initiated under Sec. 3. F. (4). Year 3 (2,670) Year 4 (3,110) (7,690) 5,811 1,879 - 779 (779) Year 5 (3,417) (8,303) 6,424 1,879 - 932 (932) Year 6 (3,639) (8,747) 6,868 1,879 - 1,043 (1,043) ----------- ------------- ------------- ------------ ------------- ------------ ------------ Total $ (16,070) $ (24,740) $ 19,104 $ 5,637 - $ 2,753 $ (2,753) ----------- ------------- ------------- ------------ ------------- ------------ ------------
Revenue Requirements Impact --------------------------------------------- Rate Rate Total Reduction Reduction Rate Rider Rider Impact Year (Table H-1) (Table H-2) (1)+(7)+(8)+(9) ---- ----------- ----------- --------------- (8) (9) (10) Year 1 $ (4,873) $ (1,013) $ (7,013) Year 2 (3,893) (1,013) (7,013) Year 3 (3,330) (1,013) (7,013) Year 4 - (1,013) (4,902) Year 5 - (1,013) (5,362) Year 6 - (1,013) (5,695) ------------ ------------ ------------ Total $ (12,096) $ (6,080) $ (36,999) ------------ ------------ ------------
Rate Case Initiated By A Signatory Other Than The Company
Revenue Requirements Impact ---------------------------------------------------------------------------------------------- Merger Savings Net Merger Amortization Net Revenue Net Rate Savings Of Costs Revenue Requirements Base Rate Rider Achieved Expense Adj. To Achieve Requirements Credit Impact Year (Attach. A) Savings (a) (Attach. B) (Attach. C) (2)-(3)-(4) (Attach. E) (5)-(6) ---- ----------- ----------- ----------- ----------- ----------- ----------- ------- (1) (2) (3) (4) (5) (6) (7) Year 1 $ (1,127) Year 2 (2,107) Not applicable due to rate freeze. Year 3 (2,670) (6,810) 4,931 1,879 - - - Year 4 (3,110) (7,690) 5,811 1,879 - - - Year 5 (3,417) (8,303) 6,424 1,879 - - - Year 6 (3,639) (8,747) 6,868 1,879 - - - ----------- ------------- ------------- ------------ ------------- ------------ ------------ Total $ (16,070) $ (31,550) $ 24,035 $ 7,515 - $ - $ - ----------- ------------- ------------- ------------ ------------- ------------ ------------
Revenue Requirements Impact --------------------------------------------- Rate Rate Total Reduction Reduction Rate Rider Rider Impact Year (Table H-1) (Table H-2) (1)+(7)+(8)+(9) ---- ----------- ----------- --------------- (8) (9) (10) Year 1 $ (4,873) $ (1,013) $ (7,013) Year 2 (3,893) (1,013) (7,013) Year 3 (3,330) (1,013) (7,013) Year 4 (2,890) (1,013) (7,013) Year 5 (2,583) (1,013) (7,013) Year 6 (2,361) (1,013) (7,013) ------------ ------------ ------------ Total $ (19,931) $ (6,080) $ (42,080) ------------ ------------ ------------
Note (a) Achieved savings are the reduction in cost of service from gross merger savings as shown in Roberson Exhibit MDR-1. 47
AEP/CSW Merger Attachment F to Example of Application of Rate Integrated Stipulation and Agreement Treatment of Merger Savings and Expense Page 3 of 3 West Texas Utilities Company Rate Case Initiated By The Company Revenue Requirements Impact ------------------------------------------------------------------------------------------------ Net Merger Savings Net Merger Amortization Net Revenue Net Rate Savings Of Costs Revenue Requirements Base Rate Rider Achieved Expense Adj. To Achieve Requirements Credit Impact Year (Attach. A) Savings (a) (Attach. B) (Attach. C) (2)-(3)-(4) (Attach. E) (5)-(6) ---- ----------- ----------- ----------- ----------- ----------- ----------- ------- (1) (2) (3) (4) (5) (6) (7) Year 1 $ (1,053) Year 2 (2,015) Not applicable due to rate cap unless a force majeure proceeding is initiated under Sec. 3. F. (4). Year 3 (2,582) Year 4 (3,040) (7,498) 5,686 1,812 - 771 (771) Year 5 (3,349) (8,116) 6,304 1,812 - 926 (926) Year 6 (3,592) (8,599) 6,787 1,812 - 1,046 (1,046) ----------- ------------- ------------- ------------ ------------- ------------ ------------ Total $ (15,631) $ (24,212) $ 18,776 $ 5,436 - $ 2,743 $ (2,743) ----------- ------------- ------------- ------------ ------------- ------------ ------------
Revenue Requirements Impact --------------------------------------------- Rate Rate Total Reduction Reduction Rate Rider Rider Impact Year (Table H-1) (Table H-2) (1)+(7)+(8)+(9) ---- ----------- ----------- --------------- (8) (9) (10) Year 1 $ (3,947) $ (1,013) $ (6,013) Year 2 (2,985) (1,013) (6,013) Year 3 (2,418) (1,013) (6,013) Year 4 - (1,013) (4,825) Year 5 - (1,013) (5,288) Year 6 - (1,013) (5,652) ------------ ------------ ------------ Total $ (9,350) $ (6,080) $ (33,804) ------------ ------------ ------------
Rate Case Initiated By A Signatory Other Than The Company
Revenue Requirements Impact -------------------------------------------------------------------------------------------- Merger Savings Net Merger Amortization Net Revenue Net Rate Savings Of Costs Revenue Requirements Base Rate Rider Achieved Expense Adj. To Achieve Requirements Credit Impact Year (Attach. A) Savings (a) (Attach. B) (Attach. C) (2)-(3)-(4) (Attach. E) (5)-(6) ---- ----------- ----------- ----------- ----------- ----------- ----------- ------- (1) (2) (3) (4) (5) (6) (7) Year 1 $ (1,053) Year 2 (2,015) Not applicable due to rate freeze. Year 3 (2,582) (6,581) 4,769 1,812 - - - Year 4 (3,040) (7,498) 5,686 1,812 - - - Year 5 (3,349) (8,116) 6,304 1,812 - - - Year 6 (3,592) (8,599) 6,787 1,812 - - - ----------- ------------- ------------- ------------ ------------- ------------ ------------ Total $ (15,631) $ (30,793) $ 23,545 $ 7,248 - $ - $ - ----------- ------------- ------------- ------------ ------------- ------------ ------------
Revenue Requirements Impact --------------------------------------------- Rate Rate Total Reduction Reduction Rate Rider Rider Impact Year (Table H-1) (Table H-2) (1)+(7)+(8)+(9) ---- ----------- ----------- --------------- (8) (9) (10) Year 1 $ (3,947) $ (1,013) $ (6,013) Year 2 (2,985) (1,013) (6,013) Year 3 (2,418) (1,013) (6,013) Year 4 (1,960) (1,013) (6,013) Year 5 (1,651) (1,013) (6,013) Year 6 (1,410) (1,013) (6,016) ------------ ------------ ------------ Total $ (14,370) $ (6,080) $ (36,081) ------------ ------------ ------------
Note (a) Achieved savings are the reduction in cost of service from gross merger savings as shown in Roberson Exhibit MDR-1. 48 Attachment G to Integrated Stipulation and Agreement In the event that future statutes provide that, upon the commencement to customer choice, CPL is not required to serve large commercial and industrial customers having loads above 1000 KW (which at the current time constitutes 550 MW of load), that amount would be deducted from CPL's recall right of 1354 MW on the date customer choice begins. Assuming CPL's large commercial and industrial load does not change, CPL's buyback rights would be 804 MW (1354 MW - 550 MW). However, if CPL is involuntarily designated as a provider of last resort and under the new statute must offer a provider of last resort service to large commercial and industrial customers, its recall rights would not be diminished because it retains the legal obligation to serve those customers. 49 Attachment H to Integrated Stipulation and Agreement Page 1 of 3 Settlement of Pending and Potential Rate Litigation 1. Additional rate decreases. In addition to the merger related rate reduction riders and in consideration for the partial settlement of the currently pending appeal of the CPL rate order and in consideration for the full settlement of the currently pending appeal of the SWEPCO fuel reconciliation proceeding and to recognize that the WTU rate freeze expired in October 1998, the Merged Company agrees to implement rate reduction riders which reflect the rate reductions on Page 3 of this Attachment beginning on the first revenue month after the effective date of the merger. Each rate decrease amount shown in Table H-1 on page 3 of this Attachment will be allocated to customer classes based upon base rate revenues and will be credited to customers based upon a percentage of monthly base rate charges as shown in H-1a. Each rate decrease amount shown in Table H-2 on page 3 of this Attachment will be allocated to customer classes as shown on Table H-2a. The rate reduction rider (Table H-1 of Attachment H) for each Texas operating company will cease upon the effective date of new base rates for such company established pursuant to Section 36.151 or Section 36.101, PURA. In the absence of the establishment of new base rates for a Texas Operating Company during the six year period, the rate reduction rider (Table H-1) for each Texas Operating will continue to apply in the years following the end of year six until new base rates for such Texas Operating Company are established. The supplemental rate reduction rider (Table H-2 of Attachment H) will remain in effect notwithstanding any base rate proceeding during the six year period after the effective date of the merger and will continue to apply in the years following the end of year six until base rates for the Texas Operating Company are changed. All rate reduction riders will be credited to customers in accordance with Attachment I. 2. Within 30 days of the effective date of the merger, SWEPCO will withdraw its pending appeal of its fuel reconciliation proceeding in Docket No. 17460 pursuant to the following provisions: a. Approval by the PUCT of the settlement of Docket No. 19265 including all material provisions of the regulatory plan consistent with Section 9.0. of the Stipulation; b. Agreement by all Signatories to this Agreement except General Counsel that they will not initiate a base rate proceeding against SWEPCO which would result in a change in base rates prior to January 1, 2001; and c. Agreement by all Signatories to this Agreement that transmission equalization payments and receipts for intra-CSW System transactions will be treated as base rate items in future proceedings for all Texas operating companies. 50 3. Within 30 days of the effective date of the merger, CPL will withdraw from its pending appeal of Docket No. 14965 all issues which pertain to Points of Error Nos. 15 and 16 in CPL's Third Motion of Rehearing filed with the PUCT (related to the lawfulness of the mandated glide path rate reductions in 1998 and 1999) pursuant to the following provisions: a. Approval by the PUCT of the settlement of Docket No. 19265 including all material provisions of the regulatory plan consistent with Section 9.0. of the Stipulation; b. Agreement by all Signatories to this Agreement except General Counsel that they will not initiate a base rate proceeding against CPL which would result in the change in base rates prior to January 1, 2001; c. CPL will have the right to continue to litigate all issues in its appeal other than those related to the mandated glide path rate reductions; and d. In consideration for the commitments made in this Attachment H, CPL will extend the terms of the Docket No. 12820 Stipulation to include a pre-tax ECOM amortization of $20,000,000 per year in 2000 and 2001 and a pre-tax ECOM amortization of $5,000,000 per year in the years 2002 through 2005. 4. All Signatories to this Agreement except General Counsel agree that they will not initiate a base rate proceeding against WTU which would result in a change in base rates to be effective prior to January 1, 2001. 5. The annual base rate reduction amounts are net, "bottom-line" amounts not subject to any offset. 6. The Texas operating companies agree to implement the above rate decreases in the manner and amounts described above notwithstanding any changes to the current regulatory structure in Texas or implementation of a legislatively-mandated rate freeze. In the event the retail electric restructuring deregulation legislation is implemented in Texas including any required divestiture, unbundling or restructuring, the Texas operating companies agree to apply the regulatory plan's provisions to regulated rates of their customers. 7. The Signatories agree that any legislatively mandated reductions or credits to base rates that are part of any retail electric deregulation legislation implemented in Texas shall not diminish or offset but shall be in addition to the base rate reductions established in this proceeding. 8. In the event that future statutes provide that, upon the commencement to customer choice. CPL is not required to serve large commercial and industrial customers having loads above 1000 KW (which at the current time constitutes 550 MW of load), that amount would be deducted from CPL's recall right of 1354 MW on the date customer choice begins. Assuming CPL's large commercial and industrial load does not change, 51 CPL's buyback rights would be 804 MW (1354 MW - 550 MW). However, if CPL is involuntarily designated as a provider of last resort and under the new statute must offer provider of last resort service to large commercial and industrial customers, its recall rights would not be diminished because it retains the legal obligation to serve those customers. 52 Attachment H to Integrated Stipulation and Agreement Page 3 of 3 AEP/CSW Merger Revenue Requirements Credit Table H-1 Rate Reduction Rider Amounts
Year CPL SWEPCO WTU Total - ---- --- ------ --- ----- (Thousands) Year 1 $15,337 $ 4,873 $ 3,947 $24,157 Year 2 12,001 3,893 2,985 18,879 Year 3 10,159 3,330 2,418 15,907 Year 4 8,788 2,890 1,960 13,638 Year 5 7,820 2,583 1,651 12,054 Year 6 7,173 2,361 1,409 10,943 ------- ------- ------- ------- Total $61,278 $19,930 $14,370 $95,578 ------- ------- ------- -------
Table H-2 Supplemental Rate Reduction Rider Amounts
Year CPL SWEPCO WTU Total ---- --- ------ --- ----- Year 1 $ 4,806,667 $ 1,013,334 $ 1,013,333 $ 6,833,334 Year 2 $ 4,806,667 $ 1,013,334 $ 1,013,333 $ 6,833,334 Year 3 $ 4,806,667 $ 1,013,333 $ 1,013,333 $ 6,833,333 Year 4 $ 4,806,667 $ 1,013,333 $ 1,013,333 $ 6,833,333 Year 5 $ 4,806,666 $ 1,013,333 $ 1,013,334 $ 6,833,333 Year 6 $ 4,806,666 $ 1,013,333 $ 1,013,334 $ 6,833,333 ----------- ----------- ----------- ----------- Total $28,840,000 $ 6,080,000 $ 6,080,000 $41,000,000 ----------- ----------- ----------- -----------
53 Attachment J to Integrated Stipulation and Agreement AEP/CSW Merger Allocation of Combined Attachment A and Attachment H Rate Reduction Riders
Central Power and Light Company Major Rate Class Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 Total - ----------------------------- ----------- ----------- ----------- ----------- ----------- ----------- ------------ Residential $10,213,347 $10,870,000 $11,233,975 $11,504,214 $11,695,018 $11,822,546 $ 67,340,000 Commercial & Small Industrial 10,733,270 10,215,576 9,907,640 9,678,443 9,516,615 9,408,456 59,500,000 Large Industrial 2,149,572 2,106,448 2,082,635 2,052,399 2,052,399 9,408,456 12,500,000 Lighting 670,478 613,743 582,417 559,098 542,634 531,630 3,500,000 ----------- ----------- ----------- ----------- ----------- ----------- ------------ Total 23,806,667 23,806,667 23,806,667 23,806,667 23,806,666 23,806,666 142,840,000 ----------- ----------- ----------- ----------- ----------- ----------- ------------
Southwestern Electric Power Company Major Rate Class Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 Total - ----------------------------- ----------- ----------- ----------- ----------- ----------- ----------- ------------ Residential $ 2,686,497 $ 2,870,327 $ 2,975,942 $ 3,058,470 $ 3,116,063 $ 3,157,701 $ 17,865,000 Commercial & Small Industrial 2,655,165 2,557,145 2,500,834 2,456,825 2,426,117 2,403,914 15,000,000 Industrial 1,439,959 1,372,602 1,333,899 1,303,667 1,282,564 1,267,309 8,000,000 Municipal 66,342 62,863 60,863 59,300 58,210 57,422 365,000 Lighting 165,371 150,397 141,795 135,071 130,379 126,987 850,000 ----------- ----------- ----------- ----------- ----------- ----------- ------------ Total 7,013,334 7,013,334 7,013,333 7,013,333 7,013,333 7,013,333 42,080,000 ----------- ----------- ----------- ----------- ----------- ----------- ------------
West Texas Utilities Company Major Rate Class Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 Total - ----------------------------- ----------- ----------- ----------- ----------- ----------- ----------- ------------ Residential $ 2,859,319 $ 2,987,880 $ 3,063,422 $ 3,165,611 $ 3,165,611 $ 3,199,327 $ 18,400,000 Commercial & Small Industrial 2,109,592 2,041,488 2,001,488 1,969,229 1,947,440 1,930,736 12,000,000 Industrial 719,716 686.782 667,419 651,777 641,228 633,078 4,000,000 Municipal 209,687 193,339 183,715 175,939 170,696 166,624 1,100,000 Lighting 115,019 103,844 97,262 91,947 88,359 83,569 580,000 ----------- ----------- ----------- ----------- ----------- ----------- ------------ Total 6,013,333 6,013,333 6,013,333 6,013,333 6,013,334 6,013,334 36,080,000 ----------- ----------- ----------- ----------- ----------- ----------- ------------
Texas Operating Companies Major Rate Class Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 Total - ----------------------------- ----------- ----------- ----------- ----------- ----------- ----------- ------------ Residential $15,759,163 $16,729,107 $17,273,339 $17,687,125 $17,976,692 $18,179,574 $103,605,000 Commercial & Small Industrial 15,538,027 14,814,209 14,409,989 14,104,497 13,890,172 13,743,106 86,500,000 Industrial 4,309,247 4,165,832 4,083,953 4,020,356 3,976,191 3,944,421 24,500,000 Municipal 276,029 256,202 244,578 235,239 228,906 224,046 1,465,000 Lighting 950,868 867,984 821,474 786,116 761,372 742,186 4,930,000 ----------- ----------- ----------- ----------- ----------- ----------- ------------ Total 36,833,334 36,833,334 36,833,333 36,833,333 36,833,333 36,833,333 221,000,000 ----------- ----------- ----------- ----------- ----------- ----------- ------------
54 Table A-1 AEP/CSW Merger Allocation of Attachment A Net Merger Savings Rate Reduction Rider
Central Power and Light Company Major Rate Class Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 Total - ----------------------------- ---------- ---------- ---------- ----------- ----------- ----------- ----------- Residential $2,306,088 $4,406,307 $5,565,959 $ 6,429,090 $ 7,038,508 $ 7,445,832 $33,191,784 Commercial & Small Industrial 1,044,736 1,996,209 2,521,574 2,912,601 3,188,687 3,373,223 15,037,030 Large Industrial 261,472 499,603 631,088 728,953 798,051 844,235 3,763,402 Lighting 50,704 96,881 122,379 141,356 154,754 163,710 729,784 ---------- ---------- ---------- ----------- ----------- ----------- ----------- Total 3,663,000 6,999,000 8,841,000 10,212,000 11,180,000 11,827,000 52,722,000 ---------- ---------- ---------- ----------- ----------- ----------- -----------
Southwestern Electric Power Company Major Rate Class Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 Total - ----------------------------- ---------- ---------- ---------- ----------- ----------- ----------- ----------- Residential $ 650,519 $1,216,188 $1,541,165 $ 1,795,133 $ 1,972,341 $ 2,100,477 $ 9,275,823 Commercial & Small Industrial 308,428 576,628 730,707 851,123 935,139 995,896 4,397,921 Large Industrial 147,622 275,982 349,719 407,359 447,569 476,650 2,104,901 Municipal 9,100 17,015 21,561 25,113 27,592 29,385 129,766 Lighting 11,331 21,187 26,848 31,272 34,359 36,592 161,589 ---------- ---------- ---------- ----------- ----------- ----------- ----------- Total 1,127,000 2,107,000 2,670,000 3,110,000 3,417,000 3,639,000 16,070,000 ---------- ---------- ---------- ----------- ----------- ----------- -----------
West Texas Utilities Company Major Rate Class Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 Total - ----------------------------- ---------- ---------- ---------- ----------- ----------- ----------- ----------- Residential $ 640,381 $1,226,171 $1,571,205 $ 1,849,909 $ 2,037,941 $ 2,186,204 $ 9,511,811 Commercial & Small Industrial 297,969 569,646 729,938 859,416 946,769 1,015,183 4,418,921 Large Industrial 86,521 165,407 211,948 249,543 274,911 294,776 1,283,106 Municipal 20,142 38,507 49,343 58,095 64,001 68,625 298,713 Lighting 7,987 15,269 19,566 23,037 25,378 26,212 117,449 ---------- ---------- ---------- ----------- ----------- ----------- ----------- Total 1,053,000 2,015,000 2,582,000 3,040,000 3,349,000 3,591,000 15,630,000 ---------- ---------- ---------- ----------- ----------- ----------- -----------
55 Table H-1a AEP/CSW Merger Allocation of Table H-1 Rate Reduction Rider
Central Power and Light Company Major Rate Class Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 Total - ----------------------------- ----------- ----------- ----------- ---------- ---------- ---------- ----------- Residential $ 6,632,530 $ 5,189,865 $ 4,393,288 $3,800,396 $3,381,782 $3,101,986 $26,499,847 Commercial & Small Industrial 6,938,284 5,429,117 4,595,816 3,975,591 3,537,678 3,244,983 27,721,469 Large Industrial 1,293,050 1,011,795 856,497 740,909 659,298 604,749 5,166,298 Lighting 473,136 370,223 313,399 271,104 241,242 221,282 1,890,386 ----------- ----------- ----------- ---------- ---------- ---------- ----------- Total 15,337,000 12,001,000 10,159,000 8,788,000 7,820,000 7,173,000 61,278,000 ----------- ----------- ----------- ---------- ---------- ---------- -----------
Southwestern Electric Power Company Major Rate Class Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 Total - ----------------------------- ----------- ----------- ----------- ---------- ---------- ---------- ----------- Residential $ 1,898,672 $ 1,516,833 $ 1,297,472 $1,126,032 $1,006,417 $ 919,919 $ 7,765,345 Commercial & Small Industrial 1,821,012 1,454,792 1,244,402 1,079,976 965,252 882,292 7,447,726 Large Industrial 973,198 777,481 665,041 577,170 515,857 471,521 3,980,268 Municipal 56,657 45,263 38,717 33,602 30,032 27,451 231,722 Lighting 123,461 98,631 84,368 73,220 65,442 59,817 504,939 ----------- ----------- ----------- ---------- ---------- ---------- ----------- Total 4,873,000 3,893,000 3,330,000 2,890,000 2,583,000 2,361,000 19,930,000 ----------- ----------- ----------- ---------- ---------- ---------- -----------
West Texas Utilities Company Major Rate Class Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 Total - ----------------------------- ----------- ----------- ----------- ---------- ---------- ---------- ----------- Residential $ 1,875,981 $ 1,418,752 $ 1,149,260 $ 931,574 $ 784,712 $ 670,165 $ 6,830,441 Commercial & General Service 1,394,083 1,054,302 854,037 692,274 583,132 498,013 5,075,841 Industrial 458,784 346,964 281,060 227,823 191,906 163,892 1,670,429 Municipal 142,424 107,711 70,724 59,574 50,878 518,562 87,251 Lighting 75,728 57,271 46,392 37,605 31,676 28,052 274,724 ----------- ----------- ----------- ---------- ---------- ---------- ----------- Total 3,947,000 2,985,000 2,418,000 1,960,000 1,651,000 1,409,000 14,370,000 ----------- ----------- ----------- ---------- ---------- ---------- -----------
56 Table H-2a AEP/CSW Merger Allocation of Table H-2 Supplemental Rate Reduction Rider
Central Power and Light Company Major Rate Class Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 Total - ----------------------------- ---------- ---------- ---------- ---------- ---------- ---------- ----------- Residential $1,274,729 $1,274,728 $1,274,728 $1,274,728 $1,274,728 $1,274,728 $ 7,648,369 Commercial & Small Industrial 2,790,250 2,790,250 2,790,250 2,790,251 2,790,250 2,790,250 16,741,501 Large Industrial 595,050 595,050 595,050 595,050 595,050 595,050 3,570,300 Lighting 146,638 146,639 146,639 146,638 146,638 146,638 879,830 ---------- ---------- ---------- ---------- ---------- ---------- ----------- Total 4,806,667 4,806,667 4,806,667 4,806,667 4,806,666 4,806,666 28,840,000 ---------- ---------- ---------- ---------- ---------- ---------- -----------
Southwestern Electric Power Company Major Rate Class Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 Total - ----------------------------- ---------- ---------- ---------- ---------- ---------- ---------- ----------- Residential $ 137,306 $ 137,306 $ 137,305 $ 137,305 $ 137,305 $ 137,305 $ 823,832 Commercial & Small Industrial 525,725 525,725 525,725 525,726 525,726 525,726 3,154,353 Large Industrial 319,139 319,139 319,139 319,138 319,138 319,138 1,914,831 Municipal 585 585 585 586 586 586 3,512 Lighting 30,579 30,579 30,579 30,578 30,578 30,579 183,472 ---------- ---------- ---------- ---------- ---------- ---------- ----------- Total 1,013,334 1,013,334 1,013,333 1,013,333 1,013,333 1,013,333 6,080,000 ---------- ---------- ---------- ---------- ---------- ---------- -----------
West Texas Utilities Company Major Rate Class Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 Total - ----------------------------- ---------- ---------- ---------- ---------- ---------- ---------- ----------- Residential $ 342,957 $ 342,957 $ 342,957 $ 342,958 $ 342,958 $ 342,958 $ 2,057,745 Commercial & General Service 417,540 417,540 417,540 417,539 417,539 417,540 2,505,238 Industrial 174,411 174,411 174,411 174,411 174,411 174,410 1,046,465 Municipal 47,121 47,121 47,121 47,120 47,121 47,121 282,725 Lighting 31,304 31,304 31,304 31,305 31,305 31,305 187,827 ---------- ---------- ---------- ---------- ---------- ---------- ----------- Total 1,013,333 1,013,333 1,013,333 1,013,333 1,013,334 1,013,334 6,080,000 ---------- ---------- ---------- ---------- ---------- ---------- -----------
57 Attachment I to Integrated Stipulation and Agreement Page 1 of 2 Principles for Texas Merger Retail Decrease Implementation 1. Riders for each Company will be implemented annually to refund the negotiated decrease amounts to major rate classes through a credit to individual customers bills based on projections of base rate revenues for each individual rate class. 2. The negotiated decrease amounts (merger and rate reduction) by major rate class will be allocated to the individual rate classes within each major rate class based upon projected base rate revenues. The resulting base rate revenue credits will be an equal percentage of projected base rate revenues for individual rate classes within a major rate class. 3. Projected base rate revenues will include all retail base rate revenues with the exception of revenues associated with miscellaneous services, fees and facility rentals. Projected base rate revenues for each individual rate class will be based upon consecutive twelve month periods, not necessarily a calendar year. 4. The individual rate class refund factors will be calculated by dividing the base rate revenue credits assigned to that rate class, determined in #2 above, by the corresponding annual projected base revenue for that rate class. 5. The year one refund factors will be filed with the PUCT 30 days prior to the anticipated effective date of the merger. These factors will be implemented as of the first day of the first billing month after the effective date of the merger and will be applicable for the initial 12 month period. The approval of this settlement by the PUCT will establish the refund methodology and all other compliance filings for annual refund factors will be administrative in nature. 6. No less than 60 days prior to the expiration of the current refund factors, each Texas operating Company will make compliance filings to implement new refund factors for the upcoming 12 month period. These factors will be based on the refund amounts for the upcoming year plus any true-up amounts from the prior 12 month period. 7. Due to the timing of these compliance filings, the exact amount of the current 12 month's over/under refund balance (true-up) will not be known at the time the next 12 month's refund factors are calculated. Estimates will need to be made for any periods (possibly two or three months) for which actual data is not available for the purposes of determining the amount of over/under refund balance to be included in the design of the net 12 month's refund factors. The annual true-up of the refund amount, plus interest calculated in conformance with the provisions of the PUCT's fuel rule governing reconciliation proceedings (PUCT Substantive Rule 23.23(b)), will continue until such 58 time as the refund factor is no longer applicable. At such time that the refund factors are no longer applicable, each Texas operating Company will true-up the over/under refund balance for any prior outstanding months which were estimated. 8. For purposes of the calculation of over/under refund balances each Texas operating Company will keep the balances of the refunds by individual rate class and any over/under balances will be included in the calculation of the next 12 month's refund factor for that individual rate class. 9. In the event of industry restructuring legislation, the base rate revenue credits will be maintained by individual rate class, to the extent possible, although it is impossible to formulate a specific plan at this time. If and when restructuring legislation is enacted, the Applicants will submit a plan for PUCT approval to allocate the credits set forth in Attachments A and H consistent with Sections 3.C, 3.F(8) and Attachment H, Section 6. EX-99.D.6.2 7 ORDER APPROVING APPLICATION 1 Exhibit D-6.2 7590-01-P UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION In the Matter of HOUSTON LIGHTING & POWER COMPANY ) Docket Nos. 50-498 CITY PUBLIC SERVICE BOARD OF ) and 50-499 SAN ANTONIO ) CENTRAL POWER AND LIGHT COMPANY ) CITY OF AUSTIN, TEXAS ) STP NUCLEAR OPERATING COMPANY ) ) (South Texas Project, Units 1 and 2 ) ORDER APPROVING APPLICATION REGARDING PROPOSED CORPORATE MERGER OF CENTRAL AND SOUTH WEST CORPORATION AND AMERICAN ELECTRIC POWER COMPANY, INC. I. Houston Lighting & Power Company; City Public Service Board of San Antonio; Central Power and Light Company (CPL): City of Austin, Texas; and STP Nuclear Operating Company are holders of Facility Operating Licenses Nos. NPF-76 and NPF-80, issued on March 22, 1988, and March 28, 1989, respectively. Facility Operating Licenses Nos. NPF-76 and NPF-80 authorize the holders to possess the South Texas Project, Units 1 and 2 (STP), and authorize STP Nuclear Operating Company to use and operate STP in accordance with the procedures and limitations set forth in the operating licenses. The Nuclear Regulatory Commission (NRC) issued Licenses Nos. NPF-76 and NPF-80 on March 22, 1988, and March 28, 1989, respectively, pursuant to Part 50 of Title 10 of the Code of Federal Regulations (10 CFR Part 50). The facility is located in Matagorda County, Texas. II. Under cover of a letter dated June 19, 1998, CPL submitted an application dated June 16, 1998, for consent under 10 CFR 50.80 to allow the indirect transfer of CPL's interest in STP that would occur in connection with a proposed merger of Central and South West Corporation (CSW, the parent holding company of CPL) and American Electric Power, Inc. (AEP). Under the proposed merger, CSW would become a wholly-owned subsidiary of AEP, with CPL remaining a wholly-owned subsidiary of CSW. Houston Lighting & Power Company; City Public Service Board of San Antonio; City of Austin, Texas; and 2 STP Nuclear Operating Company are not involved in the merger. The application was supplemented by a letter dated June 23, 1998, and enclosures thereto. CPL and the other current licensees would continue to hold the licenses, and no direct transfer of the licenses would result from the merger. On August 5, 1998, a Notice of Consideration of Approval of Application Regarding Proposed Merger was published in the Federal Register (63 FR 41876). An Environmental Assessment and Finding of No Significant Impact was published in the Federal Register on September 28, 1998 (63 FR 51629). Under 10 CFR 50.80, no license shall be transferred, directly or indirectly, through transfer of control of the license, unless the Commission gives its consent in writing. Upon review of the information contained in the application dated June 16, 1998, and enclosures to the letter dated June 23, 1998, the NRC staff has determined that the proposed merger will not affect the qualifications of CPL as holder of Facility Operating Licenses Nos. NPF-76 and NPF-80, and that the transfer of control of the licenses, to the extent effected by the proposed merger, is otherwise consistent with applicable provisions of law, regulations, and orders issued by the Commission, subject to the conditions set forth herein. These findings are supported by a safety evaluation dated November 5, 1998. III. Accordingly, pursuant to Sections 161b, 161i, 161o, and 184 of the Atomic Energy Act of 1954, as amended; 42 U.S.C. Sections 2201(b), 2201(i), 2201(o), and 2234; and 10 CFR 50.80, IT IS HEREBY ORDERED that the Commission approves the application regarding the merger agreement between CSW and AEP subject to the following: (1) CPL shall provide the Director of the Office of Nuclear Reactor Regulation with a copy of any application, at the time it is filed, to transfer (excluding grants of security interests or liens) from CPL to its proposed parents, or to any other affiliated company, facilities for the production, transmission, or distribution of electric energy having a depreciated book value exceeding 10 percent of CPL's consolidated net utility plant, as recorded on its books of account, and (2) should the merger not be completed by December 31, 1999, this Order shall become null and void, unless upon application and for good cause shown this date is extended. This Order is effective upon issuance. 2 3 IV. By December 14, 1998, any person adversely affected by this Order may file a request for a hearing with respect to issuance of the Order. Any person requesting a hearing shall set forth with particularity how such person's interest is adversely affected by this Order and shall address the criteria set forth in 10 CFR 2.714(d). If a hearing is to be held, the Commission will issue an order designating the time and place of such hearing. The issue to be considered at any such hearing shall be whether this Order should be sustained. Any request for a hearing must be filed with the Secretary of the Commission, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, Attention: Rulemakings and Adjudications Staff, or may be delivered to the Commission's Public Document Room, the Gelman Building, 2120 L Street, NW, Washington DC 20555-0001, by the above date. Copies should also be sent to the Office of the General Counsel and to the Director, Office of Nuclear Reactor Regulation, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, and to John O'Neill, Jr., Shaw, Pittman, Potts & Trowbridge, 2300 N Street, NW., Washington, DC 20037-1128, counsel for CPL. For further detailed with respect to this action, see the application from CPL dated June 16, 1998, submitted under cover of a letter dated June 19, 1998, from Shaw, Pittman, Potts and Trowbridge, counsel for CPL, supplemental letter dated June 23, 1998, and enclosures thereto, and the safety evaluation dated November 5, 1998, which are available for public inspection at the Commission's Public Document Room, the Gelman Building, 2120 L Street, NW, Washington, DC 20555-0001, and at the local public document room located at the Wharton County Junior College, J.M. Hodges Learning Center, 911 Boling Highway, Wharton, TX 77488. FOR THE NUCLEAR REGULATORY COMMISSION /s/ Samuel J. Collins, Director Office of Nuclear Reactor Regulation Dated at Rockville, Maryland, This 5th Day of November, 1998 3 4 UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION REGARDING PROPOSED MERGER CENTRAL POWER AND LIGHT COMPANY DOCKET NOS. 50-498 AND 50-499 SOUTH TEXAS PROJECT, UNITS 1 AND 2 1.0 INTRODUCTION Pursuant to 10 CFR 50.80, Central Power and Light Company (CPL) submitted an application dated June 16, 1998, under cover of a letter dated June 19, 1998, and additional supporting material under cover of a letter dated June 23, 1998, describing the proposed merger of Central and South West Corporation (CSW), the parent holding company of CPL) and American Electric Power Company, Inc. (AEP). The application requests the consent of the Nuclear Regulatory Commission (NRC) to allow the indirect transfer of CPL's interest in STP that will occur under the proposed merger of CSW and AEP. CPL, as a wholly-owned subsidiary of CSW, owns a 25.2 percent interest in South Texas Project, Units 1 and 2 (STP). Upon completion of the merger, CSW will become a wholly-owned subsidiary of AEP, with CPL remaining a wholly-owned subsidiary of CSW. The merger will result in an indirect transfer of CPL's interest in the licenses for STP to AEP, and approval for this indirect transfer is being sought from the NRC pursuant to 10 CFR 50.80. Houston Lighting & Power Company, City Public Service Board of San Antonio, and City of Austin, Texas, are the other owners of STP, and the proposed merger does not involve any of them. The STP Nuclear Operating Company (STPNOC) is a holder of the STP licenses and is the licensed operator of STP, but STPNOC is not impacted by the merger. STPNOC holds no ownership interest in either unit. Pursuant to 10 CFR 50.80, the NRC may approve the transfer of the control of a license, after notice to interested persons. Such action is contingent upon the NRC's determination that the holder of the license following the transfer of control is qualified to hold the license and the transfer is otherwise consistent with applicable provisions of law, regulations, and orders of the Commission. In the application for approval dated June 16, 1998, the applicant states on page 7: The purpose of the merger is to achieve benefits for AEP's and CSW's shareholders, customers and communities that would not be achievable if they were to remain separate companies. The potential net non-fuel cost savings related to the merger are approximately $2 billion over the first ten years following the merger. The savings will come from the elimination of duplicative activities, improved operating efficiencies, lower capital costs, and the combination of the companies' work forces. In addition, it is anticipated that there will be reduced fuel costs. 2.0 FINANCIAL QUALIFICATIONS According to CPL's application, following the proposed merger, CPL will continue to own its 25.2 percent interest in both Units 1 and 2 and will remain an electric utility as defined in 10 CFR 50.2, engaged in the generation, transmission, and distribution of electric energy through rates authorized by the Public Utility 5 Commission of Texas for retail purposes and by the Federal Energy Regulatory Commission for wholesale transactions. As an electric utility, CPL is exempt from further financial qualifications review, pursuant to 10 CFR 50.33(f). However, in view of the NRC's concern that restructuring can lead to a diminution of assets necessary for the safe operation and decommissioning of a licensee's nuclear power plant, the NRC's practice has been to condition license transfer approvals upon a requirement that the licensee not transfer significant assets from the licensee to an affiliate without first notifying the NRC. This requirement assists the NRC in assuring that a licensee will continue to maintain adequate resources to contribute to the safe operation and decommissioning of its facility. With regard to this requirement, CPL has agreed on page 4 of its June 16, 1998, application: To provide the Director of the Office of Nuclear Reactor Regulation a copy of any application, at the time it is filed, to transfer (excluding grants of security interests or liens) from CPL to its proposed parents, or to any other affiliated company, facilities for the production, transmission or distribution of electric energy having a depreciated book value exceeding ten percent of CPL's consolidated net utility plant, as recorded on its books of account. With the foregoing a condition of the Order approving the application regarding the proposed merger, and abased on the above information, the staff finds that CPL will remain financially qualified to hold the STP licenses following the proposed merger. 3.0 TECHNICAL QUALIFICATIONS STP Nuclear Operating Company, the only licensee of STP authorized to operate and maintain the facility, is not involved in the proposed merger. CPL has stated in its application that the proposed merger involves no change to either the management organization or technical personnel of STP Nuclear Operating Company. Accordingly, the proposed merger does not raise any problematic technical qualifications issues. 4.0 ANTITRUST REVIEW Section 105 of the Atomic Energy Act of 1954, as amended (the Act), requires the NRC to conduct an antitrust review in connection with an application for a license to construct or operate a facility under Section 103. Although AEP may become the holding company of CSW, which in turn is the holding company of CPL (a licensee for STP), i.e., may indirectly acquire control of the licenses, AEP will not be performing activities for which a license is needed. Since approval of the application would not involve issuance of a license and since CPL as the existing licensee will remain the licensee, the procedures under Section 105 regarding antitrust reviews do not apply, including the making of any "significant changes" determination. 5.0 FOREIGN OWNERSHIP, CONTROL, OR DOMINATION CPL indicated in its application that it is now, and will be after the merger, a corporation organized and existing under the laws of the State of Texas. All of its directors and principal officers are citizens of the United States. The application also indicated that after the merger is implemented, CPL will be an indirect wholly-owned subsidiary of AEP. Subsequent to the merger, the Board of Directors of AEP will be composed of 15 members, to include all then current board members of AEP, the Chairman of CSW, and four additional outside directors of CSW to be nominated by AEP. The current directors of AEP and the Chairman and outside directors of CSW are U.S. citizens according the application. Nothing in the application indicates that there will be any known changes in the memberships of these boards occurring prior to the proposed merger. Counsel for CPL confirmed on October 29, 1998, during a telephone conversation with Steven R. Hom of the Office of the General Counsel, that there are no board elections scheduled to occur prior to the merger, there is no present plan to change any current board member prior to the 2 6 merger, and it is intended that all AEP board members following the merger will be U.S. citizens. The application declares that following the proposed merger, CPL will not be owned, controlled or dominated by an alien, foreign corporation, or foreign government. The staff does not know or have reason to believe otherwise. 6.0 CONCLUSIONS In view of the foregoing, the staff concludes that the proposed merger of CSW into AEP as a wholly-owned subsidiary of AEP will not adversely affect the financial qualifications of CPL with respect to the operation and decommissioning of STP. Also, there do not appear to be any problematic antitrust or foreign ownership considerations related to the STP licenses that would result from the proposed merger. Thus, the proposed merger will not affect the qualifications of CPL as a holder of the licenses, and the transfer of control of the licenses, to the extent effected by the proposed merger, is otherwise consistent with applicable provisions of law, regulations, and orders issued by the Commission pursuant thereto. Accordingly, the NRC should approve the application regarding the proposed merger, subject to the condition discussed above concerning significant asset transfers. Principal Contributor: A. McKeigney Date: November 5, 1998 3 EX-99.D.7.1 8 ORDER OF KY APPROVING THE MERGER 1 Exhibit D-7.1 COMMONWEALTH OF KENTUCKY BEFORE THE PUBLIC SERVICE COMMISSION In the Matter of: JOINT APPLICATION OF KENTUCKY POWER) COMPANY, AMERICAN ELECTRIC POWER ) CASE NO. 99-149 COMPANY, INC. AND CENTRAL AND ) SOUTH WEST CORPORATION REGARDING ) A PROPOSED MERGER ) O R D E R On April 15, 1999, Kentucky Power Company d/b/a American Electric Power ("Kentucky Power"), American Electric Power Company, Inc. ("AEP"), and Central and South West Corporation ("CSW") (collectively, the "Joint Applicants") applied to the Commission for an Order: (1) declaring that the merger of CSW and AEP, with AEP being the surviving entity, may be consummated without Commission approval or, alternatively, approving pursuant to KRS 278.020(4) and 278.020(5), the proposed regulatory plan and authorizing other steps necessary to implement the regulatory plan; (2) approving a tariff providing a net merger savings credit for Kentucky Power customers; and (3) making certain findings concerning the deferral of certain merger-related expenses in conformity with SFAS 71. On April 20, 1999, the Commission established a procedural schedule that provided for discovery, an evidentiary hearing, and an opportunity for parties to file briefs. The Commission granted full intervention to the following entities: Attorney General's Office of Rate Intervention ("AG", Kentucky Industrial Utility Customers ("KIUC"), and Kentucky Electric Steel Corporation (collectively, the "Intervenors"). Following several conferences held under the Commission's auspices, the parties resolved all disputed issues and executed a "Stipulation and Settlement Agreement" which they filed with the Commission on May 24, 1999. The 2 Commission held a public hearing in this matter on May 28, 1999, at the Commission's offices in Frankfort, Kentucky. OVERVIEW OF THE TRANSACTION Kentucky Power. a Kentucky corporation, owns and operates facilities engaged in the generation, transmission, distribution and sale of electricity. It serves approximately 170,000 customers in the eastern Kentucky counties of Boyd, Breathitt, Carter, Clay, Elliott, Floyd, Greenup, Johnson, Knott, Lawrence, Leslie, Letcher, Lewis, Magoffin, Martin, Morgan, Owsley, Perry, Pike, and Rowan. It also supplies electricity to public utilities and municipalities in Kentucky for resale. Kentucky Power is a utility subject to Commission jurisdiction. KRS 278.010(3)(a). AEP, a New York corporation, is a holding company registered under the Public Utility Holding Company Act of 1935.(1) It owns, directly or indirectly, all of the outstanding common stock of seven domestic electric utility operating subsidiaries: Appalachian Power Company, Columbus Southern Power company, Indiana Michigan Power Company, Kentucky Power, Kingsport Power Company, Ohio Power Company and Wheeling Power Company. Its subsidiaries provide electricity to over 3 million customers in Kentucky, Indiana, Michigan, Ohio, Tennessee, Virginia, and West Virginia. CSW, a Delaware corporation, is a holding company registered under the Public Utility Holding Company Act of 1935. It owns all of the outstanding common stock of four domestic electric utility operating subsidiaries: Central Power and Light Company, Public Service Company of Oklahoma, Southwestern Electric Power Company and West Texas Utilities - -------- (1) 15 U.S.C. Section 79 et seq. 2 3 Company. These subsidiaries provide electricity to over 1.7 million customers in areas of Texas, Oklahoma, Arkansas and Louisiana. On December 21, 1997, AEP and CSW, with the approval of their respective Boards of Directors, executed a merger agreement. Under the terms of this agreement, shareholders of CSW will receive .6 of a share of AEP stock for each share of CSW common stock, resulting in CSW shareholders acquiring 40 percent of AEP's common stock. The four CSW domestic utility subsidiaries will become AEP subsidiaries. AEP's Board of Directors will be expanded from 12 to 15 members, with two AEP board members retiring. Five directors, formerly on the CSW Board of Directors, will be selected to serve upon AEP's Board. The Joint Applicants estimate that the proposed merger will produce approximately $2.4 billion in non-fuel savings over a 10-year period. After considering the cost to achieve these savings and pre-merger initiatives, the proposed merger is estimated to produce net merger savings of $1.965 billion. Of this amount, Kentucky Power will be allocated $73.8 million. These savings are expected to result from the elimination of duplicative functions and positions and greater economies of scale the merger is expected to produce. Because of the geographical area served by the Joint Applicants and their affiliates and the nature of their operations, the utility regulatory commissions of six states,(2) the Federal Energy Regulatory Commission ("FERC"), the Securities and Exchange Commission ("SEC"), the Federal Trade Commission ("FTC"), the United States Department of Justice ("DOJ"), and the Nuclear Regulatory Commission ("NRC") must approve the proposed merger. As of - ----------------- (2) Arkansas, Louisiana, Oklahoma, Texas, Indiana, and Kentucky. See Joint Applicants' Response to the Commission's Order of April 28, 1999, Item 2. 3 4 May 28, 1999, the NRC, Arkansas Public Service Commission, Indiana Utility Regulatory Commission, and Oklahoma Corporation Commission have granted their approval. STIPULATION AND SETTLEMENT AGREEMENT On May 24, 1999, the parties filed a "Stipulation and Settlement Agreement" ("Settlement Agreement") with the Commission. The most significant features of the Settlement Agreement are described below. Merger Savings. The Settlement Agreement provides for the implementation of a Net Merger Savings Credit ("Merger Credit") tariff that will reduce customers' bills beginning in the first full billing month 30 days after the consummation of the merger. The Merger Credit will appear on each customer's monthly bill and will be based upon kWh consumption. The Merger Credit reflects non-fuel related merger savings and the associated merger costs based on estimated values included in AEP's merger filing with the FERC. Although the amounts are only estimates, the Joint Applicants have committed to guarantee their estimate of not merger savings. Associated merger costs have been classified by AEP as either "Cost to Achieve" or "Change in Control Payments."(3) The Merger Credit will be in effect for an initial eight-year period, with all associated merger costs amortized over the same eight years. The Cost to Achieve the merger will be shared by both customers and shareholders of AEP, while the Change in Control Payments will be borne solely by AEP shareholders. At the completion of the initial eight years, customers will - ---------------------- (3) The Change in Control Payments relate to a special incentive plan adopted by CSW for 16 key employees in October 1996. See Joint Applicants' Response to Commission Staff's Information Request (requested at the informal conference of April 22, 1999), Item 4 at 61. 4 5 have received 55 percent, or $28.365 million, of the total net merger savings for the period.(4) The Merger Credit will continue beyond the initial eight-year period, reflecting the gross merger savings estimated for the eighth year, and will be allocated between customers and shareholders in the same manner as was utilized during the initial eight-year period. This annual amount of customer savings will be $5.243 million and will continue until Kentucky Power's next base rate case which will allocate total gross merger savings to customers. Should Kentucky Power file a base rate case during the initial eight-year period, the Merger Credit will remain in effect. Any legislatively mandated rates that are part of any legislation enacted to deregulate the electric industry in Kentucky will not diminish or offset, but will be in addition to, the bill reductions established in the Settlement Agreement. Rate Moratorium. The Settlement Agreement provides that Kentucky Power will not request a general increase in its existing base rates and charges that will be effective prior to January 1, 2003, or three years from the effective date of the merger, whichever is later. Kentucky Power's fuel adjustment clause, environmental surcharge, demand side management adjustment clause and system sales tracker are not included in this rate moratorium. Kentucky Power, moreover, may seek a general rate adjustment during the moratorium period if, after a public evidentiary hearing, the Commission determines that events constituting a force majeure as defined in the Settlement Agreement have occurred. The Intervenors have agreed not to Seek a reduction in base rates during the rate moratorium period. The Settlement Agreement does not preclude the Commission from initiating proceedings to investigate Kentucky Power's rates should it find that circumstances warrant such proceedings. - ----------------- (4) See Settlement Agreement, Attachment A. The annual Merger Credit amount ranges from $1.464 million to $4.626 million during the initial eight-year period. 5 6 Fuel Savings. The Settlement Agreement provides that all savings of fuel and purchase power expenses that result from the proposed merger will flow directly to Kentucky Power's retail customers through its existing fuel adjustment clause mechanism. AEP further agrees to hold Kentucky Power's native load customers harmless from higher replacement power costs of foregone revenues caused by current AEP operating companies supplying power to the service area of the CSW operating companies. Environmental Surcharge Litigation. The Settlement Agreement seeks to resolve all outstanding matters involving Kentucky Power's environmental surcharge mechanism. It requires the dismissal of all appeals,(5) including the Commission's, now before the Kentucky Court of Appeals involving the Commission's Orders in Case No. 96-489.(6) All parties will dismiss their appeals without prejudice. The Settlement Agreement further provides that Kentucky Power may, beginning January 1, 2000, recover through its environmental surcharge mechanism the costs associated with the low NOx burners for Big Sandy Generating Units No. 1 and No. 2. Kentucky Power will forego any recovery of costs eligible for recovery prior to January 1, 2000.(7) The Settlement Agreement also provides that the Commission's most recent review(8) of Kentucky Power's environmental surcharge be closed without further adjustment. - ------------------ (5) Kentucky Power Company d/b/a American Electric Power v. Kentucky Public Service Commission, et al., No. 1998-CA-001337 (filed July 25, 1998); Com. of Ky., ex rel., A.B. Chandler, III, Attorney General v. Kentucky Public Service Commission, et al, No. 1998-CA-001344 (filed July 28, 1998); Kentucky Industrial Utility Customers, Inc. v. Com. of Ky., ex rel., A.B. Chandler, III, Attorney General, No. 1998-CA-001417 (filed July 25, 1998); Kentucky Public Service Commission v. Com. of Ky., ex rel., A.B. Chandler, III, Attorney General, No. 1998-CA-001455 (filed July 27, 1998); Kentucky Power Company v. Kentucky Public Service Commission, et al., 1998-CA-002476 (filed Oct. 1, 1998). (6) Case No. 96-489, Application of Kentucky Power Company d/b/a American Electric Power to Assess a Surcharge under KRS 278.183 to Recover Costs of Compliance with the Clear Air Act and Those Environmental Requirements Which Apply to Coal Combustion Waste and By-Products. (7) In Commonwealth of Kentucky ex rel. Chandler v. Kentucky Public Service Commission, Nos. 97-CI-01138, 97-CI-01144, 97-CI-01319 (Ky. Franklin Cir. Ct. May 14, 1998), the Franklin Circuit Court 6 7 Affiliated Standards. The Settlement Agreement provides for affiliate standards and guidelines that will apply to transactions between AEP operating companies and their affiliates. These standards will take effect upon the consummation of the merger and remain in effect "until new affiliate standards imposed by either the Commission or by the General Assembly."(9) Quality of Service. The Settlement Agreement requires Kentucky Power and AEP to maintain service quality and reliability at existing levels. Kentucky Power and AEP agree to provide annually service reliability reports addressing the duration and frequency of customer disruptions and annual Call Center performance measures for those centers that handle Kentucky customer calls. They also commit to compile outage data detailing each circuit's reliability performance to identify and resolve reliability problems. Most Favored Nations Provisions. The Joint Applicants agree that if, in connection with the proposed merger, any state or federal regulatory commission imposes conditions on AEP that would benefit ratepayers in one jurisdiction, equivalent net benefits and conditions will be extended to Kentucky retail customers. COMMISSION FINDINGS Having thoroughly reviewed the Settlement Agreement, the Commission finds that the Settlement Agreement represents a reasonable resolution to the issues surrounding the proposed merger and should be approved. The Settlement Agreement allows for a fair and equitable - ------------- reversed in part the Commission's Order of May 27, 1997 and directed the Commission to permit Kentucky Power's recovery of low Nox burner costs incurred after May 19, 1997. (8) Case No. 98-624. An Examination By The Public Service Commission of The Environmental Surcharge Mechanism of Kentucky Power Company d/b/a American Electric Power As Billed From January 1, 1998 to June 30, 1998. (9) Settlement Agreement at 6. 7 8 distribution of the merger benefits between ratepayers and shareholders and protects Kentucky Power ratepayers from many of the potential risks posed by the merger. The Commission notes that the Settlement Agreement imposes new reporting requirements on Kentucky Power in the areas of service quality and reliability. While we recognize the difficulties presented by the terrain and topography in portions of Kentucky Power's service territory, the Commission reminds Kentucky Power that its top priority must be service quality and reliability. In the event that Kentucky Power's quality of service experiences a decline, the Commission is prepared to require additional measures be taken. The Commission also notes that the Settlement Agreement will end the lengthy and extensive litigation surrounding Kentucky Power's environmental surcharge mechanism. By this Order, we approve in principle those provisions and authorize our legal counsel to take all actions necessary to implement the Settlement Agreement's provisions and to dismiss all outstanding appeals pending before the Kentucky Court of Appeals. Because the issues dealing with Kentucky Power's environmental surcharge mechanism are addressed in other Commission proceedings that have not been consolidated with this proceeding, however. the Commission must implement certain of the provisions related to that mechanism through Orders in those proceedings. The Commission will issue those Orders as soon as possible.(10) - --------------------- (10) Within the next few days, the Commission will issue an Order in Case No. 98-624 to close Kentucky Power's current environmental surcharge proceedings. Implementing the provisions related to the recovery of the costs associated with the low NOx burners for Big Sandy Generating Units No. 1 and No. 2 will require the issuance of an Order in Case No. 96-489. That action will occur upon dismissal of all outstanding appeals. 8 9 REPORTING REQUIREMENTS In previous cases,(11) the Commission has determined that to effectively monitor the activities of the jurisdictional utility, its parent company and related subsidiaries, and to protect ratepayers, certain additional reports should be furnished by the jurisdictional utility to the Commission on an annual, periodic, or other basis as appropriate. The Commission finds that similar requirements are appropriate in this case as well. (12) Periodic Reports The annual financial statements of AEP should be furnished, including consolidating adjustments of AEP and its subsidiaries with a brief explanation of each adjustment and all periodic reports filed with the SEC. (13) All subsidiaries should prepare and have available monthly and annual financial information required to compile financial statements and to comply with other reporting requirements. The financial statements for any non-consolidated subsidiaries of AEP should be furnished to the Commission. AEP should also furnish the following reports on an annual basis: 1. A general description of the nature of intercompany transactions with specific identification of major transactions, and a description of the basis upon which cost allocations - ------------------- (11) See, e.g., Case No. 10296, The Application of Kentucky Utilities Company to Enter Into an Agreement and Plan of Exchange and to Carry Out Certain Transactions in Connection Therewith (Oct. 6, 1988); Case No. 89-374, Application of Louisville Gas and Electric Company for an Order Approving an Agreement and Plan of Exchange and to Carry Out Certain Transactions in Connection Therewith (May 25, 1990); Case No. 94-104, Application of the Cincinnati Gas & Electric Company and CINergy Corp. for Approval of the Acquisition of Control of The Union Light, Heat & Power Company by CINergy Corp. (May 13, 1994); Case No. 97-300, Joint Application of Louisville Gas and Electric Company and Kentucky Utilities Company for Approval of Merger (Sept. 12, 1997). (12) The imposition of these requirements is consistent with KRS 278.020(5), KRS 278.230 and Paragraph 8 of the Stipulation and Settlement Agreement. (13) The requested SEC reports include, but are not limited to, the U5S and U-13-60 reports. 9 10 and transfer pricing have been established. This report should discuss the use of the cost or market standard for the sale or transfer of assets, the allocation factors used, and the procedures used to determine these factors if they are different from the procedures used in prior years. 2. A report that identifies professional personnel transferred from Kentucky Power to AEP or any of the non-utility subsidiaries and describes the duties performed by each employee while employed by Kentucky Power and to be performed subsequent to transfer. AEP should file on a quarterly basis, a report detailing Kentucky Power's proportionate share of AEP's total operating, revenues, operating and maintenance expenses, and number of employees. Special Reports Other special reports should be furnished to the Commission as necessary. In anticipation that transfers of utility assets and investments by AEP will occur in the future, AEP should file any contracts or other agreements concerning the transfer of such assets or the pricing of intercompany transactions with the Commission at the time the transfer occurs. AEP should also file the following information: 1. A quarterly report of the number of employees of AEP and each subsidiary on the basis of payroll assignment. 2. An annual report containing the years of service at Kentucky Power and the salaries of professional employees transferred from Kentucky Power to AEP or its subsidiaries filed in conjunction with the annual transfer of employees report. 3. An annual report of cost allocation factors in use, supplemented upon significant change. 4. Summaries of any cost allocation studies when conducted and the basis for the methods used to determine the cost allocation in effect. 10 11 5. An annual report of the methods used to update or revise the cost allocation factors in use, supplemented upon significant change. 6. Current Articles of Incorporation and bylaws of affiliated companies in businesses related to the electric industry or that would be doing business with AEP. 7. Current Articles of Incorporation of affiliated companies involved in non-related business. After consummation of the merger, AEP will remain a registered holding company under the Public Utility Holding Company Act of 1935 and under the oversight of several regulatory bodies. Where the same information sought in these reports has been filed with the SEC, FERC, or another state regulatory commission, AEP may provide copies of that filing rather than prepare separate reports. Further, AEP may request the Commission to review these reporting requirements after the merger is completed to determine if the documentation being provided is either excessive or redundant. The Commission recognizes that the proposed merger has not yet received all necessary regulatory approvals. Consequently, the form or substance of the anticipated benefits of the merger might ultimately vary from those reviewed in this case. To the extent that the merger is subject to conditions or changes not reviewed in this case, the Joint Applicants should amend their filing to allow the Commission and all parties an opportunity to review the revisions to ensure that Kentucky Power and its customers are not adversely affected and that any additional benefits flow through the favored nations clause. MOTION FOR REHEARING The Kentucky Association of Plumbing-Heating-Cooling Contractors, Inc. and Kentucky Propane Gas Association (collectively "Contractors") have moved for reconsideration of the 11 12 Commission's Order of May 20, 1999 in which we denied their application for full intervention. In support of their motion, the Contractors state that they have an interest in this proceeding as the Joint Applicants have not expressly precluded the possibility of competing with their members or to refrain such competition pending completion of Administrative Case No. 369.(14) Having considered the motion, the Commission does not find good cause to modify its May 20, 1999 Order. While the Commission acknowledges the Contractors' concerns regarding utility affiliate transactions, these concerns are more appropriately addressed in Administrative Case No. 369, which was initiated specifically to review these issues as they relate to all regulated utilities. Moreover, Commission approval of the Settlement Agreement neither binds nor limits our ability to deal with the issue of affiliated transactions. The Settlement Agreement contains no provision limiting the scope of our discretion in this area. It specifically provides that its affiliate standards "apply from the date of closing of the merger until new affiliate standards imposed by state legislation or State Commission action become effective." Settlement Agreement at 6. SUMMARY After consideration of the evidence and being otherwise sufficiently advised, the Commission finds that: 1. The proposed merger of AEP and CSW will result in an indirect change in control of Kentucky Power and therefore requires prior Commission approval. KRS 278.020(4) and (5). - ------------- (14) The Administrative Case No. 369, An Investigation of The Need For Affiliate Transaction Rules and Cost Allocation Requirements For All Jurisdictional Utilities. 12 13 2. The proposed merger of AEP and CSW and the resulting indirect change in control of Kentucky Power is in accordance with law, for a proper purpose, and with the conditions and assurances established herein consistent with the public interest. 3. AEP and Kentucky Power have and, upon completion of the proposed merger, will retain the financial, managerial and technical abilities to provide reasonable utility service. 4. The "Stipulation and Settlement Agreement," appended hereto, is reasonable, does not conflict with any regulatory principle and should be approved. 5. The Contractor's Motion for Reconsideration should be denied. 6. AEP and Kentucky Power should file the reports and other information as specifically set out in this Order. 7. The Joint Applicants should submit copies of final approval received from the FERC, SEC, FTC, DOJ, and all state regulatory commissions to the extent that these documents have not been provided. With each submittal, the Joint Applicants shall further state whether Paragraph 10 of the Settlement Agreement requires changes to the regulatory plan approved herein. IT IS THEREFORE ORDERED that: 1. The Joint Applicants' Application for an Order declaring that the merger of AEP and CSW is not subject to approval pursuant to KRS 278.020(4) or (5) is denied. 2. The terms and conditions set forth in the Settlement Agreement, a copy of which is appended hereto, are adopted and approved and are incorporated into this Order as if fully set forth herein. 13 14 3. The proposed merger transaction and resulting indirect transfer of control are approved, subject to additional review in the event that the merger or the anticipated benefits are changed or modified as a result of action by other regulatory agencies. 4. The proposed Net Merger Savings Credit Tariff is approved. 5. Within 20 days of the date of this Order, Kentucky Power shall file revised tariff sheets reflecting the approved Net Merger Savings Credit Tariff. 6. AEP and Kentucky Power shall comply with all reporting requirements described herein. 7. The Kentucky retail jurisdictional share of the estimated transaction, regulatory processing and transition costs incurred to merge and combine AEP and CSW shall be deferred and amortized for recovery over eight years. This amortization shall begin with the date of the combination and shall continue for eight years on a straight-line basis. 8. The Joint Applicants shall within five days of the consummation of the proposed merger file a written notice setting forth the date of merger and the effective date of the Net Merger Saving Credit Tariff. 9. The proposed settlement of outstanding litigation involving Kentucky Power's environmental surcharge mechanism, as set forth in the Settlement Agreement, is approved. Commission counsel is authorized to execute all necessary documents to dismiss all appeals identified in Footnote 6 of this Order. 10. The Contractors' Motion for Reconsideration is denied. Done at Frankfort, Kentucky, this 14th day of June, 1999. By the Commission 14 15 ATTEST: /s/ Helen C. Helton Executive Director 15 16 APPENDIX AN APPENDIX TO AN ORDER OF THE KENTUCKY PUBLIC SERVICE COMMISSION IN CASE NO. 99-149 DATED 6/14/99 17 COMMONWEALTH OF KENTUCKY BEFORE THE PUBLIC SERVICE COMMISSION OF KENTUCKY IN THE MATTER OF: JOINT APPLICATION OF KENTUCKY POWER COMPANY ) AMERICAN ELECTRIC POWER COMPANY, INC. ) AND CENTRAL AND SOUTH WEST CORPORATION ) CASE NO. 99-149 REGARDING A PROPOSED MERGER ) STIPULATION AND SETTLEMENT AGREEMENT On February 17, 1999 the Staff of the Public Service Commission of Kentucky ("Commission") issued a letter stating staff's belief that the Commission has jurisdiction under KRS 278.020(5) to review the proposed merger of Central and South West Corporation ("CSW") into American Electric Power Company, Inc. ("AEP") and requested that Kentucky Power Company ("Kentucky Power", "KPCO" or the "Company") advise in writing by March 8, 1999 of the date AEP would file an application for Commission approval of "the indirect change in control of Kentucky Power Company." On March 5, 1999 the Company issued a letter notifying the Commission that it would file the requested application by April 15, 1999. The letter also indicated that the Company expected to provide the Staff and the Commission with sufficient information to enable the Commission to approve its application within the sixty (60) day period prescribed by the statute. The letter further preserved the Company's legal arguments regarding the application of KRS 278.020 (5) to this merger. On April 15, 1999 the Company, AEP and CSW filed a Joint Application with supporting testimony and workpapers. The proceeding was designated P.S.C. Case No. 99-149. On April 22, 1999 the Commission issued a letter indicating that the Commission staff had reviewed the Company's application and found that it met the minimum filing requirements. On May 4, 1999 the Attorney General, Office of the Rate Intervention ("Attorney General"), and Kentucky Electric Steel, Inc. ("KESI") were granted full intervention in Case No. 99-149. On May 11, 1999 Kentucky Industrial Utility Customers Inc. ("KIUC"), was also granted full intervention in Case No. 99-149. These parties will be referred to herein collectively as the "Intervenors". On April 22, 1999 a Technical Conference was held at the Commission's offices. On May 4, May 11, May 17, and May 20, 1999 settlement conferences were held at the Commission's offices. Present were the Staff and counsel for the Intervenors, as well as Company representatives. 18 Solely for the purposes of compromise and settlement of the issues in this proceeding, Central and South West Corporation, American Electric Power Company, Inc., Kentucky Power Company, which does business in Kentucky as American Electric Power, the Attorney General, Kentucky Industrial Utility Customers, Inc. and Kentucky Electric Steel, Inc. (collectively referred to as the "Parties") have met and reached a settlement agreement ("Agreement") which they hereby submit and recommend for approval to the Commission. If the Commission does not approve the settlement agreement in its entirety and incorporate it in the Final Order, the proposed Agreement shall be null and void and deemed withdrawn, unless such change is agreed to by the Parties. SETTLEMENT AGREEMENT WHEREAS AEP and CSW have filed various applications before federal and state agencies seeking approvals necessary to consummate a proposed merger of the two companies; and WHEREAS the Parties have met and explored various issues related to the proposed merger and their agreements and differences regarding the effects of the proposed merger on competition between electricity providers and on the terms and conditions under which retail electric utility service is provided; and WHEREAS the Parties recognize the costs and uncertainty of litigation and the desirability of consensual voluntary resolution of their differences and the legitimate interests and good faith of each of the parties in achieving the objectives each desires to achieve; and WHEREAS, the Parties agree as follows: That AEP, KPCO and the Intervenors will recommend to the Commission that the following Agreement be adopted by the Commission in an order or other appropriate formal action that references this Agreement or incorporates all of the provisions thereof. Where appropriate, the Commission action may address or reserve other matters ancillary or incidental to the matters addressed in this Agreement, for immediate or future disposition, in a manner not inconsistent with the Agreement. All appropriate terms are defined in the "Definitions" section of the Agreement. The Parties: 1. Will not oppose the proposed merger pending before the Federal Energy Regulatory Commission ("FERC"). 2. Will not oppose AEP's filings previously made at the United States Securities and Exchange Commission ("SEC") in connection with the proposed merger, together with any non-material changes or supplements thereto. 19 AEP, or Kentucky Power Company, conditional on merger consummation will: 1. REGULATORY PLAN. KPCO will implement a Net Merger Savings Credit tariff that will reduce bills to customers by the annual amounts shown in Attachment A beginning with the first full billing month available following thirty days from the consummation of the merger. The annual bill reduction amounts shown in Attachment A will be refunded to customers based upon kwh consumption. Each individual year's bill reduction will apply for a twelve month period. A Balancing Adjustment Factor (B.A.F.) per Kwh will be included for the second through the twelfth month of the current distribution year which will reconcile any over- or under-distribution of the net savings from prior years. The merger savings and costs are based on estimated values included in AEP's filing with the Federal Energy Regulatory Commission ("FERC") in Docket No. EC98-40-000. Absent a force majeure, KPCO will not file a petition, which, if approved, would have the effect, either directly or indirectly, of authorizing a general increase in basic rates and charges that would be effective prior to January 1, 2003 or three years from the effective date of the merger, whichever is later (the "rate moratorium"), and the Intervenors agree not to seek a reduction in base rates during the rate moratorium. During this period, the fuel adjustment clause, the environmental surcharge, the demand side management adjustment and the system sales tracker shall continue in force and shall not be subject to any freeze. During the rate moratorium period, and not withstanding any force majeure event, any discount, including but not limited to, operating reserve and interruptible discounts contained in special contracts as currently approved by the Commission, shall remain in force and shall not be changed for any customer receiving the discount. The Parties and the Commission will dismiss the appeals and cross-appeals in Case Nos. 98 CA 00137, 98 CA 001344, 98 CA 001417, 98 CA 001455 and 98 CA 002476. The dismissal shall be without prejudice in any other action with respect to the positions taken by the parties in dismissed litigation. Effective January 1, 2000, KPCO shall begin collecting the environmental surcharge, including the costs of the Low Nox burners for the Big Sandy generating plant's Unit No. 1 and Unit No. 2, in accordance with the decisions of the Franklin Circuit Court Opinion and Order dated April 30, 1998 and its Amended Opinion and Order dated May 14, 1998 in Consolidated Case Nos. 97-CI-01138, 97-CI-01144 and 97-CI-00137 (except those portions of the decision allowing retroactive recovery of the surcharge). The parties further agree that there shall be no adjustment to the environmental surcharge as a result of the six month review in P.S.C. Case No. 98-624. Notwithstanding any base rate proceeding during the eight year period after the consummation of the merger, the annual amounts shown in Attachment A will remain in effect. After the eight year period and absent a base rate proceeding, the Company will continue through the Net Merger Savings Credit to reduce bills to customers by the annual amount shown on Attachment 20 A which is the customers' portion of the net savings without the amortization of the costs to achieve during the eighth year after the consummation of the merger. KPCO must implement the above rate reductions in the manner and amounts described above notwithstanding any changes to the current regulatory structure in Kentucky. In the event that retail electric deregulation legislation is implemented in Kentucky or if there is any unbundling or restructuring, KPCO shall continue to apply the regulatory plan's provisions to regulated rates of its Kentucky retail jurisdictional customers. Any legislatively mandated adjustments to base rates, of any kind, that are part of any retail electric deregulation legislation implemented in Kentucky shall not diminish or offset, but shall be in addition to, the bill reductions established in this proceeding. Subject to this agreement, AEP and KPCO will defer and amortize their Kentucky retail jurisdictional estimated merger related costs-to-achieve over an 8-year recovery period. Costs to achieve the merger are those costs incurred to consummate the merger and combine the operations of AEP and CSW. These costs include, but are not limited to, investment banking fees; consulting and legal services incurred in connection with obtaining regulatory and shareholder approvals; transition planning and development costs; employee separation costs including severance costs, change-in-control payments and retraining costs; and facilities consolidation costs. The Commission will issue accounting orders or other orders necessary to authorize the deferral and amortization of merger costs. If the merger is not consummated, the Company commits and agrees not to seek to recover termination fees, the "Out of Pocket" and "Topping Out" fees associated with the merger as described in Sections 9.5 and 9.6 of the Agreement and Plan of Merger By and Among American Electric Power Company, Inc., Augusta Acquisition Corporation and Central and South West Corporation dated December 21, 1997 (Merger Agreement); and further commit and agree not to seek to recover the fee that may be charged by Morgan Stanley. In any proceeding to change base rates for KPCO to become effective after the consummation of the merger, the following rate treatment will be reflected: A. Estimated non-fuel merger savings, net of costs to achieve will be included in cost of service as an allowable expense in order to avoid duplication and to continue to provide shareholders with their share of the net savings. The amount to be included in the cost of service shall be based upon the test year period. (See Attachment B). B. Amortization of estimated costs to achieve will be included in cost of service as an allowable expense. The amount to be included in the cost of service shall be based upon the test year period. (See Attachment B). In any base rate proceeding after the eight year period, neither the merger savings credit rider nor the expense adjustments described in A. and B. above will be reflected in the test year. 21 2. FUEL MERGER SAVINGS. All savings of fuel and purchased power expenses resulting from the merger shall benefit retail customers through existing fuel clause recovery mechanisms applied by State Commissions. In circumstances when one or more AEP operating companies in one AEP zone are supplying power to the other AEP zone, and as a result, the supplying zone needs to purchase replacement power to serve its native load, AEP shall hold harmless the native load customers of the supplying zone from any price differential between the replacement power and the system power supplied to the other zone. Similarly, if one or more AEP operating companies in one AEP zone are supplying power to the other AEP zone, and as a result, the supplying zone loses the opportunity to sell power at a price higher than received from the zone being supplied, AEP shall credit the supplying zone for the foregone revenues. 3. For purposes of this Settlement Agreement, force majeure shall mean circumstances that cause any of the following to occur: a) the bond rating for Kentucky Power Company to fall below an investment grade rating of Baa3 (Moody's) or BBB- (Standard & Poor's), or b) an increase in the federal and/or state income taxes of KPCO, which increase is the result of changes in federal or state income tax provisions, or c) an increase in KPCO's total electric operating expenses, excluding fuel and purchased power, due to circumstances beyond its control, and further excluding the costs of compliance with federal, state or local environmental requirements which apply to coal combustion wastes and by-products from facilities utilized for production of energy from coal. For purposes of this force majeure provision, an increase is defined as an increase in expense in an annualized amount greater than five percent (5%) of AEP's Kentucky jurisdictional net revenues (i.e., operating revenues less fuel and purchased power) for the preceding twelve months. A force majeure may only exist under the terms of this Settlement Agreement if the Commission finds in a rate application filed by the Company that the circumstances allowed for under this Settlement Agreement are a force majeure, as defined in this Agreement, after a public evidentiary hearing in which al the Parties may participate. 4. STRANDED COSTS. AEP and its operating companies agree not to seek or recover any stranded costs associated with the operating companies of one AEP zone from the retail customers of the other AEP zone. 5. PROCEEDS OF FACILITY SALES. Any proceeds from the sale of facilities shall go to the AEP operating company in whose rate base the facilities are included, for further disposition in accordance with the rules and orders of the regulatory authorities whose jurisdiction encompasses the ultimate disposition of such proceeds. 6. SYSTEM INTEGRATION AGREEMENTS. To mitigate any perceived impacts of the merger on AEP's ability to exercise market power. AEP proposed in its FERC merger application a mitigation plan. To protect retail customers, AEP agrees to hold harmless the retail customers from any mitigation plan included in any FERC order approving the merger of AEP-CSW. To implement this Agreement in any general retail electric rate proceeding commenced by the filing of a petition on or after the date of this Agreement, in which an AEP operating 22 company requests a change in its basic rates and charges, or in any other proceeding where so ordered by the State Commission, AEP shall have the burden therein to prove that such requested rate relief does not reflect mitigation-related costs. AEP commits to file any allocation of the cost of new, modified or upgraded generation or transmission facilities whose costs will be subject to the System Integration Agreement or the System Transmission Agreement with the FERC and to notify each State Commission of any such filing at the time it is made. Notification to each State Commission will include an estimate of the cost of construction, an explanation of the reasons for constructing the facilities, studies supporting the construction of the facilities, and a proposed allocation of the facilities' costs. If AEP plans to purchase an in-service facility or already constructed and soon-to-be-in-service facility, AEP will follow the above described procedures and will include as part of the notification to the State Commission an explanation of the circumstances causing the AEP operating company to make the purchase in question. 7. REGULATORY AUTHORITY. AEP agrees not to seek to overturn, reverse, set aside, change or enjoin, whether through appeal or the initiation or maintenance of any action in any forum, a decision or order of a State Commission based on the assertion that the authority of the Securities and Exchange Commission as interpreted in Ohio Power Co. v. FERC, 954 F.2d 779 (D.C. Cir. 1992) cert. denied, 498 U.S. 73 (1992) impairs the State Commission's ability to examine and determine the reasonableness of non-power affiliate transaction costs to be passed to retail customers. The parties agree that the Ohio Power waiver does not include waiver of any arguments that AEP may have with respect to the reasonableness of SEC approved cost allocations. AEP will provide each State Commission with notice at least 30 days prior to any filings that propose new allocation factors with the SEC. The notice need not be in the precise form of the filing but shall include, to the extent information is available, a description of the proposed factors and the reasons supporting such factors. AEP and State Commission Staff will make a good faith attempt to resolve their differences, if any, in advance of a filing being made at the SEC. 8. AFFILIATE STANDARDS. The following affiliate standards shall apply from the date of closing of the merger until new affiliate standards imposed by state legislation or State Commission action become effective. A. The financial policies and guidelines for transactions between an AEP operating company and its affiliates shall reflect the following principles: 1. An AEP operating company's retail customers shall not subsidize the activities of the operating company's non-utility affiliates or its utility affiliates. 2. An AEP operating company's costs for jurisdictional rate purposes shall reflect only those costs attributable to its jurisdictional customers. 3. These principles shall be applied to avoid costs found to be just and reasonable for ratemaking purposes by the affected State Commission being left unallocated or stranded between various regulatory jurisdictions, 23 resulting in the failure of the opportunity for timely recovery of such costs by the operating company and/or its utility affiliates; provided, however, that no more than one hundred percent of such costs shall be allocated on an aggregate basis to the various regulatory jurisdictions. 4. An AEP operating company shall maintain and utilize accounting systems and records that identify and appropriately allocate costs between the operating company and its affiliates, consistent with these cross-subsidization principles and such financial policies and guidelines. B. Each State Commission shall have access to the employees, officers, books and records of any affiliate of its jurisdictional AEP operating company to the same extent and in like manner that each such State Commission has over a public utility operating within the state in which such State Commission exercises its regulatory authority if the affiliate had engaged in direct or indirect transactions with the jurisdictional AEP operating company. If such employees, officers, books and records can not be reasonably made available to a State Commission, then upon request of a State Commission, the AEP operating company shall, in accordance with state reimbursement rules, reimburse the State Commission for appropriate out-of-state travel expenses incurred in accessing the employees, officers, books and records. Each AEP operating company shall maintain, in accordance with generally accepted accounting principles, books, records, and accounts that are separate from the books, records, and accounts of its affiliates, consistent with Part 101 - Uniform System of Accounts Prescribed for Public Utilities and Licensees Subject to the Provisions of the Federal Power Act. Any objections to providing all books and records must be raised before the State Commission and the burden of showing that the request is unreasonable or unrelated to the proceeding is on the AEP operating company. The confidentiality of competitively sensitive information shall be maintained in accordance with each State Commission's rules and regulations. C. In accordance with generally accepted accounting principles and consistent with state and federal guidelines, an AEP operating company shall record all transactions with its affiliates, whether direct or indirect. An AEP operating company and its affiliates shall maintain sufficient records to allow for an audit of the transactions involving the operating company and its affiliates. Asset transfers from an AEP operating company to a non-utility affiliate and asset transfers from a non-utility affiliate to an AEP operating company shall be at fully distributed costs in accordance with current Securities and Exchange Commission (SEC) issued requirements or other statutory requirements if the SEC has no jurisdiction. D. An AEP operating company shall not allow a non-utility affiliate to obtain credit under any arrangement that would permit a creditor, upon default, to have recourse to the operating company's assets. The financial arrangements of an AEP operating company's affiliates are subject to the following restrictions unless otherwise approved by that operating company's State Commission: 24 1. An indebtedness incurred by a non-utility affiliate will be without recourse to the operating company. 2. An AEP operating company shall not enter into any agreements under terms of which the operating company is obligated to commit funds in order to maintain the financial viability of a non-utility affiliate. 3. An AEP operating company shall not make any investment in a non-utility affiliate under circumstances in which the operating company would be liable for the debts and/or liabilities of the non-utility affiliate incurred as a result of acts or omissions of a non-utility affiliate. 4. An AEP operating company shall not issue any security for the purpose of financing the acquisition, ownership, or operation of a non-utility affiliate. 5. An AEP operating company shall not assume any obligation or liability as guarantor, endorser, surety, or otherwise with respect to any security of a non-utility affiliate. 6. An AEP operating company shall not pledge, mortgage or otherwise use as collateral any assets of the operating company for the benefit of a non-utility affiliate. 7. AEP shall hold harmless the retail customers of an AEP operating company from any adverse effects of credit rating declines caused by the actions of non-utility affiliates. Transactions between AEP operating companies and affiliates involving a money pool for the financing of short-term funding requirements are exempt from the requirements of this paragraph. Further, the provisions of this paragraph would not preclude AEP operating companies from issuing securities or assuming obligations related to their existing coal subsidiaries. E. An untariffed, non-utility service provided by an AEP operating company or affiliated service company to any affiliate shall be itemized in a billing statement pursuant to a written contract or written arrangement. The AEP operating company and any affiliated service company shall maintain and keep available for inspection by the State Commission copies of each billing statement, contract and arrangement between the AEP operating company or affiliated service company and its affiliates that relates to the provision of such untariffed non-utility services. F. Any good or service provided by a non-utility affiliate to an AEP operating company shall be by itemized billing statement pursuant to a written contract or written arrangement. The operating company and non-utility affiliate shall maintain and keep available for inspection by the State Commission copies of each billing statement, contract and arrangement between the operating company 25 and its non-utility affiliates that relates to the provision of such goods and services in accordance with applicable State Commission retention requirements. G. Employees responsible for the day to day operations of the AEP operating companies and those of affiliated exempt wholesale generators or affiliated power marketers shall operate independently of one another. AEP shall document all employee movement between and among all affiliates. Such information shall be made available to each State Commission and consumer advocate upon request. H. An AEP operating company may not own property in common with an affiliated exempt wholesale generator or affiliated power marketer. I. No market information obtained in the conduct of utility business may be shared with an affiliated exempt wholesale generator or affiliated power marketer, except where such information has been publicly disseminated or simultaneously shared with an made available to all non-affiliated entities who have requested such information. Customer specific information shall not be made available to an affiliated exempt wholesale generator or affiliated power marketer except under the same terms as such information would be made available to a non-affiliated company, and only with the written consent of the customer specifying the information to be released. J. A non-utility affiliate may use an AEP operating company's name or logo only if, in connection with such use, the affiliate makes adequate disclosures to the effect that (i) the two entities are separate; (ii) it is not necessary to purchase the non-regulated product or service to obtain service from the operating company; and (iii) the customer will gain no advantage from the operating company by buying from the affiliate. K. An AEP operating company shall not condition or tie the provision of any product, service, pricing benefit, or waiver of associated terms or conditions, to the purchase of any good or service from its affiliated exempt wholesale generator or power marketer. L. Except as provided in paragraph M, an affiliated exempt wholesale generator or affiliated power marketer shall not share office space, office equipment, computer systems or information systems with an AEP operating company. M. Computer systems and information systems may be shared between an AEP operating company and non-utility affiliates only to the extent necessary for the provision of corporate support services; however, the operating company shall ensure that the proper security access and other safeguards are in place to ensure full compliance with these affiliate rules. N. An AEP operating company may engage in transactions directly related to the provision of corporate support services with its affiliates in accordance with requirements relating to service agreements. As a general principle, such provision of corporate support services shall not allow or provide a means for the 26 transfer or confidential information from the operating company to the affiliate, create the opportunity for preferential treatment or unfair competitive advantage, create opportunities for cross-subsidization of affiliates, or otherwise provide any means to circumvent these affiliate rules. O. Except as provided in paragraph N, an AEP operating company may only make a product or service available to an affiliated exempt wholesale generator or an affiliated power marketer if the product or service is equally available to all non-affiliated exempt wholesale generators and power marketers on the same terms, conditions and prices, and at the same time. An AEP operating company shall process all requests for a product or service from affiliated and non-affiliated exempt wholesale generators and power marketers on a non-discriminatory basis. P. An AEP operating company which provides both regulated and non-regulated services or products, or an affiliate which provides services or products to an AEP operating company, shall maintain documentation in the form of written agreements, an organization chart of AEP (depicting all affiliates and AEP operating companies), accounting bulletins, procedure and work order manuals, or other related documents, which describe how costs are allocated between regulated and non-regulated services or products. Such documentation shall be available, subject to requests for confidential treatment, for review by State Commissions in accordance with Paragraph B, above. Q. AEP shall designate an employee who will act as a contact for State Commissions and consumer advocates seeking data and information regarding affiliate transactions and personnel transfers. Such employee shall be responsible for providing data and information requested by a State Commission for any and all transactions between the jurisdictional operating company and its affiliates, regardless of which affiliate(s), subsidiary(ies) or associate(s) of an AEP operating company from which the information is sought. R. AEP shall designate an employee or agent within each signatory state who will act as a contact for retail consumers regarding service and reliability concerns and to allow a contact for retail consumers for information, questions and assistance. Such AEP representative shall be able to deal with billing, maintenance and service reliability issues. S. AEP shall provide each signatory state a current list of employees or agents that are designated to work with each State Commission and consumer advocate concerning state regulatory matters, including, but not limited to, rate cases, consumer complaints, billing and retail competition issues. T. Thirty (30) days prior to filing any affiliate contract (including service agreements) with the SEC or the FERC an AEP operating company shall submit to each affected State Commission a copy of the proposed filing. 27 U. Any violation of the provisions of these affiliate standards are subject to the enforcement powers and penalties at the State Commissions. V. AEP shall contract with an independent auditor who shall conduct biennial audits for ten years after merger consummation of affiliated transactions to determine compliance with these affiliate standards. The results of such audits shall be filed with the State Commissions. Prior to the initial audit, AEP will conduct an informational meeting with State Commissions regarding how its affiliates and affiliate transactions will or have changed as a result of the proposed merger. W. If the Public Utility Holding Company Act of 1935 is repealed or materially amended during the time this Agreement is in effect, and equivalent jurisdiction is not given to another federal agency, AEP will work with the State Commissions to ensure that AEP continues to furnish the State Commission with the appropriate information to regulate its jurisdictional AEP operation company. The State Commission may establish its reporting requirements regarding the nature of intercompany transactions concerning the operating company and a description of the basis upon which cost allocations and transfer pricing have been established in these transactions. 9. ADEQUACY AND RELIABILITY OF RETAIL ELECTRIC SERVICE. See Attachment C for the AEP/KENTUCKY POWER SERVICE QUALITY PROGRAM that has been agreed to by the parties. 10. STATUTORY AND OTHER ISSUES. Provided the proposed merger is ultimately consummated, AEP commits that upon issuance of any final and non-appealable order from any state or federal commission addressing the merger that provides benefits or imposes conditions on AEP that would benefit the ratepayers of any jurisdiction, such net benefits and conditions will be extended to all other retail customers to the extent necessary to achieve equivalent net benefits and conditions to all retail customers of AEP. 11. CONTINUED PARTICIPATION. Nothing in this Agreement is intended to preclude the Commission and its staff from addressing in a manner not inconsistent with this Agreement issues raised in the FERC Docket No. 98-40-000. 12. ENFORCEABILITY. AEP and KPCO will not assert in any action to enforce an order approving this Agreement that the Commission lacks the authority to have the provisions of this Agreement enforced under Kentucky law. DEFINITIONS 1. "AEP zone" means either the area comprising the AEP operating companies providing service in Indiana, Michigan, Kentucky, Ohio, Tennessee, Virginia and West Virginia ("East") or the area comprising the former CSW operating companies providing service in Arkansas, Texas, Oklahoma and Louisiana ("West"). 2. "AEP operating company" means an AEP affiliate that is a public utility subject to rate regulation by the FERC and/or a state utility regulatory agency. 28 3. "Affiliate" means an entity that is an operating company's holding company, a subsidiary of the operating company or a subsidiary of the holding company. 4. "Consumer advocate" means an agency of the state government designated as a representative of consumers in matters involving utility companies before the applicable State Commission. 5. "Entity" means a corporation or a natural person. 6. "Exempt wholesale generator" means an entity which is engaged directly or indirectly through one or more affiliates exclusively in the business of owning or operating all or part of a facility for generating electric energy and selling electric energy at wholesale and who: a. does not own a facility for the transmission of electricity, other than an essential interconnecting transmission facility necessary to affect a sale of electric energy at wholesale; and b. has applied to the FERC for a determination under 15 U.S.C. Section 79z-5a. 7. "FERC" means the Federal Energy Regulatory Commission, or any successor governmental agency. 8. "Non-Utility Affiliate" means an Affiliate which is not a domestic public utility. Non-utility affiliate includes a foreign affiliate. 9. "Holding Company" means AEP, or its successor in interest, or any Entity that owns directly or indirectly 10 percent or more of the voting capital stock of a utility operating company, or its successor in interest. 10. "Power Marketer" means an entity which: a. becomes an owner or broker of electric energy in a state for the purpose of selling the electric energy at wholesale; b. does not own transmission or distribution facilities in a state; c. does not have a certified service area; and d. has been granted authority by the FERC to sell electric energy at market-based rates. 11. "SEC" means the United States Securities and Exchange Commission, or any successor governmental agency. 12. "Service Agreement" means the agreement entered into between American Electric Power Service Corp. and AEP's operating companies, under which services are provided by American Electric Power Service Corp. to the operating companies. 29 13. "Service Company" means an Affiliate whose primary business purpose is to provide among other functions, administrative and general or operating services to AEP utility operating companies. 14. "Services" means the performance of activities having value to one party including, but not limited to, managerial, financial, accounting, legal, engineering, construction, purchasing, marketing, auditing, statistical, advertising, publicity, tax, research, and other similar services. 15. "Subsidiary" means any corporation 10 percent or more of whose voting capital stock is controlled by another Entity. 16. "Utility Affiliate" means an affiliate of a utility operating company that is also a public utility. Presentation of Agreement to the Commission 1. The Parties shall move for the admission of this Agreement into evidence at the hearing scheduled for May 28, 1999, or such earlier time as the Commission may establish and sponsor evidence including testimony and exhibits as may be required to support Commission approval of this Agreement. 2. The Parties stipulate and agree to the issuance by the Commission of the Proposed Order in the form attached hereto as Attachment D. All of the terms and agreements contained in the Proposed Order are to be interpreted consistent with the provisions of this Agreement, which is to be attached to and incorporated by reference in the Final Order issued by the Commission. Effect and Use of Agreement 1. This Agreement shall not constitute nor be cited as precedent or deemed an admission by any Party in any other proceeding except as necessary to enforce its terms before the Commission, or any State Court of competent jurisdiction. This Agreement is solely the result of compromise in the settlement process, shall not constitute a concession of subject matter jurisdiction, and except as expressly provided herein, is without prejudice to and shall not constitute a waiver of any position that any of the Parties may take with respect to any or all of the items resolved herein in any future regulatory or other proceedings and, failing approval by this Commission, shall not be admissible or discussed in any subsequent proceedings. 2. The evidence in this Case constitutes substantial evidence sufficient to support the Agreement and provides an adequate evidentiary basis upon which the Commission can make any finding of fact and conclusions of law necessary for the approval of the Agreement, as filed. 3. The issuance of the Final Order shall terminate any further proceedings in this Case. 4. In the event this Case is required to be litigated, the Parties expressly reserve all of their rights to make objections and motions to strike with respect to all testimony and exhibits and their right to cross-examine the witnesses presenting such testimony and exhibits. 30 5. The undersigned have represented and agreed that they are fully authorized to execute this Agreement on behalf of their designated clients who will be bound thereby. 6. The Parties to this Agreement shall not appeal the agreed Final Order or any other Commission order to the extent such orders are specifically implementing the provisions of this Agreement and shall support this Agreement in the event of any appeal by a person not a Party. This provision shall be enforceable by any Party, in any state court of competent jurisdiction. 7. The communications and discussions during the negotiations and conferences that produced the Agreement have been conducted on the explicit understanding that they are or relate to offers of settlement and shall therefore be privileged and not admissible in any proceeding. ACCEPTED and AGREED this 24th day of May, 1999. Central and South West Corporation By: /s/ Mark R. Overstreet ----------------------------- Kentucky Power Company By: /s/ Mark R. Overstreet ----------------------------- Mark R. Overstreet Sites and Harbison 31 AEP By: /s/ Richard E. Munczinski ------------------------------------ Richard E. Munczinski Senior Vice President American Electric Power Service Corporation Attorney General By: /s/ Elizabeth E. Blackford ------------------------------------ Elizabeth E. Blackford Assistant Attorney General Attorney General, Office of Rate Intervention Kentucky Industrial Utility Customers, Inc. By: /s/ David F. Boehm ------------------------------------ David F. Boehm Boehm, Kurtz & Lowry Kentucky Electric Steel, Inc. By: /s/ William H. Jones, Jr. ------------------------------------ William H. Jones, Jr. VanAntwerp, Monge, Jones & Edwards, LLP 32 ATTACHMENT A Page 1 of 1 AEP/CSW MERGER NET ANNUAL MERGER SAVINGS AND KENTUCKY CUSTOMER BILL REDUCTIONS ($000)
(1) (2) (3) (4) RATE NET CUSTOMER BILL SHAREHOLDER YEAR MERGER SAVINGS REDUCTION @ 55% NET SAVINGS @ 45% ------ -------------- --------------- ----------------- Year 1 2,469 1,464 1,005 Year 2 4,551 2,554 1,997 Year 3 5,757 3,185 2,572 Year 4 6,732 3,695 3,037 Year 5 7,385 4,037 3,348 Year 6 7,887 4,299 3,588 Year 7 8,279 4,505 3,774 Year 8 8,511 4,626 3,885 ------ ------ ------ 51,571 28,355 23,206 ====== ====== ======
Note: Annual Customer Bill Reduction after year 8 until next base rate case is $5,242,785. 33 ATTACHMENT B Page 1 of 3 AEP/CSW MERGER EXAMPLE OF BASE RATE CASE TREATMENT BASED ON YEAR 3 ($000) CREDIT PER RIDER CONTINUES (3,184) INCLUDED IN TEST YEAR GROSS MERGER SAVINGS (7,262) CHANGE IN CONTROL AMORTIZATION 328 OTHER CTA AMORTIZATION 1,178 ---------------- TOTAL CTA/CIC AMORTIZATION 1,506 ------------------- NET MERGER SAVINGS IN TEST YEAR (5,756) ADD BACK TO TEST YEAR COST OF SERVICE CUSTOMER SHARE 3,184 SHAREHOLDER PORTION 2,572 ---------------- 5,756 ------------------- NET BASE REDUCTION 0 -------- KENTUCKY CUSTOMER RATE REDUCTION (3,184) ========
34 ATTACHMENT B Page 2 of 3 AEP/CSW MERGER BASE RATE CASE TREATMENT FOR INCLUSION IN COST OF SERVICE ($000)
Add Back to Test Year Cost of Service ------------------------------------- RATE CUSTOMER SHAREHOLDER YEAR NET SAVINGS NET SAVINGS ---- ----------- ----------- Year 1 1,464 1,005 Year 2 2,554 1,997 Year 3 3,185 2,572 Year 4 3,695 3,037 Year 5 4,037 3,348 Year 6 4,299 3,588 Year 7 4,505 3,774 Year 8 4,626 3,885 ------ ------ 28,365 23,206 ====== ======
35 ATTACHMENT B Page 3 of 3 AEP/CSW MERGER AMORTIZATION OF ESTIMATED COSTS TO ACHIEVE*
RATE YEAR AMOUNT ---- ------ Year 1 1,505,502 Year 2 1,505,502 Year 3 1,505,502 Year 4 1,505,502 Year 5 1,505,502 Year 6 1,505,502 Year 7 1,505,502 Year 8 1,505,501 ---------- TOTAL 12,044,015 ** ==========
* Includes change in control payments. ** May not add due to roundings. 36 AEP/KENTUCKY POWER SERVICE QUALITY Attachment C Page 1 of 5 AEP/Kentucky Power (the Company) has as one of its highest priorities a desire to maintain and improve the quality and reliability of service to its customers. The Company commits that current levels of customer service and service reliability shall not degrade as a result of the merger and that it shall undertake all reasonable efforts to improve the quality and reliability of its service. In order to assure the Commission and Kentucky customers of continued excellent service quality in the post-merger environment, the Company commits and agrees to do the following: 1. To maintain the overall quality and reliability of its electric service at levels no less than it has achieved in the calendar years 1995-1998. The Company will provide service reliability reports annually indicating its calendar year Kentucky Customer Average Interruption Duration Index (CAIDI) and Kentucky System Average Interruption Frequency Index (SAIFI). These indices shall be determined and reported, including all storms. Definitions for these measures are included on page 3. On page 5 are listed Kentucky Power's annual SAIFI and CAIDI performance for the years 1995 through 1998. 2. To provide annual Call Center performance measures for those centers which handle Kentucky customer calls. These will include the Call Center Average Speed of Answer (ASA), Abandonment Rate, and Call Blockage. Definitions for these measures are also included on page 4. a) The performance measures described in paragraphs 1 and 2 above shall be provided by the end of May of the year following the calendar year in question. 3. Will continue to completely inspect its Kentucky electric facilities every two years and perform tree trimming, lightning arrest or replacement, animal guarding and pole and cross arm replacements. 4. AEP/Kentucky Power management will compile outage data detailing each circuit's reliability performance. In addition, by monitoring repeated outages on a regular basis, the Company will identify and resolve reliability problems which may go unnoticed by using CAIDI and SAIFI results. This data will be coupled with feedback from district field personnel and supervision and management concerning other locations and situations where the impact of outages are quantified. This process will be used to develop a comprehensive work plan each year which focuses efforts to improve service reliability. The Company will undertake all reasonable expenditures to achieve the goal of limiting customer outages. 5. Plans to continue to maintain a high quality workforce to meet its customers needs. 6. Shall designate an employee or agent within Kentucky who will act as a contact for retail consumers regarding service and reliability concerns and to provide a contact for retail consumers for information, questions and assistance. Such AEP/Kentucky Power representative shall be able to deal with billing, maintenance and service reliability issues. 37 AEP/KENTUCKY POWER SERVICE QUALITY Attachment C Page 2 of 5 a) The company further commits to maintain in Kentucky a sufficient management team to ensure that safe, reliable and efficient electric service is provided and to respond to the needs and inquiries of its Kentucky customers. 7. In the event the Commission adopts industry generic rules concerning customer service standards, AEP/Kentucky Power shall have at its option, the right to incorporate them into this agreement. a) AEP/Kentucky Power will have the opportunity to revisit with the Commission the agreed upon measure(s) should the Company wish to propose a specific performance-based ratemaking proposal provided the proposal either includes a reliability measure(s) and/or a customer satisfaction survey measure that contains service reliability as a component. b) These standards can be changed during the term of this agreement to reflect any performance-based ratemaking plans or rules which the Commission adopts either for AEP/Kentucky Power and/or generically for the electric utility industry. 8. If retail access is mandated by the Kentucky General Assembly and/or the Commission and/or by federal legislation, AEP/Kentucky Power shall have the right to petition the Commission for modifications to this service quality agreement that are made necessary by the mandating of retail access. a) Any such petition must establish the necessity of the proposed modifications and provide appropriate protections to ensure that AEP/Kentucky Power's quality of service will not decline. The Commission will act upon the petition within 90 days or the petition will be deemed to be automatically approved. 9. All prudent costs incurred to comply with the items contained in this Agreement, once incurred, will constitute known and measurable expenses that Kentucky Power shall have an opportunity to recover in accordance with traditional ratemaking principles, through recognition of these costs in its revenue requirement in future rate review. 2 38 AEP/KENTUCKY POWER SERVICE QUALITY Attachment C Page 3 of 5 AEP RELIABILITY MEASURES 1) System Average Interruption Frequency Index (SAIFI) is defined as the number of customers interrupted divided by the number of customers served. It is calculated by the equation: SAIFI= Number of customers interrupted ----------------------------------------------------------- Number of customers served 2) Customer Average Interruption Duration Index (CAIDI) is defined as the number of customer hours of interruption divided by the number of customers interrupted. It is calculated by the equation: CAIDI= Sum of all customer hours of interruption ----------------------------------------------------------- Number of customers interrupted 39 AEP/KENTUCKY POWER SERVICE QUALITY Attachment C Page 4 of 5 AEP CALL CENTER MEASURES 1) Average Speed of Answer (ASA) is defined as the average time that elapses in seconds between the instant when a call is answered and the time it is connected to a Call Center representative (CSR) or an interactive voice recorder (IVR). It is calculated using the equation: Average Speed of Answer = Time for all calls between call answer and (seconds) CSR/IVR connection ------------------------------------------- Total number of calls made to the Call Center 2) Abandonment Rate is the percentage of callers who hang up before being connected to a Call Center representative (CSR) or an interactive voice recorder (IVR). It is calculated using the equation: Abandonment Rate = {Total number of callers who hang up} (percent) ----------------------------------------------- x 100 {Total number of calls made to the Call Center} 3) Call Blockage is the percentage of non-outage call attempts which do not get connected to a Call Center (busy signal, etc.). It is calculated using the equation: Call Blockage = {Total number of non-outage calls that do not get connected} (percent) ------------------------------------------------------------ x 100 {Total number of non-outage calls made to the Call Center}
40 AEP/KENTUCKY POWER SERVICE QUALITY Attachment C Page 5 of 5 AEP/KENTUCKY POWER RELIABILITY PERFORMANCE (INCLUDES ALL STORMS)
Year SAIFI CAIDI ---- ----- ----- 1995 1.794 4.12 1996 1.530 3.10 1997 1.343 3.04 1998 1.519 5.96
41 EXHIBIT 1 ATTACHMENT D COMMONWEALTH OF KENTUCKY BEFORE THE PUBLIC SERVICE COMMISSION OF KENTUCKY IN THE MATTER OF: JOINT APPLICATION OF KENTUCKY POWER COMPANY, ) AMERICAN ELECTRIC POWER COMPANY, INC. ) AND CENTRAL AND SOUTH WEST CORPORATION ) CASE NO. 99-149 REGARDING A PROPOSED MERGER ) On February 17, 1999, the Staff of the Public Service Commission of Kentucky ("Commission") issued a letter stating staff's belief that the Commission has jurisdiction under KRS 278.020 (5) to review the proposed merger of Central and South West Corporation ("CSW") into American Electric Power Company, Inc. ("AEP") and requested that Kentucky Power Company ("Kentucky Power", "KPCO" or the "Company") advise in writing by March 8, 1999 of the date AEP would file an application for Commission approval of "the indirect change in control of Kentucky Power Company." On March 5, 1999 the Company issued a letter notifying the Commission that it would file the requested application by April 15, 1999. The letter also indicated that the Company expected to provide the Staff and the Commission with sufficient information to enable the Commission to approve its application within the sixty (60) day period prescribed by the statute. The letter further preserved the Company's legal arguments regarding the application of KRS 278.020 to this merger. On April 15, 1999, the Company, AEP and CSW filed a Joint Application with supporting testimony and work papers. The proceeding was designated P.S.C. Case No. 99-149. On April 22, 1999, the Commission issued a letter indicating that the Commission staff had reviewed the Company's application and found that it met the minimum filing requirements. 42 On May 4, 1999, the Attorney General, Office of the Rate Intervention ("Attorney General"), and Kentucky Electric Steel, Inc. ("KESI") were granted full intervention in Case No. 99-149. On May 11, 1999, Kentucky Industrial Utility Customers, Inc. ("KIUC"), was also granted full intervention in Case No. 99-149. These parties will be referred to herein collectively as the "Intervenors." On April 22, 1999, a Technical Conference was held at the Commission's offices. On May 4, 1999, May 11, 1999, May 17, 1999 and May 20, 1999 settlement conferences were held at the Commission's offices. All parties to the proceeding and the Commission staff were present and participated in the settlement conferences. Having considered the evidence and being duly advised, the Commission now finds: 1. Notice and Jurisdiction. Due and timely notice of the hearing to consider the settlement proposed by the parties was given. Kentucky Power is a "utility" within the meaning of that term in KRS 278.010(3)(a) and is subject to the jurisdiction of the Commission in the manner and to the extent provided by the laws of the Commonwealth of Kentucky. 2. The Settlement Agreement. As described in the Settlement Agreement, a copy of which is attached hereto as Exhibit A and incorporated herein by reference, the Settlement Agreement contains, among other things, provisions regarding (a) net non-fuel merger savings; (b) fuel and purchased power merger savings; (c) limitation on requests for stranded cost recovery; (d) allocation of proceeds from the sale of facilities; (e) system integration agreements; (f) Ohio Power waiver; (g) affiliate standards; (h) maintenance and enhancement of the adequacy and reliability of retail electric service, including certain reporting requirements; (i) settlement of the existing environmental surcharge litigation (Kentucky Court of Appeal Case No. 98-CA-00137, 98-CA-01344, 98-CA-01417, 98-CA-01455); and (j) settlement of the pending six month 2 43 review of KPCO's environmental surcharge in P.S.C. Case No. 98-624. The Settlement Agreement was agreed to by all parties to this proceeding. The Settlement Agreement further provides that if the proposed merger is ultimately consummated, AEP commits that upon issuance of any final and non-appealable order from any state or federal commission addressing the merger that provides benefits or imposes conditions on AEP that would benefit the ratepayers of any jurisdiction, such net benefits and conditions will be extended to all other retail customers to the extent necessary to achieve equivalent net benefits and conditions to all retail customers of AEP. The Settlement Agreement also provides that, upon approval by the Commission, the Intervenors, the Commission and its Staff shall not oppose the proposed merger before FERC or oppose AEP's previously made merger-related filings with the Securities and Exchange Commission. The Settlement Agreement further states that it shall not constitute nor be cited as precedent or deemed an admission by any party in any other proceeding except as necessary to enforce its terms before the Commission, or any State Court of competent jurisdiction on these particular issues. The Settlement Agreement provides that it is solely the result of compromise in the settlement process, shall not constitute a concession of subject matter jurisdiction, and except as expressly provided therein, is without prejudice to and shall not constitute a waiver of any position that any of the parties thereto may take with respect to any or all of the items resolved therein in any future regulatory or other proceedings. The Settlement Agreement states that if the Commission does not approve the Settlement Agreement in its entirety, it shall be null and void and deemed withdrawn, unless such change is approved by the parties. 3 44 At a hearing held May 28, 1999, Richard E. Munczinski, Senior Vice President-Corporate Planning and Budgeting of American Electric Power Service Corporation, the service corporation subsidiary of AEP, and Errol K. Wagner, Director of Regulatory Affairs for Kentucky Power testified in support of Commission approval of the Settlement Agreement. Mr. Munczinski discussed the negotiating process which resulted in the Settlement Agreement and the public benefits that would result from its approval. Mr. Wagner testified regarding the mechanism by which the bill reductions will be implemented by Kentucky Power. During the course of this proceeding information about the proposed merger was requested from and provided by Kentucky Power, AEP and CSW. Additional information about the proposed merger has since been developed in the course of FERC proceedings and proceedings before other state commissions. After lengthy and detailed negotiations, Kentucky Power, CSW, AEP, the Attorney General, Office for Rate Intervention, Kentucky Industrial Consumers, Inc. and Kentucky Electric Steel have reached a unanimous agreement on terms and conditions that help ensure that Kentucky consumers will fairly share in the benefits achieved by the merger and that Kentucky consumers will be protected against any detrimental effects. The Parties recommend that the Commission approve the Settlement Agreement as a fair and just settlement of differences regarding merger-related issues. Having reviewed the Settlement Agreement and the evidence relating thereto, the Commission finds that the recommendation of the Parties should be approved. The Commission further finds that the Settlement Agreement is a fair and reasonable resolution of the merger-related issues of concern to the Commission and the Intervenors and should be approved in its entirety without modification. 4 45 The Commission finds that AEP and Kentucky Power have and will retain the financial, technical and managerial abilities to provide reasonable service. The Commission further finds that the proposed merger of AEP and CSW is in accordance with the law, for a proper purpose and is consistent with the public interest. IT IS THEREFORE ORDERED BY THE PUBLIC SERVICE COMMISSION OF KENTUCKY that: 1. The Settlement Agreement shall be and hereby is approved in its entirely without modification and that the merger of AEP and CSW is approved pursuant to KRS 278.020(4) and KRS 278.020(5). 2. Kentucky Power shall implement the Net Merger Savings Credit Tariff in the amounts shown in the tariff filed as Exhibit 2 to this Order, which tariff is approved. 3. American Electric Power, Inc. and Central and South West Corporation will incur transaction, regulatory processing and transition costs to merge the two companies. The Commission orders that the Kentucky retail jurisdictional share of the estimated merger costs be deferred and amortized for recovery over eight years. The amortization should begin with the date of the combination and continue for eight years on a straight-line basis. 4. The proposed regulatory plan is approved as are the steps necessary to implement it, specifically: a. the regulatory treatment of the fuel saving arising from the integrated operations of AEP, CSW and Kentucky Power as set forth in the Settlement Agreement; b. Kentucky Power is authorized to include as an allowable expense in cost of service the non-fuel merger savings, net of cost to achieve and amortization of estimated costs to achieve as set forth in Attachment B to the Settlement Agreement. 5 46 5. Effective January 1, 2000, KPCO shall begin collecting the environmental surcharge, including the costs of the Low Nox burners for the Big Sandy generating plant's Unit No. 1 and Unit No. 2, in accordance with the Opinion and Order of the Franklin Circuit Court dated April 30, 1998, as amended by Opinion and Order dated May 14, 1998 in Consolidated Case Nos. 97-CI-00137, 97-CI-01138, 97-CI-01144 (except those portions of the decisions allowing retroactive recovery of the surcharge). 6. The Commission approves the settlement of the environmental surcharge litigation (Kentucky Court of Appeals Case Nos. 98-CA-00137, 98-CA-01344, 98-CA-01417, 98-CA-01455 and 98 CA 002476) as described in the Settlement Agreement and authorizes its counsel to execute the necessary documents to dismiss the appeals and cross-appeals therein. 7. The pending review of KPCO's environmental surcharge in P.S.C. Case No. 98-624 shall be terminated and that proceeding is ordered closed without adjustment to the surcharge. 8. This Order shall be effective on and after the date of its approval. ______________________ By the Commission 6 47 EXHIBIT 1 STIPULATION AND SETTLEMENT AGREEMENT 48 EXHIBIT 2 AMERICAN ELECTRIC POWER ORIGINAL SHEET NO. 25-1 CANCELING________ SHEET NO.____________ P.S.C. ELECTRIC NO. 7 NET MERGER SAVINGS CREDIT (N.M.S.C.) APPLICABLE To Tariffs R.S, R.S.-L.M.-T.O.D., Experimental R.S.-T.O.D., S.G.S., M.G.S., Experimental M.G.S.-T.O.D., L.G.S. Q.P., C.I.P., T.O.D., C.S.-I.R.P., M.W., O.L. and S.L. RATE The Net Merger Savings Credit shall provide for a monthly adjustment to base rates on a rate per kWH of monthly consumption. The Net Merger Savings Credit shall be calculated according to the following formula: Net Merger Savings Credit = M.S.F. - B.A.F. Where (M.S.F.) is the Merger Savings Factor per KWH which is based on the total Company net savings that are to be distributed to the Company's Kentucky retail jurisdictional customers in each 12 month period.
Net Savings Merger Savings to be Factor Distributed (M.S.F.) ----------- -------- Year 1* $1,463,815 .021(cent)per Kwh Year 2 2,553,660 .037(cent)per Kwh Year 3 3,184,645 .045(cent)per Kwh Year 4 3,695,003 .051(cent)per Kwh Year 5 4,037,167 .055(cent)per Kwh Year 6 4,229,432 .057(cent)per Kwh Year 7 4,504,920 .059(cent)per Kwh Year 8 4,626,369 .059(cent)per Kwh Year 9 5,242,785 .066(cent)per Kwh
* The Net Merger Savings Credit will begin in the first full billing month available following thirty days from the consummation of the merger and will continue until the effective date of a Commission order changing the Company's base rates after Year 8 of this tariff. (B.A.F.) is the Balancing Adjustment Factor per KW for the second through the twelfth months of the current distribution year which reconciles any over- or under-distribution of the net savings from prior periods. The B.A.F. will be determined by dividing the difference between amounts which were expected to be distributed and the amounts actually distributed from the application of the Net Merger Savings Credit from the previous year by the expected Kentucky retail jurisdictional KWH. The final B.A.F. will be applied to customer billings in the second month following the effective date of a Commission order changing the Company's base rates after Year 8 of this tariff. TERMS OF DISTRIBUTION 1. The total distribution to the Company's customers will, in no case, be less than the sum of the amounts shown for the first eight years above. 2. On or before the 21st of the first month of each distribution year following Year 1, the Company will file with the Commission a status report of the Net Merger Savings Credit. Such report shall include a statement showing the amounts which were expected to be distributed and the amounts actually distributed in previous periods, along with a calculation of the B.A.F. which will be implemented with customer billings in the second month of that distribution year to reconcile any previous over- or under-distributions. 3. The Net Merger Savings Credit shall be applied to the customer's bill following the rates and charges for electric service, but before application of the school tax, the franchise fee, sales tax or similar items. DATE OF ISSUE:_____________ DATE EFFECTIVE __________________________________ ISSUED BY: E.K. WAGNER ______ DIRECTOR OF REGULATORY AFFAIRS ASHLAND, KENTUCKY EX-99.D.8.1 9 ORDER OF IN APPROVING THE MERGER 1 Exhibit D-8.1 STATE OF INDIANA INDIANA UTILITY REGULATORY COMMISSION IN THE MATTER OF THE INVESTIGATION ) ON THE COMMISSION'S OWN MOTION ) INTO ANY AND ALL MATTERS RELATING ) CAUSE NO. 41210 TO THE MERGER OF AMERICAN ) ELECTRICAL POWER, INC., AND CENTRAL ) APPROVED: AND SOUTH WEST CORPORATION ) APR 26, 1999 BY THE COMMISSION: Camie J. Swanson-Hull, Commissioner David E. Ziegner, Commissioner Claudia J. Earls, Administrative Law Judge On June 29, 1998, the Commission on its own motion indicated an investigation regarding the proposed merger of American Electric Power Company, Inc. ("AEP") and Central and South West Corporation ("CSW"). AEP is the parent company of Indiana Michigan Power Company ("I&M") which provides electric utility service in the State of Indiana. The Order noted that AEP and CSW had filed an application with the Federal Energy Regulatory Commission ("FERC") for approval of the merger under Section 203 of the Federal Power Act. Petitions to intervene in this matter were filed by the Citizens Action Coalition of Indiana, Inc. ("CAC"), Indiana Consumers For Fair Utility Rates (an ad hoc group of industrial companies) ("ICFUR"), PSI Energy, Inc. ("PSI") and Steel Dynamics, Inc.(1) These petitions were granted and these entities were made parties to this proceeding. The Office of Utility Consumer Counselor ("OUCC") also participated in this proceeding. After receiving written comments of the parties on certain issues relating to the proposed merger and after holding a preliminary hearing on August 4, 1998, the Commissioner on September 2, 1998, issued an Order appointing a negotiating team of members of the Commission Staff (the "Staff Negotiating Team") to attempt to negotiate a settlement of the issues present in this matter. By docket entries, I&M was directed to respond to various data requests seeking information about the proposed merger and to provide to the Commission, the Staff Negotiating Team and the other parties certain documents relating thereto. I&M responded to the requests by providing voluminous information and documents. During the course of this proceeding, status hearings were held at which time the Staff Negotiating Team submitted reports regarding the process of negotiations. On April 9, 1999, I&M and the Staff Negotiating Team submitted to the Commission and - ------------------------- (1) SDI subsequently withdrew from the proceeding. 2 recommended for approval a Stipulation and Settlement Agreement (the "Settlement Agreement") executed by I&M, AEP and the Staff Negotiating Team. On April 14, 1999, the parties to the Settlement Agreement prefiled with the Commission prepared testimony and evidence in support of the Settlement Agreement. A public evidentiary hearing on the Settlement Agreement was held on April 19, 1999, at 10:00 a.m. in Room TC10 of the Indiana Government Center South, Indianapolis, Indiana. At that time, the Settlement Agreement and evidence relating thereto were accepted into the record. Based upon the applicable law and evidence herein, the Commission now finds: (1) NOTICE AND JURISDICTION. Due legal and timely notice of the settlement hearing was given and published as required by law. I&M is a "public utility" within the meaning of that term in IC 8-1-2-1 and is subject to the jurisdiction of the Commission in the manner and to the extent provided by the laws of the State of Indiana. At the conclusion of the evidentiary hearing held in this cause, CAC stated three bases for this Commission to determine that it did not have the authority to approve the tendered Settlement Agreement. On April 19, 1999, CAC filed a "Motion for Ruling in the Nature of a Judgment on the Evidence." The three arguments raised by CAC are as follows: (1) The Commission lacks subject matter jurisdiction to approve the "Regulatory Plan" proposed in the Settlement Agreement. (2) The Commission lacks jurisdiction to approve the "Regulatory Plan" because I&M's customers have not received adequate notice that their future rates could be adjudicated in this proceeding. (3) Even if the Commission has the general subject matter jurisdiction and jurisdiction in this particular case to approve the proposed "Regulatory Plan," the rate-making treatment proposed in the Plan is contrary to law. On April 21, 1999, I&M filed its response. We will first discuss CAC's arguments regarding the notice given to the public in this cause and then address the arguments regarding the Commission's authority to grant the relief requested in the Settlement Agreement. a. Notice of the scope of the proceeding. CAC contends that customers did not receive adequate notice that future rates could be adjudicated in this proceeding. Specifically, CAC argues that there is no reference to "rates" in the public notice provided in this cause and secondly, that even the active parties to this proceeding understood that the intended purpose of the Commission investigation was to gather information for the purposes of formulation of the Commission's position before the Federal Energy Regulatory Commission, not to adjudicate issues as the regulator of I&M's retail rates and charges. Indiana law clearly states that the IURC must have flexibility in determining the appropriate content of public notices. "The complexity and varied nature of regulatory 2 3 proceedings militate against the adoption of a more particularistic notice standard; the Commission's Rule 8(b) provides the flexibility necessary for case-by-case determinations of the appropriate content of the public notice to be published." City of Evansville v. Southern Ind. Gas & Elec. Co., 339 N.E.2d 562, 578 (Ind. Ct. App. 1975). Our administrative code requires the caption of a petition to describe in general terms all the relief being sought in the petition, 170 IAC 1-1-8(b) (emphasis added). In this proceeding, customers were given notice that "any and all matters relating to the merger" were subject to the investigation. This broad notice certainly contemplates that issues including but not limited to merger savings, merger cost allocation, and impact on jurisdictional customers of the merged utility would be considered. We find that the public notice issued in this proceeding was sufficient to notify customers that the investigation may reach the issue of rate treatment. We also note that, even where a public utility makes a complaint as to any matter affecting its own rates or service, only reasonable notice is required, and there is no necessity for specific public notice of all regulatory issues whose ultimate resolution might independently affect an increase in a utility's rates. See, e.g., City of Evansville v. Southern Ind. Gas & Electric Co., 339 N.E.2d 562, 578-579. The notice provided in this case stated that this was a Commission investigation. Under the Commission's investigatory powers, the Commission has the power and authority to issue orders consistent with its broad grant of power from the legislature which is necessary to effectuate the regulatory scheme. See, N. Ind. Pub. Serv. V. Citizens act. Coal., 548 N.E.2d 153 (Ind. 1989). In its "Memorandum of Law in Support of Motion for Ruling in the Nature of Judgment on the Evidence," CAC argues that "even the active parties to this proceeding understood that the intended purpose of the Commission investigation was to gather information...." p.7. The Commission's September 2, 1998 Order provided notice to the parties that the Commission was moving from an informal investigation pursuant to IC 8-1-2-58 to a formal adjudication pursuant to IC 8-1-2-59. The Commission had previously described the issues before it to include "how the risks, costs and benefits of the merger should be shared among the stockholders and the customers, both wholesale and retail, of AEP." Order, June 29, 1998, Exhibit A, p.4, Item 4. CAC participates in the process. As Staff witness Glazier stated at the hearing held in this Cause, "We are negotiating on behalf of the almost six million people who we work for, Mr. Muller. And as you know, you were part of the negotiation discussions." To have participated in the settlement negotiations and then allege that the parties were unaware of the scope of the proceedings is puzzling to the Commission. CAC also makes mention of the fact that I&M did not provide notice to its customers of the potential rate impact of the Commission's investigation. Yet, nowhere in its legal memorandum does CAC cite any authority that confers upon I&M an affirmative duty to provide such notice. In addition, the Commission would note that CAC has waived any such challenge to our jurisdiction. As the Indiana Supreme Court found in City of New Haven v. Indiana Suburban Sewers, Inc., (1972) 277 N.E.2d 361: If the notice prescribed is prerequisite to jurisdiction of the subject matter of the proceedings, the rule is otherwise, as the right to challenge such jurisdiction can never be lost or waived. Appellant has correctly stated such rule and supported it with good authority, but we believe the 3 4 question here is not one of jurisdiction over the subject matter of the proceedings. Such jurisdiction was established when notice of the time and place of public hearing was given more than ten (10) days prior to the date set for the hearing as prescribed by the statue, Indiana Acts 1957, ch. 313, Section 2, 1969 Supp. Burns Ind. Stat. Ann. Section 54-601c,IC 1971, 8-1-289. Having been thusly established, such jurisdiction continued throughout the proceedings, including the rehearing, and we believe that the ends of justice would not be served by faulting proceedings by reason of a defect in the form of notice, if such defect did in fact exist, when the complaining party attended and participated therein. Clearly the notice which Appellant insists should have been given would not have benefited it and its omission did it no harm. Id., at p. 362-3. CAC also argues that it did not have full rights of discovery. It never raised this concern throughout the investigation. All parties were invited to submit proposed discovery requests to the Commission. The Commission then issued data requests akin to discovery requests including data requests propounded by CAC. At no time did CAC object in this procedure. On November 30, 1998, the Commission issued a docket entry stating that it had reviewed AEP's responses to its data requests, and giving all parties an opportunity to submit additional data requests to the Commission for consideration. CAC provided no new data requests. In addition, CAC is a party to the FERC action and was a party to the FAC 40 S i subdocket before this Commission. CAC has had available to it all discovery processes in both of those proceedings. This argument appears as devoid of merit as the argument that CAC was without notice of the scope of the proceeding. Having considered the arguments of the parties the Commission finds that the public received proper notice of the proceedings held in this Cause and that the Commission has complied with the applicable authority regarding the procedural conduct of this proceeding. b. Commission's Jurisdiction to grant the requested relief. Throughout CAC's "Memorandum" it argues that I&M is "recovering through rates" shareholder savings. CAC's argument is misguided. I&M has agreed in the Settlement Agreement to pass through 55% of the net merger savings immediately and automatically upon consummation of the merger. Without this agreement, I&M could have maintained its existing rates until either it successfully petitioned the Commission for a change in its base rates or the Commission initiated either on its own or at the request of another party and concluded an investigation into the reasonableness of I&M's base rates. CAC also argues that the Settlement Agreement's allowances of the referral and amortization over the eight-year period of the merger costs is allowing the inclusion in customer rates of expenses based upon contingencies that have not yet occurred. To support its proposition, CAC cites Citizens Action Coalition v. Public Serv. Co. (Ind. 4 5 App. 1993) 612 N.E. 2d 199, 201. That case is readily distinguishable from this case insomuch as that case dealt with the Commission's speculation regarding the probability of passage of acid rain legislation. In the instant case, the contingent event is the consummation of the merger. If there is no merger, there is no effect of the Settlement Agreement. In this case, there is no speculation. If the merger occurs, I&M is allowed to amortize the expenses associated with the merger. If the merger does not occur, there will be no allocation of those expenses and no rate impact. To adopt CAC's position would be to call into question every municipal rate order this Commission has issued in the recent past which allows for an increase in rates premised upon an increase in debt service in anticipation of the issuance of bonds to fund a capital improvement project. Generally the bonds have not been issued when the municipality petitions for rate relief. Thus, the Commission in granting the rate relief is premising the relief on the issuance of the bonds, a future contingency. Orders on proposed but unconsummated transactions have occurred in the merger and/or take-over context as well. For example, in our order in Cause No. 37962, issued May 29, 1986, in a case involving the acquisition of the Zionsville waterworks system by Zionsville Water Corporation, a subsidiary of Indianapolis Water Company, the Commission approved the accounting methodology to be utilized upon consummation of the transaction for the recording of the purchase, including an acquisition adjustment. The transaction had not been consummated, and yet the accounting treatment was approved. In addition, the Commission approved the amortization of the acquisition adjustment as an "above-the-line" operating expense recoverable through rates. Order, p.19. The Commission noted that such treatment was consistent with a previous order involving Indiana Cities Water Corporation, Cause No. 37579, Order issued June 12, 1985. In addition, in several cases, future rate-making treatments were approved in advance of the closing of the transaction, and in many of the cases, pre-approval of the rate-making treatment was a condition for closing. See e.g., Indianapolis Gas Co. and Westport Net Gas Corp., Cause No. 38302 issued January 20, 1988; West Lafayette Water CO. and Green Meadows Util., Cause Nos. 39417, 38902 and 39166-U issued September 23, 1962; and Indiana American Water Co. and Farmington Utilities, Inc., Cause No. 40442, issued October 2, 1996. The final argument that CAC presents against the Settlement Agreement is that it attempts to "bind" future Commissions with respect to various expenses. As Indiana courts have stated on numerous occasions, the rate-making process is a legislative not an adjudicatory process. See, e.g. Office of Utility Consumer Counselor v. Public Service Company, 463 N.E.2d 499 (Ind. App. 3 Dist. 1984). There is no precedent set in one case for use in a subsequent case. Res judicata principles apply when an administrative agency acts in a judicial capacity, but do not apply when the agency acts in a legislative capacity. See, Indiana Gas v. Utility Consumer Counselor, 610 N.E.2d 865 (Ind. App. 5 Dist. 1993). In this case, the Settlement Agreement requests that the Commission allow I&M to book certain expenditures. In any rate proceeding, the Commission is allowed to presume a utility's costs are prudently incurred. See, Anaheim v. Federal Energy Regulatory Commission, (D.C. Circuit, 1981) 669 F.2d 799). However, where a participant in a proceeding creates a doubt as to the reasonableness of the expenditure, the burden of dispelling these doubts and of proving the questioned expenditure falls to the utility. Id. Obviously, if the Commission approves the Settlement Agreement and I&M is allowed to book certain expenditures, any party to any subsequent proceeding may question the reasonableness of any such expenses. CAC argues that by adopting our Staff's recommendation to approve the Settlement Agreement, the Commission will be 5 6 mystically transformed into a proponent of the accounting treatment afforded the expenditures in any subsequent rate proceeding. The adoption of a Staff recommendation, however, does not transform the Commission into a proponent. As the Appellate Court held in Board of Directors for Utilities v. Office of Util. Consumer Counselor. The statute does not limit the use of these reports by the Commission and to the extent that they become a part of the record and their contents may be utilized by the Commission, they are evidence. Reliance on the reports does not automatically transform the Commission into a proponent or opponent in the proceedings. To hold otherwise would place I.C. 8-1-1-5(a) in direct conflict with subsection (b), an illogical result clearly not intended by the legislature. . . . The reports are merely an additional tool to aid the assimilation of factually complex and technical information. c. Conclusion. Having considered the arguments raised by CAC, the Commission finds that due, legal and proper notice of this proceeding was given as provided by law and that this Commission has jurisdiction over Petitioner and the subject matter of this cause and has authority to approve the Settlement Agreement if it is found o be in the public interest. (4) PROVISIONS OF THE SETTLEMENT AGREEMENT. As described in the Settlement Agreement, a copy of which is attached hereto as Exhibit A, and incorporated herein by reference, the Settlement Agreement contains, among other things: (a) net non-fuel merger savings; (b) fuel and purchase power merger savings; (c) limitation on requests for stranded cost recover; (d) allocation of proceeds from the sale of facilities; (e) system integration agreements; (f) Ohio Power waiver; (g) regional transmission organization commitments; (h) affiliate standards; and (i) maintenance and enhancement of the adequacy and reliability of retail electric service, including certain reporting requirements. The Settlement Agreement further provides that if any other state commission or any federal commission issues a final and non-appealable order addressing the merger that provides benefits or imposes conditions that would benefit ratepayers of another jurisdiction, AEP will extend equivalent net benefits and conditions to all AEP retail customers. The Settlement Agreement also provides that, upon approval by the Commission, neither the Commission nor its Staff shall oppose the proposed merger before FERC or oppose AEP's previously made merger-related filings with the Securities and Exchange Commission. The Settlement Agreement also states that it shall not constitute nor be cited as precedent or deemed an admission by any party in any other proceeding except as 6 7 necessary to enforce its terms before the Commission, or any State Court of competent jurisdiction on these particular issues. The Settlement Agreement provides that it is solely the result of compromise in the settlement process, shall not constitute a concession of subject matter jurisdiction, and except as expressly provided therein, is without prejudice to and shall not constitute a waiver of any position that any of the parties thereto may take with respect to any or all of the items resolved therein in any future regulatory or other proceedings. The Settlement Agreement states that if the Commission does not approve the Settlement Agreement in its entirety, it shall be null and void and deemed withdrawn, unless such change is approved by the parties. However, the Settlement Agreement does provide the Commission with the authority to address matters ancillary or incidental to the agreement. At the settlement hearing, Robert C. Glazier, Director of Utilities for the Indiana Utility Regulatory Commission, Richard E. Munczinski, Senior Vice President-Corporate Planning and Budgeting of American Electric Power Service Corporation, the service corporation subsidiary of AEP, and Kent D. Curry, Director of Regulatory Affairs for I&M, testified in support of Commission approval of the Settlement Agreement. Mr. Glazier and Mr. Munczinski discussed the negotiating process which resulted in the Settlement Agreement and the benefits that they believe would result from its approval. Mr. Curry testified regarding the mechanism by which the bill reductions would be implemented by I&M. (5) COMMISSION FINDINGS. In our Order dated June 29, 1998, the Commission stated this investigation was commenced because the Commission believed that the proposed merger of AEP and CSW could have significant impact on the electric industry and customers in Indiana and across the region and the Commission was concerned about the proposed merger's effect on reliability of service and the development of independent system operators. During the course of this proceeding considerable information about the proposed merger was requested from and provided by I&M. Additional information about the proposed merger has been developed in the course of FERC proceedings and proceedings before other state commissions. After lengthy and detailed negotiations, I&M, AEP and the Staff Negotiating Team have reached agreement on terms and conditions which they allege will help ensure that Indiana consumers will fairly share in the benefits achieved by the merger and that Indiana consumers will be protected against any detrimental effects arising from the merger. The Staff Negotiating Team recommended that the Commission approve the Settlement Agreement as a fair and just settlement of differences regarding merger-related issues. At the hearing held in this cause, various parties expressed concern regarding various aspects of the Settlement Agreement. Those concerns included: (a) the mechanism for sharing of non-fuel merger savings; (b) the accounting methodology to be used to allocate the merger costs and projected savings; (c) the mechanism for the pass-through of fuel merger savings; (d) the assurances in the Settlement Agreement that AEP will join a Regional Transmission Organization ("RTO"); (e) the affiliated standards; (f) the adequacy and reliability of AEP's electric service; and (g) the public interest issues raised by the proposed merger. 7 8 The Commission will address each of these concerns individually. (a) Non-fuel merger savings tracker mechanism. CAC raised a concern regarding the implementation of the Regulatory Plan, contained in the Settlement Agreement and explained in more detail in the pre-filed testimony of AEP Witness Curry. This Plan is used to pass certain non-fuel merger savings on to the ratepayers of AEP. The procedural mechanism proposed to be used by AEP in this Commission's 30-day filing procedure, an administrative procedure routinely used to "track" expenses or savings back to the ratepayer. We note that as the 30-day filing procedure is an informal process, it may need some enhancement to alleviate some of the concern raised by CAC. We therefore find that in addition to complying with the normal 30-day filing procedure, each filing made to track the non-fuel merger savings should be accompanied by a verified statement indicating that the facts contained in the filing are true to the best of AEP's knowledge and that a copy of the 30-day filing has been served on each party to this Cause. Our 30-day filing process includes an option for the Commission to deny approval of any filing. The proponent of the filing may then petition the Commission for approval of the requested relief at which time the Commission would set any request for hearing. Nothing in this Order should be read to preclude any party from objecting to any future 30-day filings by AEP. With these safeguards, the Commission finds that the rider mechanism is acceptable to implement the sharing of the non-fuel merger savings. (b) Accounting Methodology. As discussed in Finding No. 1(b) hereinabove, the Settlement Agreement contemplates the Commission issuing an Order in this cause approving the proposed accounting treatment of the merger expenses and merger savings. Mr. Munczinski testified that the merger expenses are currently accruing on the parents' books and that upon consummation of the merger, the costs will be allocated to the operating companies' books. Pursuant to the terms of the Settlement Agreement, these costs are to be included in AEP's future FAC proceedings for purposes of determining whether I&M has complied with the "earnings test" contained in I.C. 8-1-2-42(d)(3)("d(3) test") In addition, for purposes of the return allowed in the d(3) test, the portion of merger savings allocated to shareholders will be utilized in essence to increase the allowable return. The Commission notes that these provisions will be of no consequence unless at some point in the future, I&M is otherwise earning in excess of its allowable return in a future FAC proceeding. In addition, the same treatment is to be utilized should I&M file a base rate case. Pursuant to the terms of the Settlement Agreement I&M may not file a base rate case with an effective date prior to January 1, 2005. Considering the probability of either of these events occurring, and consistent with the Commission's reasoning in Finding 1(b) hereinabove, the Commission finds that the accounting methodology contained in the Settlement Agreement should be approved. (c) Fuel Energy Savings Reflected Through the FAC (Fuel Adjustments Clause). The Settlement Agreement states that fuel savings will be passed through the fuel adjustment clause proceeding. In each future quarterly FAC filing, AEP is to calculate the difference between the fixed fuel rate (9.2 mills per kWh) found in the Stipulation and Settlement Agreement in Cause No. 38702-FAC40-S1 and the actual incurred fuel cost, in mills. If the weighted average of actual fuel costs are less than the 8 9 fixed fuel costs during the period of April 1, 1999 through December 31, 2003, then that difference will be credited to customers, based on total kWh consumed, as soon as possible after December 31, 2003. In this way, the fuel savings will be passed along to the consumers upon the reconciliation contemplated in the FAC 40 S, 1 Order. (d) Regional Transmission Organization. The Indiana Utility Regulatory Commission has consistently advocated the establishment of Regional Transmission Operators (RTOs), such as Independent System Operators (ISOs), as a means of mitigating the inherent market power of transmission owners and to foster a more efficient and competitive wholesale power market. The mitigation of market power by AEP's membership in an RTO is exceedingly important. To mitigate market power concerns and achieve greater reliability and economic efficiency, the IURC has been supportive of efforts to form RTOs. While we have been supporters of the Midwest Independent System Operator (MISO), we have urged the FERC to make modifications to the MISO including, among other things, to: (1) Establish Power Exchanges (PXs) that would either be (a) separate organizations that coordinated with the RTO, or (b) a part of the RTO; (2) vest the RTO with considerable authority over more of the traditional control area responsibilities; (3) ensure that coordination among RTOs, including pricing of services and information protocols, are as efficient as possible. While the IURC recognizes many positive aspects of the MISO, the IURC, in this cause as articulated by Staff Witness Glazier and in Commission statements to the FERC, continues to express its concern that more progress is needed to ensure independence, reliability and economic efficiency. One of the most immediate concerns is the need to require participation of all transmission owners in an RTO. To this end, the IURC has urged the FERC to use its authority under the Federal Power Act (FPA) to mandate the participation of all transmission owning utilities in an RTO. The IURC has also urged the FERC to allow a certain amount of time for the industry to establish appropriate boundaries for RTOs. If the industry can not agree on the appropriate boundaries for any given RTO by a date certain, the IURC has suggested the FERC use its authority to draw those boundaries. In previous testimony before the FERC and in this instant case, AEP's position has been very similar to that espoused by the IURC. By way of example, both AEP and the IURC have recognized the need for power exchanges. AEP has suggested that RTOs assume greater authority over many traditional control area responsibilities. AEP has also been a forceful advocate for large regional RTOs. Counsel Ronald Brothers, on behalf of intervenor CINergy in this cause, sought to clarify the reasons for AEP's unwillingness to join the MISO. During the course of the cross-examination, it became clear to the IURC that AEP and CINergy are in agreement in many many respects. It does not seem that the areas of disagreement are 9 10 insurmountable. By way of example, both CINergy and AEP agree that RTOs should be as large as possible to provide greater reliability and efficiency. In this regard, they both agree that an RTO could be as large as the entire eastern interconnection. CINergy and AEP agree that gaps in the membership pose significant problems. CINergy and AEP also both profess a sense of urgency. It is against this backdrop that the IURC has evaluated this Settlement Agreement. Certainly, getting AEP to commit to joining an RTO is a major accomplishment and AEP and other parties should be commended for their strides in this regard. The IURC will be assertive before the FERC to ensure that AEP joins an RTO and, to the maximum extent possible, that the RTO satisfies the conditions espoused by the IURC. The IURC is satisfied that nothing in this agreement prevents the IURC from advocating these concerns to the FERC, or advocating these positions in any other forum, or assisting the parties in bridging the remaining differences. (e) Affiliate Standards. Paragraph 8 of the Stipulation and Settlement Agreement provides for Affiliate Standards between the regulated and non-regulated affiliates of the merged company. Specific provisions of the Affiliate Standards include: (1) Principles for preventing cross-subsidization and/or cost shifting among the regulated and non-regulated affiliates and among the various regulatory jurisdictions in which the merged company will operate. (2) Guaranteed Commission access to employees, officers, books and records of any affiliate of the jurisdictional AEP operating company. (3) An AEP operating company shall not allow a non-utility affiliate to obtain credit under any arrangement that would permit a creditor, upon default, to have recourse to the operating company's assets. (4) Any untariffed, non-utility service provided by an AEP operating company or affiliated service company to any affiliate shall be itemized in a billing statement pursuant to a written contract or written agreement. Contracts between the AEP operating company and non-utility affiliates must be filed with the Commission. (5) The clear division of AEP operating company personnel, facilities and information from affiliated non-regulated wholesale generating or marketing personnel, facilities and information. (6) AEP will designate an employee who will act as a contact for the State Commission and consumer advocates seeking data and information regarding affiliate transactions and personnel transfers. (7) AEP will designate an employee who will act as a contact for retail consumers for information, questions and assistance. (8) AEP will inform the State Commission at least thirty days before making a filing at the FERC or SEC. (9) Violations of the provisions of the Affiliate Standards are subject to the enforcement powers and penalties at the State Commissions. (10) AEP will contact with an independent auditor who will conduct biennial audits for eight years after merger consummation of affiliated transactions to determine compliance with these affiliate standards. The results of such audits will be filed with the State Commissions. Prior to the initial audit, AEP will conduct an 10 11 informational meeting with State Commissions regarding how its affiliates and affiliate transactions will have changed as a result of the proposed merger. (11) If the Public Utility Holding Company Act of 1935 ("PUHCA") is repealed or materially amended during the time this agreement is in effect and equivalent jurisdiction is not given to another federal agency, AEP will work with the State Commissions to ensure that AEP continues to furnish the State Commission with the appropriate information to regulate its jurisdictional AEP operating company. During the Commission hearing AEP witness Richard E. Munczinski and Staff Negotiating Team witness Robert C. Glazier were questioned on the various provisions of the Affiliate Standards. Both witnesses were asked why the definition of affiliate in the Stipulation and Settlement Agreement differed from the definition contained in I.C. 8-1-2-49. Both witnesses responded that the difference was unintentional and not designed to circumvent any Commission rule or standard. Mr. Munczinski was asked a number of questions during the hearing designed to clarify various provisions of the Affiliate Standards section of the Stipulation and Settlement Agreement. Subsection A3 of the Affiliate Standards addresses the recovery of just and reasonable costs from the various regulatory jurisdictions. Mr. Munczinski explained that this provision protected AEP from just and reasonable costs being left unallocated or stranded. Mr. Munczinski testified that these costs would include "particularly those [costs] that apply to affiliated transactions, so that the parties have agreed that what should be included in the cost of service would be those affiliated transaction costs that meet the guidelines that are in this agreement, that the company should be made whole. . ." In return, AEP pledges that no more than one hundred percent of the cost will be allocated on an aggregate basis to the various regulatory jurisdictions. Further, Mr. Munczinski committed that if a State Commission failed to allow the recovery of just and reasonable affiliated transaction costs, AEP would not seek recovery of those stranded costs from other jurisdictions. Counsel for CAC questioned Mr. Munczinski on the terms and requirements of the independent audit addressed in Section V of the Affiliate Standards. Mr. Munczinski explained that the audit would be designed to test each provision of the Affiliate Standards to ensure AEP compliance. Further, that prior to the initial audit, AEP would conduct informational meetings with the affected State Commission to allow them to input on the audit requirements. AEP also pledged to file an audit plan with each State Commission prior to the commencement of the independent audit. Questions from the bench regarding Section W of the Affiliate Standards clarified that if PUCHA were repealed, AEP would continue to meet all appropriate reporting requirements. AEP committed to work with the State Commissions to determine what information would be reported to the Commission, including an allocation of jurisdictional costs. Mr. Munczinski assured the Commission that it was not AEP's intention to circumvent any Commission laws or requirements upon the repeal of PUCHA. Having reviewed the Affiliated Standards the Commission finds that they are reasonable and should provide more protection to AEP's Indiana customers than the current state of regulation. AEP should be advised that in determining an "affiliate" it 11 12 should use the definition contained in Indiana Code. AEP should also file an audit plan with the Commission five days prior to commencing the independent audit. (f) Reliability of Service. This Commission is very concerned that the reliability, quality and adequacy of electric service provided by AEP not deteriorate as a result of this merger. The Settlement Agreement addresses these concerns on page 11, rhetorical paragraph 9 and through the reporting requirements contained in Attachment C to the Settlement Agreement. The reporting requirements consist of annual reports on two reliability measures, known as SAIFI (System Average Interruption Frequency Index) and CAIDI (Customer Average Interruption Duration Index), and three call center measures, delineated as Average Speed of Answer, Abandonment Rate, and Call Blockage. These reports are to be provided to the IURC by the end of May for the preceding calendar year. These reports will provide an indication of AEP's ongoing reliability, quality and adequacy of electric service. This Commission was troubled by the lack of quantification of any benchmark against which to assess these measures to see if reliability, quality and adequacy of electric service is being maintained or enhanced. Attachment C of the Settlement Agreement indicated only that "Indiana Michigan Power will maintain the overall quality and reliability of its electric service at levels no less than it has achieved in the past decade." Responding to questions from the bench, both AEP witnesses Munczinski and Curry testified that AEP would be willing to file with the Commission the historical reliability and call center measures, in a form essentially similar to that contained in Attachment C for the last ten years, provided that such data exists. We find that AEP shall file all such historical data that exists with the Commission's Engineering Division within ninety (90) days of the date of this October. (g) Public Interest. The theory of law creating the Commission is that "it shall be conscientiously and impartially administered by a body composed of a personnel especially qualified by knowledge, training and experience pertaining to the subject-matter committed to it . . . consonant with reasonable fairness and substantial justice according to legislative mandate, and the circumstances shown relative to its effect in the future on the utility's ability to serve the interest and convenience of the public, the cost and expense to the parties interested being an element for consideration." In re Northwestern Indiana Tel. Co., 201 Ind. 667 (1929), at p. 674-5. When asked by counsel for CAC for a definition of "public interest," Staff witness Glazier stated that it was the balancing of the interests of economic development, employment and the effectiveness of regulation. Case law has stated that the Commission is to balance the interests of the affected utility and the public. In Mr. Glazier's Staff Report admitted into the record of this cause he stated that "[I]t appears that employment in Indiana will not be negatively impacted as a result of the proposed merger." Report, p.11. At the hearing held in this cause, Mr. Munczinski stated that "if there are affected employees [in Indiana], they would be at the management level in the service corporation or at the highest level of management in Indiana Michigan Company. What we have excluded would be the field personnel. I think we're pretty sure that in Indiana it would be all the IBEW workers, union workers, customer service representatives, things like that. But I couldn't, for instance, guarantee the legal positions or the rates director position." Later in Mr. Munczinski's testimony, he referred 12 13 to Mr. Flaherty's testimony in the Texas Docket. In that Docket, as Mr. Glazier's staff report alludes to, Mr. Flaherty stated that there "are no current plans to close any facilities in Indiana as a result of the AEP/CSW merger." Report, p.11. The representation by AEP that no facilities will be closed in Indiana and that no IBEW worker, union worker, or customer service representative will lose their job, is critical to this Commission's consideration of this merger. The Settlement Agreement left at least two critical terms undefined. One undefined term is "bulk transmission facilities." The other is "consummation of the merger." The Commission is aware of the difficulties in defining the term "bulk transmission facilities." As was explained at the hearing, there is a potential conflict between the states and FERC regarding the definition of transmission facilities giving rise to a conflict regarding jurisdiction of the transfer of those assets. AEP should be aware that this Commission intends to actively participate in FERC proceedings and this Commission will not readily cede its control over the transfer of transmission facilities. In our opinion, IC 8-1-2-83 is applicable to the transfer of assets. This Commission intends, as we previously stated herein, to be assertive before the FERC to ensure that AEP joins a FERC-approved RTO. We do not anticipate that the failure to define the term "bulk transmission facilities" will be utilized by AEP to thwart in any way the effort to establish a regional RTO. "Consummation of the merger" shall be defined as the day on which CSW shares are converted to AEP shares. AEP should immediately notify the Commission of this occurrence. Given our task of balancing the interests of all of Indiana, the Commission finds that approval of the Settlement Agreement is in the public interest. Approval serves the interest and convenience of the public, and the enormous cost in both time and money to continue litigating this matter on the state and federal level will be diminished. (h) Conclusion. At the conclusion of the hearing held in this cause, the OUCC's counsel made the following statement, "We are very appreciative of all the efforts that the Commission staff put into this negotiation. I know it is a very complex and arduous task for them, and they did a good job, and although the OUCC did not sign off on the agreement, it does not take away from our belief that the Commission staff did everything they could to reach an agreement that they thought was the best for the ratepayers of I&M." We join in the OUCC's recognition of the efforts made by the Commission 's Staff negotiating team and by AEP to reach a settlement that resolved many of the complex issues arising from this merger. It is the Commission's belief that whole no party is ever 100 percent satisfied by the results of a settlement, the negotiating process presents opportunities to raise issues which might otherwise remain unaddressed in a litigated proceeding. Having reviewed the Settlement Agreement and the evidence relating thereto and having considered all evidence submitted in this cause, the Commission finds that the recommendation of the Staff Negotiating Team should be approved. The Commission further finds that the Settlement Agreement is a fair and reasonable resolution of the merger-related issues of concern to the Commission and should be approved consistent with the findings herein which approve the Settlement Agreement while also addressing matters incidental or ancillary thereto. 13 14 IT IS THEREFORE ORDERED BY THE INDIANA UTILITY REGULATORY COMMISSION THAT: 1. The Settlement Agreement shall be and hereby is approved consistent with the findings herein. 2. I&M shall implement the bill reductions as set forth in the Agreement upon consummation of the merger as defined herein. 3. Upon consummation of the merger as defined herein, I&M shall be and hereby is authorized to defer and amortize its Indiana jurisdictional estimated merger-related cross-to-achieve savings over an eight-year period, as set forth in the Agreement consistent with finding 3(b) herein. 4. The investigation in this cause commenced by our Order dated June 29, 1998 is hereby terminated. 5. This Order shall be effective on and after the date of its approval. MCCARTY, KLEIN, RIPLEY, SWANSON-HULL AND ZIEGNER CONCUR: APPROVED: I hereby certify that the above is a true and correct copy of the Order as approved. /s/ Joseph M. Sutherland - ---------------------------------------- Joseph M. Sutherland, Secretary to the Commission 14 15 EXHIBIT A STIPULATION AND SETTLEMENT AGREEMENT 16 STATE OF INDIANA INDIANA UTILITY REGULATORY COMMISSION IN THE MATTER OF THE INVESTIGATION ) ON THE COMMISSION'S OWN MOTION ) INTO ANY AND ALL MATTERS RELATING ) CAUSE NO. 41210 TO THE MERGER OF AMERICAN ) ELECTRIC POWER, INC. AND CENTRAL ) AND SOUTH WEST CORPORATION ) STIPULATION AND SETTLEMENT AGREEMENT On June 29, 1998, the Indiana Utility Regulatory Commission ("IURC" or "Commission") initiated this investigation regarding the proposed merger of American Electric Power Company, Inc. ("AEP"), the parent company of Indiana Michigan Power Company ("I&M"), and Central and South West Corporation ("CSW"). On September 2, 1998, the Commission appointed a Staff Negotiating Team "to attempt to negotiate a settlement of the issues presented in this cause." In a Docket Entry dated November 30, 1998 the presiding officers directed that "any negotiated settlement resolving the issues presented in this Cause should be filed with the Commission on or before March 5, 1999....." The Commission extended that deadline at the request of the Staff Negotiating Team eventually to April 12, 1999. Solely for the purposes of compromise and settlement of the issues in this proceeding, Indiana Michigan Power Company, which does business in Indiana as American Electric Power and the Staff Negotiating Team (collectively referred to as the "Parties") have met and reached a settlement agreement ("Agreement") which they hereby submit and recommend for approval to the Commission. If the Commission does not approve the settlement agreement in its entirety and incorporate it in the Final Order, the proposed Agreement shall be null and void and deemed withdrawn, unless such change is agreed to by the Parties. SETTLEMENT AGREEMENT WHEREAS AEP and CSW have filed various applications before federal and state agencies seeking approvals necessary to consummate a proposed merger of the two companies, and WHEREAS AEP, I&M and the Staff Negotiating Team have met and explored over a period of months various issues related to the proposed merger and their agreements and differences regarding the effects of the proposed merger on competition between electricity providers and on the terms and conditions under which retail electric utility service is provided, and WHEREAS AEP, I&M and the Staff Negotiating Team recognize the costs and uncertainty of litigation and the desirability of consensual voluntary resolution of their differences and the legitimate interest and good faith of each of the parties in achieving the objectives each desires to achieve, and 1 17 WHEREAS the Staff Negotiating Team is authorized to make recommendations to the IURC regarding a fair and just settlement of differences in the public interest, The Parties agree as follows: The Staff Negotiating Team will recommend to the IURC that the following Agreement be adopted by the Commission in an order or other appropriate formal action that references this Agreement or incorporates all of the provisions thereof. Where appropriate, the Commission action may address or reserve other matters ancillary or incidental to the matters addressed in this Agreement, for immediate or future disposition, in a manner not inconsistent with the Agreement. All appropriate terms are defined in the "Definitions" section of the Agreement. THE IURC and STAFF: 1. Will not oppose the proposed merger pending before the Federal Energy Regulatory Commission ("FERC"). 2. Will not oppose AEP's filings previously made at the United States Securities and Exchange Commission ("SEC") in connection with the proposed merger, together with any non-material changes or supplements thereto. AEP, or its Indiana jurisdictional AEP operating company, conditional on merger consummation will: 1. REGULATORY PLAN. I&M will implement net merger savings reduction riders that will reduce bills to customers by the annual amounts shown in Attachment A beginning with the first revenue month after the consummation of the merger. The annual bill reduction amounts shown in Attachment A will be allocated to rate classes based upon total revenues, excluding fuel cost adjustment, and credited to customers' bills through the application of a per kilowatt hour factor specific to each rate class. Each individual year's bill reduction will apply for a twelve-month period except for an adjustment during each third quarter to reconcile actual kWh sales and projected kWh sales for the prior year. The last reduction will continue to apply in years following the end of year eight until base rates for the operating company are changed. The merger savings and costs are based on estimated values included in AEP's filing with FERC in Docket No. EC98-40-000. Notwithstanding any base rate proceeding during the eight-year period after the consummation of the merger, the annual amounts shown in Attachment A will remain in effect. I&M must implement the above bill reductions in the manner and amounts described above notwithstanding any changes to the current regulatory structure in Indiana. In the event that retail electric deregulation legislation is implemented in Indiana, or if there is any unbundling or restructuring, I&M shall continue to apply the regulatory plan's provisions to regulated rates of its Indiana customers. 2 18 Any legislatively mandated adjustments to base rates, of any kind, that are part of any retail electric deregulation legislation implemented in Indiana shall not diminish or offset, but shall be in addition to, the bill reductions established in this proceeding. Subject to this agreement, AEP and I&M will defer and amortize their Indiana jurisdictional estimated merger related costs-to-achieve over an 8-year recovery period. Costs to achieve the merger are those costs incurred to consummate the merger and combine the operations of AEP and CSW. These costs include, but are not limited to, investment banking fees; consulting and legal services incurred in connection with obtaining regulatory and shareholder approvals; transition planning and development costs; employee separation costs including severance costs, change-in-control payments and retaining costs; and facilities consolidation costs. The IURC will issue accounting orders or other orders necessary to authorize the deferral and amortization of merger costs. In any proceeding to change base rates for I&M to become effective after the consummation of the merger, the following rate treatment will be reflected: A. Estimated non-fuel merger savings, net of costs to achieve will be included in cost of service as an allowable expense in order to avoid duplication and to continue to provide shareholders with their share of the net savings. The amount to be included in the cost of service shall be based upon the test year period. (See Attachment B) B. Amortization of estimated costs to achieve will be included in cost of service as an allowable expense. The amount to be included in the cost of service shall be based upon the test year period. (See Attachment B) In addition, the net merger savings allocated to the shareholders will be excluded from the earnings test in determining I&M's compliance with the provisions of I.C. 8-1-2-42(d)(2) and (3). To mitigate potential stranded investment, I&M will increase the funding for the provision of paragraph 21 of the settlement agreement approved by the Commission in Cause No. 38702-FAC40-S1 in the additional amount of $5.5 million annually starting January 1, 2001 for a three-year period ending December 31, 2003. The rate filing limitation in paragraph 8 of that settlement agreement is extended by one year to January 1, 2005. In addition, I&M will abide by the provisions of paragraphs 8, 9 and 10 of that settlement agreement, regardless of the outcome of litigation in that cause. 2. FUEL MERGER SAVINGS. All savings of fuel and purchased power expenses resulting from the merger shall benefit retail customers through existing fuel clause recovery mechanisms applied by State Commissions. In circumstances when one or more AEP operating companies in one AEP zone are supplying power to the other AEP zone, and as a result the supplying zone needs to purchase replacement power to serve its native load, AEP shall hold harmless the native load customers of the supplying zone from any price differential between the replacement power and the system power supplied to the other zone. Similarly, if one or more AEP operating companies in one AEP zone are supplying power to the other AEP zone, and as a 3 19 result, the supplying zone loses the opportunity to sell power at a price higher than received from the zone being supplied, AEP shall credit the supplying zone for the foregone revenues. 3. STRANDED COSTS. AEP and its operating companies agree not to seek or recover any stranded costs associated with the operating companies of one AEP zone from the retail customers of the other AEP zone. 4. PROCEEDS OF FACILITY SALES. Any proceeds from the sale of facilities shall go to the AEP operating company in whose rate base the facilities are included, for further disposition in accordance with the rules and orders of the regulatory authorities whose jurisdiction encompasses the ultimate disposition of such proceeds. 5. SYSTEM INTEGRATION AGREEMENTS. To mitigate any perceived impacts of the merger on AEP's ability to exercise market power, AEP proposed in its FERC merger application a mitigation plan. To protect retail customers, AEP agrees to hold harmless the retail customers from any mitigation plan included in any FERC order approving the merger of AEP-CSW. To implement this Agreement in any general retail electric rate proceeding commenced by the filing of a petition on or after the date of this Agreement, in which an AEP operating company requests a change in its basic rates and charges, or in any other proceeding where so ordered by the State Commission, AEP shall have the burden therein to prove that such requested rate relief does not reflect mitigation-related costs. AEP commits to file any allocation of the cost of new, modified or upgraded generation or transmission facilities whose costs will be subject to the System Integration Agreement or the System Transmission Agreement with the FERC and to notify each State Commission of any such filing at the time it is made. Notification to each State Commission will include an estimate of the cost of construction, an explanation of the reasons for constructing the facilities, studies supporting the construction of the facilities, and a proposed allocation of the facilities' costs. If AEP plans to purchase an in-service facility or already constructed and soon-to-be-in-service facility, AEP will follow the above described procedures and will include as part of the notification to the State Commission an explanation of the circumstances causing the AEP operating company to make the purchase in question. 6. REGULATORY AUTHORITY. AEP agrees not to seek to overturn, reverse, set aside, change or enjoin, whether through appeal or the initiation or maintenance of any action in any forum, a decision or order of a State Commission based on the assertion that the authority of the Securities and Exchange Commission as interpreted in Ohio Power Co. v. FERC, 954 F.2d 779 (D.C. Cir. 1992) cert. denied, 498 U.S. 73 (1992) impairs the State Commission's ability to examine and determine the reasonableness of non-power affiliate transaction costs to be passed to retail customers. The parties agree that the Ohio Power waiver does not include waiver of any arguments that AEP may have with respect to the reasonableness of SEC approval cost allocations. AEP will provide each State Commission with notice at least 30 days prior to any filings that propose new allocation factors with the SEC. The notice need not be in the precise form of the final filing but shall include, to the extent information is available, a description of the proposed factors and the reasons supporting such factors. AEP and State Commission Staff will make a good-faith attempt to resolve their differences, if any, in advance of a filing being made at the SEC. 4 20 7. REGIONAL TRANSMISSION ORGANIZATION A. Prior to December 31, 2000, AEP will file with the FERC an unconditional application, consistent with the RTO agreement and tariff, to transfer the operation and control of its bulk transmission facilities in Indiana, Michigan, Kentucky, Ohio, Tennessee, Virginia and West Virginia owned, controlled and/or operated by AEP to the Midwest Independent Transmission System Operator, Inc. or another FERC-approved Regional Transmission Organization directly interconnected with AEP transmission facilities. Provided that, if, by June 30, 2000, there is pending before the FERC for approval an RTO to which AEP is a signatory that includes two or more directly interconnected control areas, at least one of which is not affiliated with AEP, the December 31, 2000 date shall be extended to the date that is 75 days after the date on which the FERC issues an order either approving or disapproving the RTO. B. AEP shall endeavor to incorporate equitable reciprocal pricing arrangements with contiguous RTOs in the Alliance RTO or any other filing to which AEP is a signatory seeking FERC approval of the formation of a new RTO. C. AEP will provide generation dispatch information necessary for RTOs to monitor the effect of such dispatch on the loading of that RTO's constrained transmission facilities. This information must be provided to any RTO of which AEP is a member, and to RTOs providing service over any transmission facilities directly interconnected with the AEP east zone transmission facilities. Each of these RTOs shall determine the format, quantity and timing of these data as necessary to perform this monitoring function. The information provided by AEP shall be equivalent to that provided by all parties, which have control of the dispatch of generation facilities, taking service from these RTO(s) and shall be subject to appropriate confidentiality provisions. D. AEP believes that its RTO commitment, as defined in this document, is in keeping with its goal of achieving a large, economically efficient RTO in the Eastern Interconnection. E. Nothing in this Agreement precludes the Commission, or its staff from actively participating in any proceedings at the FERC arising from any RTO filings made by AEP. However the Commission and its staff commits that it will not offer such participation as a reason to delay the consummation of the merger or to advocate a position before FERC inconsistent with Paragraph A above. 8. AFFILIATE STANDARDS. The following affiliate standards shall apply from the date of closing of the merger until new affiliate standards imposed by state legislation or State Commission action become effective. A. The financial policies and guidelines for transactions between an AEP operating company and its affiliates shall reflect the following principles: 5 21 1. An AEP operating company's retail customers shall not subsidize the activities of the operating company's non-utility affiliates or its utility affiliates. 2. An AEP operating company's costs for jurisdictional rate purposes shall reflect only those costs attributable to its jurisdictional customers. 3. These principles shall be applied to avoid costs found to be just and reasonable for rate-making purposes by the affected State Commission being left unallocated or stranded between various regulatory jurisdictions, resulting in the failure of the opportunity for timely recovery of such costs by the operating company and/or its utility affiliates; provided, however, that no more than one hundred percent of such costs shall be allocated on an aggregate basis to the various regulatory jurisdictions. 4. An AEP operating company shall maintain and utilize accounting systems and records that identify and appropriately allocate costs between the operating company and its affiliates, consistent with these cross-subsidization principles and such financial policies and guidelines. B. Each State Commission shall have access to the employees, officers, books and records of any affiliate of its jurisdictional AEP operating company to the same extent and in like manner that each such State Commission has over a public utility operating within the state in which such State Commission exercises its regulatory authority if the affiliate had engaged in direct or indirect transactions with the jurisdictional AEP operating company. If such employees, officers, books and records can not be reasonably made available to a State Commission, then upon request of a State Commission, the AEP operating company shall, in accordance with state reimbursements rules, reimburse the State Commission for appropriate out-of-state travel expenses incurred in accessing the employees, officers, books and records. Each AEP operating company shall maintain, in accordance with generally accepted accounting principles, books, records, and accounts that are separate from the books, records, and accounts of its affiliates, consistent with Part 101 - Uniform System of Accounts Prescribed for Public Utilities and Licensees Subject to the Provisions of the Federal Power Act. Any objections to providing all books and records must be raised before the State Commission and the burden of showing that the request is unreasonable or unrelated to the proceeding is on the AEP operating company. The confidentiality of competitively sensitive information shall be maintained in accordance with each State Commission's rules and regulations. C. In accordance with generally accepted accounting principles and consistent with state and federal guidelines, an AEP operating company shall record all transactions with its affiliates, whether direct or indirect. An AEP operating company and its affiliates shall maintain sufficient records to allow for an audit of the transactions involving the operating company and its affiliates. Asset transfers from an AEP operating company to a non-utility affiliate and asset 6 22 transfers from a non-utility affiliate to an AEP operating company shall be at fully distributed costs in accordance with current Securities and Exchange Commission (SEC) issued requirements or other statutory requirements if the SEC has no jurisdiction. D. An AEP operating company shall not allow a non-utility to obtain credit under any arrangement that would permit a creditor, upon default, to have recourse to the operating company's assets. The financial arrangements of an AEP operating company's affiliate are subject to the following restrictions unless otherwise approved by that operating company's State Commission. 1. Any indebtedness incurred by a non-utility affiliate will be without recourse to the operating company. 2. An AEP operating company shall not enter into any agreements under terms of which the operating company is obligated to commit funds in order to maintain the financial viability of a non-utility affiliate. 3. An AEP operating company shall not make an investment in a non-utility affiliate under circumstances in which the operating company would be liable for the debts and/or liabilities of the non-utility affiliate incurred as a result of acts or omissions of a non-utility affiliate. 4. An AEP operating company shall not issue any security for the purpose of financing the acquisition, ownership or operation of a non-utility affiliate. 5. An AEP operating company shall not assume any obligation or liability as guarantor, endorser, surety, or otherwise, in respect of any security of a non-utility affiliate. 6. An AEP operating company shall not pledge, mortgage or otherwise use as collateral any assets of the operating company for the benefit of a non-utility affiliate. 7. AEP shall hold harmless the retail customers of an AEP operating company from any adverse effects of credit rating declines caused by the actions of non-utility affiliates. Transactions between AEP operating companies and affiliates involving a money pool for the financing of short-term funding requirements are exempt from the requirements of this paragraph. Further, the provisions of this paragraph would not preclude AEP operating companies from issuing securities or assuming obligations related to their existing coal subsidiaries. E. Any untariffed, non-utility service provided by an AEP operating company or affiliated service company to any affiliate shall be itemized in a billing statement pursuant to a written contract or written arrangement. The AEP operating company and any affiliated service company shall maintain and keep available for 7 23 inspection by the State Commission copies of each billing statement, contract and arrangement between the AEP operating company or affiliated service company and its affiliates that relate to the provision of such untariffed non-utility services. F. Any good or service provided by a non-utility affiliate to an AEP operating company shall be by itemized billing statement pursuant to a written contract or written arrangement. The operating company and non-utility affiliate shall maintain and keep available for inspection by the State Commission copies of each billing statement, contract and arrangement between the operating company and its non-utility affiliates that relate to the provision of such goods and services in accordance with applicable State Commission retention requirements. G. Employees responsible for the day-to-day operations of the AEP operating companies and those of affiliated exempt wholesale generators or affiliated power marketers shall operate independently of one another. AEP shall document all employee movement between and among all affiliates. Such information shall be made available to each State Commission and consumer advocate upon request. H. An AEP operating company may not own property in common with an affiliated exempt wholesale generator or affiliated power marketer. I. No market information obtained in the conduct of utility business may be shared with an affiliated exempt wholesale generator or affiliated power marketer, except where such information has been publicly disseminated or simultaneously shared with and made available to all non-affiliated entities who have requested such information. Customer-specific information shall not be made available to an affiliated exempt wholesale generator or affiliated power marketer except under the same terms as such information would be made available to a non-affiliated company, and only with the written consent of the customer specifying the information to be released. J. A non-utility affiliate may use an AEP operating company's name or logo only if, in connection with such use, the affiliate makes adequate disclosures to the effect that (i) the two entities are separate, (ii) it is not necessary to purchase the non-regulated product or service to obtain service from the operating company; and (iii) the customer will gain no advantage from the operating company by buying from the affiliate. K. An AEP operating company shall not condition or tie the provision of any product, service, pricing benefit or waiver of associated terms or conditions to the purchase of any good or service from its affiliated exempt wholesale generator or power marketer. L. Except as provided in paragraph M, an affiliated exempt wholesale generator or affiliated power marketer shall not share office space, office equipment, computer systems or information systems with an AEP operating company. 8 24 M. Computer systems and information systems may be shared between an AEP operating company and non-utility affiliates only to the extent necessary for the provision of corporate support services; however, the operating company shall ensure that the proper security access and another safeguards are in place to ensure full compliance with these affiliate rules. N. An AEP operating company may engage in transactions directly related to the provision of corporate support services with its affiliates in accordance with requirements relating to service agreements. As a general principle, such provision of corporate support services shall not allow or provide a means for the transfer of confidential information from the operating company to the affiliate, create the opportunities for cross-subsidization of affiliates, or otherwise provide any means to circumvent these affiliate rules. O. Except as provided in paragraph N, an AEP operating company may only make a product or service available to an affiliated exempt wholesale generator or an affiliated power marketer if the product or service is equally available to all non-affiliated exempt wholesale generators and power marketers on the same terms, conditions and prices, and at the same time. An AEP operating company shall process all requests for a product or service from affiliated and non-affiliated exempt wholesale generators and power marketers on a non-discriminatory basis. P. An AEP operating company which provides both regulated and non-regulated services or products, or an affiliate which provides services or products to an AEP operating company, shall maintain documentation in the form of written agreements, an organization chart of AEP (depicting all affiliates and AEP operating companies), accounting bulletins, procedure and work order manuals or regulated and non-regulated services or products. Such documentation shall be available, subject to requests for confidential treatment, for review by State Commission in accordance with Paragraph B above. Q. AEP shall designate an employee who will act as a contact for State Commissions and consumer advocates seeking data and information regarding affiliate transactions and personnel transfers. Such employee shall be responsible for providing data and information requested by a State Commission for any and all transactions between the jurisdictional operating company and its affiliates, regardless of which affiliate(s), subsidiary(ies) or associate(s) of an AEP operating company from which the information is sought. R. AEP shall designate an employee or agent within each signatory state who will act as a contact for retail consumers regarding service and reliability concerns and to allow a contact for retail consumers for information, questions and assistance. Such AEP representative shall be able to deal with billing, maintenance and service reliability issues. S. AEP shall provide each signatory state a current list of employees or agents that are designated to work with each State Commission and consumer advocate 9 25 concerning state regulatory matters, including, but not limited to, rate cases, consumer complaints, billing and retail competition issues. T. Thirty (30) days prior to filing any affiliate contract (including service agreements) with the SEC or the FERC an AEP operating company shall submit to each affected State Commission a copy of the proposed filing. U. Any violation of the provisions of these affiliate standards are subject to the enforcement powers and penalties at the State Commissions. V. AEP shall contract with an independent auditor who shall conduct biennial audits for eight years after merger consummation of affiliated transactions to determine compliance with these affiliate standards. The results of such audits shall be filed with the State Commissions. Prior to the initial audit, AEP will conduct an informational meeting with the State Commissions regarding how its affiliates and affiliate transactions will or have changed as a result of the proposed merger. W. If the Public Utility Holding Company Act of 1935 is repealed or materially amended during the time this Agreement is in effect and equivalent jurisdiction is not given to another federal agency, AEP will work with the State Commissions to ensure that AEP continues to furnish the State Commission with the appropriate information to regulate its jurisdictional AEP operating company. The State Commission may establish its reporting requirements regarding the nature of intercompany transactions concerning the operating company and a description of the basis upon which cost allocations and transfer pricing have been established in these transactions. 9. ADEQUACY AND RELIABILITY OF RETAIL ELECTRIC SERVICE. AEP agrees to maintain or enhance the adequacy and reliability of retail electric service provided by each of the AEP operating companies. Service reports will be submitted to the State Commissions participating in this Agreement in the format described in Attachment C to this Agreement. 10. STATUTORY AND OTHER ISSUES. Provided the proposed merger is ultimately consummated, AEP commits that upon issuance of any final and non-appealable order from any state or federal commission addressing the merger that provides benefits or imposes conditions on AEP that would benefit the ratepayers of any jurisdiction, such net benefits and conditions will be extended to all other retail customers to the extent necessary to achieve equivalent net benefits and conditions to all retail customers of AEP. 11. CONTINUED PARTICIPATION. Nothing in this Agreement is intended to preclude the Commission and its staff from addressing in a manner not inconsistent with this Agreement issues raised in FERC Docket No. EC98-40-000. 12. ENFORCEABILITY. AEP and I&M will not assert in any action to enforce an order approving this Agreement that the Commission lacks the authority to have the provisions of this Agreement enforced under Indiana law. 10 26 DEFINITIONS 1. "AEP zone" means either the area comprising the AEP operating companies providing service in Indiana, Michigan, Kentucky, Ohio, Tennessee, Virginia and West Virginia ("East") or the area comprising the former CSW operating companies providing service in Arkansas, Texas, Oklahoma and Louisiana ("West"). 2. "AEP operating company" means an AEP affiliate that is a public utility subject to rate regulation by the FERC and/or a state utility regulatory agency. 3. "Affiliate" means an entity that is an operating company's holding company, a subsidiary of the operating company or a subsidiary of the holding company. 4. "Consumer advocate" means an agency of the state government designated as a representative of consumers in matters involving utility companies before the applicable State Commission. 5. "Entity" means a corporation or a natural person. 6. "Exempt wholesale generator" means an entity which is engaged directly or indirectly through one or more affiliates exclusively in the business of owning or operating all or part of a facility for generating electric energy and selling electric energy at wholesale and who: a. does not own a facility for the transmission of electricity, other than an essential interconnecting transmission facility necessary to effect a sale of electric energy at wholesale; and b. has applied to the FERC for a determination under 15 U.S.C. Section 79z-5a. 7. "FERC" means the Federal Energy Regulatory Commission, or any successor governmental agency. 8. "Non-Utility Affiliate" means an Affiliate which is not a domestic public utility. Non-utility affiliate includes a foreign affiliate. 9. "Holding Company" means AEP, or its successor in interest, or any Entity that owns directly or indirectly 10 percent or more of the voting capital stock of a utility operating company, or its successor in interest. 10. "Power Marketer" means an entity which: a. becomes an owner or broker of electric energy in a state for the purpose of selling the electric energy at wholesale; b. does not own transmission or distribution facilities in a state; 11 27 c. does not have a certified service area; and d. has been granted authority by the FERC to sell electric energy at market-based rates. 11. "Regional Transmission Organization" (RTO) means an organization that operates electric transmission equipment and facilities on a regional basis. 12. "SEC" means the United States Securities and Exchange Commission, or any successor governmental agency. 13. "Service Agreement" means the agreement entered into between American Electric Power Service Corp. and AEP's operating companies, under which services are provided by American Electric Power Service Corp. to the operating companies. 14. "Service Company" means an Affiliate whose primary business purpose is to provide, among other functions, administrative and general or operating services to AEP utility operating companies. 15. "Services" means the performance of activities having value to one party including, but not limited to, managerial, financial, accounting, legal, engineering, construction, purchasing, marketing, auditing, statistical, advertising, publicity, tax, research and other similar services. 16. "Subsidiary" means any corporation 10 percent or more of whose voting capital stock is controlled by another Entity. 17. "Utility Affiliate" means an affiliate of a utility operating company that is also a public utility. Presentation of Agreement to the Commission 1. The Parties shall move for the admission of this Agreement into evidence at the hearing scheduled for April 19, 1999 and sponsor evidence including testimony and exhibits as may be required to support Commission approval of this Agreement. 2. The Parties stipulate and agree to the issuance by the Commission of the Proposed Order in the form attached hereto as Attachment D. All of the terms and agreements contained in the Proposed Order are to be interpreted consistent with the provisions of this Agreement, which is to be attached to and incorporated by reference in the Final Order issued by the Commission. Effect and Use of Agreement 1. This Agreement shall not constitute or be cited as precedent or deemed an admission by any Party in any other proceeding except as necessary to enforce its terms before the Commission, or any state court of competent jurisdiction. This Agreement is solely the result of compromise in the settlement process, shall not constitute a concession of subject matter 12 28 jurisdiction and, except as expressly provided herein, is without prejudice to and shall not constitute a waiver of any position that any of the Parties may take with respect to any or all of the items resolved herein in any future regulatory or other proceedings and, failing approval by this Commission, shall not be admissible or discussed in any subsequent proceedings. 2. The evidence in this cause constitutes substantial evidence sufficient to support the Agreement and provides an adequate evidentiary basis upon which the Commission can make any finding of fact and conclusions of law necessary for the approval of the Agreement, as filed. 3. The issuance of the Final Order shall terminate any further proceedings in this cause. 4. In the event this cause is required to be litigated, the Parties expressly reserve all of their rights to make objections and motions to strike with respect to all testimony and exhibits and their right to cross-examine the witnesses presenting such testimony and exhibits. 5. The undersigned have represented and agreed that they are fully authorized to execute this Agreement on behalf of their designated clients who will be bound thereby. 6. The Parties to this Agreement shall not appeal the agreed Final Order or any other Commission order to the extent such orders are specifically implementing the provisions of this Agreement and shall support this Agreement in the event of any appeal by a person not a Party. This provision shall be enforceable by any Party, in any state court of competent jurisdiction. 7. The communications and discussions during the negotiations and conferences that produced the Agreement have been conducted on the explicit understanding that they are or relate to offers of settlement and shall, therefore be privileged and not admissible in any proceeding. ACCEPTED and AGREED this 12th day of April 1999. Indiana Michigan Power Company By: /s/ Marc E. Lewis --------------------------- Marc E. Lewis Senior Attorney 13 29 AEP By: /s/ Richard E. Munczinski --------------------------- Richard E. Munczinski Senior Vice President American Electric Power Service Corporation IURC Staff Negotiating Team By: /s/ Robert C. Glazier --------------------------- Robert C. Glazier Director of Utilities By: /s/ Abby R. Gray --------------------------- Abby R. Gray Special Counsel to the Staff Negotiating Team 14 30 Attachment A Page 1 of 1 AEP/CSW MERGER NET ANNUAL MERGER SAVINGS AND INDIANA CUSTOMER BILL REDUCTIONS ($000)
(1) (2) (3) (4) Net Customer Shareholder Period Merger Savings Bill Reduction Savings ------ -------------- --------------- ----------- Year 1 5,591 3,306 2,286 Year 2 10,633 5,927 4,706 Year 3 13,531 7,434 6,097 Year 4 15,903 8,668 7,235 Year 5 17,437 9,465 7,972 Year 6 18,606 10,073 8,533 Year 7 19,515 10,546 8,969 Year 8 20,039 10,818 9,221 121,255 66,238 55,017
31 Attachment B Page 1 of 3 AEP/CSW MERGER EXAMPLE OF BASE RATE CASE TREATMENT BASED ON YEAR 3 ($000) CREDIT PER RIDER CONTINUES (7,434) INCLUDED IN TEST YEAR: GROSS MERGER SAVINGS (17,048) CHANGE IN CONTROL AMORTIZATION 768 OTHER CTA AMORTIZATION 2,751 ----- TOTAL CTA AMORTIZATION 3,517 ------ NET MERGER SAVINGS IN TEST YEAR (13,531) ADD BACK TO TEST YEAR COST OF SERVICE: CUSTOMER SHARE (Attachment A, Col. 3, Year 3) 7,434 SHAREHOLDER PORTION (Attachment A, Col. 4, Year 3) 6,097 ----- 13,531 ------ NET BASE RATE REDUCTION 0 ------ INDIANA CUSTOMER RATE REDUCTION (7,434) ======
32 Attachment B Page 2 of 3 AEP/CSW MERGER BASE RATE CASE TREATMENT FOR INCLUSION IN COST OF SERVICE ($000)
Add Back to Test Year Cost of Service ------------------------------------- Customer Shareholder Net Savings Net Savings ----------- ----------- YEAR 1 3,306 2,286 YEAR 2 5,927 4,706 YEAR 3 7,434 6,097 YEAR 4 8,668 7,235 YEAR 5 9,465 7,972 YEAR 6 10,073 8,533 YEAR 7 10,546 8,969 YEAR 8 10,818 9,221
33 Attachment B Page 3 of 3 AEP/CSW MERGER AMORTIZATION OF ESTIMATED COST TO ACHIEVE
AMOUNT --------- YEAR 1 3,517,436 YEAR 2 3,517,436 YEAR 3 3,517,436 YEAR 4 3,517,436 YEAR 5 3,517,436 YEAR 6 3,517,436 YEAR 7 3,517,436 YEAR 8 3,517,436 TOTAL 28,139,494*
- ----------------- * May not add due to rounding 34 Attachment C Quality of Service Reporting Indiana Michigan Power will maintain the overall quality and reliability of its electric service at levels no less than it has achieved in the past decade. Indiana Michigan Power will provide service reliability reports annually indicating its calendar year Indiana Customer Average Interruption Duration Index (CAIDI) and Indiana System Average Interruption Frequency Index (SAIFI). These indices shall be determined and reported, including all storms. Definitions for these measures are included in this Attachment. Indiana Michigan Power also will provide annual Call Center performance measures for those centers which handle Indiana customer calls. These will include the Call Center Average Speed of Answer (ASA), Abandonment Rate, and Call Blockage. Definition for these measures are included in this Attachment. The performance information described above shall be provided by the end of May of the year following the calendar in question. 35 AEP Reliability Measures 1) System Average Interruption Frequency Index (SAIFI) is defined as the number of customers interrupted divided by the number of customers served. It is calculated by the equation: SAIFI = number of customers interrupted ------------------------------- number of customers served 2) Customer Average Interruption Duration Index (CAIDI) is defined as the number of customer hours of interruption divided by the number of customers interrupted. It is calculated by the equation: CAIDI = sum of all customers hours of interruption ------------------------------------------ number of customers interrupted 36 AEP Call Center Measures 1. Average Speed of Answer (ASA) is defined as the average time that elapses in seconds between the instant when a call is answered and the time it is connected to a Call Center representative (CSR) or an interactive voice recorder (IVR). It is calculated using the equation: Average Speed of Answer = time for all calls between call answer and CSR/IVR connection ------------------------------------------------------------- (seconds) total number of calls made to the Call Center
2. Abandonment Rate is the percentage of callers who hang up before being connected to a Call Center representative (CSR) or an interactive voice recorder (IVR). It is calculated using the equation: Abandonment Rate = {total number of callers who hang up} --------------------------------------------- x 100 (percent) total number of calls made to the Call Center
3. Call Blockage is the percentage of non-outage call attempts which do not get connected to a Call Center (busy signal, etc.). It is calculated using the equation: Call Blockage = {total number of non-outage calls that do not get connected} ------------------------------------------------------------ x 100 (percent) total number of non-outage calls made to the Call Center
37 STATE OF INDIANA INDIANA UTILITY REGULATORY COMMISSION IN THE MATTER OF THE INVESTIGATION ) ON THE COMMISSION'S OWN MOTION ) INTO ANY AND ALL MATTERS RELATING ) CAUSE NO. 41210 TO THE MERGER OF AMERICAN ) ELECTRIC POWER, INC. AND CENTRAL ) APPROVED: AND SOUTH WEST CORPORATION ) CORPORATION BY THE COMMISSION: David E. Ziegner, Commissioner Camie J. Swanson-Hull, Commissioner Claudia J. Earls, Administrative Law Judge On June 29, 1998, the Commission on its own motion initiated an investigation regarding the proposed merger of American Electric Power Company, Inc. ("AEP") and Central and South West Corporation ("CSW"). AEP is the parent company of Indiana Michigan Power Company ("I&M") which provides electric utility service in the State of Indiana. The Order noted that AEP and CSW had filed an application with the Federal Energy Regulatory Commission ("FERC") for approval of the merger under Section 203 of the Federal Power Act. Petitions to intervene in this matter were filed by the Citizens Action Coalition of Indiana, Inc., Indiana Consumers For Fair Utility Rates run ad hoc group of industrial companies), PSI Energy, Inc. and Steel Dynamics, Inc.(1) These petitions were granted and these persons were made parties to this proceeding. The Office of Utility Consumer Counselor also participated in this proceeding. After receiving written comments of the parties on certain issues relating to the proposed merger and after holding a preliminary hearing on August 4, 1998, the Commission on September 2, 1998, issued an Order appointing a negotiating team of members of the Commission Staff (the "Staff Negotiating Team") to attempt to negotiate a settlement of the issues presented in this matter. By docket entries, I&M was directed to respond to various data requests seeking information about the proposed merger and to provide to the Commission, the Staff Negotiating Team and the other parties certain documents relating thereto. I&M responded to the requests by providing the requested information and documents. During the course of this proceeding, status hearings were held at which time the Staff Negotiating Team submitted reports regarding the progress of negotiations. On April 9, 1999, I&M and the Staff Negotiating Team submitted to the Commission and recommended for approval a Stipulation and Settlement Agreement (the "Settlement (1) SDI subsequently withdrew from the proceeding. 38 Agreement") executed by I&M, AEP and the Staff Negotiating Team. On April 15, 1999, the parties to the Settlement Agreement prefiled with the Commission prepared testimony and evidence in support of the Settlement Agreement. Pursuant to notice of hearing given as provided by law, a public evidentiary hearing on the Settlement Agreement was held on April 19, 1999, at 10:00 a.m. in Room TC10 of the Indiana Government Center South, Indianapolis, Indiana. At that time, the Settlement Agreement and evidence relating thereto were accepted into the record. Having considered the evidence and being duly advised, the Commission now finds: 1. Notice and Jurisdiction. Due legal and timely notice of the settlement hearing was given and published as required by law. I&M is a "public utility" within the meaning of that term in IC 8-1-2-1 and is subject to the jurisdiction of the Commission in the manner and to the extent provided by the laws of the State of Indiana. 2. The Settlement Agreement. As described in the Settlement Agreement, a copy of which is attached hereto as Exhibit A and incorporated herein by reference, the Settlement Agreement contains, among other things, provisions regarding (a) net non-fuel merger savings; (b) fuel and purchased power merger savings; (c) limitation on requests for stranded cost recovery; (d) allocation of proceeds from the sale of facilities; (e) system integration agreements; (f) Ohio Power waiver; (g) regional transmission organization commitments; (h) affiliate standards; and (i) maintenance and enhancement of the adequacy and reliability of retail electric service, including certain reporting requirements. The Settlement Agreement further provides that if any other state commission or any federal commission issues a final and non-appealable order addressing the merger that provides benefits or imposes conditions that would benefit ratepayers of another jurisdiction. AEP will extend equivalent net benefits and conditions to all AEP retail customers. The Settlement Agreement also provides that, upon approval by the Commission, neither the commission nor its Staff shall oppose the proposed merger before FERC or oppose AEP's previously made merger-related filings with the Securities and Exchange Commission. The Settlement Agreement also states that it shall not constitute nor be cited as precedent or deemed an admission by any party in any other proceeding except as necessary to enforce its terms before the Commission, or any State Court of competent jurisdiction on these particular issues. The Settlement Agreement provides that it is solely the result of compromise in the settlement process, shall not constitute a concession of subject matter jurisdiction, and except as expressly provided therein, is without prejudice to and shall not constitute a waiver of any position that any of the parties thereto may take with respect to any or all of the items resolved therein in any future regulatory or other proceedings. The Settlement Agreement states that if the Commission does not approve the Settlement Agreement in its entirety, it shall be null and void and deemed withdrawn, unless such change is approved by the parties. 39 At the settlement hearing, Robert C. Glazier, Director of Utilities for the Indiana Utility Regulatory Commission, Richard E. Munczinski, Senior Vice President-Corporate Planning and Budgeting of American Electric Power Service Corporation, the service corporation subsidiary of AEP, and Kent D. Curry, Director of Regulatory Affairs for I&M, testified in support of Commission approval of the Settlement Agreement. Mr. Glazier and Mr. Munczinski discussed the negotiating process which resulted in the Settlement Agreement and the public benefits that would result from its approval. Mr. Curry testified regarding the mechanism by which the bill reductions will be implemented by I&M. 3. Commission Findings. In our Order dated June 29, 1998, the Commission stated that this investigation was commenced because the Commission believed that the proposed merger of AEP and CSW could have a significant impact on the electric industry and customers in Indiana and across the region and the Commission was concerned about the proposed merger's effect on the reliability of service and the development of independent system operators. During the course of this proceeding considerable information about the proposed merger was requested from and provided by I&M. Additional information about the proposed merger has since been developed in the course of FERC proceedings and proceedings before other state commissions. After lengthy and detailed negotiations. I&M, AEP and Staff Negotiating Team have reached agreement on terms and conditions which help ensure that Indiana consumers will fairly share in the benefits achieved by the merger and that Indiana consumers will be protected against any detrimental effects. The Staff Negotiating Team recommends that the Commission approve the Settlement Agreement as a fair and just settlement of differences regarding merger-related issues. Having reviewed the Settlement Agreement and the evidence relating thereto, the Commission finds that the recommendation of the Staff Negotiating Team should be approved. The Commission further finds that the Settlement Agreement is a fair and reasonable resolution of the merger-relating issues of concern to the Commission and should be approved in its entirety without modification. IT IS THEREFORE ORDERED BY THE INDIANA UTILITY REGULATORY COMMISSION THAT: 1. The Settlement Agreement shall be and hereby is approved in its entirety without modification. 2. I&M shall implement the bill reductions as set forth in the Agreement. 3. I&M shall be and hereby is authorize to defer and amortize its Indiana jurisdictional estimated merger-related costs-to-achieve savings over an eight-year period, as set forth in the Agreement. 4. The investigation in this Cause commenced by our Order dated June 29, 1998 is hereby terminated. 5. This Order shall be effective on and after the date of its approval. 40 McCARTY, KLEIN, RIPLEY, SWANSON-HULL AND ZIEGNER CONCUR: APPROVED: I hereby certify that the above is a true and correct copy of the Order as approved. - ----------------------------------- Joseph M. Sutherland, Secretary to the Commission EX-99.K 10 AGREEMENT BETWEEN APPLICANTS AND IBEW 1 Exhibit K AGREEMENT This Agreement is by and between American Electric Power ("AEP") and Central and South West Corporation ("CSW") (jointly referred to as "the Companies"), and the International Brotherhood of Electrical Workers, Local Union 329, 386, 696, 738, 876, 934, 978, 981, 1002, 1392 and 1466 ("IBEW"). The Companies and IBEW are sometimes referred to jointly herein as the "Signatories." This Agreement addresses issues affecting the Signatories in all jurisdictions served by the Companies. The Signatories agree as follows: I. Workforce A. The Companies agree not to eliminate any current IBEW employee as a direct result of the proposed merger between the Companies. As used in this Agreement, the term "direct result of the merger" shall mean the result of synergies identified at the time the merger was announced. B. The Companies agree that any IBEW represented employee whose position is eliminated as a direct result of the sale of ownership interests in the Northeast Station, Oolagah, Oklahoma, will be provided with another employment opportunity within the bargaining unit. II. Cook Negotiations The Signatories agree that normal negotiations will proceed to resolution at Cook Plant. III. Successorship 2 The Companies agree to include the recognition of existing labor agreements as a condition of the sale, divestiture or transfer of any facility subject to a collective bargaining agreement. (See Exhibit A) IV. Organizing Conduct The Signatories agree that, in the event IBEW engages in organizing efforts among AEP and/or CSW unrepresented employees, neither party shall coerce or intimidate employees during the course of an organizing campaign. The Companies agree to refrain from negative public statements concerning IBEW and any IBEW officer, representative or member. IBEW, its officers, representatives and employees agree not to publicly express negative comments concerning the Companies' integrity or motives including the integrity or motives of the Companies' officers, directors, agents or employees. The Signatories agree that all oral or written statements made during the course of an organizing campaign shall be factual. V. Union Security The Companies will, as soon as possible after the effective date of their merger, include in all IBEW contracts an "Agency Shop" provision covering employees hired after the effective date of the merger. The Companies will also, at the same time, include "Maintenance of Membership" language in all IBEW contracts. Such provision will cover all employees hired prior to the merger who are or become members of their respective local IBEW unions. The Companies also agree to a dues checkoff provision that shall be irrevocable by the employee for successive periods of one year from the date of signing or expiration of the agreement, whichever occurs sooner. (See Exhibit B) 2 3 VI. Unit Clarification For a period of five (5) years following the effective date of this Agreement, the Companies will not remove any working foreman or electric system operator positions at PSO or any senior lineman positions at Southwestern Electric Power Company ("SWEPCO") from the bargaining unit without agreement of the respective unions. VII. Leave of Absence The Companies will, upon request of the respective local IBEW unions, institute in all existing contracts Leave of Absence provisions for union business. (See Exhibit C) VIII. Service Quality Signatories agree to cooperate to establish reasonable Service Quality Standards in all jurisdictions served. IX. Other Provisions A. Upon execution of this Agreement, IBEW agrees that it will immediately cease all activities in opposition to the merger, withdraw all objections to the merger, and not file future objections to the merger. B. The Companies and IBEW agree to make a good faith effort to settle unfair labor practice complaints issued by the National Labor Relations Board. C. The Companies will reimburse IBEW up to $73,000 for costs incurred in its intervention up to the effective date of this Agreement. D. Facsimile copies of signatures are valid for purposes of evidencing execution. X. Effective Date The provisions contained in Sections II, IV, VI, VII, VIII, and IX of this Agreement will be effective upon execution of this Agreement by the last Local Union to execute this 3 4 Agreement. The provisions contained in Sections I, III and V of the Agreement will be effective upon completion of the merger between the Companies. EFFECTIVE DATE: _____________ INTERNATIONAL BROTHERHOOD OF INTERNATIONAL BROTHERHOOD OF ELECTRICAL WORKERS LOCAL UNION 329 ELECTRICAL WORKERS LOCAL UNION 386 By: __________________________ By: __________________________ INTERNATIONAL BROTHERHOOD OF INTERNATIONAL BROTHERHOOD OF ELECTRICAL WORKERS LOCAL UNION 696 ELECTRICAL WORKERS LOCAL UNION 738 By: __________________________ By: __________________________ INTERNATIONAL BROTHERHOOD OF INTERNATIONAL BROTHERHOOD OF ELECTRICAL WORKERS LOCAL UNION 876 ELECTRICAL WORKERS LOCAL UNION 934 By: __________________________ By: __________________________ INTERNATIONAL BROTHERHOOD OF INTERNATIONAL BROTHERHOOD OF ELECTRICAL WORKERS LOCAL UNION 978 ELECTRICAL WORKERS LOCAL UNION 981 By: __________________________ By: __________________________ INTERNATIONAL BROTHERHOOD OF INTERNATIONAL BROTHERHOOD OF ELECTRICAL WORKERS LOCAL UNION 1002 ELECTRICAL WORKERS LOCAL UNION 1392 By: __________________________ By: __________________________ INTERNATIONAL BROTHERHOOD OF ELECTRICAL WORKERS LOCAL UNION 1446 By: __________________________ AMERICAN ELECTRIC POWER CENTRAL AND SOUTH WEST CORPORATION By: ________________________ By: ____________________________ 4 5 EXHIBIT A Successorship: The Company agrees that the adoption of this Agreement will be a condition of the sale, divestiture or transfer of any facility covered by this Agreement. When the sale, divestiture or transfer is publicly disclosed, the Company will provide the Union with relevant information concerning such transaction upon request. 6 EXHIBIT B Union Security: Section 1. Maintenance of Membership Provision In order that employees do their part in assisting the Union to meet its obligations as a party to this Agreement, an employee hired before the effective "date" of the merger) who on or after (the effective "date" of the merger) personally pays Union dues or authorizes Union dues deduction, may only discontinue such payments or revoke a prior authorization within the 10 day calendar period preceding (the expiration "date" of the Agreement). Such revocation must be in writing and must be delivered to the Union and the Company. Section 2. Agency Fee Provision In order that employees do their part in assisting the Union to meet its obligations as a party to this Agreement, an employee hired on or after (the effective "date" of the merger) shall either personally pay Union dues or authorize Union dues deductions. Section 3. Failure to Pay Required Union Fees or Dues Should an employee covered under Section 1 above or Section 2 above fail to pay the dues or fees required as a condition of employment, the employee shall be terminated. Dues Membership: The Company agrees to deduct once each month from the pay of each employee who executes a written authorization, an amount equal to the current Union 7 dues as set forth in the Local Union By-Laws and the Constitution of the International Brotherhood of Electrical Workers. The amount of these deductions will be paid to the Financial Secretary of the Local Union. The deduction will be renewed for successive periods of one year unless revoked by written notice by certified mail to the Company and the Union within ten days prior to the anniversary date of the authorization or the expiration of the Agreement. The Union shall notify the Company of any changes in the dues amounts to be deducted. 8 Exhibit C Leave of absence for Union Officials A maximum of two employees elected or appointed to full-time union positions shall be granted leaves of absence for the period of such election or appointment. The employees shall continue to accrue seniority during such leaves, and upon termination of the leaves of absence, shall be reinstated to their former positions (or the equivalent if such former positions no longer exist) provided the employees are qualified to return to work. -----END PRIVACY-ENHANCED MESSAGE-----