-----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, RFUDwookG0kcLQHM/AHUGzM9hDaTC5hFWOLC1a3Z/RtzzN3eqJrGbb9W6X/qownp +y0nVZyvVfI2x/IpsNlNHA== 0000950123-00-001831.txt : 20000307 0000950123-00-001831.hdr.sgml : 20000307 ACCESSION NUMBER: 0000950123-00-001831 CONFORMED SUBMISSION TYPE: U-1/A PUBLIC DOCUMENT COUNT: 2 FILED AS OF DATE: 20000301 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: 558642 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. 4 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 2 Susan Tomasky Jeffrey D. Cross Executive 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 Marianne K. Smythe Joris M. Hogan Wilmer, Cutler & Pickering Milbank, Tweed, Hadley & McCloy L.L.P. 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..... ......................................... 9 A. INTRODUCTION.......................................................... 9 B. DESCRIPTION OF THE PARTIES TO THE MERGER ............................. 12 1. General Description ................................................ 12 2. Description of Energy Sales and Facilities ......................... 21 C. DESCRIPTION OF MERGER AND STATEMENT AS TO CONSIDERATION .............. 37 1. Background of the Merger ........................................... 37 2. Merger Agreement ................................................... 38 3. Reasons for the Merger ............................................. 39 4. AEP Management Following the Merger ................................ 40 ITEM 2. FEES, COMMISSIONS AND EXPENSES ..................................... 40 ITEM 3. APPLICABLE STATUTORY PROVISIONS .................................... 40 A. SECTION 10(b) ........................................................ 43 1. Section 10(b)(1) ................................................... 43 2. Section 10(b)(2) ................................................... 54 3. Section 10(b)(3) ................................................... 60 B. Section 10(c) ........................................................ 63 1. Section 10(c)(1) ................................................... 63 2. Section 10(c)(2) ................................................... 98 C. Section 10(f) ........................................................ 106 D. INTRA-SYSTEM FINANCING AND OTHER COMMISSION AUTHORIZATIONS ........... 106 E. SERVICE AGREEMENT; APPROVAL OF METHODOLOGY FOR ALLOCATING COSTS UNDER. 110 F. ACQUISITION OF NON-UTILITY BUSINESSES ................................ 114 G. ORGANIZATION OF MERGER SUB; ACQUISITION OF MERGER SUB COMMON STOCK ... 114 ITEM 4. REGULATORY APPROVAL ................................................ 115 A. ANTITRUST CONSIDERATIONS ............................................. 115 B. ATOMIC ENERGY ACT .................................................... 116 C. FEDERAL POWER ACT .................................................... 116 D. COMMUNICATIONS ACT ................................................... 118 E. ARKANSAS COMMISSION .................................................. 118 F. LOUISIANA COMMISSION ................................................. 118 G. OKLAHOMA COMMISSION .................................................. 113 H. TEXAS COMMISSION ..................................................... 119 I. INDIANA COMMISSION ................................................... 120 J KENTUCKY COMMISSION .................................................. 120 K. MISSOURI COMMISSION .................................................. 121 L. MICHIGAN COMMISSION .................................................. 115 M. AFFILIATE CONTRACTS .................................................. 121 ITEM 5. PROCEDURE .......................................................... 121 ITEM 6. EXHIBITS AND FINANCIAL STATEMENTS .................................. 122 ITEM 7. INFORMATION AS TO ENVIRONMENTAL EFFECTS ............................ 133 STATUS OF STATE RESTRUCTURING LEGISLATION Appendix A GLOSSARY OF TERMS The following abbreviations or acronyms used in this Application-Declaration are defined below: 4 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 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. 2 5 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 Consumers Consumers Energy Company 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 CPL Central Power and Light Company CSPCo Columbus Southern Power Company 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. 3 6 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 Detroit Edison Detroit Edison Company 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 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 4 7 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) FirstEnergy FirstEnergy Corporation 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 5 8 KgPCo Kingsport Power Company 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 Michigan Commission The Michigan Public Service Commission Merger Sub Augusta Acquisition Corporation, to become a wholly owned subsidiary of AEP MISO Midwest Independent Transmission System Operator, Inc. 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 6 9 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 NSP Northern States Power Company OASIS Open Access Same-Time Information System OATT Open Access Transmission Tariff 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 7 10 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 UE Union Electric Company, a public utility and a wholly owned subsidiary of Ameren Virginia Commission The Virginia State Corporations Commission Virginia Power Virginia Electric and Power Company 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 THE 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 8 11 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. 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 9 12 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.(1) 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 - ---------- (1) On January 6, 1998, Standard & Poor's revised its ratings outlook on CSW's regulated U.S. units to negative from stable and affirmed its ratings on these utilities. 10 13 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. On November 23, 1999, an Initial Decision was issued by the Administrative Law Judge at FERC approving the Merger, a copy of which is filed as Exhibit D-1.7 and incorporated by reference. FERC is scheduled to issue a final decision no later than March 2000. 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, and on December 9, 1999, granted an extension of such approval to June 30, 2000. On July 26, 1999, Applicants filed with the DOJ under the HSR Act. On February 2, 2000, DOJ notified Applicants that it had completed its review of the Merger and that no further action is warranted. 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. On January 21, 2000, the FCC approved the transfer of certain microwave licenses held by CSW. Orders approving the Merger have been received from the Arkansas Commission, the Louisiana Commission, the Oklahoma Commission, the Kentucky Commission, the Indiana Commission, and the Michigan Commission, copies of which are filed as Exhibit D-2.2, Exhibit D-3.2, Exhibit D-4.2, Exhibit D-7.1, Exhibit D-8.1, and Exhibit D-10.1, respectively, and incorporated by reference. On November 18, 1999, the Texas Commission issued an order finding the Merger to be consistent with the public interest, a copy 11 14 of which is filed as Exhibit D-5.5 and incorporated by reference. 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 OF 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, 1998, the U.S. subsidiaries of AEP had a total of 17,943 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 888,000 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, 1998, APCo had 3,577 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 12 15 and certain other matters are subject to regulation by the West Virginia Commission and the State Corporation Commission of Virginia. 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 640,000 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, 1998, CSPCo had 1,528 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 554,000 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, 1998, I&M had 3,074 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 170,000 customers in eastern Kentucky, and in supplying electric power at wholesale to other utilities and municipalities in Kentucky. At December 31, 1998, KPCo had 541 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 44,000 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, 1998, KgPCo had 65 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 13 16 approximately 685,000 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, 1998, OPCo and its wholly owned subsidiaries had 4,170 employees. Among the principal industries served by OPCo are primary metals, rubber and plastic products, stone, clay, glass and concrete products, 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, 1998, WPCo had 80 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 2.2 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 was completed in June 1999. 14 17 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. 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 $1,692,000,000 at June 30, 1999) 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 October 31, 1999, there were 194,103,349 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. 15 18 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, 1999, there were 191,157 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, 1999, there were 250,000 shares of its 7% Cumulative Preferred Stock outstanding. I&M has seven series of cumulative preferred stock outstanding, none of which is listed on any public securities exchange. June 30, 1999, there were 59,214 shares of its 4-1/8% Cumulative Preferred Stock outstanding; 14,512 shares of its 4.56% Cumulative Preferred Stock outstanding; 18,931 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, 1999, there were 14,968 shares of its 4.08% Cumulative Preferred Stock outstanding; 101,767 shares of its 4-1/2% Cumulative Preferred Stock outstanding; 23,100 shares of its 4.20% Cumulative Preferred Stock outstanding; 32,274 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, 1999, after eliminating intercompany transactions, were $6,327,000,000. Consolidated assets of AEP and its subsidiaries as of June 30, 1999, were approximately $20.6 billion, consisting of $12.9 billion in net electric utility property, plant and equipment and $7.7 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 September 30, 1999, each of which is attached and incorporated by reference as Exhibits G-15 and G-21, 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, 16 19 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 an average of 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. At December 31, 1998, the U.S. subsidiaries of CSW had 6,971 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 642,000 customers in portions of south Texas, and in supplying electric power at wholesale to other electric utility companies and municipalities. At December 31, 1998, CPL had 1,555 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 486,000 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, 1998, PSO had 1,227 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 419,000 customers in portions of northeastern Texas, northwestern Louisiana and western Arkansas, and in supplying electric power at wholesale to other electric utility companies 17 20 and municipalities. At December 31, 1998, SWEPCO had 1,461 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 188,000 customers in portions of central west Texas, and in supplying electric power at wholesale to other electric utility companies and municipalities. At December 31, 1998, WTU had 913 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 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 $1,785,000,000 at June 30, 1999) for investment in EWGs and FUCOs 18 21 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. 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, 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 October 31, 1999, there were 212,648,293 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 December 31, 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 19 22 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 December 31, 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 December 31, 1998, there were 44,636 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 December 31, 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 December 31, 1998, there were 37,727 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 December 31, 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 December 31, 1998, there were 23,675 shares of 4.40% Series Cumulative Preferred Stock outstanding. CSW's consolidated operating revenues for the six months ended June 30, 1999, after eliminating intercompany transactions, were approximately $2.5 billion. Consolidated assets of CSW and its subsidiaries as of June 30, 1999 were approximately $13.9 billion, consisting of $8.6 billion in net electric utility property, plant and equipment and $5.3 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 June 30, 1999, each of which is attached and incorporated by reference as Exhibits G-17 and G-22, 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. 20 23 2. Description of Energy Sales and Facilties a. AEP (i) Energy Sales
KwH of Electric Energy Sold (in millions) Company Twelve Months Ended December 31, 1998 APCo 38,860 CSPCo 20,221 I&M 25,285 KPCo 11,375 KgPCo 1,778 OPCo 53,300 WPCo 1,760 AEP Total 130,352(a)
(a) Total after the elimination of intercompany transactions. (ii) Electric Generating Facilities At December 31, 1998, 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) 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
21 24 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 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
22 25 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. 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 23 26 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, 1997 and 1998.
1997 1998(a) ---- ------- APCo $(237,000) $(142,500) CSPCo (138,000) (146,800) I&M 67,000 (86,100) KPCo 20,000 34,000 OPCo 288,000 341,400
(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, 1998, 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 ........................ 128,983(a)(b) 2,022 APCo .............................. 49,793 641 CSPCo ............................. 15,578(a) -- I&M ............................... 20,899 614 KPCo .............................. 10,223 258 OPCo .............................. 29,406 509
(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 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. 24 27 As of December 31, 1998, the AEP System was interconnected through 121 high-voltage transmission interconnections with 26 neighboring electric utility systems. The all-time and 1998 one-hour peak system demands were 25,940,000 and 23,192,000 kilowatts, respectively (which included 7,314,000 and 3,732,000 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 June 22, 1998, respectively. The net dependable capacity to serve the system load on such dates, including power available under contractual obligations, was 23,457,000 and 23,761,000 kilowatts, respectively. The all-time and 1998 one-hour internal peak demands were 19,557,000 and 19,414,000 kilowatts, respectively, and occurred on February 5, 1996 and July 21, 1998, respectively. The net dependable capacity to serve the system load on such dates, including power dedicated under contractual arrangements, was 23,765,000 and 23,749,000 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:
1997 1998 ---- ---- Coal 92% 99% Nuclear 7% 0% Hydroelectric and other 1% 1% Total 100% 100%
AEP's average cost of fuel per million BTUs for the calendar years ended December 31, 1997 and 1998 was 140 cents and 144 cents, respectively. b. CSW 25 28 (i) Energy Sales
KwH of Electric Energy Sold (in millions) Company Twelve Months Ended December, 31, 1998 CPL 23,059 PSO 16,862 SWEPCO 22,936 WTU 7,640 CSW Total 66,994(a)
(a) Total after elimination of intercompany transactions. (ii) Electric Generating Facilities At December 31, 1998, 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 206 Laredo Laredo, TX 174 Lon C. Hill Corpus Christi, TX 545 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 54(c) Hydroelectric--Conventional: Eagle Pass Eagle Pass, TX 6 CT--Gas: La Palma #7 San Benito, TX 48 ----- 4,464 PSO: CT/Steam--Gas: Comanche Lawton, OK 273(a) Steam--Gas:
26 29 Northeastern 1 & 2 Oologah, OK 637 Riverside Jenks, OK 916 Southwest Washita, OK 475 Tulsa Tulsa, OK 330(i) Steam--Coal: Northeastern 3 & 4 Oologah, OK 900 Oklaunion Vernon, TX 108(d) CT--Gas: Weleetka Weleetka, OK 163 Diesel--Diesel: Diesels Oklahoma 25 ----- 3,827(i) SWEPCO: Steam-Gas: Arsenal Hill Shreveport, LA 110 Knox Lee Cherokee Lake, TX 471 Lieberman Mooringsport, LA 273 Lone Star Dangerfield, TX 50 Wilkes Jefferson, TX 880 Steam--Lignite: Dolet Hills Mansfield, LA 262(e) Pirkey Hallsville, TX 580(f) Steam--Coal: Flint Creek Gentry, AR 264(g) Welsh Cason, TX 1,584 ----- 4,474 WTU: Steam-Gas: Abilene Abilene, TX 18 Fort Phantom Abilene, TX 362 Lake Pauline Quanah, TX 45 Oak Creek Bronte, TX 85 Paint Creek Stamford, TX 238 CT-Gas: Fort Stockton Ft. Stockton, TX 5 CT/Steam--Gas: Rio Pecos Girvin, TX 141(a) San Angelo San Angelo, TX 124(a) Steam--Coal: Oklaunion Vernon, TX 377(h) Diesel--Diesel: Presidio Presidio, TX 2 Vernon Vernon, TX 9 ----- 1,406 Total Generating Capability 14,171(i)
27 30
SUMMARY: Steam--Gas................................................ 7,984(i) Steam--Nuclear............................................ 630 Steam--Coal............................................... 3,919 Hydroelectric--Conventional............................... 6 CT--Gas................................................... 216 CT/Steam--Gas............................................. 538 Diesel--Diesel............................................ 36 Steam--Lignite............................................ 842 ------ 14,171(i)
(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). (i) Excludes 85 MW from units in storage at Tulsa, OK for PSO. 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 28 31 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.(2) 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 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
Facility Company Location Total Capacity Committed Ownership Interest -------- ------- -------- -------------- --------- ------------------ Brush II CSW Energy Colorado 68 68 47% Ft. Lupton CSW Energy Colorado 272 272 50% Mulberry CSW Energy Florida 120 110 50% Orange Cogen CSW Energy Florida 103 97 50% Newgulf (1) CSW Energy Texas 85 80 100% Sweeny (2) CSW Energy Texas 330 292 50% Total 978 919
(1) The Committed capacity at Newgulf is for the summer of 1999 only. (2) 205 MW of the committed capacity is for the summer of 1999 only. 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 - ---------- (2) In a separate filing, the Applicants will seek such further authority as may be required for the divestiture of generation assets. 29 32 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, 1998:
TOTAL CIRCUIT MILES OF TOTAL CIRCUIT MILES OF TRANSMISSION LINES DISTRIBUTION LINES CPL 5,000 28,455 PSO 3,573 14,289 SWEPCO 3,382 14,267 WTU 4,570 9,147 Total 16,525 66,158
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, 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 12 investor-owned utilities, 7 municipalities, 7 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 1998 was 13,718 MW on July 27, 1998. The 1998 net dependable capacity to serve the system load was 14,839 MW. Power generation at the time of the peak was 13,012 MW and net purchases at the time of the peak were 706 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 30 33 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. (iv) Fuel Supply The following table shows the sources of power used by the CSW System:
1997 1998 ---- ---- Natural Gas 36% 38% Coal 41% 39% Lignite 9% 8% Nuclear 7% 7% Other 0 0 Purchased Power 7% 8% Total 100% 100%
CSW's average cost of fuel per million BTUs for the calendar years ended December 31, 1997 and 1998 was 183 cents and 167 cents, respectively. 3. Electric Coordination The Combined System will be physically interconnected by means of the Contract Path, and economically operated as a single interconnected and coordinated system pursuant to a series of contractual arrangements. 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 and jointly dispatching 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, System Transmission Integration Agreement, AEP Interconnection Agreement, CSW Operating Agreement. The System Integration Agreement provides for the coordination and joint dispatch of generation within the Combined System. Applicants defined the term "joint economic dispatch" or "central economic dispatch" to mean the ability of the merging companies to dispatch their 31 34 generation units on a least cost basis, taking into account various operating conditions, in order to achieve certain efficiencies in the operation of the combined system which could not be realized on a stand-alone basis. 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 existing AEP Interconnection Agreement and the existing CSW Operating Agreement will remain in effect after the Merger and continue to control the distribution of costs and benefits within each zone. Briefly stated, the existing agreements will continue to govern the allocation of costs and benefits as between the operating companies of the east zone, on the one hand, and those of the west zone, on the other. The agreements, which match intra- and inter-zonal power transfers with the appropriate operating company, are necessary to assure the affected state regulators that there will be no cost or benefit transfers within the AEP system or the CSW system as a result of the Merger. The agreements and their functions are summarized below. The System Integration Agreement provides for the integration and coordination of the AEP operating companies and the CSW operating companies and the distribution of costs and benefits between the two operating zones. The purpose of the System Integration Agreement, given the settlements with various State commissions, is to ensure that the benefits achieved through the joint dispatch of the two zones on a going-forward basis are shared, in the first instance, between the two zones and then within the zones, based on the historical cost and benefit sharing arrangements under the existing AEP and CSW intrasystem agreements. It is designed to function as an umbrella agreement in addition to the existing AEP Interconnection Agreement and the existing CSW Operating Agreement, which will continue to control the distribution of costs and benefits within each zone. Under the System Integration Agreement, the east zone and the west zone are each required to have enough generating capacity to meet their respective firm load obligations. When one zone has surplus capacity available for sale and the other zone has insufficient capacity, the surplus zone will make its surplus capacity available. If neither zone has surplus capacity after meeting its firm load obligations or if third party capacity is cheaper than that from the surplus zone, then capacity will be purchased from third parties for the zone(s) with insufficient capacity. Economic energy will be transferred from one zone to another in order to minimize the total production cost of the Combined System. The AEP and CSW areas will be centrally dispatched on a least-cost basis for the Combined System. The designated agent, AEPSC, will perform these functions. The System Integration Agreement contains four service schedules governing: (1) the allocation of capacity costs and purchased power costs; (2) pricing for system capacity exchanges; (3) pricing for system energy exchanges; and (4) the allocation of "Trading and Marketing Realizations," which are the net gains or losses from the Combined System's off-system transactions. The System Integration Agreement applies to the generating resources and loads served by the Combined System, but not to the transmission facilities owned or operated by the Combined System. 32 35 The System Transmission Integration Agreement contains two service schedules governing: (1) the allocation of transmission costs and revenues between the two areas; and (2) the allocation of system control and dispatch costs associated with the integration of the two areas, the cost of the transmission capacity reserved on other systems to link the two areas, and any revenues from the resale of those capacity rights. AEPSC will coordinate the planning, operation and maintenance of transmission facilities and capacity of the Combined System. The System Transmission Integration Agreement will also provide a mechanism for coordinating the existing AEP Transmission Agreement and CSW Coordination Agreement. Specifically, the AEP and CSW transmission agreements will remain in place in their current form to avoid cost shifts among the operating companies and between the zones and to reflect the existing ownership of transmission. The existing agreements will continue to govern the allocation of costs and benefits associated with transmission assets, as between the operating companies of the east zone, on the one hand, and those of the west zone, on the other. 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, on November 23, 1999, the Administrative Law Judge at FERC issued an Initial Decision that found the rates, terms, and conditions of service contained in the above agreements, as modified by the Stipulation between Applicants and FERC Staff, are just, reasonable and not otherwise unlawful. The Administrative Law Judge's Initial Decision is filed as Exhibit D-1.7 and incorporated by reference. The existing AEP Interconnection Agreement and existing CSW Operating Agreement will provide for the joint dispatch of the respective zones. As noted above, these agreements will remain in place in their current form to avoid cost shifts among the operating companies and zones and to reflect the existing ownership of generation assets. With respect to AEP, the operating utilities of the AEP system have historically planned, constructed, and operated their generation and transmission facilities on a combined system "pool" basis. Pool costs are shared pursuant to the AEP Interconnection Agreement, which has been amended from time to time by the AEP operating companies. The AEP Interconnection Agreement expressly provides, among other things, for the sharing of the costs of generation facilities used in the integrated operation of the AEP system. The AEP Interconnection Agreement does not, however, contain any express provision for the sharing of the costs of transmission facilities used in the integrated operation of the AEP system. That is the function of the Transmission Equalization Agreement ("TEA"). The TEA provides for the sharing of the costs of the system's Extra High Voltage transmission facilities among the AEP operating companies. With respect to CSW, the CSW Operating Agreement provides for the coordination of construction and operation of jointly-owned facilities; unit sales to assist companies to meet 33 36 capacity reserve levels; emergency energy; economy energy; off-system sales and purchases; and central load dispatching. Schedule A of the CSW Operating Agreement provides for planning and construction of joint units to be owned by the CSW operating companies in percentages allocated by the CEO "to achieve a Prorated Reserve Level" for all participating companies. Schedule B lists the ownership by individual CSW operating companies of particular generating units. Basically, the agreement preserves the planning and investment in generation by the four operating companies when they were independently operated and, at the same time, integrates and coordinates the planning and investment of the CSW integrated system. b. Central Dispatch Planning and Central Economic Dispatch. AEPSC will coordinate the planning, operation and maintenance of generating capacity resources and jointly dispatch 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 joint dispatch 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. In this way, the Combined Company will jointly dispatch the Combined System upon consummation of the Merger. Post-Merger, there will be two data relay centers; one in Dallas and the other in Columbus. Central Economic Dispatch will run on a computer system (EMS). The EMS will control all generating units in the Combined System to the desired economic base points adjusted 34 37 for frequency control requirements of the respective control areas. These centers will be staffed with personnel 24 hours a day, 365 days a year. Merger transition teams are currently designing the organizational structure and job responsibilities. c. 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 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. d. 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 35 38 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.(3) Thus, the Applicants would continue to use the HVDC ties to integrate CSW's Texas assets with its non-Texas assets in the same manner that previously has been approved by the Commission. e. Future Participation in an RTO On June 3, 1999, AEP and four other utilities filed the Alliance RTO Application, which was conditionally approved by FERC on December 20, 1999, a copy of which is filed as Exhibit D-1.8 and incorporated by reference. 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.(4) 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. - ---------- (3) 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 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. (4) 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. 36 39 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,(5) FERC found that an RTO would improve efficiencies in the management of the transmission grid (RTO NOPR at page 33,716); would improve grid reliability (Id.); would improve market performance (RTO NOPR at page 33,717); and would facilitate lighter governmental regulation (Id.). It is FERC's view that all utilities should participate in a FERC-approved RTO. 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 - ---------- (5) Notice of Proposed Rulemaking, Regional Transmission Organizations, Docket No. RM99-2-000, 87 FERC ss. 61,173 (May 13, 1999) ("RTO NOPR"). 37 40 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 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. On December 31, 1999, Applicants executed Amendment No. 1 to the Merger Agreement which provides that either AEP or CSW may terminate the Merger Agreement after June 30, 2000 if the Merger has not been consummated by that date. 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: 38 41 - - 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 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. 39 42 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 6, 7, 12, 32 and 33 Issuance of AEP Common Stock; amendment to AEP's financing and rules existing authority to allow the Combined Company to engage in thereunder 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 and Merger common rules thereunder 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. 40 43 13 and rules Merger of CSWS into AEPSC with AEPSC as the surviving thereunder 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; - - 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 41 44 (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: (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 42 45 (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. 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. 43 46 SEC, 1994 WL 704047 (D.C. Cir. Nov. 16, 1994) on remand, Entergy Corp., HCAR No. 26410 (Nov. 17, 1995) (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 third (two categories) to the sixth largest (two categories) public utility system in the United States depending on the criterion of measurement. Giving effect to the Merger as of December 31, 1998, on a pro forma basis, the Combined Company would have ranged from the largest (two 44 47 categories) to the sixth largest public utility system in the United States, again depending on the criterion of measurement. (As of December 31, 1998)
Electric U.S. Operating Total Electric U.S. Sales Market Generation System Revenues Assets Customers in KwH Capitalization Capacity ($Millions) ($Millions) (Millions) (Billions) ($Millions)(a) (MWh) Duke 17,610 26,806 2.0 82.0 23,255 17,300 Southern 11,403 36,192 3.8 164.3 20,280 31,159 Entergy 11,495 22,848 2.5 113.2 7,669 21,727 PG&E 19,942 33,234 4.6 77.9 12,052 10,938 AEP 6,346 19,483 3.0 130.4 9,027 23,759 CSW 3,488 13,744 1.7 67.0 5,833 14,205 Combined Company 9,834 33,227 4.7 197.4 14,860 37,964 Proposed PECO/Unicom 11,972 38,748 4.9 172.5 16,211 30,039 Combined (b)
(a) Based on number of shares outstanding multiplied by the closing stock price at December 31, 1998. (b) Recently announced merger which would form a new registered holding company. Sources: POWERdat database (Resource Data International, Inc.); Form 10-K and Form 10-Q Filings; 10 Year Statistical Reports; and Annual Reports. The table above does not reflect Applicants' agreement 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, 1998, Duke, Southern, Entergy, PECO/UNICOM and PG&E would have been larger than the Combined Company in terms of operating revenues; Southern, PECO/UNICOM and PG&E would have been larger than the Combined Company in terms of total assets; and Duke, PECO/UNICOM and Southern would have been larger than the Combined Company in total market capitalization. In addition, the Combined Company would be sixth largest in terms of operating revenues, fourth largest in terms of total assets and market capitalization; and second largest in terms of total U.S. electric customers. 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 45 48 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"). 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").(6) 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 11 percent to 15 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.
Number of Net Electric Utility Electric Electric Total Net Plant Revenues Customers 12 Total Sales Generation ($Thousands) ($Thousands) Mo. Avg. (MwH) (MwH) Combined Company 18,589,138 9,833,518 4,733,734 197,345,794 192,992,107 Region (b) 172,487,197 84,261,562 33,525,779 (a) 1,558,199,149 1,332,170,731 % of total 11% 12% 14% 13% 15%
- ---------- (6) 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. 46 49 represented by Combined Company (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 distributor customers and Southwestern Power Administration has 92 customers comprised of municipalities, federal agencies and cooperatives. (b) The Region includes the Interconnected Utilities and the Combined Company Sources: POWERdat database (Resource Data International, Inc.); Form 10-K and Form 10-Q Filings; 10 Year Statistical Reports; and Annual Reports. Specifically, as the table above indicates, at December 31, 1998, 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 (11%); electric revenues (12%); number of electric customers (14%); MwH sales (13%); and total net generation (15%). 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 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.(7) 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. - ---------- (7) The "state of the art" is discussed in depth in Item 3.B.1.a below. 47 50 (ii) Antitrust Considerations The Commission's analysis under Section 10(b)(1) also includes a consideration of federal antitrust policies.(8) 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 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. As explained more fully herein, the FERC Administrative Law Judge has recommended that the FERC find the Merger to be consistent with the public interest based, in part, upon the absence of adverse competitive consequences 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 - ---------- (8) See, e.g., Conective, HCAR No. 26832 (Feb. 25, 1998)[hereinafter "Connectiv"]. 48 51 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. ii(a). The Role of the DOJ Pursuant to the HSR Act, AEP and CSW are required to file with the Antitrust Division 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 proposed transaction and, where the competitive consequences appear substantial, to permit the Antitrust Division to challenge the legality of the transaction."(9) The HSR Act prohibits consummation of the Merger until the statutory waiting period has expired or been terminated. On July 26, 1999, Applicants filed with the Antitrust Division under the HSR Act. On August 26, 1999, AEP and CSW received a request for additional information from the Antitrust Division. AEP and CSW filed the additional information with the Antitrust Division in November 1999. On February 2, 2000, the Antitrust Division notified Applicants that it had completed its review of the Merger and that no further action is warranted. 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. On November 23, 1999, the ALJ at FERC issued an Initial Decision which found that the Applicants met their burden of establishing that the Merger would not produce adverse competitive effects (see Exhibit D-1.7, page 9). The ALJ further found that AEP and CSW demonstrated that the Merger "will not give [them] the ability to use transmission to affect competition in an adverse manner." Id. With respect to ratepayer protection measures that were offered by Applicants, the ALJ found that the ratepayer protection measures "provide full protection for wholesale requirements and transmission customers from any adverse rate consequences resulting from the proposed merger." Id., page 11. The ALJ further found that these ratepayer protections "are more than sufficient to ensure that affected ratepayers do not pay any merger costs that [AEP and CSW] incur in excess of merger benefits." Id. In sum, the ALJ concluded that 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.(10) A final decision from FERC approving the Merger is expected no later than March, 2000. - ---------- (9) Premerger Practice Notification Manual at xi (American Bar Association 1991). (10) 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). 49 52 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. The Administrative Law Judge at FERC agreed that Applicants' mitigation plans eliminate any Guidelines screen failures attributable to a combination of Applicants' generating facilities (see Exhibit D-1.7, page 9). 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 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 50 53 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. The Texas Decision approved Applicants' agreement 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 load demand requirements following electric industry restructuring in Oklahoma and no longer being 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 51 54 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 was conditionally approved by FERC on December 20, 1999. 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. The Texas Decision affirmed Applicants' agreement to 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 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.(11) By utilizing the Combined Company's OATT, customers within the Combined Company's service territory will be able to - ---------- (11) Power Generation Markets Quarterly, First Quarter 1999. 52 55 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. The Administrative Law Judge at FERC concluded that Mr. Henderson disposed of fears of vertical market power being vested in the Applicants (see Exhibit D-1.7, page 9). 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. The Administrative Law Judge at FERC found that the Merger will produce no adverse competitive effects. A final decision from FERC approving the Merger is expected no later than March, 2000. 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. 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 53 56 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. 54 57 (i) Competitive Negotiations 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 55 58 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. 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 56 59 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. 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. 57 60 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. 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 CSW - -------------------------------------------------------------------------------------------------------------- High Low Dividends High Low Dividends - -------------------------------------------------------------------------------------------------------------- 1996 1st Qtr ......... 44-3/4 40-1/8 0.60 28-1/2 26-3/8 0.435 2nd Qtr ......... 42-3/4 38-5/8 0.60 28-7/8 26-1/2 0.435 3rd Qtr ......... 43-1/8 40 0.60 28-1/2 25-3/4 0.435 4th Qtr ......... 42-1/2 39-1/2 0.60 28 25-1/2 0.435 - -------------------------------------------------------------------------------------------------------------- 1997 1st Qtr ......... 43-3/16 40 0.60 25-3/4 21-1/4 0.435 2nd Qtr ......... 42-1/2 39-1/8 0.60 22-7/8 18-1/4 0.435 3rd Qtr ......... 46-5/8 41-1/2 0.60 22-7/16 19-3/4 0.435 4th Qtr ......... 52 45-1/4 0.60 27-5/16 20-5/8 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. 58 61 (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]."(12) 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(13) shall have occurred and that there shall exist no fact or 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 expect to incur total transaction and regulatory related 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 - ---------- (12) "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. (13) "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 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." 59 62 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 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)). 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 60 63 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, 1998, the respective capital structures of AEP and CSW were as follows:
AEP CSW (in $ millions) (in $ millions) Common Stock Equity ............ $ 4,842 40.28% $ 3,624 45.75% Preferred Stock ................ 174 1.44% 176 2.22% Long-Term Debt ................. 7,006 58.28% 3,785 47.80% Trust Preferred Securities ..... -0- -0- 335 4.23% Total ......................... $12,022 100.00% $ 7,920 100.00%
If the Merger had been consummated on December 31, 1998, the pro forma consolidated capital structure of the Combined Company as of such date (according to generally accepted 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 ......................... $ 8,466 42.34% Preferred Stock ............................. 350 1.75% Long-Term Debt (a) .......................... 10,844 54.23% Trust Preferred Securities .................. 335 1.68% Total ...................................... $19,995 100.00%
(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 42.34% 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 61 64 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. 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 62 65 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 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; 63 66 (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)). As demonstrated below, the Merger meets each of these standards. 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 64 67 cited with favor U.S. Supreme Court and Circuit Court of Appeals cases(14) that recognized the need of an agency to "adapt [its] rules and policies to the demands of changing circumstances"(15) and to "treat experience not as a jailer but as a teacher."(16) 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. 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. In order to - ---------- (14) 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). (15) NIPSCO, supra, citing Rust v. Sullivan at 186-187. Accord, Sempra, supra at n. 23. (16) NIPSCO, supra, citing Shawmut Assn. v. SEC at 796-97. Accord, Sempra, supra at n. 23. 65 68 facilitate the development of non-utility generation, many states, including Texas, Louisiana and Ohio, developed integrated resource planning requirements that require utilities to focus on both supply-side and demand-side resources and to competitively bid their resource procurement requirements to obtain the lowest cost available. As a result of these initiatives at both the federal and state levels, the share of nationwide generating capacity from non-utility generators has more than tripled from 3.6 percent in 1987 to 11.5 percent in 1999. In fact, since 1990, non-utility generators have contributed half of all new investment in generating facilities. See Edison Electric Institute, Directory of Electric Power Producers, 106th ed. (1999). 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. Order No. 888 was intended to facilitate third-party utilization of the transmission grid in order to develop a more competitive market for wholesale power transactions. Under Order No. 888, a utility must transmit power for third parties upon their request, on either a firm or non-firm basis. If the transmitting utility does not have sufficient capacity to transmit the power on a firm basis, it must either offer to expand its transmission system to accommodate the request or, if appropriate, to redispatch generation to relieve constraints and thereby make capacity available. In the interim, a utility must offer transmission on a non-firm basis to the requesting entity. In response to deregulation in the wholesale market for electricity, most 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 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.(17) Attached as Appendix A is a summary of the status of state electric restructuring activities in the states in which the Combined Company will operate. - ---------- (17) Again, the state restructuring initiatives are not the subject of this Application. The Combined Company will seek such additional approvals, as may be required, in connection with state-mandated restructuring. 66 69 In conjunction with the implementation of retail restructuring, many states are requiring that utilities divest themselves of utility generating assets. For example, in Texas, no power generation company may own and/or control more than 20% of the installed generation capacity in ERCOT. In Arkansas, the Arkansas Commission can force divestiture of generation assets to alleviate market power. As a result of these actions, since August 1997, more than 50,000 MW of generating capacity has been sold (or is currently under contract to be sold) by utilities, and an additional 30,000 MW is currently for sale. In total this represents more than 10 percent of U.S. generating capacity.(18) 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 570 marketers have registered with the FERC to trade in electric power. See Edison Electric Institute, Directory of Power Producers, 106th ed. (1999). 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. - ---------- (18) RTO NOPR at page 33, 690. 67 70 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 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."(19) 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 - ---------- (19) Rodney E. Stevenson & David W. Penn, "Discretionary Evolution: Restructuring the Electric Utility Industry," Land Economics, Vol. 71, No. 3 (Aug. 1, 1995). See also Paul L. Joskow, "Electricity Sectors in Transition," The Energy Journal, Vol. 19, No. 2 (Apr. 1, 1998) (noting the changes occurring to the "traditional industrial structures" due to "technological advances that have expanded the geographic expanse over which integrated AC networks can be controlled reliably . . ."); Jason Makansi & Robert Swanekamp, eds., "Powerplant IT Benchmarks Power to Process Industries," Power Magazine, Vol. 140, No. 5 (May 1, 1996) (reporting that in order to "adapt[] organizational structures to the IT systems" utilities are organizing "tactical group[s] . . . around [a central information "hub"], not around individual plants, geography, etc"); "Automation Developments," Transmission & Distribution World (Apr. 30, 1998) (identifying Allegheny Power's recent purchase of "a computerized maintenance management system (CMMS) program to help it with utility-wide substation maintenance of a grid that spans 29,000 sq miles (75,000 sq km), seven regional offices and 41 service centers [and serves] customers in portions of Maryland, Ohio, Pennsylvania, Virginia and West Virginia") 68 71 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 betweenthe 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 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. 69 72 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 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 70 73 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 Commission has long noted that electric utility systems could be integrated without direct interconnections. E.g., Unitil (interconnection by contractual right to use third-party's transmission even though no particular lines would transfer power). In Unitil, the Commission found that three noncontiguous electric distribution territories were sufficiently capable of interconnection due to contractual rights to use a third-party's transmission service, even though no particular lines would transfer power among the companies. Unitil at 564-66. The description of the transmission arrangements in Unitil -- "power will be delivered through a non-affiliate system and a transmission charge will be paid" id. at 566) -- is analogous to the transmission service requested across Ameren. 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. 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 71 74 this limit.(20) See Dr. Hieronymus' testimony filed as an exhibit to Exhibit D-1.2. This is sufficient to allow the Combined System to be physically interconnected or capable of physical interconnection, which is the standard applied under the Act. 15 U.S.C.ss.79b(a)(29)(A). Accord WPL Holdings, supra, wherein the Commission held that interconnection through a 200 MW firm transmission contract met the standards of the Act. Capacity exchanges will be made between the east zone and the west zone for periods of one year or less when one zone has capacity available for sale and the other zone needs capacity to meet its reserve requirements, and when the selling region's capacity market price is lower than the buying region's cost of installing capacity or purchasing such capacity in the market. In this regard, the production cost modeling studies conducted by the Applicants indicate that, during the first ten years of post-Merger operations, the Combined Company will be able to economically transfer 250 MW from the east zone to the west zone 87.5 % of the time and from the west zone to the east zone 4.3% of the time.(21) See Testimony of J. Craig Baker at page 24. 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.(22) 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. - ---------- (20) 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. (21) The underlying study, the results of which are set forth in Exhibit D-2.1, focused on production costs and the cost of transmission over the Contract Path, and did not factor in the potential for the wholesale market to address production cost differences between the east and west zones. Applicants have not conducted a study solely for the purpose of determining the effect of various wholesale market conditions upon Contract Path utilization. (22) 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). 72 75 (ii) Single Interconnected and Coordinated System Under normal conditions, the Combined System will be "economically operated as a single interconnected and coordinated system" as required by the second clause of Section 2(a)(29)(A). The Commission has noted that, 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." Conectiv, supra, citing The North American Co., HCAR No. 3466 (April 14, 1942), aff'd, 133 F.2d 148 (2d Cir.1943), aff'd on constitutional issues, 327 U.S. 686 (1946). Cf. Section 1(b)(4) of the Act which cites, as one of the problems the Act was intended to address, the harm to the public interest and the interest of investors and consumers "[w]hen the growth and extension of holding companies bear[] no relation to economy of management and operation or the integration and coordination of related operating properties." The Commission and the courts have emphasized this aspect of the coordination requirement in recent decisions. In 1992, in a matter involving Entergy, intervenors argued that the system would no longer be "economically operated", as required by the second clause of Section 2(a)(29)(A), as the result of the transfer of spun-off certain generating facilities from system utilities to an unregulated affiliate. The problem, identified by intervenors, was that power from these facilities would no longer be offered first for in-system use. The Court of Appeals for the District of Columbia Circuit noted that: Although that reading might be consistent with the words of section 11 [and, by implication, Section 2(a)(29)(A)], it is by no means the required one. The Commission reads "economically" to impose a less stringent requirement, i.e., that facilities, in addition to their physical interconnection, be consolidated so as to take advantage of efficiencies. We are satisfied that the Commission's interpretation neither contravenes Congress's intent nor is "unreasonable." City of New Orleans v. SEC, 969 F.2d 1163 (July 17, 1992), citing Chevron U.S.A. Inc. v. Natural Resources Defense Council, Inc., 467 U.S. 837 (1984) (emphasis added). In this regard, the Court of Appeals anticipated the situation that is faced by system operators today, in which there is a "tool kit" of resources that can be used to obtain the maximum benefits for the Combined System. The emphasis on economical operation of the system as a whole was reinforced by the 1999 Madison Gas decision, in which the D.C. Circuit expressly found that "section 2(a)(29)(A) requires that a system's combined `assets' (and not the interconnection in particular) be economically operated." Madison Gas, supra. The coordination requirement was recently addressed in Unitil, supra. In that case, the Commission concluded that the merged system was sufficiently coordinated by means of factors 73 76 which will also be present in the Combined System, specifically, "centralized dispatch and . . . [the] coordinated planning, construction, operation and maintenance of generation and transmission facilities." Unitil, at 565 (footnotes omitted).(23) In its analysis of the coordination requirement, the Unitil decision places particular emphasis on the importance of centralized dispatch: Section 2(a)(29) further requires that the utility . . . be "economically operated as a single interconnected and coordinated system." The Commission has interpreted this language to refer to the physical operation of utility assets as a system in which . . . the generation and/or flow of current within the system may be centrally controlled and allocated as need or economy directs. Unitil, at 566 (footnote omitted).(24) 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)). As explained more fully herein, there will be "joint dispatch" of the generating units of the Combined System within the meaning of Commission precedent. It is important to note, however, that federal deregulation and state restructuring initiatives have dramatically altered the way in which the electric utility industry coordinates and integrates electric utility operations. As a result, joint dispatch is but one aspect of the economic operation of a single interconnected and coordinated system. Accordingly, this filing addresses means, in addition to simple joint dispatch, of coordinating the operations of the Combined System. (a) Joint Dispatch - ---------- (23) See also Electric Energy, Inc., 38 SEC 658, 670-71 (1958) (acquired company satisfies "coordinated system" standard if its "generation, transmission and distribution" functions can be efficiently coordinated with the existing system through communications equipment, joint dispatch and joint planning). (24) This passage from Unitil also stresses the need for "flexible considerations" in applying the Act's integration requirements. Unitil, at 566. 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. 74 77 AEP and CSW will have joint dispatch which will be implemented by means of a System Integration Agreement and the System Transmission Integration Agreement, along with the use of Central Dispatch Planning and Central Economic Dispatch software programs. It should be noted that the term "joint dispatch" is nowhere defined in the Act or the rules thereunder. Consistent with the precedent discussed above, the term "joint dispatch" in this application refers to the ability of an integrated system to dispatch its generation on a least-cost basis, taking into account various operating conditions, to achieve the maximum efficiencies in the operation of the subject assets. In the instant case, a single control center will schedule the generating resources of the Combined System on a day-ahead and an hour-ahead basis. The joint dispatch of all of the power supply resources of the Combined System will be controlled by this center. The generating resources of the Combined System will be jointly dispatched on a least-cost basis. Subject to currently prevailing constraints, unit commitment will be performed to meet the Combined System's obligations, taking into account the specific obligations within each control area.(25) The control areas will be jointly dispatched in real time to minimize total generation costs for the Combined System, subject to currently prevailing transmission constraints. The Combined System will have firm transmission rights over the Contract Path. The joint dispatch of the Combined System will be performed in two steps. o The first step is unit commitment. In this step, the system operator projects the system peak load requirements for a period and, to meet that requirement, schedules available generating units to be on-line in economic order subject to any operational or other constraints. The system operator will not load the less economic units unless the load requires them. The system operator will also examine the energy market to determine if reliable energy can be purchased at lower cost in order to avoid loading higher cost generating sources. o The second step is the incremental loading of the on-line generation sources and purchases. This step is performed continuously as each unit's available generation is dispatched above its minimum load in order to match the generation to the load. Generation of the Combined System's various units will be dispatched from lowest to highest cost. The joint dispatch will be consistent with available firm transmission, including the HVDC ties connecting the ERCOT and non-ERCOT components of the west zone and the Contract Path between the east zone and the west zone. See Testimony of J. Craig Baker, filed as Exhibit D-1.2. Following the Merger, there will be - ---------- (25) In determining the Combined System's generation dispatch priorities, each zone's most economic generation will be used to serve its native load customers and previously committed firm load contracts. 75 78 two data relay centers, one in Dallas and the other in Columbus. A computer system (EMS) will control both the CSW and the AEP generating units to the desired economic base points adjusted for frequency control requirements of the respective control areas. These centers will be staffed with personnel 24 hours a day, 365 days a year. Merger transition teams are currently designing the organization structure and job responsibilities. AEPSC will engage in the joint dispatch of the Combined System through Central Dispatch Planning and Central Economic Dispatch of the generation units of the Combined System. 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 Central Economic Dispatch program will be the current CSW dispatch program, modified to take into account the internal transmission capabilities of the Combined System.(26) It will jointly dispatch all of the generators of the Combined System by calculating at regular intervals (currently every four seconds) the most economic generation dispatch base points resulting from current operating conditions. These conditions include, but are not limited to, the amount of load to be served, cost of fuel, current loading of the generators, reserve obligations, fuel constraints and transmission capabilities. After the economic-based points have been calculated on a joint basis, the EMS will transmit that information to the data relay centers in Dallas and Columbus. The respective data relay centers will send this information to the Combined System's generating units, thereby assuring the desired economic base points adjusted for frequency control requirements of the control areas. The economic base points for the generators located in the eastern zone will be transmitted to the data relay center in Columbus via a high-speed data link. The Central Economic Dispatch program is designed to achieve the most economic dispatch of the total generation of the Combined System. This program must honor certain physical conditions of the system. The generation dispatch is controlled in order not to overload transmission lines or exceed the capability of the interconnections. The program must also honor limitations on generating units, as they appear from time to time. Capacity exchanges will be made between the east zone and the west zone for periods of one year or less when one zone has capacity available for sale and the other zone needs capacity to meet its reserve requirements, and when the selling region's capacity market price is lower than the buying region's cost of installing capacity or purchasing such capacity in the market. In this regard, the production cost modeling studies conducted by Applicants indicate that, during - ---------- (26) This dispatch system is currently used by CSW to coordinate its SPP and ERCOT operations. 76 79 the first ten years of post-Merger operations, the Combined Company will almost always be able to economically transfer 250 MW between the east and west zones (resulting in a 91.9% utilization of the Contract Path). When economic energy is expected to flow that would exceed the 250 MW Contract Path, then non-firm transmission service would be requested from third parties to accomplish the joint dispatch. As explained in the Application, the Combined System will make use of its rights to nominate secondary points of receipt and delivery under its transmission service agreements with WR and Ameren for transfers of capacity from the west zone to the east zone. For transfers of economic energy in excess of the Contract Path, Applicants will use the OATT of neighboring utilities to effect delivery. The transfer limits of the Central Economic Dispatch program would be adjusted to reflect the transmission conditions occurring in real-time. The System Integration Agreement gives legal effect to the foregoing technical description. (b) Other Aspects of Coordination Applicants will coordinate the operations of the Combined System in other ways. As noted above, industry restructuring and deregulation have made obsolete a view that looks solely to joint dispatch as a measure of coordination and integration. Accordingly, Applicants intend, within the bounds of regulatory constraints, other more modern means of coordinating the Combined System. Thus, (i) joint marketing and trading efforts will take advantage of the Combined System's generation capacity, wholesale customer base, diversity of weather, time and fuel supply; (ii) AEPSC will coordinate the design and purchase of new generating facilities, the operation and maintenance of generating capacity resources, centralized trading and marketing activities, the acquisition and provision of transmission services needed for inter-zone power transfers, billing and administration, and other administrative services; and (iii) information system networks, customer service, procurement organizations, organizational structures for power generation, energy delivery and customer relations, and support services will all be centrally coordinated. (1) Coordinated Trading Operations The Combined System will coordinate through its joint marketing and trading efforts, both as a buyer and as a seller. System dispatchers will continually monitor the generation needs and supply of the Combined System. The rapidly evolving wholesale power markets surrounding the energy industry will allow the Combined System to operate its generation assets as a single system by buying and selling power to decrease the overall production costs of the Combined System. The diversity of generation capacity, wholesale customer base, weather, time, fuel supply and localized economic conditions of the Combined System will create opportunities to allocate resources more efficiently. This can be accomplished in a number of ways in addition to physically moving power from one zone to another. For example, power can be delivered to and from various parts of the Combined System by neighboring utilities using their respective transmission systems. Upon consummation of the Merger, joint purchases can be made and dispatched to the operating companies in a manner that would achieve the greatest benefits. Weather diversity would make these purchases more 77 80 economically efficient as changes in daily and hourly load forecasts can be accommodated by joint purchasing and coordinated dispatch. This ability to diversify supply over a broader region with diverse weather and time zones is another way that companies can achieve the benefits of economic integration in a market-based commodity like electricity. In addition, the Combined System also anticipates making use of the competitive power markets to maximize efficiency and coordination on the Combined System. The trading and marketing operations of the Combined System will be conducted by, and on behalf of, the regulated side of the business. Briefly stated, power trading and the generation business have a synergistic relationship. Trading assists the generation function in terms of price discovery and "finding" the customer. It provides an opportunity to create value when, for example, there is a difference between gas and electric prices. Trading will also enable the Combined System to manage risk that might otherwise be associated with a change in market prices. Ownership of generation provides, among other things, industry expertise and knowledge that enable the traders to make more-informed decisions, for the benefit of both shareholders and customers. As noted previously, in the past, electric utility companies operated as self-contained, regulated monopolies that sold their product almost exclusively to their captive retail customers. By and large, a traditional utility's customers were limited to those end-users situated in that utility's service territory. A traditional utility created the most value for its shareholders by incurring the least possible costs to generate just enough electricity to serve its native load. Achieving a constant uniform cost of production across a system necessarily resulted in the greatest return for investors. Federal deregulation and state restructuring have materially altered this paradigm. Today there is a vibrant market for electricity. A utility sells electricity not only to the customers located in its service area, but also to wholesale customers. The importance of trading operations was magnified by passage of the Energy Act and the issuance of FERC Order Nos. 888 and 889. One commentator has recently described the resulting markets as follows: What resulted is a highly competitive and sophisticated 24-hour power market. . . . Next we examine what a happens in "real-time." . . . Economic power schedulers, working in the front office, monitor the utility's entire real-time system, making sure that the planners have accurately matched the power supply assets with the hourly demand or native load. Economic power schedulers also make sure that the planners have utilized the least expensive power supply assets. Schedulers may also make adjustments to the power plan in order to maximize the goals of reducing costs providing customers with the lowest possible wholesale prices. To make these adjustments economic power schedulers rely on available power supply assets and the hourly or "spot" market. Unexpected changes in the weather, mechanical problems at the generating station and congestion on the transmission grid are only a few of the factors that can result in deviations from the planner's schedule. Let's assume the scheduler needs an additional 10 MW of power for two hours, one hour from now. He or she . . . may consult a data screen that displays the 78 81 real-time spot-market price and the incremental cost of generation or the cost of producing the additional or next 10 MW of electricity. If the incremental cost of generation is less than the market price, the power scheduler may ask the generating plant to increase production or start a peaking unit. If the price of power from pre-existing contracts is less than the spot market price or generation, the scheduler may draw upon the amount of electricity stipulated in the contract. But if the spot market price is less than the incremental cost of generation or contract power, the scheduler may notify the traders in the "front office." They immediately go to the spot market and begin the buying process. The economic power scheduler may also find that the utility is "long" on power or has excess capacity for several hours. The traders may now begin the selling process. Trading in the spot market has the same requirements as day-ahead, weekly and monthly trading except that it happens at a much faster pace. Spot market trading averages less than 20 minutes for securing a buyer or seller scheduling transmission or obtaining an NERC tag, applying competitive intelligence and price and credit risk management, confirming the trade and notifying billing, finance and accounting in the "back office." Nelson, Kenneth C., "The New World of Power Marketing," Management Quarterly, v. 40, pp. 13-32 (Spring 1999). To summarize, today a utility creates value by selling as much electricity as it can do so profitably, after meeting the requirements of native load. Whether electricity can be sold profitably is controlled by a variety of factors: the prevailing price of electricity, the location of the potential customer, the price of fuel, and other factors. As these factors have proven to be volatile, many utilities have created trading groups composed of individuals with specialized, sophisticated skill sets necessary to predict market behavior and to devise appropriate trading strategies. These trading strategies necessarily have an impact on that particular utility's generation plans. In other words, if the price of electricity is such that a utility can sell electricity profitably, the trading group will direct that utility's generating units to generate electricity to capacity. If, on the other hand, the price of electricity is so low that it is cheaper to purchase electricity to meet native load instead of incurring production costs, then that trading group will direct its generating units to curtail operations. (2) Coordinated Operations The Combined System will also be coordinated in a variety of ways beyond simply the coordination of the generation and transmission within the system. Among other things, AEPSC, as the designated agent under the System Integration Agreement, will coordinate the planning and design or purchase of new power resources; the operation and maintenance of generating units; joint dispatch; centralized trading and marketing activities, the acquisition and provision of transmission services needed for inter-zone power transfers, and billing and administration. All 79 82 of these functions are to be provided on a Combined System basis, treating the east zone and the west zone on an integrated basis. (3) Coordinated Administrative and General Services The coordination and integration of the Combined System is expected to be further achieved through the coordination and integration of information system networks; customer service; procurement organizations; organizational structures for power generation, nuclear generation, and energy delivery and customer relations; and support services. Many administrative and general services will be performed for the Combined System by AEPSC. In applying the integration standard, the Commission has historically looked beyond simply the coordination of generation and transmission within the system to the coordination of other activities.(27) As noted above, the Court of Appeals for the District of Columbia Circuit has recently made clear that the Commission can appropriately look to "a system's combined 'assets' (and not the interconnection in particular)" in determining whether the coordination requirement is met. Madison Gas, supra at n.4. At issue in that matter was the cost of the interconnection in view of the estimated production cost savings from a proposed merger. In Madison Gas, the Court of Appeals determined that in analyzing whether a system will be economically coordinated, the focus must be on whether the acquisition "as a whole" will "tend toward efficiency and economy." Id.(28) The Merger will clearly meet this standard. As explained in the Application, CSW and AEP estimate that the net savings from the Merger will exceed $2 billion over 10 years. All aspects of the Combined System will be centrally and efficiently planned and operated. As with the integrated systems in other Application-Declarations approved by the Commission, the Combined System in this matter will be capable of being economically operated as a single interconnected and coordinated system as demonstrated by the variety of means through which - ---------- (27) See, e.g., General Public Utilities Corp., HCAR No. 13116 (Mar. 2, 1956) (integration is accomplished through power dispatching by a central load dispatcher as well as through coordination of maintenance and construction requirements); Middle South Utilities, Inc., 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); North American Company, 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). (28) The Court of Appeals further noted that "[b]y its terms, however, section 10(c)(1) does not require that new acquisitions comply to the letter with section 11." Id. at 1144. 80 83 its operations will be coordinated and the efficiencies and economies expected to be realized by the Merger. (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." As Mr. Ganson Purcell, Chairman of the Securities and Exchange Commission, testified before the Subcommittee of the House Committee on Interstate and Foreign Commerce in 1946 concerning this standard of the Act: 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. . . .(29) 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. . . .(30) No absolute size limitation is specified. 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 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.(31) - ---------- (29) 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). (30) Id. at 857 (referring to American Gas and Electric system). (31) Another way to analyze what should constitute an "area" or "region" is to examine how potential competitors of the Combined Company operate in the marketplace. In its 1998 Annual Report, Enron Corporation described itself as the "premier integrated energy merchant in the rapidly growing competitive North American wholesale energy market." Enron 1998 Annual Report, p. 13. In the same section of the report, Enron states that it has generation under construction in Mississippi and Tennessee, has acquired generation within ten miles of New York City, and has gas storage available in Houston, with the ability to move electricity and gas from Houston to the East Coast or Midwest "on a moment's notice" (id., p. 14). The Report also contains a multi-colored map of "Wholesale Energy Operations and Services, North America" showing a nationwide network of gas pipelines and electric grid, with generation assets stretching from California to New York. Enron is operating on a hemispheric basis, with operations in Canada and the United States, and with offices in Mexico. From Enron's perspective, the appropriate "area or region" is at least as large as the entire United States. 81 84 The 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 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"(32) in light of "the state of the art and the area or region affected" as discussed in Item 3.B.1.a.(iv) below.(33) - -------------------------------------------------------------------------------- Other companies similarly view the appropriate marketplace on a nationwide basis. For example, the Southern Company has electricity generation and/or distribution operations in nine states, including Alabama, Georgia, Florida, Mississippi, Virginia, Indiana, Massachusetts, Texas and California, and is constructing new gas distribution projects in North Carolina and Maine. Entergy Corporation provides services in several states, including supplying electricity in Arkansas, Louisiana, Mississippi and Texas, as well as in Massachusetts via its nuclear power subsidiary. Duke Energy Corporation, headquartered in Charlotte, North Carolina, furnishes energy-related services in North and South Carolina, is currently developing electric generation plants in Connecticut, Missouri, Florida, California, Texas and Virginia, and offers energy trading and marketing services in New York, Rhode Island, Pennsylvania, Indiana, Georgia, South Carolina, Texas, Oklahoma, New Mexico, Nevada and Utah. Edison International, in addition to its utility operating company subsidiary located in California, has twenty-three energy generation facilities located in Northern California, New Jersey, New York, Illinois, Pennsylvania, Florida, Washington, West Virginia and Nevada. PP&L, Inc., headquartered in Pennsylvania, provides energy related services in Pennsylvania, New Jersey, Maryland, Ohio, Delaware, West Virginia, Virginia and various New England states, recently acquired generation facilities in Maine, Oregon and Montana, and is developing power plants in Arizona and Connecticut. NRG Energy has generation facilities in California, Colorado, Connecticut, Florida, Illinois, Maine, Massachusetts, Michigan, Minnesota, New Hampshire, New Jersey, New York, North Carolina, Oklahoma, Pennsylvania, South Carolina, Utah, Virginia and Washington, and is developing generation facilities in Louisiana. Sempra owns a gas and electric utility company in California, has generation facilities in Connecticut, and has a gas pipeline in North Carolina. Other utilities view the marketplace on a global basis without regard to national borders. The FERC recently approved the acquisition of PacifiCorp by ScottishPower p.l.c. and the acquisition of New England Electric System (and the potentially indirect acquisition of Energy Utilities) by National Grid Group p.l.c., utilities located outside the United States. British Energy, through its interest in Amergen Energy, has indirectly acquired the Pilgrim Nuclear Plant from Boston Energy, the Three Mile Island Unit 1 from General Public Utility Systems, and the Clinton Nuclear Plant from Illinois Power Company. (32) 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. (33) In fact, as discussed in note 12 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. 82 85 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.(34) 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., 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. - ---------- (34) 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. 83 86 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.(35) 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 - ---------- (35) 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. 84 87 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.(36) 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 sellers to allocate gas to the highest bidding buyer." Id. at 78. Developments in the natural gas industry that have eroded traditional boundaries are being duplicated today in the electricity industry.(37) Many gas marketers are moving into the new - ---------- (36) 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. (37) 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 85 88 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. Electric utilities are in the process of divesting or separating their transmission and distribution assets from their generation assets. As a result of federal and state electric industry restructuring legislation, more than 570 energy marketing companies have registered with the FERC and are currently competing with electric utilities to market electricity on a wholesale and retail basis to customers who were previously an electric utilities' captive customers. Edison Electric Institute, Directory of Electric Power Producers, 106th ed. (1999). In short, as it has for the natural gas industry, the Commission can easily interpret the concept of "area or region" to include an area or region in which the merging companies both buy or sell electricity. 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. (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 - -------------------------------------------------------------------------------- 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). 86 89 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 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 87 90 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. 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, the Kentucky Commission, the Louisiana Commission, and the Michigan Commission approving the Merger, as well as the order of the Texas Commission finding the Merger consistent with the public interest, impose an extensive list of service quality standards on the utility operating companies operating within their states. In Oklahoma and Michigan, the Oklahoma Commission and the Michigan 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, Kentucky, and Michigan, 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 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. 88 91 Likewise, the order of the Texas Commission approved 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 jointly dispatch generating units under its control, make economic purchases of power, and supply power to its customers. The fact that certain generating capacity will 89 92 no longer be controlled by the Combined Company will not change the centrally coordinated, least-cost approach to operating the combined system.(38) - 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.(39) - ---------- (38) In fact, under the recent order of the Texas Commission, 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 Order, page 15. (39) 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. 90 93 The FERC's conclusion that the states will take appropriate action to protect their jurisdiction was correct.(40) 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 order of the Texas Commission approved several provisions designed to ensure the effectiveness of its 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 order specifically safeguards 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, Kentucky, and Michigan, and the order of the Texas Commission finds that the Merger is consistent with the public interest. 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. - ---------- (40) 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 order of the Texas Commission contains a similar provision. 91 94 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 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 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 92 95 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. 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 therequirements of Section 11(b)(2).4 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 - ---------- (41) 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. 93 96 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 nomore than two tiers of holding companies through the 'great-grandfather clause' of Section 11(b)(2).(42) 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.'(43) See also, - ---------- (42) 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.'). (43) 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 94 97 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). (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 - -------------------------------------------------------------------------------- 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.). 95 98 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 transitional structure certainly will not result in a 'highly-pyramided and complex holding company system' at odds with the purposes of the 1935 Act.(44) 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, - ---------- (44) 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. 96 99 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 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. 97 100 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).(45) These decisions are not apposite here, however, where the Commission has 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. The projected savings have not changed since the initial filing of this Application. Applicants continue to project $1,966 million of net non-fuel cost savings over the ten-year period immediately following consummation of the Merger. The State settlements have not affected these estimates because the States that have approved the Merger have accepted the Applicants' proposal to guarantee ratepayers certain Merger-related savings, regardless of whether these savings are actually achieved. The Applicants have also committed not to pass merger costs in excess of merger savings on to ratepayers. Based upon the resolution of issues related to the allocation of Merger-related savings between customers and shareholders of the - ---------- (45) 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. 98 101 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. In addition, FERC-jurisdictional customers will receive the benefits of Merger savings in future rate proceedings or through their current formula rates. Applicants also anticipate net fuel-related savings of approximately $98 million over this same period that will be passed on to customers. 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 joint dispatch of energy by the Combined Company. In this regard, fuel-related savings will result from the economic transfer of energy between the east zone and the west zone companies in order to displace relatively higher cost generation in one zone with relatively lower cost generation from the other zone. At the present time, the east zone operating companies and the west zone operating companies, respectively, interchange power within their zones under the terms of their respective operating agreements for the purpose of minimizing generation costs. Through the Merger, the Combined System will create additional opportunities for cost-effective energy transfers. In addition, based on the projected resource needs of both companies over the 1999-2002 time period, it appears that capacity transfers of up to 250 MW from the east zone to the west zone could be made.(46) 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 (a) $ 996 Elimination of Duplicate Corporate and Administrative Programs Administrative and General Overhead (b) 74 Advertising 20 Association Dues 4 Benefits 85 Credit Facilities 1 Directors' Fees 6 Facilities 81 Information Services (c) 440 Insurance 71 Professional Services (d) 213
- ---------- (46) Because of the volatility in the marketplace for firm capacity, Applicants have not attempted to quantify the capacity savings or reflect them in the fuel-related savings at this time. 99 102 Research and Development 11 Shareholder Services 9 Telecommunications 29 Purchasing Economies (Not Fuel-related) (e) 367 Total Savings 2,407 Less: Costs to Achieve (f) (248) Pre-merger Initiatives (193) Net Savings $ 1,966
(a) The position reductions are attributable to the Merger. The reduction opportunities arise from overlap and duplication in functional performance, rather than from stand-alone initiatives unrelated to the Merger. The total corporate and operations support position reductions were estimated to be 1,061 positions. (b) These costs are variable with the total number of positions and change as the number of positions increase or decrease. As position reductions are achieved through the Merger, miscellaneous overhead expenses are also reduced. (c) When the Merger is consummated, the Combined Company plans to consolidate the respective IS departments which will eliminate duplicative system development hardware, software and consolidate data center costs. (d) The savings calculated were generated from the reduction of the combined audit fees, legal fees, and general consulting services. (e) Savings represent an estimated 7-8% reduction in total material costs due to larger purchasing volumes and the availability of greater purchasing power. This amount was determined based on the experience of other companies, review of certain component per unit costs, management's knowledge of vendors and potential approaches to material standardization and vendor concentration. (f) 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 west zone and approximately $1,253 million will be allocated to the east zone. 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. 100 103 The allocation of savings among the operating companies was made using a Synergies Analysis prepared by Applicants and explained in more detail in the testimony of Thomas Flaherty filed with the Texas Commission. First, savings were categorized as either labor or non-labor. Labor savings were then further categorized into a functional area and a sub-functional area. For example, in his testimony filed with the Texas Commission, Mr. Russell Davis first identified savings for the finance area. Within that area, savings were then sub-categorized by payroll, accounts payable, general accounting, and other activities. Each of these subcategories was given a work order and assigned an allocation factor. General accounting, for example, received an allocation factor based on the number of general ledger transactions. In this way, the savings identified by work order and allocation factor were allocated to the appropriate subsidiaries. With respect to non-labor savings, the Synergies Analysis allocated savings in the same manner as labor savings by categorizing savings into functional and sub-functional areas. For example, the savings for professional services are split into the sub-categories of legal, auditing, accounting and finance, engineering and other. A synergy savings work order was assigned to each functional and sub-functional area based on an analysis of the companies benefiting from each area of savings. An allocation factor was assigned to each work order based on an analysis of the savings. For example, professional service savings for production engineering used the allocation factor "megawatts of generating capacity." The Synergies Analysis then allocated the identified savings to either the electric operating companies, the non-regulated subsidiaries, or the service company. In addition, Applicants allocated the costs to be incurred by Applicants in order to achieve savings to their subsidiary companies on a pro-rata basis. If for example, CPL received 12% of the savings, then CPL would pay 12% of the costs to achieve the savings and other related costs. The following table provides the amount of estimated Merger savings which has been allocated to each of AEP's and CSW's subsidiaries:
- ------------------------------------------------------------------------------ Company Name Total Savings less Pre-Merger Initiatives and Cost to Achieve ('000) - ------------------------------------------------------------------------------ AEP Regulated Savings - ------------------------------------------------------------------------------ KgPCo 9,090 - ------------------------------------------------------------------------------ APCo 324,532 - ------------------------------------------------------------------------------ KPCo 76,134 - ------------------------------------------------------------------------------ I&M 241,254 - ------------------------------------------------------------------------------ WPCo 9,298 - ------------------------------------------------------------------------------ OPCo 305,628 - ------------------------------------------------------------------------------ CSPCo 184,372 - ------------------------------------------------------------------------------ AEG 24 - ------------------------------------------------------------------------------ Cardinal Operating Company 1,872 - ------------------------------------------------------------------------------ Central Operating Company 12 - ------------------------------------------------------------------------------
101 104 - ------------------------------------------------------------------------------ Indiana-Kentucky Power Company 334 - ------------------------------------------------------------------------------ Ohio Valley Electric Cooperative 440 - ------------------------------------------------------------------------------ Buckeye Power Company 3,266 - ------------------------------------------------------------------------------ Central Appalachian Coal Co. -- - ------------------------------------------------------------------------------ Central Coal Co. 2 - ------------------------------------------------------------------------------ Central Ohio Coal Company 5,732 - ------------------------------------------------------------------------------ Windsor Coal Co. 6,776 - ------------------------------------------------------------------------------ Southern Ohio Coal Co. 22,384 - ------------------------------------------------------------------------------ Southern Appalachian Coal Co. -- - ------------------------------------------------------------------------------ Cedar Coal Co. 6 - ------------------------------------------------------------------------------ Water Transportation Division 5,218 - ------------------------------------------------------------------------------ Cook Coal Terminal 1,320 - ------------------------------------------------------------------------------ Price River Coal Co. -- - ------------------------------------------------------------------------------ Blackhawk Coal Co. 6 - ------------------------------------------------------------------------------ Simco, Inc. 2 - ------------------------------------------------------------------------------ Conesville Coal Prep Co. 1,202 - ------------------------------------------------------------------------------ Sporn Plant Joint Books 2,920 - ------------------------------------------------------------------------------ Amos Plant Joint Books 2,910 - ------------------------------------------------------------------------------ Rockport Plant Joint Books 1,318 - ------------------------------------------------------------------------------ Gavin FGD 364 - ------------------------------------------------------------------------------ Tidd Plant PFBC Project -- - ------------------------------------------------------------------------------ Sporn Plant - OPCo Share -- - ------------------------------------------------------------------------------ Amos Plant - OPCo Share -- - ------------------------------------------------------------------------------ Rockport - I&M Share -- - ------------------------------------------------------------------------------ Rockport - AEG Share -- - ------------------------------------------------------------------------------ Carolina Power & Light 7,628 - ------------------------------------------------------------------------------ Non-affiliated 36 - ------------------------------------------------------------------------------ AEP Non-Regulated Savings 38,492 - ------------------------------------------------------------------------------ Total AEP Savings 1,252,572 - ------------------------------------------------------------------------------ - ------------------------------------------------------------------------------ CSW Regulated Savings - ------------------------------------------------------------------------------ CPL 237,026 - ------------------------------------------------------------------------------ Energy Consulting SVCS 273 - ------------------------------------------------------------------------------ Joint Fuels Project 274 - ------------------------------------------------------------------------------ External Lab Services 24 - ------------------------------------------------------------------------------ PSO 159,773 - ------------------------------------------------------------------------------ SWEPCO 175,534 - ------------------------------------------------------------------------------ WTU 84,222 - ------------------------------------------------------------------------------ CSW Non-Regulated Savings 55,668 - ------------------------------------------------------------------------------ Total CSW Savings 712,794 - ------------------------------------------------------------------------------ Total Savings Less Cost to Achieve and Pre-Merger Initiatives 1,965,339 - ------------------------------------------------------------------------------
102 105 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, Oklahoma, Texas, and Michigan. 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 Texas Commission approved 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. 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, Michigan, 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 103 106 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. In addition, 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. The order of the Michigan Commission provides for a credit to ratepayers of 55% of the $25.4 million, or approximately $14 million, of the total savings. Once the Merger is consummated, Michigan customers will receive their share of the savings through credits of approximately 1 percent to 1.5 percent every year for at least eight years. In addition, the order of the Michigan Commission provides that I&M, AEP's utility subsidiary, will not request an increase in its existing base rates until January 1, 2005. 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 Oklahoma Commission and the Texas Commission approved Applicants' divestiture of generation assets based upon the mitigation measures that Applicants proposed to protect ratepayers. The order of the Texas Commission approved several significant provisions designed to protect consumers from the economic effects of the divestiture, including (i) a requirement that proceeds from the CPL 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, (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. 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. 104 107 25325 (June 3, 1991) (expected savings of $91 million over ten years); CINergy, supra (estimated savings of approximately $895 million over ten years). The Commission has long recognized that, in reviewing an application under Section 10(c)(2), it is appropriate to consider "not only benefits resulting from the combination of utility assets, but also financial and organizational economies and efficiencies." WPL Holdings, supra; see also Chevron Holdings, Inc., HCAR No. 27122 (Dec. 27, 1999); Roanoke Gas Co., HCAR No. 26966 (April 1, 1999); BEC Energy, HCAR No. 26874 (May 15, 1999); Western Resources, Inc., HCAR No. 26783 (Nov. 24, 1997); KU Energy Corp., HCAR No. 25409 (Nov. 13, 1991). 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). If economies and efficiencies are anticipated from the transaction as a whole, the Commission is justified in approving it. See Madison Gas, at page 9 ("The Act, however, requires that the 'acquisition' as a whole, not merely the construction of an interconnection, tend toward efficiency and economy."); cf. Union Electric Company, 45 SEC 489, 495-96 (1974) (approving acquisition of assets not physically connected to the rest of the system since the acquisition would "contribute in the main to the development of an integrated system."); New Century Energies, supra, at pp. 9-10 (approving the acquisition of utility assets not physically interconnected where "their combination will result in a larger, financially stronger company, that, through the pooling of resources and expertise, will be able to achieve increased financial stability and strength, greater opportunities for earnings and dividend growth, reduction of operating costs, deferral of certain capital expenditures, efficiencies of operations, better use of facilities for the benefit of customers, seasonal diversity of demand, improved ability to use new technologies, greater retail and industrial sales diversity and improved capability to make wholesale power purchases and sales.") 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) 105 108 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, the Louisiana Commission, the Kentucky Commission, and the Michigan Commission. An order has been issued by the Texas Commission which found the Merger to be consistent with the public interest. See Item 4, infra, for further discussion of regulatory approvals and the 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 106 109 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 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 other subsidiaries(47) and AEPSC to participate in the Money Pool, and (2) the - ---------- (47) The other subsidiaries include Cedar Coal Co., Central Appalachian Coal Co., Central Coal Co., Central Ohio Coal Co., Colomet, Inc., Simco Inc., Southern Appalachian Coal Co., Southern Ohio Coal Co., Windsor Coal Co., Blackhawk Coal Co., Conesville Coal Preparation Company, Franklin 107 110 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 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 - -------------------------------------------------------------------------------- Real Estate Company, Indiana Franklin Realty Company and West Virginia Power Co., and are referred to herein as the "Coal Subsidiaries." Each of the Coal Subsidiaries is a wholly owned subsidiary of one or more AEP U.S. electric subsidiary companies, except Franklin Real Estate Company, which is a direct subsidiary of AEP, and Indiana Franklin Realty Company, which is a subsidiary of Franklin Real Estate Company. 108 111 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 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 109 112 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 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, 110 113 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 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 111 114 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 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. 112 115 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 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 113 116 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).(48) 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. 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 - ---------- (48) 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. 114 117 various aspects of the transactions proposed herein.(49) 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, the Indiana Commission, and the Michigan Commission. The Texas Commission issued an order finding the Merger to be consistent with the public interest. An Initial Decision has been issued by a FERC Administrative Law Judge approving the Merger. Applicants expect a final decision from FERC by March 2000 approving the Merger. On January 21, 2000, the FCC approved the transfer of certain microwave licenses held by CSW. On February 2, 2000, DOJ notified Applicants that it had completed its review of the Merger and that no further action is warranted. 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 26, 1999. On August 26, 1999, AEP and CSW received a request for additional information from the Antitrust Division. AEP and CSW filed the additional information with the Antitrust Division in November, 1999. On February 2, 2000, the Antitrust Division notified Applicants that it had completed its review of the Merger and that no further action is warranted. 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. - ---------- (49) 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, the Kentucky Commission and Michigan 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. 115 118 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 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 with a condition that the Merger must be completed by December 31,1999. The NRC Order is filed as Exhibit D-6.2, and incorporated by reference. On October 25, CPL requested an extension of the date by which the Merger must be completed. On December 9, 1999, the NRC granted an extension to June 30, 2000. 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.(50) As part of the transfer, AEP agreed to - ---------- (50) 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 116 119 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. On December 20, 1999, FERC conditionally approved the application forming the Alliance RTO, which would geographically include the transmission systems of AEP, Consumers, Detroit Edison, FirstEnergy and Virginia Power. 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 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. On November 23, 1999, the Administrative Law Judge at FERC issued an Initial Decision which approved the Merger, a copy of which is filed as Exhibit D-1.7 and incorporated by reference. The Administrative Law Judge found that the Merger is consistent with the public interest; the rates, terms and conditions of service are just, reasonable and not otherwise unlawful; and the joint open access transmission tariff providing for post-Merger transmission services is just, reasonable and not otherwise unlawful. As noted above, a final decision from FERC approving the Merger is expected in the first quarter, 2000. 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. On January 21, 2000, the FCC approved the transfer of certain microwave licenses held by CSW. Applicants expect the FCC to approve the transfer of the remaining licenses prior to the consummation of the Merger. - -------------------------------------------------------------------------------- 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. 117 120 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. 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 118 121 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 approving the Merger, a copy of which is filed as Exhibit D-4.2 and incorporated by reference. The order of the Oklahoma Commission was appealed to the Oklahoma State Supreme Court by Municipal Electric Systems of Oklahoma and Oklahoma Association of Electric Cooperatives. The appeal by Municipal Electric Systems of Oklahoma was dismissed on September 8, 1999, and the appeal by Oklahoma Association of Electric Cooperatives was dismissed on October 11, 1999. On October 15, 1999, the Oklahoma Association of Electric Cooperatives informed the Commission that it had have reached a settlement with Applicants resolving all outstanding issues among them, and that the Oklahoma Association of Electric Cooperatives no longer opposed the Merger. In addition thereto, the Oklahoma Association of Electric Cooperatives withdrew all comments and requests for hearing that they had previously filed in this proceeding. 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. On November 18, 1999, the Texas Commission issued an order finding the Merger to be consistent with the public interest. A copy of the order is filed as Exhibit D-5.5 and incorporated by reference. An Administrative Law Judge had previously recommended that the Texas Commission find the Merger to be consistent with the public interest under Texas Law. A copy of the Administrative Law Judge's Proposal for Decision is filed as Exhibit D-5.4 and incorporated by reference. In the proceedings before the Texas Commission, Applicants entered into an Integrated Stipulation and Agreement 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 Christi, Victoria, Abilene, Big Lake, Vernon and 119 122 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 would not file testimony in that proceeding. Furthermore, agreements were 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. On January 27, 2000, the FERC approved the subject settlement. L. MICHIGAN COMMISSION On December 16, 1999, the Michigan Commission approved a Settlement Agreement with AEP related to the Merger. In approving the Settlement Agreement, the Michigan Commission agreed not to oppose the Merger at the federal level. AEP agreed to share Merger savings with Michigan customers; establish performance standards that will maintain or improve 120 123 customer service and system reliability; join a RTO by December 31, 2000; and establish affiliate rules to protect consumers and promote fair competition. M. 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. 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 121 124 *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), as amended (see Current Report of AEP on Form 8-K, dated December 16, 1999 (File No. 1-3525) 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 *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 122 125 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 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 123 126 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 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 124 127 *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. *D-1.5 Application for Approval of the Alliance Regional Transmission Organization under Section 205 of the Federal Power Act, Docket No. ER99-3144 (filed June 3, 1999). *D-1.6 Application for Approval of Transaction under Section 203 of the Federal Power Act, Docket No. EC 99-80 (filed June 3, 1999). D-1.7 Initial Decision, Docket Nos. EC98-40, et al. (issued November 23, 1999) (to be filed by amendment). D-1.8 Order on Proposed Disposition, Alliance Companies, 89 FERC P. 61,298 (December 20, 1999) (to be filed by amendment). *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) 125 128 Exhibit H - Notice to Customers of SWEPCO 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 126 129 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 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 127 130 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) 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 128 131 *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 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-5.4 Proposal for Decision issued September 30, 1999 (to be filed by amendment). 129 132 D-5.5 Order of Public Utility Commission of Texas dated November 18, 1999 (to be filed by amendment). *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 D-10.1 Order of Michigan Commission approving Settlement, dated December 16, 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) *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 *F-2 Opinion of Counsel *F-1-1 Past-tense Opinion of Counsel *F-2-1 Past-tense Opinion of Counsel *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 130 133 *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) *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) 131 134 *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 *G-19 Quarterly Report of AEP on Form 10-Q for the quarter ended June 30, 1999 (File No. 1-3525) and incorporated herein by reference *G-20 Quarterly Report of CSW on Form 10-Q for the quarter ended June 30, 1999 (File No. 1-1443) and incorporated herein by reference G-21 Quarterly Report of AEP on Form 10-Q for the quarter ended September 30, 1999 (File No. 1-3525) and incorporated herein by reference G-22 Quarterly Report of CSW on Form 10-Q for the quarter ended September 30, 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 132 135 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. 133 136 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: March 1, 2000 134 137 STATUS OF STATE RESTRUCTURING LEGISLATION The following is a summary of restructuring legislation in the states in which the Combined Company will operate: 1. Arkansas 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. 2. Louisiana In Louisiana, the staff of the Louisiana Commission, in May 1999, presented a report on restructuring, recommending a slow approach to adoption of restructuring legislation. The report states that Louisiana has lower than national average electric rates, and competition could increase prices, not lower them. The report recommends that no action be taken at this time, but "reluctantly" submitted a draft restructuring plan in case the Louisiana Commission decides to order retail competition. In Louisiana, the Louisiana Commission can order retail competition without legislative action. 3. Ohio On July 6, 1999, the governor of Ohio signed "The Ohio Electric Restructuring Act of 1999" (the "Ohio Act") that will restructure the electric utility industry in Ohio affecting OPCo and CSPCo. The Ohio Act provides for customer choice of electricity supplier and a residential rate reduction of 5% of the unbundled generation rate beginning on January 1, 2001. The Ohio Act also provides for a five-year transition period to move from cost based rates to market pricing for generation services. The law provides Ohio electric utilities the opportunity to recover regulatory assets and other potential stranded costs. Retail electric services that will be competitive are defined in the Ohio Act as electric generation service, aggregation service, and power marketing and brokering. The Ohio Commission has been granted broad oversight responsibility under the Ohio Act. The Ohio Act requires the Ohio Commission to promulgate rules for competitive retail electric generation service. 135 138 The Ohio Act further provides Ohio electric utilities with an opportunity to recover Ohio Commission approved allowable transition costs through unbundled rates paid by customers who do not switch generation suppliers and through a wires charge by customers who switch generation suppliers. Transition costs can include regulatory assets, impairments of generating assets and other stranded costs, employee severance and retraining costs and other costs. Recovery of transition revenues can under certain circumstances extend beyond the five-year transition period but cannot continue beyond December 31, 2010. AEP must file a transition plan with the Ohio Commission by January 3, 2000, and the Ohio Commission is required to issue a transition order no later than October 31, 2000. On December 30, 1999, AEP, on behalf of its subsidiaries CSPCo and OPCo, filed its restructuring transition plan required by the Ohio Act. The filing provides details on the companies' proposed rate unbundling, corporate separation, operational support, employee assistance and consumer education plans. The filing also includes a request to recover transition costs and a proposal for independent operation of transmission facilities. The Ohio Act also provides that the property tax assessment percentage on electric generation equipment be lowered from 100% to 25% of value effective January 1, 2001. Electric utilities will also become subject to the Ohio Corporate Franchise Tax and municipal income taxes on January 1, 2002. The last year for which electric utilities will pay the excise tax based on gross receipts is the year ending April 30, 2002. As of May 1, 2001 electric distribution companies will be subject to an excise tax based on kilowatt-hours sold to Ohio customers. It is expected that these changes will put the company's generation operations on an equal basis with other competitive businesses in Ohio regarding state taxation. 4. Oklahoma In April, 1997, the Oklahoma Legislature passed restructuring legislation providing for retail access by July 1, 2002. That legislation called for a number of studies to be completed on a variety of restructuring issues, including independent system operator issues, technical issues, financial issues, transition issues and consumer issues. The study on independent system operator issues was completed in January, 1998. The Legislative Joint Electric Utility Task Force completed its studies of the remaining issues and provided its final report to the Oklahoma Legislature on October 1, 1999. 5. Texas On June 18, 1999, the Texas Legislature passed restructuring legislation that will restructure the electric utility industry within the state. The new law gives Texas customers of investor-owned utilities the opportunity to choose their electricity provider beginning January 1, 2002. The legislation also provides a rate freeze until that date followed by a 6% rate reduction for residential and small commercial customers, additional rate reductions for low income customers and a number of customer protections. Rural electric cooperatives and municipal electric systems can choose whether to participate in retail competition. Some of the key provisions of the legislation include: 136 139 - - Beginning January 1, 2002, retail customers of investor-owned electric companies will be able to choose their electric provider. The affiliated retail electric provider of the utility that serves the customer on December 31, 2001 will continue to serve the customer unless the customer chooses another retail electric provider. Delivery of the electricity will continue to be the responsibility of the local electric utility company at regulated prices. Each utility must unbundle its business activities into a retail electric provider, a power generation company and a transmission and distribution utility. - - Retail electric cooperatives and municipal electric systems can choose whether to participate in retail competition. - - Investor-owned utilities must freeze their rates effective September 1, 1999, through the start of competition on January 1, 2002. Investor-owned utilities at January 1, 2002 will lower rates for residential and small commercial customers by 6%. This reduced rate is known as the "Price to Beat," which will be available to those customers for five years. - - The legislation establishes a system benefit fund for low-income customer assistance, customer education and to offset reductions in school property tax revenues. The fund will be funded through a charge on retail electric providers that can be set by the Texas Commission at up to 65 cents per MWH. - - Electric utilities are allowed to recover all of their net, verifiable, non-mitigable stranded costs that otherwise may not be recoverable in the future competitive market. A majority of those regulatory assets and stranded costs can be recovered through securitization, which is a financing process to recover regulatory assets and stranded costs through the use of debt that lowers the financing cost of assets compared to conventional utility financing methods. - - Each year during the 1999 through 2001 rate freeze period, utilities with stranded costs are required to apply any earnings in excess of the most recently approved cost of capital (if issued on or after January 1, 1992) to reduce stranded costs. Utilities without stranded costs must either flow such amounts back to customers or make capital expenditures to improve transmission or distribution facilities or to improve air quality. - - Investor-owned utilities will be required to auction entitlements to at least 15% of their generating capacity for five years or until 40% of the residential and small commercial consumption of electricity in the utility's service area is provided by nonaffiliated retail electric providers. - - Grandfathered power plants, those built or started prior to implementation of the Texas Clean Air Act of 1972, must reduce emissions of Nitrogen Oxide by 50% and Sulfur Dioxide by 25% by May, 2003. The law also requires an additional 137 140 2,000 MW of renewable power generation in Texas by 2009 from retail electric providers, municipally owned utilities and electric cooperatives. - - A legislative oversight committee will be established to monitor the implementation and effectiveness of electric utility restructuring and make recommendations for any necessary further legislative action. The Texas Commission has established numerous task forces to address various issues associated with the restructuring legislation and to provide for further guidance regarding implementation of the restructuring. 6. Virginia 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 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. APCo's retail pilot program would allow approximately 2% of its retail customers to participate in June, 2000, and an additional 8% of its retail customers would be allowed to participate by March, 2001. Both phases of the program would be weighted heavily toward industrial customers. APCo proposed that industrial customers will account for 35 MW of the 50 MW load opened to competition in June, 2000, and will account for 140 MW of the 200 MW load opened to competition in March, 2001. The Virginia Commission held hearings on APCo's proposal in November, 1999. 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. 7. West Virginia On February 7, 2000, the West Virginia Public Service Commission passed a plan to restructure the state's electric industry. The restructuring plan would begin January 1, 2001. Provisions in the plan include a four-year freeze on electric rates and a nine-year transition period during which only incremental increases could occur while competition begins. The plan would add a small charge to all electric bills in order to collect approximately $84 million which the PSC would then redistribute to residential customers near the end of the 13 year period for rate relief during the transition to competition. 138 EX-99.I.2 2 SHORT-TERM BORROWING PROGRAM 1 Exhibit I-2 Short-Term Borrowing Program Pursuant to Central and South West Corp., et al., HCAR No. 26697 (Mar. 28, 1997), this Commission granted an extension of authority for CSW, CPL, PSO, SWEPCO, WTU and CSWS (the "Money Pool Participants") to continue their short-term borrowing program through March 31, 2002, including the sale of commercial paper by CSW to commercial paper dealers and financial institutions, and the sale of short-term notes to banks and their trust departments, by the Money Pool Participants. Pursuant to Central and South West Corp., et al., HCAR No. 26854 (Apr. 3, 1998), this Commission authorized increased short-term borrowing limits for CSW and the Money Pool Participants as follows: - -------------------------------------------------------------------------------- CSW $2,500,000,000 - -------------------------------------------------------------------------------- CPL $ 600,000,000 - -------------------------------------------------------------------------------- PSO $ 300,000,000 - -------------------------------------------------------------------------------- SWEPCO $ 250,000,000 - -------------------------------------------------------------------------------- WTU $ 165,000,000 - -------------------------------------------------------------------------------- CSWS $ 210,000,000 - --------------------------------------------------------------------------------
Pursuant to American Elec. Power Co., et al., HCAR No. 27049 (July 14, 1999), this Commission authorized the following short-term borrowing limits for AEP and certain of its subsidiaries identified below (the "AEP Utility Subsidiaries"): - -------------------------------------------------------------------------------- AEP $ 500,000,000 - -------------------------------------------------------------------------------- AEGCo $ 125,000,000 - -------------------------------------------------------------------------------- APCo $ 325,000,000 - -------------------------------------------------------------------------------- CSPCo $ 350,000,000 - -------------------------------------------------------------------------------- I&M $ 500,000,000 - -------------------------------------------------------------------------------- KPCo $ 150,000,000 - -------------------------------------------------------------------------------- KgPCo $ 30,000,000 - -------------------------------------------------------------------------------- OPCo $ 450,000,000 - -------------------------------------------------------------------------------- WPCo $ 30,000,000 - -------------------------------------------------------------------------------- TOTAL:$2,460,000,000 - --------------------------------------------------------------------------------
Applicants hereby request authority, effective upon consummation of the Merger, for the Combined Company to continue the Money Pool and to manage and fund it consistent with all the terms and conditions of Central and South West Corp., et al., HCAR No. 26697 (Mar. 28, 1997); Central and South West Corp., et al., HCAR No. 26854 (Apr. 3, 1998) and all previous orders of this Commission relating to the Money Pool subject to the following: (1) CSW's $2,500,000,000 short-term borrowing authorization shall transfer to the Combined Company and 139 2 Combined Company's short-term borrowing limit shall be increased from $500,000,000 to $5,000,000,000 (such limit consisting of (a) $2,500,000,000 authorized for CSW, (b) $2,460,000,000 authorized for AEP and AEP Utility Subsidiaries, and (c) $40,000,000 for AEPSC); (2) the Combined Company and the AEP Utility Subsidiaries shall be added as participants to the Money Pool and permitted to issue short term debt up to the amounts specified in American Elec. Power Co., et al., HCAR No. 26867 (May 4, 1998); and (3) the Coal Subsidiaries and AEPSC shall be added as participants to the Money Pool, although their borrowings would be exempt under Rule 52(b). 140 -----END PRIVACY-ENHANCED MESSAGE-----