-----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, VM3tM1O7GpHP8PxFc+ubbr68LANFJ8WMUn277myc1c6nh7Q6KjmJkFJCD8WSVinW jn5AQNDvQdIFN3tuPBRNdw== 0000004904-97-000038.txt : 19970328 0000004904-97-000038.hdr.sgml : 19970328 ACCESSION NUMBER: 0000004904-97-000038 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 13 CONFORMED PERIOD OF REPORT: 19961231 FILED AS OF DATE: 19970326 SROS: NYSE 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: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-03525 FILM NUMBER: 97564162 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 10-K 1 AEPCO 1996 FORM 10-K SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 --------------- FORM 10-K --------------- (Mark One) [ x ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 1996 [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from __________ to ___________ ---------------- Commission Registrant; State of Incorporation; I.R.S. Employer File Number Address; and Telephone Number Identification No. - ----------- ----------------------------------- ------------------ 1-3525 American Electric Power Company, Inc. 13-4922640 (A New York Corporation) 1 Riverside Plaza Columbus, Ohio 43215 Telephone (614) 223-1000 0-18135 AEP Generating Company 31-1033833 (An Ohio Corporation) 1 Riverside Plaza Columbus, Ohio 43215 Telephone (614) 223-1000 1-3457 Appalachian Power Company 54-0124790 (A Virginia Corporation) 40 Franklin Road, S.W. Roanoke, Virginia 24011 Telephone (540) 985-2300 1-2680 Columbus Southern Power Company 31-4154203 (An Ohio Corporation) 215 North Front Street Columbus, Ohio 43215 Telephone (614) 464-7700 1-3570 Indiana Michigan Power Company 35-0410455 (An Indiana Corporation) One Summit Square P. O. Box 60 Fort Wayne, Indiana 46801 Telephone (219) 425-2111 1-6858 Kentucky Power Company 61-0247775 (A Kentucky Corporation) 1701 Central Avenue Ashland, Kentucky 41101 Telephone (800) 572-1141 1-6543 Ohio Power Company 31-4271000 (An Ohio Corporation) 301 Cleveland Avenue, S.W. Canton, Ohio 44702 Telephone (330) 456-8173 -------------- AEP Generating Company, Columbus Southern Power Company and Kentucky Power Company meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and are therefore filing this Form 10-K with the reduced disclosure format specified in General Instruction I(2) to such Form 10-K. Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes . No. . ---------- --- SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT: Name of each exchange Registrant Title of each class on which registered ---------- ------------------- --------------------- AEP Generating Company None American Electric Power Common Stock, Company, Inc. $6.50 par value New York Stock Exchange Appalachian Power Cumulative Preferred Stock, Company Voting, no par value: 4-1/2% Philadelphia Stock Exchange 8-1/4% Junior Subordinated Deferrable Interest Debentures, Series A, Due 2026 New York Stock Exchange 8% Junior Subordinated Deferrable Interest Debentures, Series B, Due 2027 New York Stock Exchange Columbus Southern 8-3/8% Junior Subordinated Power Company Deferrable Interest Debentures, Series A, Due 2025 New York Stock Exchange 7.92% Junior Subordinated Deferrable Interest Debentures, Series B, Due 2027 New York Stock Exchange Indiana Michigan Cumulative Preferred Stock, Power Company Non-Voting, $100 par value: 4-1/8% Chicago Stock Exchange 8% Junior Subordinated Deferrable Interest Debentures, Series A, Due 2026 New York Stock Exchange Kentucky Power Company 8.72% Junior Subordinated Deferrable Interest Debentures, Series A, Due 2025 New York Stock Exchange Ohio Power Company 8.16% Junior Subordinated Deferrable Interest Debentures, Series A, Due 2025 New York Stock Exchange 7.92% Junior Subordinated Deferrable Interest Debentures, Series B, Due 2027 New York Stock Exchange Indicate by check mark if disclosure of delinquent filers with respect to American Electric Power Company, Inc. pursuant to Item 405 of Regulation S-K (Section 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in the definitive proxy statement of American Electric Power Company, Inc. incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. Indicate by check mark if disclosure of delinquent filers with respect to Appalachian Power Company, Indiana Michigan Power Company or Ohio Power Company pursuant to Item 405 of Regulation S-K (Section 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in the definitive information statements of Appalachian Power Company or Ohio Power Company incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT: Registrant Title of each class ---------- ------------------- AEP Generating Company None American Electric Power Company, Inc. None Appalachian Power Company None Columbus Southern Power Company None Indiana Michigan Power Company None Kentucky Power Company None Ohio Power Company 4-1/2% Cumulative Preferred Stock, Voting, $100 par value Aggregate market value Number of shares of voting stock held of common stock by non-affiliates of outstanding of the registrants at the registrants at March 7, 1997 March 7, 1997 ---------------------- ------------------ AEP Generating Company None 1,000 ($1,000 par value) American Electric Power Company, Inc. $7,747,000,000 188,235,000 ($6.50 par value) Appalachian Power Company $12,500,000 13,499,500 (no par value) Columbus Southern Power Company None 16,410,426 (no par value) Indiana Michigan Power Company None 1,400,000 (no par value) Kentucky Power Company None 1,009,000 ($50 par value) Ohio Power Company $18,700,000 27,952,473 (no par value) NOTE ON MARKET VALUE OF VOTING STOCK HELD BY NON-AFFILIATES All of the common stock of AEP Generating Company, Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company and Ohio Power Company is owned by American Electric Power Company, Inc. (see Item 12 herein). The voting stock owned by non-affiliates of (i) Appalachian Power Company consists of 198,388 shares of Cumulative Preferred Stock, no par value; and (ii) Ohio Power Company consists of 258,252 shares of Cumulative Preferred Stock, $100 par value. Some of the series of Cumulative Preferred Stock are not regularly traded. The aggregate market value of the Cumulative Preferred Stock is based on the average of the high and low prices on the closest trading date to March 7, 1997 for series traded on the Philadelphia Stock Exchange, or the most recent reported bid prices for those series not recently traded. Where recent market price information was not available with respect to a series, the market price for such series is based on the price of a recently traded series with an adjustment related to any difference in the current yields of the two series. DOCUMENTS INCORPORATED BY REFERENCE PART OF FORM 10-K INTO WHICH DOCUMENT DESCRIPTION IS INCORPORATED ----------- ------------------- Portions of Annual Reports of the following companies for the fiscal year ended December 31, 1996: Part II AEP Generating Company American Electric Power Company, Inc. Appalachian Power Company Columbus Southern Power Company Indiana Michigan Power Company Kentucky Power Company Ohio Power Company Portions of Proxy Statement of American Electric Power Company, Inc., dated March 10, 1997, for Annual Meeting of Shareholders Part III Portions of Information Statements of the following companies for 1997 Annual Meeting of Shareholders, to be filed within 120 days after December 31, 1996: Part III Appalachian Power Company Ohio Power Company ---------------- THIS COMBINED FORM 10-K IS SEPARATELY FILED BY AEP GENERATING COMPANY, AMERICAN ELECTRIC POWER COMPANY, INC., APPALACHIAN POWER COMPANY, COLUMBUS SOUTHERN POWER COMPANY, INDIANA MICHIGAN POWER COMPANY, KENTUCKY POWER COMPANY AND OHIO POWER COMPANY. INFORMATION CONTAINED HEREIN RELATING TO ANY INDIVIDUAL REGISTRANT IS FILED BY SUCH REGISTRANT ON ITS OWN BEHALF. EXCEPT FOR AMERICAN ELECTRIC POWER COMPANY, INC., EACH REGISTRANT MAKES NO REPRESENTATION AS TO INFORMATION RELATING TO THE OTHER REGISTRANTS. TABLE OF CONTENTS Page Number ------ Glossary of Terms . . . . . . . . . . . . . . . . . . . . . . . . . i Part I Item 1. Business. . . . . . . . . . . . . . . . . . . . . . . . . 1 Item 2. Properties. . . . . . . . . . . . . . . . . . . . . . . . 27 Item 3. Legal Proceedings . . . . . . . . . . . . . . . . . . . . 31 Item 4. Submission of Matters to a Vote of Security Holders . . . 32 Executive Officers of the Registrants. . . . . . . . . . . . . . . 32 Part II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters. . . . . . . . . . . . . . . . . . 35 Item 6. Selected Financial Data . . . . . . . . . . . . . . . . . 35 Item 7. Management's Discussion and Analysis of Results of Operations and Financial Condition. . . . . . . . . 35 Item 8. Financial Statements and Supplementary Data . . . . . . . 36 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure . . . . . . . . 36 Part III Item10. Directors and Executive Officers of the Registrants . . . 37 Item11. Executive Compensation. . . . . . . . . . . . . . . . . . 38 Item12. Security Ownership of Certain Beneficial Owners and Management. . . . . . . . . . . . . . . . . 41 Item13. Certain Relationships and Related Transactions. . . . . . 42 Part IV Item14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K. . . . . . . . . . . . . . . . . . 43 Signatures. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45 Index to Financial Statement Schedules. . . . . . . . . . . . . . . S-1 Independent Auditors' Report. . . . . . . . . . . . . . . . . . . . S-2 Exhibit Index . . . . . . . . . . . . . . . . . . . . . . . . . . . E-1 GLOSSARY OF TERMS When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below. Term Meaning ---- ------- AEGCo . . . . . . . AEP Generating Company, an electric utility subsidiary of AEP. AEP . . . . . . . . American Electric Power Company, Inc. AEP System or the System. . . . The American Electric Power System, an integrated electric utility system, owned and operated by AEP's electric utility subsidiaries. AFUDC . . . . . . . Allowance for funds used during construction. Defined in regulatory systems of accounts as the net cost of borrowed funds used for construction and a reasonable rate of return on other funds when so used. APCo . . . . . . . Appalachian Power Company, an electric utility subsidiary of AEP. Buckeye . . . . . . Buckeye Power, Inc., an unaffiliated corporation. CCD Group . . . . . CSPCo, CG&E and DP&L. CG&E. . . . . . . . The Cincinnati Gas & Electric Company, an unaffiliated utility company. Cook Plant. . . . . The Donald C. Cook Nuclear Plant, owned by I&M. CSPCo . . . . . . . Columbus Southern Power Company, an electric utility subsidiary of AEP. DOE . . . . . . . . United States Department of Energy. DP&L. . . . . . . . The Dayton Power and Light Company, an unaffiliated utility company. Federal EPA . . . . United States Environmental Protection Agency. FERC. . . . . . . . Federal Energy Regulatory Commission (an independent commission within the DOE). I&M . . . . . . . . Indiana Michigan Power Company, an electric utility subsidiary of AEP. IURC. . . . . . . . Indiana Utility Regulatory Commission. KEPCo . . . . . . . Kentucky Power Company, an electric utility subsidiary of AEP. KPSC. . . . . . . . Kentucky Public Service Commission. MPSC. . . . . . . . Michigan Public Service Commission. NEIL. . . . . . . . Nuclear Electric Insurance Limited. NPDES . . . . . . . National Pollutant Discharge Elimination System. NRC . . . . . . . . Nuclear Regulatory Commission. Ohio EPA. . . . . . Ohio Environmental Protection Agency. OPCo. . . . . . . . Ohio Power Company, an electric utility subsidiary of AEP. OVEC. . . . . . . . Ohio Valley Electric Corporation, an electric utility company in which AEP and CSPCo own a 44.2% equity interest. PCB's . . . . . . . Polychlorinated biphenyls. PUCO. . . . . . . . The Public Utilities Commission of Ohio. PUHCA . . . . . . . Public Utility Holding Company Act of 1935, as amended. RCRA. . . . . . . . Resource Conservation and Recovery Act of 1976, as amended. Rockport Plant. . . A generating plant, consisting of two 1,300,000-kilowatt coal-fired generating units, near Rockport, Indiana. SEC . . . . . . . . Securities and Exchange Commission. Service Corporation . . . . American Electric Power Service Corporation, a service subsidiary of AEP. SO2 Allowance . . . An allowance to emit one ton of sulfur dioxide granted under the Clean Air Act Amendments of 1990. TVA . . . . . . . . Tennessee Valley Authority. VEPCo . . . . . . . Virginia Electric and Power Company, an unaffiliated utility company. Virginia SCC. . . . State Corporation Commission of Virginia. West Virginia PSC . Public Service Commission of West Virginia. Zimmer or Zimmer Plant. . . . Wm. H. Zimmer Generating Station, commonly owned by CSPCo, CG&E and DP&L. i PART I --------------------------------------------------------------------- Item 1. BUSINESS - ---------------------------------------------------------------------------- General AEP was incorporated under the laws of the State of New York in 1906 and reorganized in 1925. It is a public utility holding company which owns, directly or indirectly, all of the outstanding common stock of its electric utility and other subsidiaries. Substantially all of the operating revenues of AEP and its subsidiaries are derived from the furnishing of electric service. In addition, in recent years AEP has been pursuing various unregulated business opportunities in the U.S. and worldwide as discussed in New Business Development. The service area of AEP's electric utility subsidiaries covers portions of the states of Indiana, Kentucky, Michigan, Ohio, Tennessee, Virginia and West Virginia. The generating and transmission facilities of AEP's 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. The electric utility subsidiaries of AEP have traditionally provided electric service, consisting of generation, transmission and distribution, on an integrated basis to their retail customers. As a result of the changing nature of the electric business (see Competition and Business Change), effective January 1, 1996, AEP's subsidiaries realigned into four functional business units: Power Generation; Nuclear Generation; Energy Delivery; and Corporate Development. In addition, the electric utility subsidiaries began to do business as "American Electric Power." The legal and financial structure of AEP and its subsidiaries, however, did not change. At December 31, 1996, the subsidiaries of AEP had a total of 17,951 employees. AEP, as such, has no employees. The operating subsidiaries of AEP are: APCo (organized in Virginia in 1926) is engaged in the generation, purchase, transmission and distribution of electric power to approximately 867,000 retail 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, 1996, APCo and its wholly owned subsidiaries had 3,900 employees. Among the principal industries served by APCo are coal mining, primary metals, chemicals and textile mill products. In addition to its AEP System interconnections, APCo also is interconnected with the following unaffiliated utility companies: Carolina Power & Light Company, Duke Power Company and VEPCo. A comparatively small part of the properties and business of APCo is located in the northeastern end of the Tennessee Valley. APCo has several points of interconnection with TVA and has entered into agreements with TVA under which APCo and TVA interchange and transfer electric power over portions of their respective systems. CSPCo (organized in Ohio in 1937, the earliest direct predecessor company having been organized in 1883) is engaged in the generation, purchase, transmission and distribution of electric power to approximately 609,000 customers in 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, 1996, CSPCo had 1,837 employees. CSPCo's service area is comprised of two areas in Ohio, which include portions of twenty-five counties. One area includes the City of Columbus and the other is a predominantly rural area in south central Ohio. Approximately 80% of CSPCo's retail revenues are derived from the Columbus area. Among the principal industries served are food processing, chemicals, primary metals, electronic machinery and paper products. In addition to its AEP System interconnections, CSPCo also is interconnected with the following unaffiliated utility companies: CG&E, DP&L and Ohio Edison Company. I&M (organized in Indiana in 1925) is engaged in the generation, purchase, transmission and distribution of electric power to approximately 542,000 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, 1996, I&M had 3,393 employees. Among the principal industries served are primary metals, transportation equipment, electrical and electronic machinery, fabricated metal products, rubber and miscellaneous plastic products and chemicals and allied products. Since 1975, I&M has leased and operated the assets of the municipal system of the City of Fort Wayne, Indiana. In addition to its AEP System interconnections, I&M also is interconnected with the following unaffiliated utility companies: Central Illinois Public Service Company, CG&E, Commonwealth Edison Company, Consumers Energy Company, Illinois Power Company, Indianapolis Power & Light Company, Louisville Gas and Electric Company, Northern Indiana Public Service Company, PSI Energy Inc. and Richmond Power & Light Company. KEPCo (organized in Kentucky in 1919) is engaged in the generation, purchase, transmission and distribution of electric power to approximately 167,000 customers in an area in eastern Kentucky, and in supplying electric power at wholesale to other utilities and municipalities in Kentucky. At December 31, 1996, KEPCo had 718 employees. In addition to its AEP System interconnections, KEPCo also is interconnected with the following unaffiliated utility companies: Kentucky Utilities Company and East Kentucky Power Cooperative Inc. KEPCo is also interconnected with TVA. Kingsport Power Company (organized in Virginia in 1917) provides electric service to approximately 43,000 customers in Kingsport and eight neighboring communities in northeastern Tennessee. Kingsport Power Company has no generating facilities of its own. It purchases electric power distributed to its customers from APCo. At December 31, 1996, Kingsport Power Company had 87 employees. OPCo (organized in Ohio in 1907 and reincorporated in 1924) is engaged in the generation, purchase, transmission and distribution of electric power to approximately 673,000 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, 1996, OPCo and its wholly owned subsidiaries had 4,418 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. In addition to its AEP System interconnections, OPCo also is interconnected with the following unaffiliated utility companies: CG&E, The Cleveland Electric Illuminating Company, DP&L, Duquesne Light Company, Kentucky Utilities Company, Monongahela Power Company, Ohio Edison Company, The Toledo Edison Company and West Penn Power Company. Wheeling Power Company (organized in West Virginia in 1883 and reincorporated in 1911) provides electric service to approximately 41,000 customers in northern West Virginia. Wheeling Power Company has no generating facilities of its own. It purchases electric power distributed to its customers from OPCo. At December 31, 1996, Wheeling Power Company had 96 employees. Another principal electric utility subsidiary of AEP is AEGCo, which was organized in Ohio in 1982 as an electric generating company. AEGCo sells power at wholesale to I&M, KEPCo and VEPCo. AEGCo has no employees. See Item 2 for information concerning the properties of the subsidiaries of AEP. The Service Corporation provides accounting, administrative, information systems, engineering, financial, legal, maintenance and other services at cost to the AEP System companies. The executive officers of AEP and its public utility subsidiaries are all employees of the Service Corporation. REGULATION General AEP and its subsidiaries are subject to the broad regulatory provisions of PUHCA administered by the SEC. The public utility subsidiaries' retail rates and certain other matters are subject to regulation by the public utility commissions of the states in which they operate. Such subsidiaries are also subject to regulation by the FERC under the Federal Power Act in respect of rates for interstate sale at wholesale and transmission of electric power, accounting and other matters and construction and operation of hydroelectric projects. I&M is subject to regulation by the NRC under the Atomic Energy Act of 1954, as amended, with respect to the operation of the Cook Plant. Possible Change to PUHCA The provisions of PUHCA, administered by the SEC, regulate all aspects of a registered holding company system, such as the AEP System. PUHCA requires that the operations of a registered holding company system be limited to a single integrated public utility system and such other businesses as are incidental or necessary to the operations of the system. In addition, PUHCA governs, among other things, financings, sales or acquisitions of assets and intra-system transactions. On June 20, 1995, the SEC released a report from its Division of Investment Management recommending a conditional repeal of PUHCA, including its limits on financing and on geographic and business diversification. Specific federal authority, however, would be preserved over access to the books and records of registered holding company systems, audit authority over registered holding companies and their subsidiaries and oversight over affiliate transactions. This authority would be transferred to the FERC. In January and February 1997, legislation was introduced in Congress that would repeal PUHCA and transfer certain federal authority to the FERC as recommended in the SEC report as part of broader legislation regarding changes in the electric industry. It is expected that a number of bills contemplating the restructuring of the electric utility industry will be introduced in the current Congress. See Competition and Business Change. If PUHCA is repealed, registered holding company systems, including the AEP System, will be able to compete in the changing industry without the constraints of PUHCA. Management of AEP believes that removal of these constraints would be beneficial to the AEP System. PUHCA and the rules and orders of the SEC currently require that transactions between associated companies in a registered holding company system be performed at cost with limited exceptions. Over the years, the AEP System has developed numerous affiliated service, sales and construction relationships and, in some cases, invested significant capital and developed significant operations in reliance upon the ability to recover its full costs under these provisions. Legislation has been introduced in Congress to repeal PUHCA or modify its provisions governing intra-system transactions. The effect of repeal or amendment of PUHCA on AEP's intra-system transactions depends on whether the assurance of full cost recovery is eliminated immediately or phased-in and whether it is eliminated for all intra-system transactions or only some. If the cost recovery assurance is eliminated immediately for all intra-system transactions, it could have a material adverse effect on results of operations and financial condition of AEP and OPCo. Conflict of Regulation Public utility subsidiaries of AEP can be subject to regulation of the same subject matter by two or more jurisdictions. In such situations, it is possible that the decisions of such regulatory bodies may conflict or that the decision of one such body may affect the cost of providing service and so the rates in another jurisdiction. In a case involving OPCo, the U.S. Court of Appeals for the District of Columbia held that the determination of costs to be charged to associated companies by the SEC under PUHCA precluded the FERC from determining that such costs were unreasonable for ratemaking purposes. The U.S. Supreme Court also has held that a state commission may not conclude that a FERC approved wholesale power agreement is unreasonable for state ratemaking purposes. Certain actions that would overturn these decisions or otherwise affect the jurisdiction of the SEC and FERC are under consideration by the U.S. Congress and these regulatory bodies. Such conflicts of jurisdiction often result in litigation and, if resolved adversely to a public utility subsidiary of AEP, could have a material adverse effect on the results of operations or financial condition of such subsidiary or AEP. CLASSES OF SERVICE The principal classes of service from which the major electric utility subsidiaries of AEP derive revenues and the amount of such revenues (from kilowatt-hour sales) during the year ended December 31, 1996 are as follows:
AEP AEGCo APCo CSPCo I&M KEPCo OPCo System(a) -------- --------- ----------- ---------- -------- ---------- ---------- (in thousands) Retail Residential Without Electric Heating . $ -- $ 231,504 $ 325,351 $ 232,212 $ 41,602 $ 280,640 $1,132,140 With Electric Heating. . . -- 340,796 115,339 111,556 64,839 155,081 826,411 -------- ---------- ---------- ---------- -------- ---------- ---------- Total Residential . . . . -- 572,300 440,690 343,768 106,441 435,721 1,958,551 Commercial . . . . . . . . -- 284,765 383,621 253,750 58,417 265,886 1,284,670 Industrial . . . . . . . . -- 368,421 147,543 312,777 92,322 635,404 1,618,843 Miscellaneous. . . . . . . -- 32,035 16,043 6,445 846 8,065 66,930 -------- ---------- ---------- ---------- -------- ---------- ---------- Total Retail. . . . . . . -- 1,257,521 987,897 916,740 258,026 1,345,076 4,928,994 Wholesale (sales for resale) 225,767 332,800 93,496 391,478 57,141 526,702 792,592 -------- ---------- ---------- ---------- -------- ---------- ---------- Total from KWH Sales. . . 225,767 1,590,321 1,081,393 1,308,218 315,167 1,871,778 5,721,586 Provision for Revenue Refunds -- (7,581) -- -- -- -- (7,581) -------- ---------- ---------- ---------- -------- ---------- ---------- Total Net of Provision for Revenue Refunds . . . . 225,767 1,582,740 1,081,393 1,308,218 315,167 1,871,778 5,714,005 Other Operating Revenues. . 125 42,129 24,290 20,275 8,154 39,930 135,229 -------- ---------- ---------- ---------- -------- ---------- ---------- Total Electric Operating Revenues $225,892 $1,624,869 $1,105,683 $1,328,493 $323,321 $1,911,708 $5,849,234 - ---------------------- ======== ========== ========== ========== ======== ========== ==========
(a) Includes revenues of other subsidiaries not shown and reflects elimination of intercompany transactions. SALE OF POWER AEP's electric utility subsidiaries own or lease generating stations with total generating capacity of 23,759 megawatts. See Item 2 for more information regarding the generating stations. They operate their generating plants as a single interconnected and coordinated electric utility system and share the costs and benefits in the AEP System Power Pool. Most of the electric power generated at these stations is sold, in combination with transmission and distribution services, to retail customers of AEP's utility subsidiaries in their service territories. These sales are made at rates that are established by the public utility commissions of the state in which they operate. See Rates. Some of the electric power is sold at wholesale to non-affiliated companies. AEP System Power Pool APCo, CSPCo, I&M, KEPCo and OPCo are parties to the Interconnection Agreement, dated July 6, 1951, as amended (the Interconnection Agreement), defining how they share the costs and benefits associated with the System's generating plants. This 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. In addition, since 1995, APCo, CSPCo, I&M, KEPCo and OPCo have been parties to the AEP System Interim Allowance Agreement which provides, among other things, for the transfer of SO2 Allowances associated with transactions under the Interconnection Agreement. The following table shows the net credits or (charges) allocated among the parties under the Interconnection Agreement and Interim Allowance Agreement during the years ended December 31, 1994, 1995 and 1996: 1994 1995 1996(a) ---------- ---------- ---------- (in thousands) APCo . . . . . . . . . $(254,000) $(252,000) $(258,000) CSPCo. . . . . . . . . (105,000) (143,000) (145,000) I&M. . . . . . . . . . 107,000 118,000 121,000 KEPCo. . . . . . . . . 12,000 23,000 2,000 OPCo . . . . . . . . . 240,000 254,000 280,000 - ---------------- (a) Includes credits and charges from allowance transfers related to the transactions. Wholesale Sales of Power to Non-Affiliates AEGCo, APCo, CSPCo, I&M, KEPCo and OPCo also sell electric power on a wholesale basis to non-affiliated electric utilities and power marketers. Such sales are either made by the AEP System and then allocated among APCo, CSPCo, I&M, KEPCo and OPCo based on member-load-ratios or made by individual companies pursuant to various long-term power agreements. The following table shows the net realization (revenue less operating, maintenance, fuel and federal income tax expenses) of the various companies from such sales during the years ended December 31, 1994, 1995 and 1996: 1994(a) 1995(a) 1996(a) ------- ------- ------- (in thousands) AEGCo(b) . . . . . . . $ 30,800 $ 29,200 $ 26,300 APCo(c). . . . . . . . 25,000 24,100 36,800 CSPCo(c) . . . . . . . 11,700 12,000 18,100 I&M(c)(d). . . . . . . 34,600 34,700 43,000 KEPCo(c) . . . . . . . 4,800 5,000 7,600 OPCo(c). . . . . . . . 20,000 20,200 30,200 ------- ------- ------- Total System. . . $126,900 $125,200 $162,000 ======= ======= ======= - ---------------- (a) Such sales do not include wholesale sales to full/partial requirement customers of AEP System companies. See the discussion below. (b) All amounts for AEGCo are from sales made pursuant to a long-term power agreement. See AEGCo -- Unit Power Agreements. (c) All amounts, except for I&M, are from System sales which are allocated among APCo, CSPCo, I&M, KEPCo and OPCo based upon member-load-ratio. All System sales made in 1994, 1995 and 1996 were made on a short-term basis, except that $21,800,000, $22,500,000 and $33,300,000, respectively, of the contribution to operating income for the total System were from long-term System sales. (d) In addition to its allocation of System sales, the 1994, 1995 and 1996 amounts for I&M include $21,600,000, $21,000,000 and $20,900,000 from a long-term agreement to sell 250 megawatts of power scheduled to terminate in 2009. The AEP System has long-term system agreements to sell the following to unaffiliated utilities: (1) 100 megawatts of electric power through 1997; (2) 205 megawatts of electric power through 2010; and (3) 50 megawatts of electric power through August 2001. In addition to long-term and short-term sales, APCo, CSPCo, I&M, KEPCo and OPCo serve unaffiliated wholesale customers that are full/partial requirement customers. The aggregate maximum demand for these customers in 1996 was 606, 105, 413, 18 and 136 megawatts for APCo, CSPCo, I&M, KEPCo and OPCo, respectively. Although the terms of the contracts with these customers vary, they generally can be terminated by the customer upon one to four years' notice. Since 1995, customers have given notices of termination, effective in 1998 and 1999, for 405, 63 and 131 megawatts for APCo, I&M and OPCo, respectively. In June 1993, certain municipal customers of APCo, who have since given APCo notice to terminate their contracts in 1998, filed an application with the FERC for transmission service in order to reduce by 50 megawatts the power these customers then purchased under existing Electric Service Agreements (ESAs) and to purchase power from a third party. APCo maintains that its agreements with these customers are full-requirements contracts which preclude the customers from purchasing power from third parties. On February 10, 1994, the FERC issued an order finding that the ESAs are not full requirements contracts and that the ESAs give these municipal wholesale customers the option of substituting alternative sources of power for energy purchased from APCo. On May 24, 1994, APCo appealed the February 10, 1994 order of the FERC to the U.S. Court of Appeals for the District of Columbia Circuit. On July 1, 1994, the FERC ordered the requested transmission service and granted a complaint filed by the municipal customers directing certain modifications to the ESAs in order to accommodate their power purchases from the third party. Following FERC's denial of APCo's requests for rehearing, on December 20, 1995, APCo appealed the July 1, 1994 orders to the U.S. Court of Appeals for the District of Columbia. Effective August 1994, these municipal customers reduced their purchases by 40 megawatts. Certain of these customers further reduced their purchases by an additional 21 megawatts effective February 1996. On December 17, 1996, the U.S. Court of Appeals reversed the FERC's order directing APCo to provide transmission service and remanded the case to the FERC. TRANSMISSION SERVICES AEP's electric utility subsidiaries own and operate transmission and distribution lines and other facilities to deliver electric power. See Item 2 for more information regarding the transmission and distribution lines. AEP's electric utility subsidiaries operate their transmission lines as a single interconnected and coordinated system and share the cost and benefits in the AEP System Transmission Pool. Most of the transmission and distribution services is sold, in combination with electric power, to retail customers of AEP's utility subsidiaries in their service territories. These sales are made at rates that are established by the public utility commissions of the state in which they operate. See Rates. Some transmission services also are separately sold to non-affiliated companies. AEP System Transmission Pool APCo, CSPCo, I&M, KEPCo and OPCo are parties to the Transmission Agreement, dated April 1, 1984, as amended (the Transmission Agreement), defining how they share the costs associated with their relative ownership of the extra-high-voltage transmission system (facilities rated 345 kv and above) and certain facilities operated at lower voltages (138 kv and above). Like the Interconnection Agreement, this sharing is based upon each company's "member-load-ratio." See Sale of Power. The following table shows the net credits or (charges) allocated among the parties to the Transmission Agreement during the years ended December 31, 1994, 1995 and 1996: 1994 1995 1996 --------- --------- --------- (in thousands) APCo . . . . . . . . . $(10,200) $ (5,400) $ (6,500) CSPCo. . . . . . . . . (30,100) (31,100) (30,600) I&M. . . . . . . . . . 50,300 46,700 46,300 KEPCo. . . . . . . . . 4,300 3,500 3,300 OPCo . . . . . . . . . (14,300) (13,700) (12,500) Transmission Services for Non-Affiliates APCo, CSPCo, I&M, KEPCo, OPCo and other System companies also provide transmission services for non-affiliated companies. The following table shows the net realization (revenue less operating, maintenance, fuel and federal income tax expenses) of the various companies from such services during the years ended December 31, 1994, 1995 and 1996: 1994 1995 1996 -------- -------- -------- (In thousands) APCo . . . . . . . . . . $ 4,100 $ 6,000 $13,800 CSPCo. . . . . . . . . . 3,100 4,200 8,000 I&M. . . . . . . . . . . 6,700 4,800 7,700 KEPCo. . . . . . . . . . 800 1,200 2,800 OPCo . . . . . . . . . . 15,700 17,800 17,800 ------- ------- ------- Total System . . . . . . $30,400 $34,000 $50,100 ======= ======= ======= The AEP System has contracts with non-affiliated companies for transmission of approximately 5,000 megawatts of electric power on an annual or longer basis. On April 12, 1993, APCo, CSPCo, I&M, KEPCo and OPCo and two other AEP System companies filed a transmission tariff with the FERC under which these AEP System companies would provide limited transmission service to certain companies. The tariff covered the terms and conditions of the service, as well as the price which the companies pay for transmission services, regardless of the source of electric power generation. On September 3, 1993, the FERC issued an order accepting the transmission service tariff for filing, with the tariff becoming effective on September 7, 1993, subject to refund. On April 24, 1996, the FERC issued orders 888 and 889. These orders, which resulted from the FERC's March 29, 1995 Notice of Proposed Rulemaking ("Mega-NOPR"), require each public utility that owns or controls interstate transmission facilities to file an open access network and point-to-point transmission tariff that offers services comparable to the utility's own uses of its transmission system. The orders also require utilities to functionally unbundle their services, by requiring them to use their own tariffs in making off-system and third-party sales. As part of the orders, the FERC issued a pro-forma tariff which reflects the Commission's views on the minimum non-price terms and conditions for non-discriminatory transmission service. In addition, the orders require all transmitting utilities to establish an Open Access Same-time Information System ("OASIS") which electronically posts transmission information such as available capacity and prices, and require utilities to comply with Standards of Conduct which prohibit utilities' system operators from providing non-public transmission information to the utility's merchant employees. The orders also allow a utility to seek recovery of certain prudently-incurred stranded costs that result from unbundled transmission service. On July 9, 1996, the AEP System companies filed a tariff conforming with the FERC's pro-forma transmission tariff, subject to the resolution of certain pricing issues, which are still pending before FERC. AEP is presently engaged in discussions with several utilities regarding the creation of an independent system operator to operate the transmission system in the Midwestern region of the United States. See Competition and Business Change -- AEP Position on Competition. OVEC AEP, CSPCo and several unaffiliated utility companies jointly own OVEC, which supplies the power requirements of a uranium enrichment plant near Portsmouth, Ohio owned by the DOE. The aggregate equity participation of AEP and CSPCo in OVEC is 44.2%. The DOE demand under OVEC's power agreement, which is subject to change from time to time, is 1,760,000 kilowatts. On October 1, 1997, it is scheduled to increase to approximately 1,900,000 kilowatts and to remain at about that level through the remaining term of the contract. The proceeds from the sale of power by OVEC, aggregating $312,000,000 in 1996, are designed to be sufficient for OVEC to meet its operating expenses and fixed costs and to provide a return on its equity capital. APCo, CSPCo, I&M and OPCo, as sponsoring companies, are entitled to receive from OVEC, and are obligated to pay for, the power not required by DOE in proportion to their power participation ratios, which averaged 42.1% in 1996. The power agreement with DOE terminates on December 31, 2005, subject to early termination by DOE on not less than three years notice. The power agreement among OVEC and the sponsoring companies expires by its terms on March 12, 2006. BUCKEYE Contractual arrangements among OPCo, Buckeye and other investor-owned electric utility companies in Ohio provide for the transmission and delivery, over facilities of OPCo and of other investor-owned utility companies, of power generated by the two units at the Cardinal Station owned by Buckeye and back-up power to which Buckeye is entitled from OPCo under such contractual arrangements, to facilities owned by 27 of the rural electric cooperatives which operate in the State of Ohio at 301 delivery points. Buckeye is entitled under such arrangements to receive, and is obligated to pay for, the excess of its maximum one-hour coincident peak demand plus a 15% reserve margin over the 1,226,500 kilowatts of capacity of the generating units which Buckeye currently owns in the Cardinal Station. Such demand, which occurred on January 18, 1994, was recorded at 1,146,933 kilowatts. CERTAIN INDUSTRIAL CUSTOMERS Ravenswood Aluminum Corporation and Ormet Corporation operate major aluminum reduction plants in the Ohio River Valley at Ravenswood, West Virginia, and in the vicinity of Hannibal, Ohio, respectively. The power requirements of such plants presently are approximately 356,000 kilowatts for Ravenswood and 534,000 kilowatts for Ormet. On October 3, 1996, the PUCO approved, with some exceptions, a contract pursuant to which OPCo will continue to provide electric service to Ravenswood for the period July 1, 1996 through July 31, 2003. On February 6, 1997, the PUCO approved an amendment to the contract addressing these exceptions and the amended contract is now in effect. On November 14, 1996, the PUCO approved (1) an interim agreement pursuant to which OPCo will continue to provide electric service to Ormet for the period December 1, 1997 through December 31, 1999 and (2) a joint petition with an electric cooperative to transfer the right to serve Ormet to the electric cooperative after December 31, 1999. As part of the territorial transfer, OPCo and Ormet entered into an agreement which contains penalties and other provisions designed to avoid having OPCo provide involuntary back-up power to Ormet. See Legal Proceedings for a discussion of litigation involving Ormet. AEGCO Since its formation in 1982, AEGCo's business has consisted of the ownership and financing of its 50% interest in the Rockport Plant and, since 1989, leasing of its 50% interest in Unit 2 of the Rockport Plant. The operating revenues of AEGCo are derived from the sale of capacity and energy associated with its interest in the Rockport Plant to I&M, KEPCo and VEPCo, pursuant to unit power agreements. Pursuant to these unit power agreements, AEGCo is entitled to recover its full cost of service from the purchasers and will be entitled to recover future increases in such costs, including increases in fuel and capital costs. See Unit Power Agreements. Pursuant to a capital funds agreement, AEP has agreed to provide cash capital contributions, or in certain circumstances subordinated loans, to AEGCo, to the extent necessary to enable AEGCo, among other things, to provide its proportionate share of funds required to permit continuation of the commercial operation of the Rockport Plant and to perform all of its obligations, covenants and agreements under, among other things, all loan agreements, leases and related documents to which AEGCo is or becomes a party. See Capital Funds Agreement. Unit Power Agreements A unit power agreement between AEGCo and I&M (the I&M Power Agreement) provides for the sale by AEGCo to I&M of all the power (and the energy associated therewith) available to AEGCo at the Rockport Plant. I&M is obligated, whether or not power is available from AEGCo, to pay as a demand charge for the right to receive such power (and as an energy charge for any associated energy taken by I&M) such amounts, as when added to amounts received by AEGCo from any other sources, will be at least sufficient to enable AEGCo to pay all its operating and other expenses, including a rate of return on the common equity of AEGCo as approved by FERC, currently 12.16%. The I&M Power Agreement will continue in effect until the date that the last of the lease terms of Unit 2 of the Rockport Plant has expired unless extended in specified circumstances. Pursuant to an assignment between I&M and KEPCo, and a unit power agreement between KEPCo and AEGCo, AEGCo sells KEPCo 30% of the power (and the energy associated therewith) available to AEGCo from both units of the Rockport Plant. KEPCo has agreed to pay to AEGCo in consideration for the right to receive such power the same amounts which I&M would have paid AEGCo under the terms of the I&M Power Agreement for such entitlement. The KEPCo unit power agreement expires on December 31, 1999, unless extended. A unit power agreement among AEGCo, I&M, VEPCo, and APCo provides for, among other things, the sale of 70% of the power and energy available to AEGCo from Unit 1 of the Rockport Plant to VEPCo by AEGCo from January 1, 1987 through December 31, 1999. VEPCo has agreed to pay to AEGCo in consideration for the right to receive such power those amounts which I&M would have paid AEGCo under the terms of the I&M Power Agreement for such entitlement. Approximately 32% of AEGCo's operating revenue in 1996 was derived from its sales to VEPCo. Capital Funds Agreement AEGCo and AEP have entered into a capital funds agreement pursuant to which, among other things, AEP has unconditionally agreed to make cash capital contributions, or in certain circumstances subordinated loans, to AEGCo to the extent necessary to enable AEGCo to (i) maintain such an equity component of capitalization as required by governmental regulatory authorities, (ii) provide its proportionate share of the funds required to permit commercial operation of the Rockport Plant, (iii) enable AEGCo to perform all of its obligations, covenants and agreements under, among other things, all loan agreements, leases and related documents to which AEGCo is or becomes a party (AEGCo Agreements), and (iv) pay all indebtedness, obligations and liabilities of AEGCo (AEGCo Obligations) under the AEGCo Agreements, other than indebtedness, obligations or liabilities owing to AEP. The Capital Funds Agreement will terminate after all AEGCo Obligations have been paid in full. INDUSTRY PROBLEMS The electric utility industry, including the operating subsidiaries of AEP, has encountered at various times in the last 15 years significant problems in a number of areas, including: delays in and limitations on the recovery of fuel costs from customers; proposed legislation, initiative measures and other actions designed to prohibit construction and operation of certain types of power plants under certain conditions and to eliminate or reduce the extent of the coverage of fuel adjustment clauses; inadequate rate increases and delays in obtaining rate increases; jurisdictional disputes with state public utilities commissions regarding the interstate operations of integrated electric systems; requirements for additional expenditures for pollution control facilities; increased capital and operating costs; construction delays due, among other factors, to pollution control and environmental considerations and to material, equipment and fuel shortages; the economic effects on net income (which when combined with other factors may be immediate and adverse) associated with placing large generating units and related facilities in commercial operation, including the commencement at that time of substantial charges for depreciation, taxes, maintenance and other operating expenses, and the cessation of AFUDC with respect to such units; uncertainties as to conservation efforts by customers and the effects of such efforts on load growth; depressed economic conditions in certain regions of the United States; increasingly competitive conditions in the wholesale and retail markets; proposals to deregulate certain portions of the industry and revise the rules and responsibilities under which new generating capacity is supplied; and substantial increases in construction costs and difficulties in financing due to high costs of capital, uncertain capital markets, charter and indenture limitations restricting conventional financing, and shortages of cash for construction and other purposes. SEASONALITY Sales of electricity by the AEP System tend to increase and decrease because of the use of electricity by residential and commercial customers for cooling and heating and relative changes in temperature. FRANCHISES The operating companies of the AEP System hold franchises to provide electric service in various municipalities in their service areas. These franchises have varying provisions and expiration dates. In general, the operating companies consider their franchises to be adequate for the conduct of their business. COMPETITION AND BUSINESS CHANGE General The public utility subsidiaries of AEP, like other electric utilities, have traditionally provided electric generation and energy delivery, consisting of transmission and distribution services, as a single product to their retail customers. FERC has required utilities to sell transmission services separately from their other services. Proposals are being made that would also require electric utilities to sell distribution services separately. These proposals generally allow competition in the generation and sale of electric power, but not in its transmission and distribution. Competition in the generation and sale of electric power will require resolution of complex issues, including who will pay for the unused generating plant of, and other stranded costs incurred by, the utility when a customer stops buying power from the utility; will all customers have access to the benefits of competition; how will the rules of competition be established; what will happen to conservation and other regulatory-imposed programs; how will the reliability of the transmission system be ensured; and how will the utility's obligation to serve be changed. As a result, it is not clear how or when competition in generation and sale of electric power will be instituted. However, if competition in generation and sale of electric power is instituted, the public utility subsidiaries of AEP believe that they have a favorable competitive position because of their relatively low costs. If stranded costs are not recovered from customers, however, the public utility subsidiaries of AEP, like all electric utilities, will be required by existing accounting standards to recognize stranded investment losses. Wholesale The public utility subsidiaries of AEP, like the electric industry generally, face increasing competition to sell available power on a wholesale basis, primarily to other public utilities and also to power marketers. The Energy Policy Act of 1992 was designed, among other things, to foster competition in the wholesale market (a) through amendments to PUHCA, facilitating the ownership and operation of generating facilities by "exempt wholesale generators" (which may include independent power producers as well as affiliates of electric utilities) and (b) through amendments to the Federal Power Act, authorizing the FERC under certain conditions to order utilities which own transmission facilities to provide wholesale transmission services for other utilities and entities generating electric power. The principal factors in competing for such sales are price (including fuel costs), availability of capacity and reliability of service. The public utility subsidiaries of AEP believe that they maintain a favorable competitive position on the basis of all of these factors. However, because of the availability of capacity of other utilities and the lower fuel prices in recent years, price competition has been, and is expected for the next few years to be, particularly important. FERC orders 888 and 889, issued in April 1996, provide that utilities must functionally unbundle their transmission services, by requiring them to use their own tariffs in making off-system and third-party sales. See Transmission Services. The public utility subsidiaries of AEP have functionally separated their wholesale power sales from their transmission functions, as required by orders 888 and 889. Retail The public utility subsidiaries of AEP generally have the exclusive right to sell electric power at retail within their service areas. However, they do compete with self-generation and with distributors of other energy sources, such as natural gas, fuel oil and coal, within their service areas. The primary factors in such competition are price, reliability of service and the capability of customers to utilize sources of energy other than electric power. With respect to self-generation, the public utility subsidiaries of AEP believe that they maintain a favorable competitive position on the basis of all of these factors. With respect to alternative sources of energy, the public utility subsidiaries of AEP believe that the reliability of their service and the limited ability of customers to substitute other cost-effective sources for electric power place them in a favorable competitive position, even though their prices may be higher than the costs of some other sources of energy. Significant changes in the global economy in recent years have led to increased price competition for industrial companies in the United States, including those served by the AEP System. Such industrial companies have requested price reductions from their suppliers, including their suppliers of electric power. In addition, industrial companies which are downsizing or reorganizing often close a facility based upon its costs, which may include, among other things, the cost of electric power. The public utility subsidiaries of AEP cooperate with such customers to meet their business needs through, for example, various off-peak or interruptible supply options and believe that, as low cost suppliers of electric power, they should be less likely to be materially adversely affected by this competition and may be benefitted by attracting new industrial customers to their service territories. The legislatures and/or the regulatory commissions in many states are considering "retail customer choice" which, in general terms, means the transmission by an electric utility of electric power generated by an entity of the customer's choice over its transmission and distribution system to a retail customer in such utility's service territory. A requirement to transmit directly to retail customers would have the result of permitting retail customers to purchase electric power, at the election of such customers, not only from the electric utility in whose service area they are located but from another electric utility, an independent power producer or an intermediary, such as a power marketer. Although AEP's power generation would have competitors under some of these proposals, its transmission and distribution would not. If competition develops in retail power generation, the public utility subsidiaries of AEP believe that they have a favorable competitive position because of their relatively low costs. Federal: Legislation to provide for retail competition among electric energy suppliers has been introduced in both the U.S. Senate and House of Representatives. Indiana: In January 1997, S.B. 427 was introduced in the Indiana Senate. The bill proposed that all customers would have the unrestricted right to choose their generator of electricity by July 1, 2004. Under the bill, customers could choose their power supplier after October 1, 1999, by paying an access charge. Transmission and distribution services would continue to be regulated at the federal and state levels, respectively. The Indiana Senate Commerce Committee held hearings on S.B. 427, and on February 25, 1997, amended the bill to have a legislative committee study electric industry competition. Michigan: In June 1995, the MPSC issued an order approving an experimental five-year retail wheeling program and ordered Consumers Energy Company and Detroit Edison Company, unaffiliated utilities, to make retail delivery services available to a group of industrial customers, in the amount of 60 megawatts and 90 megawatts, respectively. The experiment commences when each utility needs new capacity. The experiment seeks, as its goal, to determine whether a retail wheeling program best serves the public interest in a manner that promotes retail competition in a non-discriminatory fashion. During the experiment, the MPSC will collect information regarding the effects of retail wheeling. Consumers, Detroit Edison and other parties have appealed the MPSC's order to the Michigan Court of Appeals. In January 1996, the Governor of Michigan endorsed a proposal of the Michigan Jobs Commission to promote competition and customer choice in energy and requested that the MPSC review the existing statutory and regulatory framework governing Michigan utilities in light of increasing competition in the utility industry. I&M, in response to a MPSC order promulgated pursuant to the Michigan Jobs Committee proposals, filed in June 1996 a proposed open access distribution tariff applicable to new or expanding electric loads. The MPSC has not yet taken action on I&M's filing. In December 1996, the MPSC staff issued a report on electric industry restructuring which recommends a phase-in program from 1997 through 2004 of direct access to electricity suppliers applicable to all customers. The MPSC is holding hearings on the staff report and has directed utilities to provide information on the implementation of the staff's recommendations. Ohio: On April 15, 1994, the Ohio Energy Strategy Task Force released its final report. The report contained seven broad implementation strategies along with 53 specific initiatives to be undertaken by government and the private sector. One strategy recommended continuing to encourage competition in the electric utility industry in a manner which maximizes benefits and efficiencies for all customers. An initiative under this strategy recommends facilitating informal roundtable discussions on issues concerning competition in the electric utility industry and promoting increased competitive options for Ohio businesses that do not unduly harm the interests of utility company shareholders or ratepayers. The PUCO has begun such discussions. As a result, on February 15, 1996, the PUCO adopted guidelines for interruptible electric service, including a buy-through provision that will enable customers to avoid being interrupted during utility capacity deficiencies by having the utility purchase off-system replacement power for the customer. On February 28, 1997, CSPCo and OPCo implemented four new interruptible electric services in conformance with the PUCO guidelines. Also stemming from the roundtable discussions, on December 24, 1996, the PUCO issued conjunctive electric service guidelines under which customers may be aggregated for cost-of-service, rate design, rate eligibility and billing purposes. The Ohio investor-owned electric utilities were ordered by the PUCO to file conjunctive electric service tariff applications conforming to the guidelines. In February 1997, the Ohio General Assembly formed the Joint Committee on Electric Utility Deregulation to study and report to the General Assembly concerning deregulation of the electric utility industry in Ohio. The Joint Committee is scheduled to issue its report by October 1, 1997. In February 1997, H.B. 220 was introduced in the Ohio House of Representatives. The bill is essentially identical to H.B. 653 introduced in the last session. The bill proposes that all customers be permitted to select their electricity suppliers effective January 1, 1998. The bill eliminates price regulation of electricity generation functions in favor of market based prices. Service area rights for Ohio's electricity suppliers would be confined to distribution service. Transmission and distribution services would continue to be regulated at the federal and state levels, respectively. The bill would require Ohio's electric utilities to functionally unbundle their generation, transmission and distribution services. Electric utilities would be permitted to recover transition costs provided that such recovery does not cause prices to exceed those in effect on the effective date of the legislation. Virginia: In September 1995, the Virginia SCC instituted a proceeding to review and consider policy regarding restructuring and the role of competition in the electric utility industry in Virginia. Pursuant to the Virginia SCC's order, its staff conducted an investigation into current issues in the electric utility industry and, in July 1996, filed a report of its observations and recommendations. Following the receipt of comments from interested parties, the Virginia SCC issued an order in November 1996 directing the three largest electric utility companies in the state, including APCo, to file various studies and information with the Virginia SCC by March 31, 1997. In addition, the November 1996 order directs the staff of the Virginia SCC to file reports on subjects pertinent to the ongoing investigation throughout 1997. In February 1997, the Virginia legislature passed a resolution requiring the staff of the Virginia SCC to develop and provide to the joint subcommittee of the legislature studying restructuring of the electric utility industry, by November 1997, its draft of a working model of a restructured electric utility industry most appropriate for Virginia. Five working groups, consisting of representatives from the Virginia SCC staff and other interested parties, have been organized to develop various aspects of such a model. West Virginia: In December 1996, the West Virginia PSC issued an order initiating a general investigation into the restructuring of the regulated electric industry, the establishment of competition in power supply markets, and the establishment of retail wheeling and intra-state open access of jurisdictional power distribution systems. Pursuant to the West Virginia PSC's order, various parties have filed comments and the West Virginia PSC has scheduled a hearing on these matters commencing May 1, 1997. Certain Other States in the Vicinity of AEP's Service Territory: In March 1996, the Illinois Commerce Commission approved, and two Illinois-based electric utilities implemented, retail wheeling pilot programs whereby certain classes of customers are eligible to choose their electricity providers. In addition, several bills have been introduced in the Illinois legislature that would provide for retail competition among electric energy suppliers. In May 1996, the New York Public Service Commission issued an Opinion and Order Regarding Competitive Opportunities for Electric Service. The Opinion and Order required each of the seven major electric utilities in New York to file a rate/restructuring plan with the New York Public Service Commission in which the utilities were to classify transmission and distribution facilities and address the formation of an independent system operator for their transmission systems. The Opinion and Order called for the establishment of a competitive wholesale power market by early 1997 and the introduction of retail customer choice early in 1998. In late 1996, Pennsylvania enacted the Electricity Generation Customer Choice and Competition Act. The Act requires Pennsylvania's electric utilities to unbundle their rates and services and to provide open access over their transmission and distribution systems to allow competitive suppliers to generate and sell electricity directly to consumers in Pennsylvania. The Act provides for phased implementation of retail access, with 33% of the peak load having direct access by January 1, 1999, 66% of the peak load having direct access by January 1, 2000, and all customers having direct access by January 1, 2001. Transmission and distribution of electricity will continue to be regulated as a monopoly subject to the jurisdiction of the Pennsylvania Public Utility Commission. AEP Position on Competition In October 1995, AEP announced that it favored freedom for customers to purchase electric power from anyone that they choose. Generation and sale of electric power would be in the competitive marketplace. To facilitate reliable, safe and efficient service, AEP supports creation of independent system operators to operate the transmission system in a region of the United States. In addition, AEP supports the evolution of regional power exchanges which would establish a competitive marketplace for the sale of electric power. Transmission and distribution would remain monopolies and subject to regulation with respect to terms and price. Regulators would be able to establish distribution service charges which would provide, as appropriate, for recovery of stranded costs and regulatory assets. AEP's working model for industry restructuring envisions a progressive transition to full customer choice. Implementation of these measures would require legislative changes and regulatory approvals. Possible Strategic Responses In response to the competitive forces and regulatory changes being faced by AEP and its public utility subsidiaries, as discussed under this heading and under Regulation, AEP and its public utility subsidiaries have from time to time considered, and expect to continue to consider, various strategies designed to enhance their competitive position and to increase their ability to adapt to and anticipate changes in their utility business. These strategies may include business combinations with other companies, internal restructurings involving the complete or partial separation of their generation, transmission and distribution businesses, acquisitions of related or unrelated businesses, and additions to or dispositions of portions of their franchised service territories. AEP and its public utility subsidiaries may from time to time be engaged in preliminary discussions, either internally or with third parties, regarding one or more of these potential strategies. No assurances can be given as to whether any potential transaction of the type described above may actually occur, or as to its ultimate effect on the financial condition or competitive position of AEP and its public utility subsidiaries. NEW BUSINESS DEVELOPMENT AEP continues to consider new business opportunities, particularly those which allow use of its expertise. These endeavors began in 1982 and are conducted through AEP Resources, Inc. (Resources), AEP Resources International, Limited (AEPRI), AEP Resources Engineering & Services Company (formerly AEP Energy Services, Inc.) (AEPRES) and AEP Energy Services, Inc. (formerly AEP Energy Solutions, Inc.) (AEPES). Resources' and AEPRI's primary business is development of, and investment in, exempt wholesale generators, foreign utility companies, qualifying cogeneration facilities and other power projects. On February 24, 1997, AEP and Public Service Company of Colorado (PSCo) jointly agreed with the Board of Directors of Yorkshire Electricity Group plc (Yorkshire Electricity) in the United Kingdom to make a cash tender offer (the Tender Offer) for Yorkshire Electricity. The Tender Offer values Yorkshire Electricity at U.S. $2.4 billion. The Tender Offer will be effected by Yorkshire Holdings plc, a holding company owned by Yorkshire Power Group Limited, which is equally owned and controlled by Resources and New Century International Inc. (NCII), a wholly-owned subsidiary of PSCo. Resources and NCII will each contribute U.S. $360 million toward the Tender Offer with the remaining U.S. $1.7 billion funded through a non-recourse loan to Yorkshire Power Group Limited. Yorkshire Electricity is an English inde- pendent regional electricity company. It is principally engaged in the distribution of electricity to 2.1 million customers in its authorized service territory comprised of 4,180 square miles in northeast England. AEPRI's subsidiary, AEP Pushan Power LDC, has a 70% interest in Nanyang General Light Electric Co., Ltd. (Nanyang Electric), a joint venture organized to develop and build two 125 megawatt coal-fired generating units near Nanyang City in the Henan Province of The Peoples Republic of China. Nanyang Electric was established in 1996 by AEP Pushan Power LDC, Henan Electric Power Development Co. (15% interest) and Nanyang Municipal Finance Development Co. (15% interest). Funding for the construction of the generating units has commenced and will continue through completion which is expected to occur by 1999. AEPRI's share of the total cost of the project of $172 million is estimated to be approximately $120 million. AEPRES offers engineering, construction, project management and other consulting services for projects involving transmission, distribution or generation of electric power both domestically and internationally. AEP has received approval from the SEC under PUHCA to finance up to 50%, and is seeking approval to finance up to 100%, of its consolidated retained earnings (approximately $1,500,000,000), for investment in exempt wholesale generators and foreign utility companies. Resources expects to investigate opportunities to develop and invest in new, and invest in existing, generation projects worldwide. In September 1996, the SEC authorized AEP to invest up to $100,000,000 in subsidiaries engaged in the business of marketing energy commodities, including electricity and gas. The SEC also adopted Rule 58, effective March 24, 1997, which permits AEP and other registered holding companies to invest up to 15% of consolidated capitalization in energy-related companies. In September 1996, AEP formed AEPES to market natural gas and consider marketing electric power at retail where permitted by state law. In July 1996, AEP Power Marketing, Inc. (AEP Marketing), a wholly-owned subsidiary of AEP, requested authority from FERC to market electric power at wholesale at market-based rates. In September, the FERC accepted the filing, conditioned upon, among other things, that the utility subsidiaries of AEP not (1) sell nonpower goods or services to any affiliate at a price below its cost or market price, whichever is higher and (2) purchase nonpower goods or services from any affiliate at a price above market price. AEP Marketing filed a request that FERC clarify that this condition only apply to transactions between utility subsidiaries and AEP Marketing. AEP Marketing is inactive pending FERC's decision. These continuing efforts to invest in and develop new business opportunities offer the potential of earning returns which may exceed those of rate-regulated operations. However, they also involve a higher degree of risk which must be carefully considered and assessed. AEP may make substantial investments in these and other new businesses. CONSTRUCTION PROGRAM OF OPERATING COMPANIES New Generation The AEP System companies are continuously involved in an assessment of the adequacy of its generation, transmission, distribution and other facilities necessary to provide for the reliable supply of electric power and energy to its customers. In this assessment and planning process, assumptions are continually being reviewed as new information becomes available, and assessments and plans are modified accordingly, as appropriate. Thus, system reinforcement plans are subject to change, particularly with the anticipated restructuring of the electric utility industry and the move to increasing competition in the marketplace. See Competition and Business Change. Committed or anticipated capability changes to the AEP System generation resources through the year 2000 include: a purchase from an independent power producer's hydro project with an expected capacity value of 28 megawatts, reratings of several existing AEP System generating units, and the termination of the Rockport Unit 1 sale of 455 megawatts to VEPCo on December 31, 1999 (see AEGCo). Beyond these changes, there are no specific commitments for additions of new generation resources on the AEP System. In this regard, the most recent resource plan filed by AEP's electric utility subsidiaries with various state commissions indicates no need for new generation until about the year 2002, at the very earliest. When the time for commitment to specific capacity additions approaches, all means for adding such capacity, including self-build and external resource options, will be considered. However, given the restructuring that is expected to take place in the industry, the need of AEP's operating companies for any additional generation resources in the foreseeable future is highly uncertain. Proposed Transmission Facilities APCo: On March 23, 1990, APCo and VEPCo announced plans, subject to regulatory approval, for major new transmission facilities. APCo will construct approximately 115 miles of 765,000-volt line from APCo's Wyoming station in southern West Virginia to APCo's Cloverdale station near Roanoke, Virginia. VEPCo will construct approximately 102 miles of 500,000-volt line from APCo's Joshua Falls station east of Lynchburg, Virginia to VEPCo's Ladysmith station north of Richmond, Virginia. The construction of the transmission lines and related station improvements will provide needed reinforcement for APCo's internal load, reinforce the ability to exchange electric power between the two companies and relieve present constraints on the transmission of electric power from potential independent power producers in the APCo service area to VEPCo. APCo's cost is estimated at $245,000,000 while VEPCo's cost is estimated at $164,000,000. Management estimates that the project cannot be completed before December 2002, but the actual service date will be dependent upon the time necessary to meet various regulatory requirements. The U.S. Forest Service (Forest Service) is directing the preparation of an Environmental Impact Statement (EIS) which will be required prior to the granting of special use permits for crossing Federal lands. On June 18, 1996, the Forest Service released a Draft EIS. The Forest Service preliminarily identified a "No Action Alternative" as its preferred alternative. If this alternative is incorporated in the Final EIS, APCo would not be authorized to cross the Federally-administered lands of the Forest Service with the proposed transmission line. Hearings before the Virginia SCC were concluded in September 1993. A report was issued by the hearing examiner in December 1993 which recommended that the Virginia SCC grant APCo approval to construct the proposed 765,000-volt line. In an interim order issued on December 13, 1995, the Virginia SCC found that major additional transmission capacity was needed to serve APCo's native load customers. The Virginia SCC further asked that APCo provide additional information on possible routing modifications and utilization of the additional transmission capacity prior to a final ruling. On July 25, 1996, the Virginia SCC issued an order extending indefinitely the date for filing comments and suspending its proceeding on the transmission line due to the findings of the Draft EIS. However, the Virginia SCC ordered APCo to file, on or before December 1, 1996, a proposal detailing its intentions with regard to meeting the need for major additional transmission capacity identified in the Virginia SCC's interim order of December 13, 1995. In APCo's December 1996 filing with the Virginia SCC, APCo reviewed the need for the project, taking into account the additional transmission improvements completed after August 1991, and improvements projected to be in service prior to completion of the proposed project. As part of the review, APCo also considered the implications of electric utility industry restructuring. Based on the review and after considering all possible alternatives, APCo concluded that the need for reinforcement of the transmission system serving its central and eastern areas remains compelling and that the proposed Wyoming-Cloverdale project is the most proper alternative for addressing that need. APCo intends to file an amended application in Virginia. APCo refiled with the West Virginia PSC in February 1993 its application for certification. An application filed in June 1992 was withdrawn at the request of the West Virginia PSC to permit additional time for review by the West Virginia PSC. The West Virginia PSC rejected APCo's application for certification in May 1993, directing APCo to supplement its line siting information. APCo intends to refile its application with the West Virginia PSC. Given the findings set forth in the Draft EIS and the preliminary position of the Forest Service, APCo cannot presently predict the schedule for completion of the state and Federal permitting process. APCo and KEPCo: APCo and KEPCo have announced an improvement plan to be implemented during a four-year period (1996-1999) to reinforce their 138,000-volt transmission system. Included in this plan is a new transmission line to link KEPCo's Big Sandy Plant to communities in eastern Kentucky. APCo's and KEPCo's estimated project costs are $5,115,000 and $84,184,000, respectively. The KPSC approved the project in its order dated June 11, 1996. Construction commenced in late 1996. Construction Expenditures The following table shows the construction expenditures by AEGCo, APCo, CSPCo, I&M, KEPCo, OPCo and the AEP System and their respective consolidated subsidiaries during 1994, 1995 and 1996 and their current estimate of 1997 construction expenditures, in each case including AFUDC but excluding nuclear fuel and other assets acquired under leases. The construction expenditures for the years 1994-1996 were, and it is anticipated that the estimated construction expenditures for 1997 will be, approximately:
1994 1995 1996 1997 Actual Actual Actual Estimate -------- -------- -------- -------- (in thousands) AEGCo. . . . . . . . . $ 3,900 $ 4,000 $ 2,200 $ 4,000 APCo . . . . . . . . . 230,300 217,600 192,900 205,000 CSPCo. . . . . . . . . 81,500 99,500 93,600 124,000 I&M. . . . . . . . . . 114,500 113,000 90,500 106,000 KEPCo. . . . . . . . . 53,200 39,300 75,800 72,000 OPCo (a) . . . . . . . 149,000 116,900 113,800 151,800 -------- -------- -------- -------- AEP System (b). . . $642,100 $601,200 $578,000 $672,000 ======== ======== ======== ========
- ---------------- (a) Excludes expenditures associated with flue-gas desulfurization system which was constructed by a non-affiliate at the Gavin Plant and is being leased by OPCo. Actual expenditures for such system for 1994, 1995 and 1996 and the current estimate for 1997 are $176,220,000, $48,804,000, $6,400,000 and $14,000,000, respectively. (b) Includes expenditures of other subsidiaries not shown. Reference is made to the footnotes to the financial statements entitled Commitments and Contingencies incorporated by reference in Item 8, for further information with respect to the construction plans of AEP and its operating subsidiaries for the next three years. The System construction program is reviewed continuously and is revised from time to time in response to changes in estimates of customer demand, business and economic conditions, the cost and availability of capital, environmental requirements and other factors. Changes in construction schedules and costs, and in estimates and projections of needs for additional facilities, as well as variations from currently anticipated levels of net earnings, Federal income and other taxes, and other factors affecting cash requirements, may increase or decrease the estimated capital requirements for the System's construction program. From time to time, as the System companies have encountered the industry problems described above, such companies also have encountered limitations on their ability to secure the capital necessary to finance construction expenditures. Environmental Expenditures: Expenditures related to compliance with air and water quality standards, included in the gross additions to plant of the System, during 1994, 1995 and 1996 and the current estimate for 1997 are shown below. Substantial expenditures in addition to the amounts set forth below may be required by the System in future years in connection with the modification and addition of facilities at generating plants for environmental quality controls in order to comply with air and water quality standards which have been or may be adopted.
1994 1995 1996 1997 Actual Actual Actual Estimate -------- -------- -------- -------- (in thousands) AEGCo. . . . . . . . . $ 0 $ 0 $ 0 $ 0 APCo . . . . . . . . . 32,000 7,800 10,500 6,800 CSPCo. . . . . . . . . 13,700 10,000 1,800 1,900 I&M. . . . . . . . . . 0 0 0 300 KEPCo. . . . . . . . . 9,500 600 0 800 OPCo (a) . . . . . . . 22,400 3,100 1,600 5,900 ------- ------- ------- ------- AEP System (a) . . . . $77,600 $21,500 $13,900 $15,700 ======= ======= ======= =======
- ------------------ (a) Excludes expenditures associated with flue-gas desulfurization system which was constructed by a non-affiliate at the Gavin Plant and is being leased by OPCo. Actual expenditures for such system for 1994, 1995 and 1996 and the current estimate for 1997 are $176,220,000, $48,804,000, $6,400,000 and $14,000,000, respectively. FINANCING It has been the practice of AEP's operating subsidiaries to finance current construction expenditures in excess of available internally generated funds by initially issuing unsecured short-term debt, principally commercial paper and bank loans, at times up to levels authorized by regulatory agencies, and then to reduce the short-term debt with the proceeds of subsequent sales by such subsidiaries of long-term debt securities and preferred stock, and cash capital contributions by AEP. It has been the practice of AEP, in turn, to finance cash capital contributions to the common stock equities of its subsidiaries by issuing unsecured short-term debt, principally commercial paper, and then to sell additional shares of Common Stock of AEP for the purpose of retiring the short-term debt previously incurred. In 1996, AEP issued 1,600,000 shares of Common Stock pursuant to its Dividend Reinvestment and Stock Purchase Plan. Although prevailing interest costs of short-term bank debt and commercial paper generally have been lower than prevailing interest costs of long-term debt securities, whenever interest costs of short-term debt exceed costs of long-term debt, the companies might be adversely affected by reliance on the use of short-term debt to finance their construction and other capital requirements. During the period 1994-1996, external funds from financings and capital contributions by AEP amounted, with respect to APCo and KEPCo to approximately 40% and 61%, respectively, of the aggregate construction expenditures shown above. During this same period, the amount of funds used to retire long-term and short-term debt and preferred stock of AEGCo, CSPCo, I&M and OPCo exceeded the amount of funds from financings and capital contributions by AEP. The ability of AEP and its subsidiaries to issue short-term debt is limited by regulatory restrictions and, in the case of most of the operating subsidiaries, by provisions contained in certain debt and other instruments. The approximate amounts of short-term debt which the companies estimate that they were permitted to issue under the most restrictive such restriction, at January 1, 1997, and the respective amounts of short-term debt outstanding on that date, on a corporate basis, are shown in the following tabulation:
Total AEP Short-Term Debt AEP AEGCo APCo(b) CSPCo I&M(c) KEPCo OPCo(c) System(a) --------------- ----- ----- ------- ----- ------ ----- ------- --------- (in millions) Amount authorized ...... $150 $80 $227 $175 $175 $150 $223 $1,260 Amount outstanding: Notes payable ....... $ -- $10 $ -- $ 20 $ 4 $ 34 $ 4 $ 92 Commercial paper .... 42 -- 61 32 40 18 37 228 ---- --- ---- ---- ---- ---- ---- ------ $ 42 $10 $ 61 $ 52 $ 44 $ 52 $ 41 $ 320 ==== === ==== ==== ==== ==== ==== ======
- ------------------------- (a) Includes short-term debt of other subsidiaries not shown. (b) On February 28, 1997, APCo shareholders approved an amendment to APCo's charter removing a provision limiting APCo's ability to issue indebtedness. Without this provision, APCo would have been authorized to issue up to $250 million of short-term debt. (c) On February 28, 1997, I&M and OPCo shareholders approved amendments to their respective charters removing provisions limiting their ability to issue unsecured indebtedness. Without this provision, OPCo would have been authorized to issue up to $250 million of short-term debt. Reference is made to the footnotes to the financial statements incorporated by reference in Item 8 for further information with respect to unused short-term bank lines of credit. In order to issue additional first mortgage bonds and preferred stock, it is necessary for APCo, CSPCo, I&M, KEPCo and OPCo to comply with earnings coverage requirements contained in their respective mortgages and charters. The most restrictive of these provisions in each instance generally requires (1) for the issuance of first mortgage bonds for purposes other than the refunding of outstanding first mortgage bonds, a minimum, before income tax, earnings coverage of twice the pro forma annual interest charges on first mortgage bonds and (2) for the issuance of additional preferred stock by APCo, I&M and OPCo, a minimum, after income tax, gross income coverage of one and one-half times pro forma annual interest charges and preferred stock dividends, in each case for a period of twelve consecutive calendar months within the fifteen calendar months immediately preceding the proposed new issue. In computing such coverages, the companies include as a component of earnings revenues collected subject to refund (where applicable) and, to the extent not limited by the instrument under which the computation is made, AFUDC, including amounts positioned and classified as an allowance for borrowed funds used during construction. These coverage provisions have from time to time restricted the ability of one or more of the above subsidiaries of AEP to issue senior securities. The respective mortgage and preferred stock coverages of APCo, CSPCo, I&M, KEPCo and OPCo under their respective mortgage and charter provisions, calculated on the foregoing basis and in accordance with the respective amounts then recorded in the accounts of the companies, assuming the respective short-term debt of the companies at those dates were to remain outstanding for a twelve-month period at the respective rates of interest prevailing at those dates, were at least those stated in the following table: December 31, -------------------- 1994 1995 1996 ---- ---- ---- APCo Mortgage coverage . . . . . . . 3.12 3.47 3.98 Preferred stock coverage . . . 1.65 1.78 1.99 CSPCo Mortgage coverage . . . . . . . 3.64 3.90 4.44 I&M Mortgage coverage . . . . . . . 6.23 6.25 6.66 Preferred stock coverage . . . 2.74 2.63 3.07 KEPCo Mortgage coverage . . . . . . . 2.60 2.86 3.22 OPCo Mortgage coverage . . . . . . . 5.04 6.17 6.62 Preferred stock coverage . . . 2.58 3.04 3.63 Although certain other subsidiaries of AEP either are not subject to any coverage restrictions or are not subject to restrictions as constraining as those to which APCo, CSPCo, I&M, KEPCo and OPCo are subject, their ability to finance substantial portions of their construction programs may be subject to market limitations and other constraints unless other assurances are furnished. AEP believes that the ability of some of its subsidiaries to issue short- and long-term debt securities and preferred stock in the amounts required to finance their business may depend upon the timely approval of rate increase applications. If one or more of the subsidiaries are unable to continue the issuance and sale of securities on an orderly basis, such company or companies will be required to consider the use of alternative financing arrangements, if available, which may be more costly or the curtailment of construction and other outlays. AEP's subsidiaries have also utilized, and expect to continue to utilize, additional financing arrangements, such as leasing arrangements, including the leasing of utility assets, coal mining and transportation equipment and facilities and nuclear fuel. Pollution control revenue bonds have been used in the past and may be used in the future in connection with the construction of pollution control facilities; however, Federal tax law has limited the utilization of this type of financing except for purposes of certain financing of solid waste disposal facilities and of certain refunding of outstanding pollution control revenue bonds issued before August 16, 1986. Shares of AEP Common Stock may be sold by AEP from time to time at prices below the then current book value per share and repurchased by AEP at prices above book value. Such sales or purchases, if any, would have a dilutive effect on the book value of then outstanding shares but are not expected to have a material adverse effect on AEP's business including its future financing plans or capabilities and pending construction projects. RATES General The rates charged by the electric utility subsidiaries of AEP are approved by the FERC or one of the state utility commissions as applicable. The FERC regulates wholesale rates and the state commissions regulate retail rates. In recent years the number of rate increase applications filed by the operating subsidiaries of AEP with their respective state commissions and the FERC has decreased. Under current rate regulation, if increases in operating, construction and capital costs exceed increases in revenues resulting from previously granted rate increases and increased customer demand, then it may be appropriate for certain of AEP's electric utility subsidiaries to file rate increase applications in the future. Generally the rates of AEP's operating subsidiaries are determined based upon the cost of providing service including a reasonable return on investment. Certain states served by the AEP System allow alternative forms of rate regulation in addition to the traditional cost-of-service approach. The IURC may approve alternative regulatory plans which could include setting customer rates based on market or average prices, price caps, index-based prices and prices based on performance and efficiency. The Virginia SCC may approve (i) special rates, contracts or incentives to individual customers or classes of customers and (ii) alternative forms of regulation including, but not limited to, the use of price regulation, ranges of authorized returns, categories of services and price indexing. All of the seven states served by the AEP System, as well as the FERC, either permit the incorporation of fuel adjustment clauses in a utility company's rates and tariffs, which are designed to permit upward or downward adjustments in revenues to reflect increases or decreases in fuel costs above or below the designated base cost of fuel set forth in the particular rate or tariff, or permit the inclusion of specified levels of fuel costs as part of such rate or tariff. AEP cannot predict the timing or probability of approvals regarding applications for additional rate changes, the outcome of action by regulatory commissions or courts with respect to such matters, or the effect thereof on the earnings and business of the AEP System. See Competition and Business Change. APCo FERC: On February 14, 1992, APCo filed with the FERC applications for an increase in its wholesale rates to Kingsport Power Company and non-affiliated customers in the amounts of approximately $3,933,000 and $4,759,000, respectively. APCo began collecting the rate increases, subject to refund, on September 15, 1992. In addition, the Financial Accounting Standards Board has issued Statement of Financial Accounting Standards No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions (SFAS 106), which requires employers, beginning in 1993, to accrue for the costs of retiree benefits other than pensions. These rates include the higher level of SFAS 106 costs. On November 9, 1993, the administrative law judge issued an initial decision recommending, among other things, the higher level of post-retirement benefits other than pensions under SFAS 106. FERC action on APCo's applications is pending. Virginia: On December 20, 1996, APCo filed an application with the Virginia SCC to increase its annual fuel factor revenues by approximately $17,000,000. On January 31, 1997, the Virginia SCC approved APCo's request, effective February 1, 1997. West Virginia: Under the terms of a 1993 settlement agreement in the West Virginia jurisdiction, APCo agreed to a three-year base rate freeze and suspension of the West Virginia PSC Expanded Net Energy Cost (ENEC) recovery mechanism until October 31, 1996. On December 27, 1996, the West Virginia PSC approved a settlement agreement among APCo and other parties. In accordance with that agreement, the West Virginia PSC reduced APCo's base rates and ENEC rates by $5,000,000 and $28,000,000, respectively, on a one-time annual basis, effective November 1, 1996. Under the terms of the agreement, APCo's rates would not increase prior to January 1, 2000 and, through this date, ENEC cost variances will be subject to deferred accounting and a cumulative ENEC recovery balance will be maintained. Regardless of the actual cumulative ENEC recovery balance at December 31, 1999, ratepayers will not be responsible for any cumulative underrecovery and any cumulative overrecoveries will be treated in a manner to be determined by the West Virginia PSC, except that ENEC overrecoveries during each calendar year through December 31, 1999, in excess of $10,000,000 per period, will be accumulated and shared equally between APCo and its ratepayers. CSPCo Zimmer Plant: The Zimmer Plant was placed in commercial operation as a 1,300-megawatt coal-fired plant on March 30, 1991. CSPCo owns 25.4% of the Zimmer Plant with the remainder owned by two unaffiliated companies, CG&E (46.5%) and DP&L (28.1%). Zimmer Plant -- Rate Recovery: In May 1992, the PUCO issued an order providing for a phased-in rate increase of $123,000,000 for the Zimmer Plant to be implemented in three steps over a two-year period and disallowed $165,000,000 of Zimmer Plant investment. CSPCo appealed the PUCO ordered Zimmer disallowance and phase-in plan to the Ohio Supreme Court. In November 1993, the Supreme Court issued a decision on CSPCo's appeal affirming the disallowance and finding that the PUCO did not have statutory authority to order phased-in rates. The court instructed the PUCO to fix rates to provide gross annual revenues in accordance with the law and to provide a mechanism to recover the amounts deferred as regulatory assets under the phase-in order. As a result of the Supreme Court decision, in January 1994 the PUCO approved a 7.11% or $57,167,000 rate increase effective February 1, 1994. The increase is comprised of a 3.72% base rate increase to complete the rate increase phase-in and a temporary 3.39% surcharge, which will be in effect until the phase-in plan deferrals are recovered, estimated to be June 1997. In 1996, 1995 and 1994, $31,500,000, $28,500,000 and $18,500,000, respectively, of net phase-in deferrals were collected through the surcharge. The deferral balance was $15,400,000 at December 31, 1996 and $46,900,000 at December 31, 1995. The recovery of amounts deferred under the phase-in plan and the increase in rates to the full rate level did affect net income since the deferred costs are amortized commensurate with their recovery. From the in-service date of March 1991 until rates went into effect in May 1992, deferred carrying charges of $43,000,000 were recorded on the Zimmer Plant investment. Recovery of the deferred carrying charges will be sought in the next PUCO base rate proceeding in accordance with the PUCO accounting order that authorized the deferral. OPCo Under the terms of a stipulation agreement approved by the PUCO in November 1992, beginning December 1, 1994, the cost of coal burned at the Gavin Plant is subject to a 15-year predetermined price of $1.575 per million Btus with quarterly escalation adjustments. A 1995 PUCO-approved settlement agreement fixes the EFC factor at 1.465 cents per kwh for the period June 1995 through November 1998 (less Ohio jurisdictional emission allowance gains currently set at .043 cents per kwh which, commencing on December 1, 1996, are being returned to customers). After November 2009, the price that OPCo can recover for coal from its affiliated Meigs mine which supplies the Gavin Plant will be limited to the lower of cost or the then-current market price. The agreements provide OPCo with the opportunity to recover any operating losses incurred under the predetermined or fixed price, as well as its investment in, and liabilities and closing costs associated with, its affiliated mining operations attributable to its Ohio jurisdiction, to the extent the actual cost of coal burned at the Gavin Plant is below the predetermined price. Based on the estimated future cost of coal burned at Gavin Plant, management believes that the Ohio jurisdictional portion of the investment in, and liabilities and closing costs of, the affiliated mining operations, including deferred amounts, will be recovered under the terms of the predetermined price agreement. Management intends to seek from non-Ohio jurisdictional ratepayers recovery of the non-Ohio jurisdictional portion of the investment in, and the liabilities and closing costs of, OPCo's Meigs, Muskingum and Windsor mines, but there can be no assurance that such recovery will be approved. The non-Ohio jurisdictional portion of shutdown costs for these mines, which includes the investment in the mines, leased asset buy-outs, reclamation costs and employee benefits, is estimated to be approximately $90,000,000 for Meigs, $55,000,000 for Muskingum and $35,000,000 for Windsor, after tax at December 31, 1996. OPCo's Muskingum and Windsor mines may have to close by January 2000 as a result of compliance by the Muskingum River Plant and Cardinal Unit 1 with the Phase II requirements of the Clean Air Act Amendments of 1990 (see Environmental and Other Matters -- Air Pollution Control - Clean Air Act). The Muskingum and Windsor mines supply coal to Muskingum River Plant and Cardinal Plant, respectively. The Muskingum and/or Windsor mines could close prior to January 2000 depending on the economics of continued operation under the terms of the 1995 settlement agreement. Unless future shutdown costs and/or the cost of coal production of OPCo's Meigs, Muskingum and Windsor mines can be recovered, AEP's and OPCo's results of operations would be adversely affected. In November 1992, the municipal wholesale customers of OPCo filed a complaint with the SEC requesting an investigation of the sale of the Martinka mining operation to an unaffiliated company and an investigation into the pricing of OPCo's affiliated coal purchases back to 1986. OPCo has filed a response with the SEC seeking to dismiss this complaint. These customers also sought to intervene in three proceedings before the SEC. In September 1996, the SEC denied two requests to intervene, but has not ruled on the complaint. FUEL SUPPLY The following table shows the sources of power generated by the AEP System: 1992 1993 1994 1995 1996 ---- ---- ---- ---- ---- Coal . . . . . . . . . . . . 93% 86% 91% 88% 87% Nuclear. . . . . . . . . . . 6% 13% 8% 11% 12% Hydroelectric and other. . . 1% 1% 1% 1% 1% Variations in the generation of nuclear power are primarily related to refueling outages and, in 1992, a forced outage at Cook Plant Unit 2. See Cook Nuclear Plant. Coal The Clean Air Act Amendments of 1990 provide for the issuance of annual allowance allocations covering sulfur dioxide emissions at levels below historic emission levels for many coal-fired generating units of the AEP System. Phase I of this program began in 1995 and Phase II begins in 2000, with both phases requiring significant changes in coal supplies and suppliers. The full extent of such changes, particularly in regard to Phase II, however, has not been determined. See Environmental and Other Matters -- Air Pollution Control - Clean Air Act for the current compliance plan. In order to meet emission standards for existing and new emission sources, the AEP System companies will, in any event, have to obtain coal supplies, in addition to coal reserves now owned by System companies, through the acquisition of additional coal reserves and/or by entering into additional supply agreements, either on a long-term or spot basis, at prices and upon terms which cannot now be predicted. No representation is made that any of the coal rights owned or controlled by the System will, in future years, produce for the System any major portion of the overall coal supply needed for consumption at the coal-fired generating units of the System. Although AEP believes that in the long run it will be able to secure coal of adequate quality and in adequate quantities to enable existing and new units to comply with emission standards applicable to such sources, no assurance can be given that coal of such quality and quantity will in fact be available. No assurance can be given either that statutes or regulations limiting emissions from existing and new sources will not be further revised in future years to specify lower sulfur contents than now in effect or other restrictions. See Environmental and Other Matters herein. The FERC has adopted regulations relating, among other things, to the circumstances under which, in the event of fuel emergencies or shortages, it might order electric utilities to generate and transmit electric power to other regions or systems experiencing fuel shortages, and to rate-making principles by which such electric utilities would be compensated. In addition, the Federal Government is authorized, under prescribed conditions, to allocate coal and to require the transportation thereof, for the use of power plants or major fuel-burning installations. System companies have developed programs to conserve coal supplies at System plants which involve, on a progressive basis, limitations on sales of power and energy to neighboring utilities, appeals to customers for voluntary limitations of electric usage to essential needs, curtailment of sales to certain industrial customers, voltage reductions and, finally, mandatory reductions in cases where current coal supplies fall below minimum levels. Such programs have been filed and reviewed with officials of Federal and state agencies and, in some cases, the state regulatory agency has prescribed actions to be taken under specified circumstances by System companies, subject to the jurisdiction of such agencies. The mining of coal reserves is subject to Federal requirements with respect to the development and operation of coal mines, and to state and Federal regulations relating to land reclamation and environmental protection, including Federal strip mining legislation enacted in August 1977. Continual evaluation and study is given to possible closure of existing coal mines and divestiture or acquisition of coal properties in light of Federal and state environmental and mining laws and regulations which may affect the System's need for or ability to mine such coal. Western coal purchased by System companies is transported by rail to a terminal on the Ohio River for transloading to barges for delivery to generating stations on the river. Subsidiaries of AEP lease approximately 3,464 coal hopper cars to be used in unit train movements, as well as 14 towboats, 295 jumbo barges and 184 standard barges. Subsidiaries of AEP also own or lease coal transfer facilities at various other locations. The System generating companies procure coal from coal reserves which are owned or mined by subsidiaries of AEP, and through purchases pursuant to long-term contracts, or on a spot purchase basis, from unaffiliated producers. The following table shows the amount of coal delivered to the AEP System during the past five years, the proportion of such coal which was obtained either from coal-mining subsidiaries, from unaffiliated suppliers under long-term contracts or through spot or short-term purchases, and the average delivered price of spot coal purchased by System companies:
1992 1993 1994 1995 1996 ------ ------ ------ ------ ------ Total coal delivered to AEP operated plants (thousands of tons) . . . . . 44,738 40,561 49,024 46,867 51,030 Sources (percentage): Subsidiaries. . . . . . . . . 25% 20% 15% 14% 13% Long-term contracts . . . . . 65% 66% 65% 75% 71% Spot or short-term purchases. . . . . . . . . 10% 14% 20% 11% 16% Average price per ton of spot-purchased coal . . . . . $23.88 $23.55 $23.00 $25.15 $23.85
The average cost of coal consumed during the past five years by all AEP System companies, AEGCo, APCo, CSPCo, I&M, KEPCo and OPCo is shown in the following tables:
1992 1993 1994 1995 1996 ------ ------ ------ ------ ------ Dollars per ton AEP System Companies . . . . . $34.31 $33.57 $33.95 $32.52 $31.70 AEGCo . . . . . . . . . . . . 20.11 17.74 18.59 18.80 18.22 APCo . . . . . . . . . . . . . 43.00 42.65 39.89 38.86 37.60 CSPCo . . . . . . . . . . . . 33.87 33.87 32.80 33.23 31.70 I&M . . . . . . . . . . . . . 24.23 23.80 22.85 23.25 22.99 KEPCo. . . . . . . . . . . . . 30.24 27.08 26.83 26.91 27.25 OPCo . . . . . . . . . . . . . 38.36 38.12 41.10 37.58 35.96 Cents per Million Btu's AEP System Companies . . . . . 154.41 150.89 152.41 145.26 140.48 AEGCo. . . . . . . . . . . . . 120.90 107.71 112.06 112.87 109.25 APCo . . . . . . . . . . . . . 173.05 173.32 161.37 156.96 152.54 CSPCo. . . . . . . . . . . . . 143.94 143.66 140.45 140.79 134.60 I&M. . . . . . . . . . . . . . 135.11 129.39 123.62 125.50 121.16 KEPCo. . . . . . . . . . . . . 126.92 113.90 113.40 114.77 114.42 OPCo . . . . . . . . . . . . . 163.89 161.25 173.51 157.62 151.55
The coal supplies at AEP System plants vary from time to time depending on various factors, including customers' usage of electric power, space limitations, the rate of consumption at particular plants, labor unrest and weather conditions which may interrupt deliveries. At December 31, 1996, the System's coal inventory was approximately 45 days of normal System usage. This estimate assumes that the total supply would be utilized by increasing or decreasing generation at particular plants. The following tabulation shows the total consumption during 1996 of the coal-fired generating units of AEP's principal electric utility subsidiaries, coal requirements of these units over the remainder of their useful lives and the average sulfur content of coal delivered in 1996 to these units. Reference is made to Environmental and Other Matters for information concerning current emissions limitations in the AEP System's various jurisdictions and the effects of the Clean Air Act Amendments.
Average Sulfur Content Estimated Require- of Delivered Coal Total Consumption ments for Remainder ---------------------------- During 1996 of Useful Lives Pounds of SO2 (In Thousands of Tons) (In Millions of Tons) By Weight Per Million Btu's ---------------------- --------------------- --------- ----------------- AEGCo (a) . . . . . 5,091 257 0.3% 0.8 APCo. . . . . . . . 10,743 434 0.8% 1.3 CSPCo (b) . . . . . 5,859 226 2.8% 4.8 I&M (c) . . . . . . 6,975 296 0.8% 1.6 KEPCo . . . . . . . 2,425 89 1.2% 1.9 OPCo . . . . . . . 20,473 658 2.3% 3.8
- --------------------- (a) Reflects AEGCo's 50% interest in the Rockport Plant. (b) Includes coal requirements for CSPCo's interest in Beckjord, Stuart and Zimmer Plants. (c) Includes I&M's 50% interest in the Rockport Plant. AEGCo: See Fuel Supply -- I&M for a discussion ofthe coal supply for the Rockport Plant. APCo: Substantially all of the coal consumed at APCo's generating plants is obtained from unaffiliated suppliers under long-term contracts and/or on a spot purchase basis. The average sulfur content by weight of the coal received by APCo at its generating stations approximated 0.8% during 1996, whereas the maximum sulfur content permitted, for emission standard purposes, for existing plants in the regions in which APCo's generating stations are located ranged between 0.78% and 2% by weight depending in some circumstances on the calorific value of the coal which can be obtained for some generating stations. CSPCo: CSPCo has coal supply agreements with unaffiliated suppliers for the delivery of approximately 3,500,000 tons per year through 1998. Some of this coal is washed to improve its quality and consistency for use principally at Unit 4 of the Conesville Plant. CSPCo has been informed by CG&E and DP&L that, with respect to the CCD Group units partly owned but not operated by CSPCo, sufficient coal has been contracted for or is believed to be available for the approximate lives of the respective units operated by them. Under the terms of the operating agreements with respect to CCD Group units, each operating company is contractually responsible for obtaining the needed fuel. I&M: I&M has two coal supply agreements with unaffiliated suppliers pursuant to which the suppliers are delivering low sulfur coal from surface mines in Wyoming, principally for consumption by the Rockport Plant. Under these agreements, the suppliers will sell to I&M, for consumption by I&M at the Rockport Plant or consignment to other System companies, coal with an average sulfur content not exceeding 1.2 pounds of sulfur dioxide per million Btu's of heat input. One contract with remaining deliveries of 55,335,543 tons expires on December 31, 2014 and another contract with remaining deliveries of 49,005,000 tons expires on December 31, 2004. All of the coal consumed at I&M's Tanners Creek Plant is obtained from unaffiliated suppliers under long-term contracts and/or on a spot purchase basis. KEPCo: Substantially all of the coal consumed at KEPCo's Big Sandy Plant is obtained from unaffiliated suppliers under long-term contracts and/or on a spot purchase basis. KEPCo has coal supply agreements with unaffiliated suppliers pursuant to which KEPCo will receive approximately 2,500,000 tons of coal in 1997. To the extent that KEPCo has additional coal requirements, it may purchase coal from the spot market and/or suppliers under contract to supply other System companies. OPCo: The coal consumed at OPCo's generating plants is obtained from both affiliated and unaffiliated suppliers. The coal obtained from unaffiliated suppliers is purchased under long-term contracts and/or on a spot purchase basis. OPCo and certain of its coal-mining subsidiaries own or control coal reserves in the State of Ohio which contain approximately 205,000,000 tons of clean recoverable coal, which ranges in sulfur content between 3.4% and 4.5% sulfur by weight (weighted average, 3.8%), which can be recovered based upon existing mining plans and projections and employing current mining practices and techniques. OPCo and certain of its mining subsidiaries own an additional 113,000,000 tons of clean recoverable coal in Ohio which ranges in sulfur content between 2.4% and 3.4% sulfur by weight (weighted average 2.6%). Recovery of this coal would require substantial development. OPCo and certain of its coal-mining subsidiaries also own or control coal reserves in the State of West Virginia which contain approximately 105,000,000 tons of clean recoverable coal ranging in sulfur content between 1.4% and 3.3% sulfur by weight (weighted average, 2.0%) of which approximately 28,000,000 tons can be recovered based upon existing mining plans and projections and employing current mining practices and techniques. Nuclear I&M has made commitments to meet certain of the nuclear fuel requirements of the Cook Plant. The nuclear fuel cycle consists of the mining and milling of uranium ore to uranium concentrates; the conversion of uranium concentrates to uranium hexafluoride; the enrichment of uranium hexafluoride; the fabrication of fuel assemblies; the utilization of nuclear fuel in the reactor; and the reprocessing or other disposition of spent fuel. Steps currently are being taken, based upon the planned fuel cycles for the Cook Plant, to review and evaluate I&M's requirements for the supply of nuclear fuel. I&M has made and will make purchases of uranium in various forms in the spot, short-term, and mid-term markets until it decides that deliveries under long-term supply contracts are warranted. For purposes of the storage of high-level radioactive waste in the form of spent nuclear fuel, I&M has completed modifications to its spent nuclear fuel storage pool to permit normal operations through 2010. I&M's costs of nuclear fuel consumed do not assume any residual or salvage value for residual plutonium and uranium. Nuclear Waste and Decommissioning The Nuclear Waste Policy Act of 1982, as amended, establishes Federal responsibility for the permanent off-site disposal of spent nuclear fuel and high-level radioactive waste. Disposal costs are paid by fees assessed against owners of nuclear plants and deposited into the Nuclear Waste Fund created by the Act. In 1983, I&M entered into a contract with DOE for the disposal of spent nuclear fuel. Under terms of the contract, for the disposal of nuclear fuel consumed after April 6, 1983 by I&M's Cook Plant, I&M is paying to the fund a fee of one mill per kilowatt-hour, which I&M is currently recovering from customers. For the disposal of nuclear fuel consumed prior to April 7, 1983, I&M must pay the U.S. Treasury a fee estimated at approximately $71,124,000, exclusive of interest of $100,622,000 at December 31, 1996. The aggregate amount has been recorded as long-term debt. Because of the current uncertainties surrounding DOE's program to provide for permanent disposal of spent nuclear fuel, I&M has not yet paid any of the pre-April 1983 fee. At December 31, 1996, funds collected from customers to pay the pre-April 1983 fee and accrued interest approximated the long-term debt liability. In November 1996, the IURC and MPSC issued orders approving flexible funding procedures in which any excess funds collected for pre-April 7, 1983 spent nuclear fuel disposal would be deposited into I&M's nuclear decommissioning trust funds. On May 30, 1995, I&M and a group of unaffiliated utilities owning and operating nuclear plants filed a petition for review in the U.S. Court of Appeals for the District of Columbia Circuit requesting that the court issue a declaration that the Nuclear Waste Policy Act of 1982 (NWPA) imposes on DOE an unconditional obligation to begin acceptance of spent nuclear fuel and high level radioactive waste by January 31, 1998. On July 23, 1996, the court ruled that the NWPA creates an obligation in DOE, reciprocal to the utilities' obligation to pay, to start disposing of the spent nuclear fuel and high level radioactive waste no later than January 31, 1998. The court remanded the case to DOE, holding that determination of a remedy was premature, since DOE had not yet defaulted on its obligations. In December 1996, I&M received a letter from DOE advising that DOE anticipates that it will be unable to begin acceptance of spent nuclear fuel and high level radioactive waste for disposal in a repository or interim storage facility by January 31, 1998. On January 31, 1997, in anticipation of DOE's breach of their statutory and contractual obligations, I&M along with 35 unaffiliated utilities and 33 states filed joint petitions for review in the U.S. Court of Appeals for the District of Columbia Circuit requesting that the court permit the utilities to suspend further payments into the nuclear waste fund, authorize escrow of the payments, and order further action on the part of DOE to meet its obligations under the NWPA. Studies completed in 1994 estimate decommissioning and low-level radioactive waste disposal costs for the Cook Plant to range from $634,000,000 to $988,000,000 in 1993 nondiscounted dollars. The wide range is caused by variables in assumptions, including the estimated length of time spent nuclear fuel must be stored at the Cook Plant subsequent to ceasing operations, which depends on future developments in the federal government's spent nuclear fuel disposal program. Continued delays in the federal fuel disposal program can result in increased decommissioning costs. I&M is recovering decommissioning costs in its three rate-making jurisdictions based on at least the lower end of the range in the most recent respective decommissioning study available at the time of the rate proceeding (the study range utilized in the Indiana rate case, I&M's primary jurisdiction, was $588,000,000 to $1.102 billion in 1991 dollars). I&M records decommissioning costs in other operation expense and records a noncurrent liability equal to the decommissioning cost recovered in rates which was $27,000,000 in 1996, $30,000,000 in 1995 (including $4,000,000 in special deposits) and $26,000,000 in 1994. At December 31, 1996, I&M had recognized a decommissioning liability of $313,845,000. I&M will continue to reevaluate periodically the cost of decommissioning and to seek regulatory approval to revise its rates as necessary. Funds recovered through the rate-making process for disposal of spent nuclear fuel consumed prior to April 7, 1983 and for nuclear decommissioning have been segregated and deposited in external funds for the future payment of such costs. Trust fund earnings decrease the amount to be recovered from ratepayers. The ultimate cost of retiring I&M's Cook Plant may be materially different from the estimates contained in the site-specific study and the funding targets as a result of (a) the type of decommissioning plan selected, (b) the escalation of various cost elements (including, but not limited to, general inflation), (c) the further development of regulatory requirements governing decommissioning, (d) the limited availability to date of significant experience in decommissioning such facilities and (e) the technology available at the time of decommissioning differing significantly from that assumed in these studies. Accordingly, management is unable to provide assurance that the ultimate cost of decommissioning the Cook Plant will not be significantly greater than current projections. In February 1996, the Financial Accounting Standards Board (FASB) issued an exposure draft entitled Accounting for Certain Liabilities Related to Closure or Removal of Long-Lived Assets. I&M generally records such liabilities over the life of its plant commensurate with rate recovery. The exposure draft proposes that the present value of decommissioning and certain other closure or removal obligations be recorded as a liability when the obligation is incurred. A corresponding asset would be recorded in the plant investment account and recovered through depreciation charges over the asset's life. A proposed transition rule would require that an entity report in income the cumulative effect of initially applying the new standard. However, as a cost-based rate-regulated entity, I&M would expect to record a corresponding regulatory asset for the cumulative effect of initially applying the new standard. The FASB is reconsidering several aspects of the exposure draft. It is unclear at this time what, if any, changes the FASB will make to the proposal. Until it becomes apparent what the FASB will decide and how certain questions raised by the exposure draft are resolved, I&M cannot determine its ultimate impact. The Low-Level Waste Policy Act of 1980 (LLWPA) mandates that the responsibility for the disposal of low-level waste rests with the individual states. Low-level radioactive waste consists largely of ordinary refuse and other items that have come in contact with radioactive materials. To facilitate this approach, the LLWPA authorized states to enter into regional compacts for low-level waste disposal subject to Congressional approval. The LLWPA also specified that, beginning in 1986, approved compacts may prohibit the importation of low-level waste from other regions, thereby providing a strong incentive for states to enter into compacts. Michigan, the state where the Cook Plant is located, was a member of the Midwest Compact, but its membership was revoked in 1991. Michigan is responsible for developing a disposal site for the low-level waste generated in Michigan. Although Michigan amended its law regarding low-level waste site development in 1994 to allow a volunteer to host a facility, little progress has been made to date. A bill was introduced in 1996 to further address the issue but no action was taken. The bill is expected to be reintroduced in 1997. Development of required legislation and progress with the site selection process has been inhibited by many factors, and management is unable to predict when a new disposal site for Michigan low-level waste will be available. On July 1, 1995, the disposal site in South Carolina reopened to accept waste from most areas of the U.S., including Michigan. This was the first opportunity for the Cook Plant to dispose of low-level waste since 1990. To the extent practicable, the waste formerly placed in storage and the waste presently generated are now being sent to the disposal site. Currently, the Cook Plant produces less than 1,500 cubic feet of low-level waste annually. Energy Policy Act -- Nuclear Fees The Energy Policy Act of 1992 (Energy Act), contains a provision to fund the decommissioning and decontamination of DOE's existing uranium enrichment facilities from a combination of sources including assessments against electric utilities which purchased enrichment services from DOE facilities. I&M's remaining estimated liability is $42,743,000, subject to inflation adjustments, and is payable in annual assessments over the next 10 years. I&M recorded a regulatory asset concurrent with the recording of the liability. The payments are being recorded and recovered as fuel expense. In a case involving an unaffiliated utility, the U.S. Court of Federal Claims decided in June 1995 that these assessments are unlawful. On November 13, 1995, the Federal Government appealed this decision to the U.S. Court of Appeals for the Federal Circuit. I&M has filed with DOE claims for refunds under certain of its enrichment services contracts based on this decision. I&M also intends to pursue refund claims on other enrichment services contracts directly to the U.S. Court of Federal Claims. ENVIRONMENTAL AND OTHER MATTERS AEP's subsidiaries are subject to regulation by Federal, state and local authorities with regard to air and water-quality control and other environmental matters, and are subject to zoning and other regulation by local authorities. It is expected that costs related to environmental requirements will eventually be reflected in the rates of AEP's electric utility subsidiaries and that, in the long term, AEP's electric utility subsidiaries will be able to provide for required environmental controls. However, some customers may curtail or cease operations as a consequence of higher energy costs. There can be no assurance that all such costs will be recovered. Moreover, legislation currently being proposed at the state and Federal levels governing restructuring of the electric utility industry may also affect the recovery of certain costs. See Competition and Business Change. Except as noted herein, AEP's subsidiaries which own or operate generating, transmission and distribution facilities are in substantial compliance with pollution control laws and regulations. Air Pollution Control Clean Air Act: For the AEP System, compliance with the Clean Air Act (CAA) is requiring substantial expenditures which generally are being recovered through increases in the rates of AEP's operating subsidiaries. OPCo is incurring a major portion of such costs. There can be no assurance that all such costs will be recovered. See Construction Program of Operating Companies - -- Construction Expenditures. The Acid Rain Program (Title IV) provisions of the Clean Air Act Amendments of 1990 (CAAA) create an emission allowance program pursuant to which utilities are authorized to emit a designated quantity of sulfur dioxide, measured in tons per year, on a system wide or aggregate basis. Emission reductions are required by virtue of the establishment of annual allowance allocations at a level below historical emission levels for many utility units. Effective January 1, 1995, Title IV of the CAAA established Phase I sulfur dioxide allowance limitations (caps or ceilings on emissions) for certain units that emitted sulfur dioxide above a rate of 2.5 pounds per million Btu heat input in 1985, premised upon sulfur dioxide emissions at a rate of 2.5 pounds per million Btu heat input at 1985 utilization levels. The following AEP System units are Phase I-affected units: I&M's Tanners Creek Unit 4; CSPCo's Beckjord Unit 6, Conesville Units 1-4, Picway Unit 5 and Stuart Units 1-4; and OPCo's Gavin Units 1-2, Muskingum River Units 1-5, Cardinal Unit 1, Mitchell Units 1-2 and Kammer Units 1-3. Phase I permits have been issued for all Phase I-affected units in the AEP System. All fossil fuel-fired steam generating units with capacity greater than 25 megawatts are affected in Phase II of the Acid Rain program. All Phase II-affected units are allocated allowances with which compliance must be accomplished beginning January 1, 2000. The basis for Phase II allowance allocation depends on 1985 sulfur dioxide emission rates -- if a unit emitted sulfur dioxide in 1985 at a rate in excess of 1.2 pounds per million Btu heat input, the allowance allocation is premised upon an emission rate of 1.2 pounds at 1985 utilization levels. If a unit emitted sulfur dioxide in 1985 at a rate of less than 1.2 pounds, the allowance allocation is in most instances premised upon the actual 1985 emission rate. Title IV also contains provisions governing nitrogen oxides (NOx) emissions. In April 1995, Federal EPA promulgated NOx emission limitations for tangentially fired boilers and dry bottom wall-fired boilers for Phase I and Phase II units. In addition, on December 19, 1996, Federal EPA published final NOx emission limitations in the Federal Register for wet bottom wall-fired boilers, cyclone boilers, units applying cell burner technology and all other types of boilers. These emission limitations are to be achieved by January 1, 2000. A petition for review of the regulations was filed by a number of utilities, including AEP System operating companies, in the U.S. Court of Appeals for the District of Columbia Circuit on December 26, 1996. The CAA contains additional provisions, other than the Acid Rain Program, which could require reductions in emissions of nitrogen oxides from fossil fuel-fired power plants. Title I, dealing generally with attainment of federally set National Ambient Air Quality Standards, establishes a tiered system for classifying degrees of non-attainment with the air quality standard for ozone. Depending upon the severity of non-attainment within a given non-attainment area, reductions in nitrogen oxides emissions from fossil fuel-fired power plants may be required as part of a state's plan for achieving attainment with the ozone air quality standard. While ozone non-attainment is largely restricted to urban areas, AEP System generating units could be determined to be affecting ozone concentrations and may therefore, eventually be required to reduce nitrogen oxides emissions pursuant to Title I. In addition, certain environmental organizations and states have taken the position that nitrogen oxides emissions from the midwest must be reduced in order to achieve the air quality standard for ozone in the northeast as well as the Lake Michigan and Atlanta, Georgia areas. All AEP coal-fired plants are potentially subject to the imposition of additional emission controls resulting from these initiatives. The Environmental Council of States formed the Ozone Transport Assessment Group (OTAG) in early 1995 to develop estimates of levels of reduction in volatile organic compound and/or nitrogen oxides emissions required for significant reductions in ozone concentrations in the eastern United States. OTAG, consisting of the environmental commissioners and air directors of 37 eastern states, Federal EPA and representatives from environmental and industry groups, is currently scheduled to complete modeling and technical work by the spring of 1997 with evaluation of technical findings and recommendations on regional emission controls to be submitted to Federal EPA in the summer of 1997. Federal EPA published a notice of intent in the January 10, 1997 Federal Register proposing the specification of ranges or amounts of nitrogen oxides and volatile organic compounds reductions required by states to reduce downwind concentrations of ozone. Federal EPA will direct states to revise their state implementation plans (SIPs) to provide for specified emission reductions within a set time period. Federal EPA's proposal for reductions of nitrogen oxides and volatile organic compounds is scheduled to be issued in March 1997 and final SIP calls requiring revisions in state plans will be issued in the summer of 1997. The cost of meeting Nox emissions reduction requirements which might be imposed to achieve the ozone ambient air quality standard cannot be precisely predicted but could be substantial. Utility boilers are potentially subject to additional control requirements under Title III of the CAAA governing hazardous air pollutant emissions. Federal EPA is directed to conduct studies concerning the potential public health impacts of pollutants identified by the legislation as hazardous in connection with their emission from electric utility steam generating units. Federal EPA was required to report the results of this study to Congress by November 1993 and is required to regulate emissions of these pollutants from electric utility steam generating units if it is determined that such regulation is necessary and appropriate, based on the results of the study. In October 1996, Federal EPA submitted to Congress an interim report that did not make any determinations regarding additional regulation of electric utilities. Additionally, Federal EPA is directed to study the deposition of hazardous pollutants to the Great Lakes, the Chesapeake Bay, Lake Champlain and other coastal waters. As part of this assessment, Federal EPA is authorized to adopt regulations to prevent serious adverse effects to public health and serious or widespread environmental effects. It is possible that emissions from electric utility steam generating units may be regulated under this water body deposition assessment program. The CAAA expand the enforcement authority of the Federal government by increasing the range of civil and criminal penalties for violations of the Clean Air Act and enhancing administrative civil provisions, adding a citizen suit provision and imposing a national operating permit system, emission fee program and enhanced monitoring, record keeping and reporting requirements for existing and new sources. On February 13, 1997, Federal EPA issued a regulation providing for the use of any credible evidence or information in lieu of, or in addition to, test methods prescribed by regulation to determine the compliance status of permitted sources of air pollution. This rule may effectively make emission limits previously adopted for many air emission sources including those of the AEP System's operating subsidiaries more stringent. On March 10, 1997, a group of utilities, including AEP System operating companies, filed a petition for review of these regulations in the U.S. Court of Appeals for the District of Columbia Circuit. Global Climate Change: Increasing concentrations of "greenhouse gases," including carbon dioxide (CO2), in the atmosphere have led to concerns about the potential for the earth's climate to change in ways that could result in adverse human health effects, destruction of sensitive ecosystems, inundated low-lying areas caused by sea-level rise, shifts in agricultural production and other serious environmental consequences. The proponents of this view maintain that rising levels of greenhouse gas emissions will cause some of the sun's energy that is normally radiated back into space to be trapped in the atmosphere, warming the biosphere and triggering these detrimental effects. At the Earth Summit in Rio de Janeiro, Brazil in June 1992, 165 nations, including the United States, signed a global climate change treaty. Each country that ratifies the treaty commits itself to a process of achieving the aim of reducing greenhouse gas emissions, including CO2, to their 1990 level by the year 2000. On October 7, 1992, the U.S. Senate ratified the treaty. The treaty went into effect on March 21, 1994. In April 1995, the first meeting of the nations that have ratified was held. The parties declared that the existing commitments under the treaty are not adequate to address the threat of global climate change and authorized the immediate commencement of negotiations on a protocol or other legal instrument for emission controls in the post-2000 period. The protocol or other legal instrument is required to set forth "policies and measures," and "quantified limitation and reduction objectives within specified time frames, such as 2005, 2010 and 2020" to be adopted by signatory nations. The parties will meet in December 1997 in Kyoto, Japan to finalize the agreement. On January 17, 1997, the U.S. government submitted text for a proposed treaty that would establish a future system of legally binding emission budgets with trading of emission credits between nations that are parties to the new agreement and which have emission control obligations. Although the U.S. proposal does not specify either the level of emission reductions or timeframe in which they must be achieved, it is expected to result in at least a cap on greenhouse gas emissions at the level emitted in the year 1990. In accordance with the obligations set forth in the global climate change treaty, on April 21, 1993, President Clinton committed the United States to reducing greenhouse gas emissions to 1990 levels by the year 2000. On October 19, 1993, the President unveiled the Administration's Climate Change Action Plan for meeting this emission reduction target. The plan emphasizes reductions in fossil fuel use, the largest source of CO2 emissions, primarily through reliance on voluntary energy efficiency programs and partnerships between the Federal government and U.S. industry. One such collaboration is between the electric utility industry and DOE. Known as the Climate Challenge, this initiative has identified flexible, cost-effective measures to reduce, avoid or sequester future greenhouse gas emissions. AEP System companies joined with nearly 800 investor-owned, municipal, rural electric cooperative and Federal utilities in a voluntary agreement signed with DOE on April 20, 1994 that has led to individual utility Participation Accords resulting in substantial reductions in future greenhouse gas emissions. On February 3, 1995, the AEP System entered into its Climate Challenge Participation Accord with DOE. The Accord contains a diverse portfolio of supply-side, demand-side and forest management/tree planting activities that will be undertaken on the AEP System between now and the year 2000 with a projected reduction in CO2 emissions of 9,550,000 tons from what would have otherwise been emitted but for these actions. As a result of the AEP System's historical practice of using low-cost indigenous coal supplies to produce electricity, AEP System power plants are significant sources of CO2 emissions. Management is working to support further efforts to properly study the issue of global climate change to define the extent, if any, to which it poses a threat to the environment. Management is concerned that new laws may be passed or new regulations promulgated without sufficient scientific study and support. Since the AEP System is a major emitter of carbon dioxide, its financial condition and results of operations could be materially adversely affected by the imposition of limitations on CO2 emissions if the compliance costs incurred are not fully recovered from ratepayers. In addition, any such severe program to stabilize or reduce CO2 emissions could impose substantial costs on industry and society and seriously erode the economic base that AEP's operations serve. West Virginia: West Virginia promulgated sulfur dioxide limitations which Federal EPA approved in February 1978. The emission limitations for the Mitchell Plant have been approved by Federal EPA for primary ambient air quality (health-related) standards only. West Virginia is obliged to reanalyze sulfur dioxide emission limits for the Mitchell Plant with respect to secondary ambient air quality (welfare-related) standards. Because the Clean Air Act provides no specific deadline for approval of emission limits to achieve secondary ambient air quality standards, it is not certain when Federal EPA will take dispositive action regarding the Mitchell Plant. West Virginia has had a request to increase the sulfur dioxide emission limitation for Kammer pending before Federal EPA for many years, although the change has not been acted upon by Federal EPA. On August 4, 1994, however, Federal EPA issued a Notice of Violation to OPCo alleging that Kammer Plant was operating in violation of the applicable federally enforceable sulfur dioxide emission limit. On May 20, 1996, the Notice of Violation and an enforcement action subsequently filed by Federal EPA were resolved through the entry of a consent decree in the U.S. District Court for the Northern District of West Virginia. The decree provides for compliance with an interim emission limit of 6.5 pounds of sulfur dioxide per million Btu actual heat input on a three-hour basis and 5.8 pounds of sulfur dioxide per million Btu on an annual basis. West Virginia and industrial sources in the area of the Kammer Plant are developing a revision to the state implementation plan with respect to sulfur dioxide emission limitations which is to be submitted no later than November 1998. The interim emission limit for Kammer will remain in effect until after that time. Stack Height Regulations: On June 27, 1985, Federal EPA issued stack height regulations pursuant to an order of the United States Court of Appeals for the District of Columbia Circuit. These regulations were appealed by a number of states, environmental groups and investor-owned electric utilities (including APCo, CSPCo, I&M, KEPCo and OPCo), along with three electric utility trade associations. OPCo also filed a separate petition for review to raise issues unique to its Kammer Plant. Various petitions for reconsideration filed with and denied by Federal EPA were also appealed. This litigation was consolidated into a single case. On January 22, 1988, the U.S. Court of Appeals for the District of Columbia Circuit issued a decision in part upholding the June 1985 stack height rules and remanding certain of the June 1985 rules to Federal EPA for further consideration. With respect to Kammer Plant, the January 1988 court decision rejected OPCo's appeal, holding that Federal EPA acted lawfully in revoking stack height credit previously granted for Kammer Plant in October 1982. OPCo has also commenced administrative proceedings with the State of West Virginia and Federal EPA in an effort to preserve stack height credit for Kammer Plant. While it is not possible to state with particularity the ultimate impact of the final rules on AEP System operations, at present it appears that the most likely AEP System plants at which the final rules could possibly result in more stringent emission limitations are CSPCo's Conesville Plant, AEGCo's and I&M's Rockport Plant, I&M's Tanners Creek Plant and OPCo's Gavin and Kammer plants. Gavin and Rockport plants were not affected by Federal EPA's stack height rules as issued in June 1985. However, the provision exempting these plants was remanded to Federal EPA in the January 1988 court decision. Accordingly, the ultimate impact of the stack height rules on Gavin and Rockport plants will not be known until Federal EPA completes administrative proceedings on remand and reissues final stack height rules. OPCo and AEGCo and I&M intend to participate in the remand rulemaking affecting Gavin and Rockport plants, respectively. State air pollution control agencies are required to implement the stack height rules by revising emission limitations for sources subject to the rules and submitting such revisions to Federal EPA. On June 1, 1989, Ohio EPA adopted a rule concerning CSPCo's Conesville Plant in response to Federal EPA's stack height rules adopted in 1985. Under Federal EPA policy published in January 1988, emission reductions required by the stack height rules may be obtained at plants other than the plant directly affected by the rules, and thereafter credited to the directly affected plant. Under Ohio EPA's June 1, 1989 rule, the sulfur dioxide emission limitations for Conesville Units 5 and 6 remain at 1.2 pounds sulfur dioxide per million Btu heat input as long as the emission rate at CSPCo's retired Poston Units 1-4 remains at 0.0 pounds sulfur dioxide per million Btu heat input. Federal EPA has yet to take action concerning Ohio EPA's June 1, 1989 rule. Administrative Developments Regarding Sulfur Dioxide: On November 15, 1994, Federal EPA published a notice in the Federal Register proposing to retain the present 24-hour national ambient air quality standard for sulfur dioxide. Federal EPA also sought comment on the need to adopt additional regulations to address short-term peak exposures to sulfur dioxide. On January 2, 1997, Federal EPA proposed a new intervention level program under the authority of Section 303 of the Clean Air Act to address high five-minute peak SO2 concentrations. The proposal calls for regulatory intervention to reduce emissions from a source or group of sources responsible for five-minute peak SO2 concentrations above prescribed levels. The effect on AEP operations of Federal EPA's proposed intervention level program for further regulating sulfur dioxide emissions, if finalized, cannot be predicted, but may be significant. Life Extension: On July 21, 1992, Federal EPA published final regulations in the Federal Register governing application of new source rules to generating plant repairs and pollution control projects undertaken to comply with the Clean Air Act Amendments of 1990. Generally, the rule provides that plants undertaking pollution control projects will not trigger new source review requirements. The Natural Resources Defense Council and a group of utilities, including five AEP System companies, have filed petitions in the U.S. Court of Appeals for the District of Columbia Circuit seeking a review of the regulations. National Ambient Air Quality Standards: Federal EPA proposed revisions to the National Ambient Air Quality Standard for ozone on December 13, 1996. The proposed standard is significantly more stringent than the current standard and, if adopted, would result in redesignation of many areas currently designated attainment. The proposal, if adopted, could lead to substantial reductions in allowable nitrogen oxide emissions from System power plants. Federal EPA also proposed revision of the National Ambient Air Quality Standard for particulate matter (PM) on December 13, 1996. Federal EPA's proposed revision would add a standard for particulate matter below 2.5 microns in size (PM2.5). Federal EPA is required by court order to make a final determination on this issue by July 19, 1997. The new PM2.5 standard, if finalized, could lead to substantial reductions in allowable emissions of SO2, nitrogen oxides and particulate matter from System power plants. Water Pollution Control The Clean Water Act prohibits the discharge of pollutants to waters of the United States from point sources except pursuant to an NPDES permit issued by Federal EPA or a state under a federally authorized state program. Under the Clean Water Act, effluent limitations requiring application of the best available technology economically achievable are to be applied, and those limitations require that no pollutants be discharged if Federal EPA finds elimination of such discharges is technologically and economically achievable. The Clean Water Act provides citizens with a cause of action to enforce compliance with its pollution control requirements. Since 1982, many such actions against NPDES permit holders have been filed. To date, no AEP System plants have been named in such actions. All System Plants are operating with NPDES permits. Under EPA's regulations, operation under an expired NPDES permit is authorized provided an application is filed at least 180 days prior to expiration. Renewal applications are being prepared or have been filed for renewal of NPDES permits which expire in 1997. The NPDES permits generally require that certain thermal impact study programs be undertaken. These studies have been completed for all System plants. Thermal variances are in effect for all plants with once-through cooling water. The thermal variances for Conesville and Muskingum River plants impose thermal management conditions that could result in load curtailment under certain conditions, but the cost impacts are not expected to be significant. Based on favorable results of in-stream biological studies, the thermal temperature limits for both Conesville and Muskingum River plants were raised in the renewed permits issued in 1996. Consequently, the potential for load curtailment and adverse cost impacts is further reduced. Certain mining operations conducted by System companies as discussed under Fuel Supply are also subject to Federal and state water pollution control requirements, which may entail substantial expenditures for control facilities, not included at present in the System's construction cost estimates set forth herein. The Federal Water Quality Act of 1987 requires states to adopt stringent water quality standards for a large category of toxic pollutants and to identify specialized control measures for dischargers to waters where it is shown through the use of total maximum daily loads (TMDLs) that water quality standards are not being met. Implementation of these provisions could result in significant costs to the AEP System if biological monitoring requirements and water quality-based effluent limits are placed in NPDES permits. In March 1995, Federal EPA finalized a set of rules which establish minimum water quality standards, antidegradation policies and implementation procedures for more stringently controlling releases of toxic pollutants into the Great Lakes system. This regulatory package is called the Great Lakes Water Quality Initiative (GLWQI). The most direct compliance cost impact could be related to I&M's Cook Plant. Management cannot presently determine whether the GLWQI would have a significant adverse impact on AEP operations. The significance of such impact will depend on the outcome of Federal EPA's policy on intake credits and site specific variables as well as Michigan's implementation strategy. Federal EPA's rule is presently under review by the District of Columbia Circuit Court of Appeals in litigation initiated by several industry groups. If Indiana and Ohio eventually adopt the GLWQI criteria for statewide application, AEP System plants located in those states could also be affected. Hazardous Substances and Wastes Section 311 of the Clean Water Act imposes substantial penalties for spills of Federal EPA-listed hazardous substances into water and for failure to report such spills. The Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) expanded the reporting requirements to cover the release of hazardous substances generally into the environment, including water, land and air. AEP's subsidiaries store and use some of these hazardous substances, including PCB's contained in certain capacitors and transformers, but the occurrence and ramifications of a spill or release of such substances cannot be predicted. CERCLA and similar state law provide governmental agencies with the authority to require clean-up of hazardous waste sites and releases of hazardous substances into the environment and to seek compensation for damages to natural resources. Since liability under CERCLA is strict and can be applied retroactively, AEP System companies which previously disposed of PCB-containing electrical equipment and other hazardous substances may be required to participate in remedial activities at such disposal sites should environmental problems result. AEP System companies are presently defendants in five cases involving cost-recovery lawsuits at Federal EPA-identified CERCLA sites. OPCo is involved at three of these sites and I&M at the two other sites. Seven AEP System companies are identified as Potentially Responsible Parties (PRPs) for six additional federal sites, including CSPCo, KEPCo and Wheeling Power Company at one site each, I&M at two sites, and OPCo at two sites. I&M has been named as a PRP at one state remediation site. Management's present estimates do not anticipate material cleanup costs for identified sites for which AEP subsidiaries have been declared PRPs or are defendants in CERCLA cost recovery litigation. However, if for reasons not currently identified significant costs are incurred for cleanup, future results of operations and possibly financial condition would be adversely affected unless the costs can be recovered through rates. Regulations issued by Federal EPA under the Toxic Substances Control Act govern the use, distribution and disposal of PCBs, including PCBs in electrical equipment. Deadlines for removing certain PCB-containing electrical equipment from service have been met. In addition to handling hazardous substances, the System companies generate solid waste associated with the combustion of coal, the vast majority of which is fly ash, bottom ash and flue gas desulfurization wastes. These wastes presently are considered to be non-hazardous under RCRA and applicable state law and the wastes are treated and disposed in surface impoundments or landfills in accordance with state permits or authorization or beneficially utilized. As required by RCRA, EPA evaluated whether high volume coal combustion wastes (such as fly ash, bottom ash and flue gas desulfurization wastes) should be regulated as hazardous waste. In August, 1993 EPA issued a regulatory determination that such high volume coal combustion wastes should not be regulated as hazardous waste. For low volume coal combustion wastes, such as metal and boiler cleaning wastes, Federal EPA will gather additional information and make a regulatory determination by April 1998. Until that time, these low volume wastes are provisionally excluded from regulation under the hazardous waste provisions of RCRA. All presently generated hazardous waste is being disposed of at permitted off-site facilities in compliance with applicable Federal and state laws and regulations. For System facilities which generate such wastes, System companies have filed the requisite notices and are complying with RCRA and applicable state regulations for generators. Nuclear waste produced at the Cook Plant regulated under the Atomic Energy Act is excluded from regulation under RCRA. Federal EPA's technical requirements for underground storage tanks containing petroleum will require retrofitting or replacement of an appreciable number of tanks. Compliance costs for tank replacement and site remediation have not been significant to date. Electric and Magnetic Fields (EMF) EMF is found everywhere there is electricity. Electric fields are created by the presence of electric charges. Magnetic fields are produced by the flow of those charges. This means that EMF is created by electricity flowing in transmission and distribution lines, or being used in household wiring and appliances. A number of studies in the past several years have examined the possibility of adverse health effects from EMF. While some of the epidemiological studies have indicated some association between exposure to EMF and health effects, the majority of studies have indicated no such association. On October 31, 1996, the National Academy of Sciences (NAS) released a report, based on a review of over 500 studies spanning 17 years of research, which contained the following summary statement: "... the conclusion of the committee is that the current body of evidence does not show that exposure to these fields presents a human health hazard..." The epidemiological studies that have received the most public attention, including the NAS report, reflect a weak correlation between surrogate or indirect estimates of EMF exposure and certain cancers. Studies using direct measurements of EMF exposure show no such association. Federal EPA is currently studying whether exposure to EMF is associated with cancer in humans. In 1990, Federal EPA issued a draft report on EMF, received interagency review and public comment, and is in the process of preparing its final report. A December 1992 brochure from Federal EPA, Questions And Answers About Electric And Magnetic Fields (EMFs), states at page 3, "The bottom line is that there is no established cause and effect relationship between EMF exposure and cancer or other disease." The Energy Policy Act of 1992 established a coordinated Federal EMF research program. The program funding is $65,000,000 over five years, half of which is to be provided by private parties including utilities. AEP has committed to contribute $446,571 over the five-year period. AEP has also supported an extensive EMF research program coordinated by the Electric Power Research Institute, working closely with its staff and contributing more than $500,000 to this effort in 1996. See Research and Development. AEP's participation in the programs is a continuation of its efforts to monitor and support further research and to communicate with its customers and employees about this issue. Its operating company subsidiaries provide their residential customers with information and field measurements on request, although there is no scientific basis for interpreting such measurements. A number of lawsuits based on EMF-related grounds have been filed in recent years against electric utilities. A suit was filed on May 23, 1990 against I&M involving claims that EMF from a 345 KV transmission line caused adverse health effects. No specific amount has been requested for damages in this case. The trial date has been set at August 18, 1997. Some states have enacted regulations to limit the strength of magnetic fields at the edge of transmission line rights-of-way. No state which the AEP System serves has done so. In March 1993, The Ohio Power Siting Board issued its amended rules providing for additional consideration of the possible effects of EMF in the certification of electric transmission facilities. Under the amended EMF rules, persons seeking approval to build electric transmission lines have to provide estimates of EMF from transmission lines under a variety of conditions. In addition, applicants are required to address possible health effects and discuss the consideration of design alternatives with respect to EMF. Management cannot predict the ultimate impact of the question of EMF exposure and adverse health effects. If further research shows that EMF exposure contributes to increased risk of cancer or other health problems, or if the courts conclude that EMF exposure harms individuals and that utilities are liable for damages, or if states limit the strength of magnetic fields to such a level that the current electricity delivery system must be significantly changed, then the results of operations and financial condition of AEP and its operating subsidiaries could be materially adversely affected unless these costs can be recovered from ratepayers. RESEARCH AND DEVELOPMENT AEP and its subsidiaries are involved in a number of research projects which are directed toward developing more efficient methods of burning coal, reducing the contaminants resulting from combustion of coal, and improving the efficiency and reliability of power transmission, distribution and utilization, including load management. AEP System operating companies are members of the Electric Power Research Institute (EPRI), a nonprofit organization that manages research and development on behalf of the U.S. electric utility industry. EPRI, founded in 1973, manages technical research and development programs for its members to improve power production, delivery and use. Approximately 700 utilities are members. Total AEP dues to EPRI were $9,900,000 for 1996, $9,600,000 for 1995 and $3,200,000 for 1994. Total research and development expenditures by AEP and its subsidiaries, including EPRI dues, were approximately $16,400,000 for the year ended December 31, 1996, $13,600,000 for the year ended December 31, 1995 and $7,600,000 for the year ended December 31, 1994. This includes expenditures of $3,300,000 for 1996, $1,100,000 for 1995 and $2,200,000 for 1994 related to pressurized fluidized-bed combustion, a process in which sulfur is removed during coal combustion and nitrogen oxide formation is minimized. Item 2. PROPERTIES - ------------------------------------------------------------------------------ At December 31, 1996, subsidiaries of AEP owned (or leased where indicated) generating plants with the net power capabilities (winter rating) shown in the following table:
Net Kilowatt Owner, Plant Type and Name Location (Near) Capability -------------------------- --------------- ------------ AEP Generating Company: Steam -- Coal-Fired: Rockport Plant (AEGCo share) Rockport, Indiana 1,300,000(a) Appalachian Power Company: Steam -- Coal-Fired: John E. Amos, Units 1 & 2 St. Albans, West Virginia 1,600,000 John E. Amos, Unit 3 (APCo share) St. Albans, West Virginia 433,000(b) Clinch River Carbo, Virginia 705,000 Glen Lyn Glen Lyn, Virginia 335,000 Kanawha River Glasgow, West Virginia 400,000 Mountaineer New Haven, West Virginia 1,300,000 Philip Sporn, Units 1 & 3 New Haven, West Virginia 308,000 Hydroelectric -- Conventional: Buck Ivanhoe, Virginia 10,000 Byllesby Byllesby, Virginia 20,000 Claytor Radford, Virginia 76,000 Leesville Leesville, Virginia 40,000 London Montgomery, West Virginia 16,000 Marmet Marmet, West Virginia 16,000 Niagara Roanoke, Virginia 3,000 Reusens Lynchburg, Virginia 12,000 Winfield Winfield, West Virginia 19,000 Hydroelectric -- Pumped Storage: Smith Mountain Penhook, Virginia 565,000 --------- 5,858,000 --------- Columbus Southern Power Company: Steam -- Coal-Fired: Beckjord, Unit 6 New Richmond, Ohio 53,000(c) Conesville, Units 1-3, 5 & 6 Coshocton, Ohio 1,165,000 Conesville, Unit 4 Coshocton, Ohio 339,000(c) Picway, Unit 5 Columbus, Ohio 100,000 Stuart, Units 1-4 Aberdeen, Ohio 608,000(c) Zimmer Moscow, Ohio 330,000(c) --------- 2,595,000 --------- Indiana Michigan Power Company: Steam -- Coal-Fired: Rockport Plant (I&M share) Rockport, Indiana 1,300,000(a) Tanners Creek Lawrenceburg, Indiana 995,000 Steam -- Nuclear: Donald C. Cook Bridgman, Michigan 2,110,000 Gas Turbine: Fourth Street Fort Wayne, Indiana 18,000(d) Hydroelectric -- Conventional: Berrien Springs Berrien Springs, Michigan 3,000 Buchanan Buchanan, Michigan 2,000 Constantine Constantine, Michigan 1,000 Elkhart Elkhart, Indiana 1,000 Mottville Mottville, Michigan 1,000 Twin Branch Mishawaka, Indiana 3,000 --------- 4,434,000 --------- Kentucky Power Company: Steam -- Coal-Fired: Big Sandy Louisa, Kentucky 1,060,000 --------- Ohio Power Company: Steam -- Coal-Fired: John E. Amos, Unit 3 (OPCo share) St. Albans, West Virginia 867,000(b) Cardinal, Unit 1 Brilliant, Ohio 600,000 General James M. Gavin Cheshire, Ohio 2,600,000(e) Kammer Captina, West Virginia 630,000 Mitchell Captina, West Virginia 1,600,000 Muskingum River Beverly, Ohio 1,425,000 Philip Sporn, Units 2, 4 & 5 New Haven, West Virginia 742,000 Hydroelectric -- Conventional: Racine Racine, Ohio 48,000 ---------- 8,512,000 ---------- Total Generating Capability . . . . . . . 23,759,000 ========== Summary: Total Steam -- Coal-Fired . . . . . . . . . . . . . . . . . . . . . . . . . 20,795,000 Nuclear . . . . . . . . . . . . . . . . . . . . . . . . . . 2,110,000 Total Hydroelectric -- Conventional . . . . . . . . . . . . . . . . . . . . . . . . 271,000 Pumped Storage . . . . . . . . . . . . . . . . . . . . . . . 565,000 Other . . . . . . . . . . . . . . . . . . . . . . . . . . . 18,000 ---------- Total Generating Capability . . . . . . . 23,759,000 - ----------------- ==========
(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 CG&E and DP&L. (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. See Item 1 under Fuel Supply, for information concerning coal reserves owned or controlled by subsidiaries of AEP. The following table sets forth the total circuit miles of transmission and distribution lines of the AEP System, APCo, CSPCo, I&M, KEPCo and OPCo and that portion of the total representing 765,000-volt lines: Total Circuit Miles of Transmission and Circuit Miles of Distribution Lines 765,000-volt Lines ------------------- ------------------ AEP System (a) . . . . . . 127,376(b) 2,022 APCo . . . . . . . . . . . 49,282 641 CSPCo (a). . . . . . . . . 15,000 --- I&M. . . . . . . . . . . . 20,795 614 KEPCo. . . . . . . . . . . 10,025 258 OPCo . . . . . . . . . . . 28,826 509 - ------------------ (a) Includes 766 miles of 345,000-volt jointly owned lines. (b) Includes lines of other AEP System companies not shown. TITLES The AEP System's electric generating stations are generally located on lands owned in fee simple. The greater portion of the transmission and distribution lines of the System has been constructed over lands of private owners pursuant to easements or along public highways and streets pursuant to appropriate statutory authority. The rights of the System in the realty on which its facilities are located are considered by it to be adequate for its use in the conduct of its business. Minor defects and irregularities customarily found in title to properties of like size and character may exist, but such defects and irregularities do not materially impair the use of the properties affected thereby. System companies generally have the right of eminent domain whereby they may, if necessary, acquire, perfect or secure titles to or easements on privately-held lands used or to be used in their utility operations. Substantially all the physical properties of APCo, CSPCo, I&M, KEPCo and OPCo are subject to the lien of the mortgage and deed of trust securing the first mortgage bonds of each such company. SYSTEM TRANSMISSION LINES AND FACILITY SITING Legislation in the states of Indiana, Kentucky, Michigan, Ohio, Virginia, and West Virginia requires prior approval of sites of generating facilities and/or routes of high-voltage transmission lines. Delays and additional costs in constructing facilities have been experienced as a result of proceedings conducted pursuant to such statutes, as well as in proceedings in which operating companies have sought to acquire rights-of-way through condemnation, and such proceedings may result in additional delays and costs in future years. PEAK DEMAND The AEP System is interconnected through 120 high-voltage transmission interconnections with 29 neighboring electric utility systems. The all-time and 1996 one-hour peak System demands were 25,940,000 and 24,373,000 kilowatts, respectively (which included 7,314,000 and 4,136,000 kilowatts, respectively, of scheduled deliveries to unaffiliated systems which the System might, on appropriate notice, have elected not to schedule for delivery) and occurred on June 17, 1994 and February 5, 1996, respectively. The net dependable capacity to serve the System load on such date, including power available under contractual obligations, was 23,457,000 and 23,765,000 kilowatts, respectively. The all-time and 1996 one-hour internal peak demand was 19,557,000, and occurred on February 5, 1996. The net dependable capacity to serve the System load on such date, including power dedicated under contractual arrangements, was 23,765,000 kilowatts. The all-time one-hour integrated and internal net system peak demands and 1996 peak demands for AEP's generating subsidiaries are shown in the following tabulation: All-time one-hour integrated 1996 one-hour integrated net system peak demand net system peak demand ---------------------------- -------------------------- (in thousands) Number of Number of Kilowatts Date Kilowatts Date --------- ---------------- --------- ---------------- APCo 8,303 January 17, 1997 8,214 February 5, 1996 CSPCo 4,172 June 17, 1994 4,045 July 19, 1996 I&M 5,027 June 17, 1994 4,899 July 19, 1996 KEPCo 1,711 January 17, 1997 1,686 February 5, 1996 OPCo 7,291 June 17, 1994 6,766 May 17, 1996 All-time one-hour integrated 1996 one-hour integrated net internal peak demand net internal peak demand ---------------------------- -------------------------- (in thousands) Number of Number of Kilowatts Date Kilowatts Date --------- ---------------- --------- ---------------- APCo 6,908 February 5, 1996 6,908 February 5, 1996 CSPCo 3,378 August 14, 1995 3,335 August 7, 1996 I&M 3,879 August 7, 1996 3,879 August 7, 1996 KEPCo 1,418 February 5, 1996 1,418 February 5, 1996 OPCo 5,641 August 14, 1995 5,547 August 7, 1996 HYDROELECTRIC PLANTS Licenses for hydroelectric plants, issued under the Federal Power Act, reserve to the United States the right to take over the project at the expiration of the license term, to issue a new license to another entity, or to relicense the project to the existing licensee. In the event that a project is taken over by the United States or licensed to a new licensee, the Federal Power Act provides for payment to the existing licensee of its "net investment" plus severance damages. Licenses for six System hydroelectric plants expired in 1993. Four new licenses were issued in 1994 and two were issued in 1996. The license for the hydroelectric plant at Elkhart, Indiana expires in 2000. In 1995, a notice of intent to relicense the Elkhart project was filed. COOK NUCLEAR PLANT Unit 1 of the Cook Plant, which was placed in commercial operation in 1975, has a nominal net electric rating of 1,020,000 kilowatts. Unit 1's availability factor was 97.6% during 1996 and 66.3% during 1995. Unit 2, of slightly different design, has a nominal net electrical rating of 1,090,000 kilowatts and was placed in commercial operation in 1978. Unit 2's availability factor was 87.0% during 1996 and 94.4% during 1995. Outages to refuel affected the availability of Unit 1 in 1995 and Unit 2 in 1996. Units 1 and 2 are licensed by the NRC to operate at 100% of rated thermal power to October 25, 2014 and December 23, 2017, respectively. Costs associated with the operation, maintenance and retirement of nuclear plants continue to be significant and less predictable than costs associated with other sources of generation, in large part due to changing regulatory requirements and safety standards and experience gained in the construction and operation of nuclear facilities. I&M may also incur costs and experience reduced output at its Cook Plant because of the design criteria prevailing at the time of construction and the age of the plant's systems and equipment. In addition, for economic or other reasons, operation of the Cook Plant for the full term of its now assumed life cannot be assured. Nuclear industry-wide and Cook Plant initiatives have contributed to slowing the growth of operating and maintenance costs. However, the ability of I&M to obtain adequate and timely recovery of costs associated with the Cook Plant, including replacement power and retirement costs, is not assured. Nuclear Incident Liability The Price-Anderson Act limits public liability for a nuclear incident at any licensed reactor in the United States to $8.9 billion. I&M has insurance coverage for liability from a nuclear incident at its Cook Plant. Such coverage is provided through a combination of private liability insurance, with the maximum amount available of $200,000,000, and mandatory participation for the remainder of the $8.9 billion liability, in an industry retrospective deferred premium plan which would, in case of a nuclear incident, assess all licensees of nuclear plants in the U.S. Under the deferred premium plan, I&M could be assessed up to $158,600,000 payable in annual installments of $20,000,000 in the event of a nuclear incident at Cook or any other nuclear plant in the U.S. There is no limit on the number of incidents for which I&M could be assessed these sums. I&M also has property damage, decontamination and decommissioning insurance for loss resulting from damage to the Cook Plant facilities in the amount of $3.6 billion. Energy Insurance Bermuda (EIB), Nuclear Mutual Limited (NML) and Nuclear Electric Insurance Limited (NEIL) provide $2.75 billion of coverage and nuclear insurance pools provide the remainder. If EIB's, NML's and NEIL's losses exceed their available resources, I&M would be subject to a total retrospective premium assessment of up to $26,900,000. NRC regulations require that, in the event of an accident, whenever the estimated costs of reactor stabilization and site decontamination exceed $100,000,000, the insurance proceeds must be used, first, to return the reactor to, and maintain it in, a safe and stable condition and, second, to decontaminate the reactor and reactor station site in accordance with a plan approved by the NRC. The insurers then would indemnify I&M for property damage up to $3.35 billion less any amounts used for stabilization and decontamination. The remaining $250,000,000, as provided by NEIL (reduced by any stabilization and decontamination expenditures over $3.35 billion), would cover decommissioning costs in excess of funds already collected for decommissioning. See Fuel Supply -- Nuclear Waste. NEIL's extra-expense program provides insurance to cover extra costs resulting from a prolonged accidental outage of a nuclear unit. I&M's policy insures against such increased costs up to approximately $3,500,000 per week (starting 21 weeks after the outage) for one year, $2,800,000 per week for the second and third years, or 80% of those amounts per unit if both units are down for the same reason. If NEIL's losses exceed its available resources, I&M would be subject to a total retrospective premium assessment of up to $8,925,000. POTENTIAL UNINSURED LOSSES Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including liabilities relating to damage to the Cook Plant and costs of replacement power in the event of a nuclear incident at the Cook Plant. Future losses or liabilities which are not completely insured, unless allowed to be recovered through rates, could have a material adverse effect on results of operations and the financial condition of AEP, I&M and other AEP System companies. Item 3. LEGAL PROCEEDINGS - ------------------------------------------------------------------------------ On April 4, 1991, then Secretary of Labor Lynn Martin announced that the U.S. Department of Labor (DOL) had issued a total of 4,710 citations to operators of 847 coal mines who allegedly submitted respirable dust sampling cassettes that had been altered so as to remove a portion of the dust. The cassettes were submitted in compliance with DOL regulations which require systematic sampling of airborne dust in coal mines and submission of the entire cassettes (which include filters for collecting dust particulates) to the Mine Safety and Health Administration (MSHA) for analysis. The amount of dust contained on the cassette's filter determines an operator's compliance with respirable dust standards under the law. OPCo's Meigs No. 2, Meigs No. 31, Martinka, and Windsor Coal mines received 16, 3, 15 and 2 citations, respectively. MSHA has assessed civil penalties totalling $56,900 for all these citations. OPCo's samples in question involve about 1 percent of the 2,500 air samples that OPCo submitted over a 20-month period from 1989 through 1991 to the DOL. OPCo is contesting the citations before the Federal Mine Safety and Health Review Commission. An administrative hearing was held before an administrative law judge with respect to all affected coal operators. On July 20, 1993, the administrative law judge rendered a decision in this case holding that the Secretary of Labor failed to establish that the presence of a "white center" on the dust sampling filter indicated intentional alteration. In the case of an unaffiliated mine, the administrative law judge ruled on April 20, 1994, that there was not an intentional alteration of the dust sampling filter. The Secretary of Labor appealed to the Federal Mine Safety and Health Review Commission the July 20, 1993 and April 20, 1994 administrative law judge decisions and in November 1995 the Commission affirmed these decisions. The Secretary of Labor has appealed the Commission's decision to the U.S. Court of Appeals for the District of Columbia Circuit. All remaining cases, including the citations involving OPCo's mines, have been stayed. On February 28, 1994, Ormet Corporation filed a complaint in the U.S. District Court, Northern District of West Virginia, against AEP, OPCo, the Service Corporation and two of its employees, Federal EPA and the Administrator of Federal EPA. Ormet is the operator of a major aluminum reduction plant in Ohio and is a customer of OPCo. See Certain Industrial Customers. Pursuant to the Clean Air Act Amendments of 1990, OPCo received SO2 Allowances for its Kammer Plant. See Environmental and Other Matters. Ormet's complaint sought a declaration that it is the owner of approximately 89% of the Phase I and Phase II SO2 allowances issued for use by the Kammer Plant. On March 31, 1995, the District Court issued an opinion and order dismissing Ormet's claims based on a lack of jurisdiction. On April 11, 1995, Ormet appealed the District Court's decision to the U.S. Court of Appeals for the Fourth Circuit with respect to the Service Corporation and OPCo only. On October 23, 1996, the Court of Appeals issued an opinion reversing the District Court. On January 10, 1997, OPCo and the Service Corporation filed their answer and counterclaims in the District Court. See Item 1 for a discussion of certain environmental and rate matters. Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS - ------------------------------------------------------------------------------ AEP, APCo, I&M and OPCo. None. AEGCo, CSPCo and KEPCo. Omitted pursuant to Instruction I(2)(c). ------------ EXECUTIVE OFFICERS OF THE REGISTRANTS AEP The following persons are, or may be deemed, executive officers of AEP. Their ages are given as of March 15, 1997.
Name Age Office (a) - ---- --- ---------- E. Linn Draper, Jr. .55 Chairman of the Board, President and Chief Executive Officer of AEP and of the Service Corporation Peter J. DeMaria . .62 Controller of AEP; Executive Vice President-Administration and Chief Accounting Officer of the Service Corporation William J. Lhota . .57 Executive Vice President of the Service Corporation Gerald P. Maloney . .64 Vice President and Secretary of AEP; Executive Vice President-Chief Financial Officer of the Service Corporation James J. Markowsky .52 Executive Vice President-Power Generation of the Service Corporation
- -------------------- (a) All of the executive officers listed above have been employed by the Service Corporation or System companies in various capacities (AEP, as such, has no employees) during the past five years, except E. Linn Draper, Jr. who was Chairman of the Board, President and Chief Executive Officer of Gulf States Utilities Company from 1987 until 1992 when he joined AEP and the Service Corporation. All of the above officers are appointed annually for a one-year term by the board of directors of AEP, the board of directors of the Service Corporation, or both, as the case may be. APCo The names of the executive officers of APCo, the positions they hold with APCo, their ages as of March 15, 1997, and a brief account of their business experience during the past five years appears below. The directors and executive officers of APCo are elected annually to serve a one-year term.
Name Age Position (a) Period - ---- --- ------------ ------ E. Linn Draper, Jr. .55 Director 1992-Present Chairman of the Board and Chief Executive Officer 1993-Present Vice President 1992-1993 Chairman of the Board, President and Chief Executive Officer of AEP and the Service Corporation 1993-Present President of AEP 1992-1993 President and Chief Operating Officer of the Service Corporation 1992-1993 Chairman of the Board, President and Chief Executive Officer of Gulf States Utilities Company 1987-1992 Peter J. DeMaria . .62 Director 1988-Present Vice President 1991-Present Controller 1995-Present Treasurer 1978-1995 Controller of AEP 1995-Present Treasurer of AEP 1978-1995 Executive Vice President-Administration and Chief Accounting Officer of the Service Corporation 1984-Present William J. Lhota . .57 Director 1990-Present President and Chief Operating Officer 1996-Present Vice President 1989-1995 Executive Vice President of the Service Corporation 1993-Present Executive Vice President-Operations of the Service Corporation 1989-1993 Gerald P. Maloney . .64 Director and Vice President 1970-Present Vice President of AEP 1974-Present Secretary of AEP 1994-Present Executive Vice President-Chief Financial Officer of the Service Corporation 1991-Present James J. Markowsky. .52 Director 1993-Present Vice President 1995-Present Executive Vice President-Power Generation of the Service Corporation 1996-Present Executive Vice President-Engineering and Construction of the Service Corporation 1993-1996 Senior Vice President and Chief Engineer of the Service Corporation 1988-1993
- -------------------- (a) Positions are with APCo unless otherwise indicated. OPCo The names of the executive officers of OPCo, the positions they hold with OPCo, their ages as of March 15, 1997, and a brief account of their business experience during the past five years appear below. The directors and executive officers of OPCo are elected annually to serve a one-year term.
Name Age Position (a) Period - ---- --- ------------ ------ E. Linn Draper, Jr. .55 Director 1992-Present Chairman of the Board and Chief Executive Officer 1993-Present Vice President 1992-1993 Chairman of the Board, President and Chief Executive Officer of AEP and the Service Corporation 1993-Present President of AEP 1992-1993 President and Chief Operating Officer of the Service Corporation 1992-1993 Chairman of the Board, President and Chief Executive Officer of Gulf States Utilities Company 1987-1992 Peter J. DeMaria. . .62 Director 1978-Present Vice President 1991-Present Controller 1995-Present Treasurer 1978-1995 Controller of AEP 1995-Present Treasurer of AEP 1978-1995 Executive Vice President-Administration and Chief Accounting Officer of the Service Corporation 1984-Present William J. Lhota. . .57 Director 1989-Present President and Chief Operating Officer 1996-Present Vice President 1989-1995 Executive Vice President of the Service Corporation 1993-Present Executive Vice President-Operations of the Service Corporation 1989-1993 Gerald P. Maloney . .64 Director 1973-Present Vice President 1970-Present Vice President of AEP 1974-Present Secretary of AEP 1994-Present Executive Vice President-Chief Financial Officer of the Service Corporation 1991-Present James J. Markowsky. .52 Director 1989-Present Vice President 1995-Present Executive Vice President-Power Generation of the Service Corporation 1996-Present Executive Vice President-Engineering and Construction of the Service Corporation 1993-1996 Senior Vice President and Chief Engineer of the Service Corporation 1988-1993
- -------------------- (a) Positions are with OPCo unless otherwise indicated. PART II - ------------------------------------------------------------------------ Item 5. MARKET FOR REGISTRANTS' COMMON EQUITY AND RELATED STOCKHOLDER MATTERS - ------------------------------------------------------------------------------- AEP. AEP Common Stock is traded principally on the New York Stock Exchange. The following table sets forth for the calendar periods indicated the high and low sales prices for the Common Stock as reported on the New York Stock Exchange Composite Tape and the amount of cash dividends paid per share of Common Stock. Per Share ------------------ Market Price ------------------ Quarter Ended High Low Dividend(1) - ------------- ------- ------- ----------- March 1995 . . . . . . . $35-3/4 $31-1/4 $.60 June 1995. . . . . . . . 35-3/8 31-1/2 .60 September 1995 . . . . . 36-1/2 33-5/8 .60 December 1995. . . . . . 40-5/8 35-7/8 .60 March 1996 . . . . . . . 44-3/4 40-1/8 .60 June 1996. . . . . . . . 42-3/4 38-5/8 .60 September 1996 . . . . . 43-1/8 40 .60 December 1996. . . . . . 42-1/2 39-1/2 .60 - -------------------- (1) See Note 5 of the Notes to the Consolidated Financial Statements of AEP for information regarding restrictions on payment of dividends. At December 31, 1996, AEP had approximately 158,477 shareholders of record. AEGCo, APCo, CSPCo, I&M, KEPCo and OPCo. The information required by this item is not applicable as the common stock of all these companies is held solely by AEP. Item 6. SELECTED FINANCIAL DATA - ------------------------------------------------------------------------------- AEGCo. Omitted pursuant to Instruction I(2)(a). AEP. The information required by this item is incorporated herein by reference to the material under Selected Consolidated Financial Data in the AEP 1996 Annual Report (for the fiscal year ended December 31, 1996). APCo. The information required by this item is incorporated herein by reference to the material under Selected Consolidated Financial Data in the APCo 1996 Annual Report (for the fiscal year ended December 31, 1996). CSPCo. Omitted pursuant to Instruction I(2)(a). I&M. The information required by this item is incorporated herein by reference to the material under Selected Consolidated Financial Data in the I&M 1996 Annual Report (for the fiscal year ended December 31, 1996). KEPCo. Omitted pursuant to Instruction I(2)(a). OPCo. The information required by this item is incorporated herein by reference to the material under Selected Consolidated Financial Data in the OPCo 1996 Annual Report (for the fiscal year ended December 31, 1996). Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION - ------------------------------------------------------------------------------- AEGCo. Omitted pursuant to Instruction I(2)(a). Management's narrative analysis of the results of operations and other information required by Instruction I(2)(a) is incorporated herein by reference to the material under Management's Narrative Analysis of Results of Operations in the AEGCo 1996 Annual Report (for the fiscal year ended December 31, 1996). AEP. The information required by this item is incorporated herein by reference to the material under Management's Discussion and Analysis of Results of Operations and Financial Condition in the AEP 1996 Annual Report (for the fiscal year ended December 31, 1996). APCo. The information required by this item is incorporated herein by reference to the material under Management's Discussion and Analysis of Results of Operations and Financial Condition in the APCo 1996 Annual Report (for the fiscal year ended December 31, 1996). CSPCo. Omitted pursuant to Instruction I(2)(a). Management's narrative analysis of the results of operations and other information required by Instruction I(2)(a) is incorporated herein by reference to the material under Management's Narrative Analysis of Results of Operations in the CSPCo 1996 Annual Report (for the fiscal year ended December 31, 1996). I&M. The information required by this item is incorporated herein by reference to the material under Management's Discussion and Analysis of Results of Operations and Financial Condition in the I&M 1996 Annual Report (for the fiscal year ended December 31, 1996). KEPCo. Omitted pursuant to Instruction I(2)(a). Management's narrative analysis of the results of operations and other information required by Instruction I(2)(a) is incorporated herein by reference to the material under Management's Narrative Analysis of Results of Operations in the KEPCo 1996 Annual Report (for the fiscal year ended December 31, 1996). OPCo. The information required by this item is incorporated herein by reference to the material under Management's Discussion and Analysis of Results of Operations and Financial Condition in the OPCo 1996 Annual Report (for the fiscal year ended December 31, 1996). Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA - ------------------------------------------------------------------------------- AEGCo. The information required by this item is incorporated herein by reference to the financial statements and supplementary data described under Item 14 herein. AEP. The information required by this item is incorporated herein by reference to the financial statements and supplementary data described under Item 14 herein. APCo. The information required by this item is incorporated herein by reference to the financial statements and supplementary data described under Item 14 herein. CSPCo. The information required by this item is incorporated herein by reference to the financial statements and supplementary data described under Item 14 herein. I&M. The information required by this item is incorporated herein by reference to the financial statements and supplementary data described under Item 14 herein. KEPCo. The information required by this item is incorporated herein by reference to the financial statements and supplementary data described under Item 14 herein. OPCo. The information required by this item is incorporated herein by reference to the financial statements and supplementary data described under Item 14 herein. Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE - ------------------------------------------------------------------------------- AEGCo, AEP, APCo, CSPCo, I&M, KEPCo and OPCo. None. PART III -------------------------------------------------------------------- Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS - ------------------------------------------------------------------------------- AEGCo. Omitted pursuant to Instruction I(2)(c). AEP. The information required by this item is incorporated herein by reference to the material under Nominees for Director and Section 16(a) Beneficial Ownership Reporting Compliance of the definitive proxy statement of AEP, dated March 10, 1997, for the 1997 annual meeting of shareholders. Reference also is made to the information under the caption Executive Officers of the Registrants in Part I of this report. APCo. The information required by this item is incorporated herein by reference to the material under Election of Directors of the definitive information statement of APCo for the 1997 annual meeting of stockholders, to be filed within 120 days after December 31, 1996. Reference also is made to the information under the caption Executive Officers of the Registrants in Part I of this report. CSPCo. Omitted pursuant to Instruction I(2)(c). I&M. The names of the directors and executive officers of I&M, the positions they hold with I&M, their ages as of March 15, 1997, and a brief account of their business experience during the past five years appear below. The directors and executive officers of I&M are elected annually to serve a one-year term.
Name Age Position (a)(b)(c) Period - ---- --- ------------------ ------ E. Linn Draper, Jr. .55 Director 1992-Present Chairman of the Board and Chief Executive Officer 1993-Present Vice President 1992-1993 Chairman of the Board, President and Chief Executive Officer of AEP and of the Service Corporation 1993-Present President of AEP 1992-1993 President and Chief Operating Officer of the Service Corporation 1992-1993 Chairman of the Board, President and Chief Executive Officer of Gulf States Utilities Company 1987-1992 Peter J. DeMaria. . .62 Director 1992-Present Vice President 1991-Present Controller 1995-Present Treasurer 1978-1995 Controller of AEP 1995-Present Treasurer of AEP 1978-1995 Executive Vice President-Administration and Chief Accounting Officer of the Service Corporation 1984-Present William N. D'Onofrio.49 Director 1984-Present Vice President 1984-1995 Director-Regions of the Service Corporation 1996-Present William J. Lhota. . .57 Director 1989-Present President and Chief Operating Officer 1996-Present Vice President 1989-1995 Executive Vice President of the Service Corporation 1993-Present Executive Vice President-Operations of the Service Corporation 1989-1993 Gerald P. Maloney . .64 Director 1978-Present Vice President 1970-Present Vice President of AEP 1974-Present Secretary of AEP 1994-Present Executive Vice President-Chief Financial Officer of the Service Corporation 1991-Present James J. Markowsky. .52 Director 1995-Present Vice President 1993-Present Executive Vice President-Power Generation of the Service Corporation 1996-Present Executive Vice President-Engineering & Construction of the Service Corporation 1993-1996 Senior Vice President and Chief Engineer of the Service Corporation 1988-1993 D. M. Trenary . . . .60 Director 1994-Present Indiana Region Manager 1994-Present Division Manager 1989-1994 W. E. Walters . . . .49 Director 1991-Present Michiana Region Manager 1994-Present Executive Assistant to President 1987-1994 C. R. Boyle, III. . .49 Director and Vice President 1996-Present President and Chief Operating Officer of KEPCo 1990-1995 G. A. Clark . . . . .45 Director 1995-Present Governmental Affairs Manager 1996-Present General Counsel 1994-1995 General Attorney 1991-1993 D. B. Synowiec. . . .53 Director 1995-Present Plant Manager 1990-Present J. H. Vipperman . . .56 Director and Vice President 1996-Present Executive Vice President-Energy Delivery of the Service Corporation 1996-Present President and Chief Operating Officer of APCo 1990-1995 E. H. Wittkamper. . .58 Director 1996-Present Director of System Operations (Fort Wayne) 1996 System Operations Manager (Fort Wayne) 1990-1996
- -------------------- (a) Positions are with I&M unless otherwise indicated. (b) Dr. Draper is a director of BCP Management, Inc., which is the general partner of Borden Chemicals and Plastics L.P., and Mr. Lhota is a director of Huntington Bancshares Incorporated and State Auto Financial Corporation. (c) Drs. Draper and Markowsky and Messrs. DeMaria, Lhota and Maloney are directors of AEGCo, APCo, CSPCo, KEPCo and OPCo. Dr. Draper and Messrs. DeMaria and Maloney are also directors of AEP. Mr. Vipperman is a director of APCo, CSPCo, KEPCo and OPCo. KEPCo. Omitted pursuant to Instruction I(2)(c). OPCo. The information required by this item is incorporated herein by reference to the material under the heading Election of Directors of the definitive information statement of OPCo for the 1997 annual meeting of shareholders, to be filed within 120 days after December 31, 1996. Reference also is made to the information under the caption Executive Officers of the Registrants in Part I of this report. Item 11. EXECUTIVE COMPENSATION - ------------------------------------------------------------------------------ AEGCo. Omitted pursuant to Instruction I(2)(c). AEP. The information required by this item is incorporated herein by reference to the material under Compensation of Directors, Executive Compensation and the performance graph of the definitive proxy statement of AEP, dated March 10, 1997, for the 1997 annual meeting of shareholders. APCo. The information required by this item is incorporated herein by reference to the material under Executive Compensation of the definitive information statement of APCo for the 1997 annual meeting of stockholders, to be filed within 120 days after December 31, 1996. CSPCo. Omitted pursuant to Instruction I(2)(c). KEPCo. Omitted pursuant to Instruction I(2)(c). OPCo. The information required by this item is incorporated herein by reference to the material under Executive Compensation of the definitive information statement of OPCo for the 1997 annual meeting of shareholders, to be filed within 120 days after December 31, 1996. I&M. Certain executive officers of I&M are employees of the Service Corporation. The salaries of these executive officers are paid by the Service Corporation and a portion of their salaries has been allocated and charged to I&M. The following table shows for 1996, 1995 and 1994 the compensation earned from all AEP System companies by the chief executive officer and four other most highly compensated executive officers (as defined by regulations of the SEC) of I&M at December 31, 1996. Summary Compensation Table
Long-Term Compensation Annual Compensation ------------------ ------------------- Payouts All Other Salary Bonus ------------------ Compensation Name and Principal Position Year ($) ($)(1) LTIP Payouts($)(1) ($)(2) --------------------------- ---- ------- ------- ------------------ ------------ E. Linn Draper, Jr. -- Chairman of the board, 1996 720,000 281,664 675,903 31,990 president and chief executive officer of the 1995 685,000 236,325 334,851 30,790 Company and the Service Corporation; chairman 1994 620,000 209,436 137,362 29,385 and chief executive officer of other subsidiaries Peter J. DeMaria -- Controller and director of the 1996 360,000 140,832 290,825 21,190 Company; executive vice president--administration 1995 330,000 113,850 143,829 20,050 and chief accounting officer and director of the 1994 305,000 103,029 59,032 18,750 Service Corporation; vice president, controller and director of other subsidiaries G. P. Maloney -- Vice president, secretary and 1996 360,000 140,832 286,288 21,190 director of the Company; executive vice president 1995 330,000 113,850 141,582 20,060 -- chief financial officer and director of the 1994 300,000 101,340 58,094 19,745 Service Corporation; vice president and director of other subsidiaries William J. Lhota -- Executive vice president and 1996 320,000 125,184 263,114 19,690 director of the Service Corporation; president, 1995 300,000 103,500 132,592 19,140 chief operating officer and director of other 1994 280,000 94,584 54,409 19,185 subsidiaries James J. Markowsky -- Executive vice president 1996 303,000 118,534 254,535 19,480 -- power generation and director of the Service 1995 285,000 98,325 126,599 17,515 Corporation; vice president and director of 1994 267,000 90,193 51,930 14,755 other subsidiaries
- -------------------- (1) Amounts in the "Bonus" column reflect payments under the Management Incentive Compensation Plan for performance measured for each of the years ended December 31, 1994, 1995 and 1996. Payments are made in March of the subsequent year. Amounts for 1996 are estimates but should not change significantly. Amounts in the "Long-Term Compensation" column reflect performance share unit targets earned under the Performance Share Incentive Plan (which became effective January 1, 1994) for the one-, two- and three-year performance periods ending December 31, 1994, 1995 and 1996, respectively. The one- and two-year performance periods were transition performance periods. See below under "Long-Term Incentive Plans -- Awards in 1996" for additional information. (2) For 1996, includes (i) employer matching contributions under the AEP System Employees Savings Plan: Dr. Draper, $3,600; Mr. DeMaria, $3,175; Mr. Maloney, $4,500; Mr. Lhota, $4,500; and Dr. Markowsky, $3,235; (ii) employer matching contributions under the AEP System Supplemental Savings Plan, a non-qualified plan designed to supplement the AEP Savings Plan: Dr. Draper, $18,000; Mr. DeMaria, $7,625; Mr. Maloney, $6,300; Mr. Lhota, $4,800; and Dr. Markowsky, $5,855; and (iii) subsidiary companies director fees: $10,390 for each of the named executive officers. Long-Term Incentive Plans -- Awards In 1996 Each of the awards set forth below establishes performance share unit targets, which represent units equivalent to shares of Common Stock, pursuant to the Company's Performance Share Incentive Plan. Since it is not possible to predict future dividends and the price of AEP Common Stock, credits of performance share units in amounts equal to the dividends that would have been paid if the performance share unit targets were established in the form of shares of Common Stock are not included in the table. The ability to earn performance share unit targets is tied to achieving specified levels of total shareholder return ("TSR") relative to the S&P Electric Utility Index. Notwithstanding AEP's TSR ranking, no performance share unit targets are earned unless AEP shareholders realize a positive TSR over the relevant three-year performance period. The Human Resources Committee may, at its discretion, reduce the number of performance share unit targets otherwise earned. In accordance with the performance goals established for the periods set forth below, the threshold, target and maximum awards are equal to 25%, 100% and 200%, respectively, of the performance share unit targets. No payment will be made for performance below the threshold. Payments of earned awards are deferred in the form of restricted stock units (equivalent to shares of AEP Common Stock) until the officer has met the equivalent stock ownership target discussed in the Human Resources Committee Report. Once officers meet and maintain their respective targets, they may elect either to continue to defer or to receive further earned awards in cash and/or Common Stock.
Estimated Future Payouts of Performance Share Units Under Performance Non-Stock Price-Based Plan Number of Period Until -------------------------- Performance Maturation Threshold Target Maximum Name Share Units or Payout (#) (#) (#) - ----------------- ----------- ----------- --------- ------- ------- E. L. Draper, Jr. 7,339 1996-1998 1,835 7,339 14,678 P. J. DeMaria 3,211 1996-1998 803 3,211 6,422 G. P. Maloney 3,211 1996-1998 803 3,211 6,422 W. J. Lhota 2,854 1996-1998 714 2,854 5,708 J. J. Markowsky 2,702 1996-1998 676 2,702 5,404
Retirement Benefits The American Electric Power System Retirement Plan provides pensions for all employees of AEP System companies (except for employees covered by certain collective bargaining agreements), including the executive officers of the Company. The Retirement Plan is a noncontributory defined benefit plan. The following table shows the approximate annual annuities under the Retirement Plan that would be payable to employees in certain higher salary classifications, assuming retirement at age 65 after various periods of service. Pension Plan Table
Years of Accredited Service Highest Average -------------------------------------------------------------- Annual Earnings 15 20 25 30 35 40 45 - --------------- -------- -------- -------- -------- -------- -------- -------- $ 300,000 $ 69,795 $ 93,060 $116,325 $139,590 $162,855 $182,805 $202,755 400,000 93,795 125,060 156,325 187,590 218,855 245,455 272,055 500,000 117,795 157,060 196,325 235,590 274,855 308,105 341,355 700,000 165,795 221,060 276,325 331,590 386,855 433,405 479,955 900,000 213,795 285,060 356,325 427,590 498,855 558,705 618,555 1,200,000 285,795 381,060 476,325 571,590 666,855 746,655 826,455
The amounts shown in the table are the straight life annuities payable under the Retirement Plan without reduction for the joint and survivor annuity. Retirement benefits listed in the table are not subject to any deduction for Social Security or other offset amounts. The retirement annuity is reduced 3% per year in the case of retirement between ages 60 and 62 and further reduced 6% per year in the case of retirement between ages 55 and 60. If an employee retires after age 62, there is no reduction in the retirement annuity. The Company maintains a supplemental retirement plan which provides for the payment of benefits that are not payable under the Retirement Plan due primarily to limitations imposed by Federal tax law on benefits paid by qualified plans. The table includes supplemental retirement benefits. Compensation upon which retirement benefits are based, for the executive officers named in the Summary Compensation Table above, consists of the average of the 36 consecutive months of the officer's highest aggregate salary and Management Incentive Compensation Plan awards, shown in the "Salary" and "Bonus" columns, respectively, of the Summary Compensation Table, out of the officer's most recent 10 years of service. As of December 31, 1996, the number of full years of service applicable for retirement benefit calculation purposes for such officers were as follows: Dr. Draper, four years; Mr. DeMaria, 37 years; Mr. Maloney, 41 years; Mr. Lhota, 32 years; and Dr. Markowsky, 25 years. Dr. Draper has a contract with the Company and AEP Service Corporation which provides him with a supplemental retirement annuity that credits him with 24 years of service in addition to his years of service credited under the Retirement Plan less his actual pension entitlement under the Retirement Plan and any pension entitlement from the Gulf States Utilities Company Trusteed Retirement Plan, a plan sponsored by his prior employer. Fourteen AEP System employees (including Messrs. DeMaria, Maloney and Lhota and Dr. Markowsky) whose pensions may be adversely affected by amendments to the Retirement Plan made as a result of the Tax Reform Act of 1986 are eligible for certain supplemental retirement benefits. Such payments, if any, will be equal to any reduction occurring because of such amendments. Assuming retirement in 1997 of the executive officers named in the Summary Compensation Table, only Mr. Maloney would be affected and his annual supplemental benefit would be $2,361. The Company made available a voluntary deferred-compensation program in 1982 and 1986, which permitted certain members of AEP System management to defer receipt of a portion of their salaries. Under this program, a participant was able to defer up to 10% or 15% annually (depending on the terms of the program offered), over a four-year period, of his or her salary, and receive supplemental retirement or survivor benefit payments over a 15-year period. The amount of supplemental retirement payments received is dependent upon the amount deferred, age at the time the deferral election was made, and number of years until the participant retires. The following table sets forth, for the executive officers named in the Summary Compensation Table, the amounts of annual deferrals and, assuming retirement at age 65, annual supplemental retirement payments under the 1982 and 1986 programs.
1982 Program 1986 Program -------------------------------- -------------------------------- Annual Amount of Annual Amount of Annual Supplemental Annual Supplemental Amount Retirement Amount Retirement Deferred Payment Deferred Payment Name (4-Year Period) (15-Year Period) (4-Year Period) (15-Year Period) - ---- --------------- ---------------- --------------- ---------------- P. J. DeMaria . . . $10,000 $52,000 $13,000 $53,300 G. P. Maloney . . . 15,000 67,500 16,000 56,400
Directors of I&M receive a fee of $100 for each meeting of the Board of Directors attended in addition to their salaries. The AEP System is an integrated electric utility system and, as a result, the member companies of the AEP System have contractual, financial and other business relationships with the other member companies, such as participation in the AEP System savings and retirement plans and tax returns, sales of electricity, transportation and handling of fuel, sales or rentals of property and interest or dividend payments on the securities held by the companies' respective parents. Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT - ------------------------------------------------------------------------------- AEGCo. Omitted pursuant to Instruction I(2)(c). AEP. The information required by this item is incorporated herein by reference to the material under Share Ownership of Directors and Executive Officers of the definitive proxy statement of AEP, dated March 10, 1997, for the 1997 annual meeting of shareholders. APCo. The information required by this item is incorporated herein by reference to the material under Share Ownership of Directors and Executive Officers in the definitive information statement of APCo for the 1997 annual meeting of stockholders, to be filed within 120 days after December 31, 1996. CSPCo. Omitted pursuant to Instruction I(2)(c). I&M. All 1,400,000 outstanding shares of Common Stock, no par value, of I&M are directly and beneficially held by AEP. Holders of the Cumulative Preferred Stock of I&M generally have no voting rights, except with respect to certain corporate actions and in the event of certain defaults in the payment of dividends on such shares. The table below shows the number of shares of AEP Common Stock and stock-based units that were beneficially owned, directly or indirectly, as of January 1, 1997, by each director and nominee of I&M and each of the executive officers of I&M named in the summary compensation table, and by all directors and executive officers of I&M as a group. It is based on information provided to I&M by such persons. No such person owns any shares of any series of the Cumulative Preferred Stock of I&M. Unless otherwise noted, each person has sole voting power and investment power over the number of shares of AEP Common Stock and stock-based units set forth opposite his name. Fractions of shares and units have been rounded to the nearest whole number.
Stock Name Shares Units(a) Total ---- -------- -------- ------- Coulter R. Boyle, III . . . . . . . 3,454(b) 933 4,387 Gregory A. Clark. . . . . . . . . . 954(b) 346 1,300 Peter J. DeMaria. . . . . . . . . . 7,603(b)(c)(d)(e)12,947 20,550 William N. D'Onofrio. . . . . . . . 3,981(b)(d) 685 4,666 E. Linn Draper, Jr. . . . . . . . . 6,793(b)(d) 35,915 42,708 William J. Lhota. . . . . . . . . . 14,053(b)(c)(d) 5,383 19,436 Gerald P. Maloney . . . . . . . . . 5,512(b)(c)(d) 12,765 18,277 James J. Markowsky. . . . . . . . . 7,123(b)(e) 11,755 18,878 David B. Synowiec . . . . . . . . . 2,335(b) 545 2,880 Dale M. Trenary . . . . . . . . . . 160(b) 568 728 Joseph H. Vipperman . . . . . . . . 5,510(b)(d) 3,972 9,482 William E. Walters. . . . . . . . . 5,200(b) 403 5,603 Earl H. Wittkamper. . . . . . . . . 2,902(b) 420 3,322 All Directors and Executive Officers 150,811(d)(f) 86,637 237,448
- ----------------- (a) This column includes amounts deferred in stock units and held under the Management Incentive Compensation Plan and Performance Share Incentive Plan. (b) Includes shares and share equivalents held in the following plans in the amounts listed below:
AEP Employee Stock AEP Performance AEP Employees Savings Ownership Plan (Shares) Share Incentive Plan (Shares) Plan (Share Equivalents) ----------------------- ----------------------------- ------------------------ Mr. Boyle . . . . . . . . . . 50 -- 3,404 Mr. Clark . . . . . . . . . . 8 -- 946 Mr. DeMaria . . . . . . . . . 90 881 2,945 Mr. D'Onofrio . . . . . . . . 64 -- 3,917 Dr. Draper. . . . . . . . . . -- 2,050 2,383 Mr. Lhota . . . . . . . . . . 64 812 11,809 Mr. Maloney . . . . . . . . . 92 867 3,053 Dr. Markowsky . . . . . . . . 71 775 6,154 Mr. Synowiec. . . . . . . . . 58 -- 2,277 Mr. Trenary . . . . . . . . . 44 -- 116 Mr. Vipperman . . . . . . . . 86 527 4,766 Mr. Walters . . . . . . . . . 48 -- 5,152 Mr. Wittkamper. . . . . . . . 37 -- 1,628 All Directors and Executive Officers 712 5,912 48,550 With respect to the shares and share equivalents held in these plans, such persons have sole voting power, but the investment/disposition power is subject to the terms of such plans.
(c) Does not include, for Messrs. DeMaria, Lhota and Maloney, 85,231 shares in the American Electric Power System Educational Trust Fund over which Messrs. DeMaria, Lhota and Maloney share voting and investment power as trustees (they disclaim beneficial ownership). The amount of shares shown for all directors and executive officers as a group includes these shares. (d) Includes the following numbers of shares held in joint tenancy with a family member: Mr. DeMaria, 1,232; Mr. D'Onofrio, 500; Dr. Draper, 2,083; Mr. Lhota, 1,368; Mr. Maloney, 1,500; and Mr. Vipperman, 131. (e) Includes the following numbers of shares held by family members over which beneficial ownership is disclaimed: Mr. DeMaria, 2,392; and Dr. Markowsky, 18. (f) Represents less than 1% of the total number of shares outstanding. KEPCo. Omitted pursuant to Instruction I(2)(c). OPCo. The information required by this item is incorporated herein by reference to the material under Share Ownership of Directors and Executive Officers in the definitive information statement of OPCo for the 1997 annual meeting of shareholders, to be filed within 120 days after December 31, 1996. Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS - ------------------------------------------------------------------------------ AEP, APCo, I&M and OPCo. None. AEGCo, CSPCo, and KEPCo. Omitted pursuant to Instruction I(2)(c). PART IV --------------------------------------------------------------------- Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K - ------------------------------------------------------------------------------ (a) The following documents are filed as a part of this report: 1. Financial Statements: Page ---- The following financial statements have been incorporated herein by reference pursuant to Item 8. AEGCo: Independent Auditors' Report; Statements of Income for the years ended December 31, 1996, 1995 and 1994; Statements of Retained Earnings for the years ended December 31, 1996, 1995 and 1994; Statements of Cash Flows for the years ended December 31, 1996, 1995 and 1994; Balance Sheets as of December 31, 1996 and 1995; Notes to Financial Statements. AEP and its subsidiaries consolidated: Consolidated Statements of Income for the years ended December 31, 1996, 1995 and 1994; Consolidated Statements of Retained Earnings for the years ended December 31, 1996, 1995 and 1994; Consolidated Balance Sheets as of December 31, 1996 and 1995; Consolidated Statements of Cash Flows for the years ended December 31, 1996, 1995 and 1994; Notes to Consolidated Financial Statements; Schedule of Consolidated Cumulative Preferred Stocks of Subsidiaries at December 31, 1996 and 1995; Schedule of Consolidated Long-term Debt of Subsidiaries at December 31, 1996 and 1995; Independent Auditors' Report. APCo: Consolidated Statements of Income for the years ended December 31, 1996, 1995 and 1994; Consolidated Balance Sheets as of December 31, 1996 and 1995; Consolidated Statements of Cash Flows for the years ended December 31, 1996, 1995 and 1994; Consolidated Statements of Retained Earnings for the years ended December 31, 1996, 1995 and 1994; Notes to Consolidated Financial Statements; Independent Auditors' Report. CSPCo: Independent Auditors' Report; Consolidated Statements of Income for the years ended December 31, 1996, 1995 and 1994; Consolidated Balance Sheets as of December 31, 1996 and 1995; Consolidated Statements of Cash Flows for the years ended December 31, 1996, 1995 and 1994; Consolidated Statements of Retained Earnings for the years ended December 31, 1996, 1995 and 1994; Notes to Consolidated Financial Statements. I&M: Independent Auditors' Report; Consolidated Statements of Income for the years ended December 31, 1996, 1995 and 1994; Consolidated Statements of Cash Flows for the years ended December 31, 1996, 1995 and 1994; Consolidated Balance Sheets as of December 31, 1996 and 1995; Consolidated Statements of Retained Earnings for the years ended December 31, 1996, 1995 and 1994; Notes to Consolidated Financial Statements. KEPCo: Independent Auditors' Report; Statements of Income for the years ended December 31, 1996, 1995 and 1994; Statements of Retained Earnings for the years ended December 31, 1996, 1995 and 1994; Balance Sheets as of December 31, 1996 and 1995; Statements of Cash Flows for the years ended December 31, 1996, 1995 and 1994; Notes to Financial Statements. OPCo: Independent Auditors' Report; Consolidated Statements of Income for the years ended December 31, 1996, 1995 and 1994; Consolidated Statements of Cash Flows for the years ended December 31, 1996, 1995 and 1994; Consolidated Balance Sheets as of December 31, 1996 and 1995; Consolidated Statements of Retained Earnings for the years ended December 31, 1996, 1995 and 1994; Notes to Consolidated Financial Statements. 2. Financial Statement Schedules: Financial Statement Schedules are listed in the Index to Financial Statement Schedules (Certain schedules have been omitted because the required information is contained in the notes to financial statements or because such schedules are not required or are not applicable.) S-1 Independent Auditors' Report S-2 3. Exhibits: Exhibits for AEGCo, AEP, APCo, CSPCo, I&M, KEPCo and OPCo are listed in the Exhibit Index and are incorporated herein by reference E-1 (b) No Reports on Form 8-K were filed during the quarter ended December 31, 1996. SIGNATURES PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED. THE SIGNATURE OF THE UNDERSIGNED COMPANY SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING REFERENCE TO SUCH COMPANY AND ANY SUBSIDIARIES THEREOF. AEP Generating Company By: /s/ G. P. Maloney ----------------------------- (G. P. Maloney, Vice President) Date: March 25, 1997 PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED. THE SIGNATURE OF EACH OF THE UNDERSIGNED SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING REFERENCE TO THE ABOVE-NAMED COMPANY AND ANY SUBSIDIARIES THEREOF. Signature Title Date --------- ----- ---- (i) Principal Executive Officer: President, *E. Linn Draper, Jr. Chief Executive Officer and Director (ii) Principal Financial Officer: /s/ G. P. Maloney Vice President March 25, 1997 ------------------------- and Director (G. P. Maloney) (iii) Principal Accounting Officer: /s/ P. J. DeMaria Vice President, Controller March 25, 1997 ------------------------- and Director (P. J. DeMaria) (iv) A Majority of the Directors: *Henry Fayne *John R. Jones, III *Wm. J. Lhota *James J. Markowsky *By: /s/ G. P. Maloney March 25, 1997 - ------------------------------ (G. P. Maloney, Attorney-in-Fact) SIGNATURES PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED. American Electric Power Company, Inc. By: /s/ G. P. Maloney --------------------------------- (G. P. Maloney, Vice President) Date: March 25, 1997 PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED. Signature Title Date --------- ----- ---- (i) Principal Executive Officer: Chairman of the Board, *E. Linn Draper, Jr. President, Chief Executive Officer and Director (ii) Principal Financial Officer: /s/ G. P. Maloney Vice President, Secretary March 25, 1997 -------------------------- and Director (G. P. Maloney) (iii) Principal Accounting Officer: /s/ P. J. DeMaria Controller and Director March 25, 1997 -------------------------- (P. J. DeMaria) (iv) A Majority of the Directors: *Robert M. Duncan *Robert W. Fri *Arthur G. Hansen *Lester A. Hudson, Jr. *Leonard J. Kujawa *Angus E. Peyton *Donald G. Smith *Linda Gillespie Stuntz *Morris Tanenbaum *Ann Haymond Zwinger *By: /s/ G. P. Maloney March 25, 1997 ----------------------------- (G. P. Maloney, Attorney-in-Fact) SIGNATURES PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED. THE SIGNATURE OF THE UNDERSIGNED COMPANY SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING REFERENCE TO SUCH COMPANY AND ANY SUBSIDIARIES THEREOF. Appalachian Power Company By: /s/ G. P. Maloney ---------------------------- (G. P. Maloney, Vice President) Date: March 25, 1997 PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED. THE SIGNATURE OF EACH OF THE UNDERSIGNED SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING REFERENCE TO THE ABOVE-NAMED COMPANY AND ANY SUBSIDIARIES THEREOF. Signature Title Date --------- ----- ---- (i) Principal Executive Officer: Chairman of the Board, *E. Linn Draper, Jr. Chief Executive Officer and Director (ii) Principal Financial Officer: /s/ G. P. Maloney Vice President March 25, 1997 ------------------------- and Director (G. P. Maloney) (iii) Principal Accounting Officer: /s/ P. J. DeMaria Vice President, Controller March 25, 1997 ------------------------- and Director (P. J. DeMaria) (iv) A Majority of the Directors: *Henry Fayne *Wm. J. Lhota *James J. Markowsky *J. H. Vipperman *By: /s/ G. P. Maloney March 25, 1997 ---------------------------- (G. P. Maloney, Attorney-in-Fact) SIGNATURES PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED. THE SIGNATURE OF THE UNDERSIGNED COMPANY SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING REFERENCE TO SUCH COMPANY AND ANY SUBSIDIARIES THEREOF. Columbus Southern Power Company By: /s/ G. P. Maloney -------------------------- (G. P. Maloney, Vice President) Date: March 25, 1997 PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED. THE SIGNATURE OF EACH OF THE UNDERSIGNED SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING REFERENCE TO THE ABOVE-NAMED COMPANY AND ANY SUBSIDIARIES THEREOF. Signature Title Date --------- ----- ---- (i) Principal Executive Officer: Chairman of the Board, *E. Linn Draper, Jr. Chief Executive Officer and Director (ii) Principal Financial Officer: /s/ G. P. Maloney Vice President March 25, 1997 --------------------------- and Director (G. P. Maloney) (iii) Principal Accounting Officer: /s/ P. J. DeMaria Vice President, Controller March 25, 1997 --------------------------- and Director (P. J. DeMaria) (iv) A Majority of the Directors: *Henry Fayne *Wm. J. Lhota *James J. Markowsky *J. H. Vipperman *By: /s/ G. P. Maloney March 25, 1997 - ---------------------------------- (G. P. Maloney, Attorney-in-Fact) SIGNATURES PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED. THE SIGNATURE OF THE UNDERSIGNED COMPANY SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING REFERENCE TO SUCH COMPANY AND ANY SUBSIDIARIES THEREOF. Indiana Michigan Power Company By: /s/ G. P. Maloney ------------------------------ (G. P. Maloney, Vice President) Date: March 25, 1997 PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED. THE SIGNATURE OF EACH OF THE UNDERSIGNED SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING REFERENCE TO THE ABOVE-NAMED COMPANY AND ANY SUBSIDIARIES THEREOF. Signature Title Date --------- ----- ---- (i) Principal Executive Officer: Chairman of the Board, *E. Linn Draper, Jr. Chief Executive Officer and Director (ii) Principal Financial Officer: /s/ G. P. Maloney Vice President March 25, 1997 --------------------------- and Director (G. P. Maloney) (iii) Principal Accounting Officer: /s/ P. J. DeMaria Vice President, Controller March 25, 1997 --------------------------- and Director (P. J. DeMaria) (iv) A Majority of the Directors: *C. R. Boyle, III *G. A. Clark *W. N. D'Onofrio *Wm. J. Lhota *James J. Markowsky *D. B. Synowiec *D. M. Trenary *J. H. Vipperman *W. E. Walters *E. H. Wittkamper *By: /s/ G. P. Maloney March 25, 1997 --------------------- (G. P. Maloney, Attorney-in-Fact) SIGNATURES PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED. THE SIGNATURE OF THE UNDERSIGNED COMPANY SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING REFERENCE TO SUCH COMPANY AND ANY SUBSIDIARIES THEREOF. Kentucky Power Company By: /s/ G. P. Maloney ------------------------- G. P. Maloney, Vice President) Date: March 25, 1997 PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED. THE SIGNATURE OF EACH OF THE UNDERSIGNED SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING REFERENCE TO THE ABOVE-NAMED COMPANY AND ANY SUBSIDIARIES THEREOF. Signature Title Date --------- ----- ---- (i) Principal Executive Officer: Chairman of the Board, *E. Linn Draper, Jr. Chief Executive Officer and Director (ii) Principal Financial Officer: /s/ G. P. Maloney Vice President March 25, 1997 --------------------------- and Director (G. P. Maloney) (iii) Principal Accounting Officer: /s/ P. J. DeMaria Vice President, Controller March 25, 1997 --------------------------- and Director (P. J. DeMaria) (iv) A Majority of the Directors: *Wm. J. Lhota *James J. Markowsky *J. H. Vipperman *By: /s/ G. P. Maloney March 25, 1997 - ---------------------------------- (G. P. Maloney, Attorney-in-Fact) SIGNATURES PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED. THE SIGNATURE OF THE UNDERSIGNED COMPANY SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING REFERENCE TO SUCH COMPANY AND ANY SUBSIDIARIES THEREOF. Ohio Power Company By: /s/ G. P. Maloney -------------------------- (G. P. Maloney, Vice President) Date: March 25, 1997 PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED. THE SIGNATURE OF EACH OF THE UNDERSIGNED SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING REFERENCE TO THE ABOVE-NAMED COMPANY AND ANY SUBSIDIARIES THEREOF. Signature Title Date --------- ----- ---- (i) Principal Executive Officer: Chairman of the Board, *E. Linn Draper, Jr. Chief Executive Officer and Director (ii) Principal Financial Officer: /s/ G. P. Maloney Vice President March 25, 1997 --------------------------- and Director (G. P. Maloney) (iii) Principal Accounting Officer: /s/ P. J. DeMaria Vice President, Controller March 25, 1997 --------------------------- and Director (P. J. DeMaria) (iv) A Majority of the Directors: *Henry Fayne *Wm. J. Lhota *James J. Markowsky *J. H. Vipperman *By: /s/ G. P. Maloney March 25, 1997 - ---------------------------------- (G. P. Maloney, Attorney-in-Fact) INDEX TO FINANCIAL STATEMENT SCHEDULES Page ---- INDEPENDENT AUDITORS' REPORT . . . . . . . . . . . . . . . . . . . . . . . S-2 The following financial statement schedules for the years ended December 31, 1996, 1995 and 1994 are included in this report on the pages indicated. AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Schedule II -- Valuation and Qualifying Accounts and Reserves . . . S-3 APPALACHIAN POWER COMPANY AND SUBSIDIARIES Schedule II -- Valuation and Qualifying Accounts and Reserves . . . S-3 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Schedule II -- Valuation and Qualifying Accounts and Reserves . . . S-3 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Schedule II -- Valuation and Qualifying Accounts and Reserves . . . S-4 KENTUCKY POWER COMPANY Schedule II -- Valuation and Qualifying Accounts and Reserves . . . S-4 OHIO POWER COMPANY AND SUBSIDIARIES Schedule II -- Valuation and Qualifying Accounts and Reserves . . . S-4 INDEPENDENT AUDITORS' REPORT American Electric Power Company, Inc. and Subsidiaries: We have audited the consolidated financial statements of American Electric Power Company, Inc. and its subsidiaries and the financial statements of certain of its subsidiaries, listed in Item 14 herein, as of December 31, 1996 and 1995, and for each of the three years in the period ended December 31, 1996, and have issued our reports thereon dated February 25, 1997; such financial statements and reports are included in your respective 1996 Annual Report and are incorporated herein by reference. Our audits also included the financial statement schedules of American Electric Power Company, Inc. and its subsidiaries and of certain of its subsidiaries, listed in Item 14. These financial statement schedules are the responsibility of the respective Company's management. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedules, when considered in relation to the corresponding basic financial statements taken as a whole, present fairly in all material respects the information set forth therein. Deloitte & Touche LLP Columbus, Ohio February 25, 1997
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES ============================================================================================== Column A Column B Column C Column D Column E - ---------------------------------------------------------------------------------------------- Additions --------------------- Balance atCharged toCharged to Balance at BeginningCosts and Other End of Description of Period Expenses Accounts Deductions Period - ---------------------------------------------------------------------------------------------- (in thousands) Deducted from Assets: Accumulated Provision for Uncollectible Accounts: Year Ended December 31, 1996 $5,430 $16,382 $ 7,224 (a)$25,344(b) $3,692 Year Ended December 31, 1995 $4,056 $12,907 $ 5,927 (a)$17,460(b) $5,430 Year Ended December 31, 1994 $4,048 $20,265 $(3,556)(a)$16,701(b) $4,056
- --------------------- (a) Recoveries on accounts previously written off. (b) Uncollectible accounts written off.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES ============================================================================================== Column A Column B Column C Column D Column E - ---------------------------------------------------------------------------------------------- Additions --------------------- Balance atCharged toCharged to Balance at BeginningCosts and Other End of Description of Period Expenses Accounts Deductions Period - ---------------------------------------------------------------------------------------------- (in thousands) Deducted from Assets: Accumulated Provision for Uncollectible Accounts: Year Ended December 31, 1996 $2,253 $1,748 $779(a) $4,093(b) $ 687 Year Ended December 31, 1995 $ 830 $3,442 $963(a) $2,982(b) $2,253 Year Ended December 31, 1994 $1,344 $2,297 $596(a) $3,407(b) $ 830
- -------------------- (a) Recoveries on accounts previously written off. (b) Uncollectible accounts written off.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES ============================================================================================== Column A Column B Column C Column D Column E - ---------------------------------------------------------------------------------------------- Additions --------------------- Balance atCharged toCharged to Balance at BeginningCosts and Other End of Description of Period Expenses Accounts Deductions Period - ---------------------------------------------------------------------------------------------- (in thousands) Deducted from Assets: Accumulated Provision for Uncollectible Accounts: Year Ended December 31, 1996 $1,061 $7,720 $3,978(a)$11,727(b) $1,032 Year Ended December 31, 1995 $1,768 $4,873 $3,531(a)$ 9,111(b) $1,061 Year Ended December 31, 1994 $ 991 $6,181 $2,778(a)$ 8,182(b) $1,768
- -------------------- (a) Recoveries on accounts previously written off. (b) Uncollectible accounts written off.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES ============================================================================================== Column A Column B Column C Column D Column E - ---------------------------------------------------------------------------------------------- Additions --------------------- Balance atCharged toCharged to Balance at BeginningCosts and Other End of Description of Period Expenses Accounts Deductions Period - ---------------------------------------------------------------------------------------------- (in thousands) Deducted from Assets: Accumulated Provision for Uncollectible Accounts: Year Ended December 31, 1996 $334 $2,208 $791(a) $3,177(b) $156 Year Ended December 31, 1995 $121 $1,506 $632(a) $1,925(b) $334 Year Ended December 31, 1994 $505 $ 774 $707(a) $1,864(b) $121
- -------------------- (a) Recoveries on accounts previously written off. (b) Uncollectible accounts written off.
KENTUCKY POWER COMPANY SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES ============================================================================================== Column A Column B Column C Column D Column E - ---------------------------------------------------------------------------------------------- Additions --------------------- Balance atCharged toCharged to Balance at BeginningCosts and Other End of Description of Period Expenses Accounts Deductions Period - ---------------------------------------------------------------------------------------------- (in thousands) Deducted from Assets: Accumulated Provision for Uncollectible Accounts: Year Ended December 31, 1996 $259 $1,507 $311(a) $1,805(b) $272 Year Ended December 31, 1995 $260 $ 925 $234(a) $1,160(b) $259 Year Ended December 31, 1994 $208 $ 600 $ 84(a) $ 632(b) $260
- --------------------- (a) Recoveries on accounts previously written off. (b) Uncollectible accounts written off.
OHIO POWER COMPANY AND SUBSIDIARIES SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES ============================================================================================== Column A Column B Column C Column D Column E - ---------------------------------------------------------------------------------------------- Additions --------------------- Balance atCharged toCharged to Balance at BeginningCosts and Other End of Description of Period Expenses Accounts Deductions Period - ---------------------------------------------------------------------------------------------- (in thousands) Deducted from Assets: Accumulated Provision for Uncollectible Accounts: Year Ended December 31, 1996 $1,424 $ 2,874 $ 532 (a)$3,397(b) $1,433 Year Ended December 31, 1995 $1,019 $ 1,952 $ 472 (a)$2,019(b) $1,424 Year Ended December 31, 1994 $ 960 $10,087 $(7,785)(a)$2,243(b) $1,019
- --------------------- (a) Recoveries on accounts previously written off. (b) Uncollectible accounts written off. EXHIBIT INDEX Certain of the following exhibits, designated with an asterisk(*), are filed herewith. The exhibits not so designated have heretofore been filed with the Commission and, pursuant to 17 C.F.R. Section 229.10(d) and Section 240.12b-32, are incorporated herein by reference to the documents indicated in brackets following the descriptions of such exhibits. Exhibits, designated with a dagger (), are management contracts or compensatory plans or arrangements required to be filed as an exhibit to this form pursuant to Item 14(c) of this report. Exhibit Number Description - -------------- ----------- AEGCo 3(a) -- Copy of Articles of Incorporation of AEGCo [Registration Statement on Form 10 for the Common Shares of AEGCo, File No. 0-18135, Exhibit 3(a)]. 3(b) -- Copy of the Code of Regulations of AEGCo [Registration Statement on Form 10 for the Common Shares of AEGCo, File No. 0-18135, Exhibit 3(b)]. 10(a) -- Copy of Capital Funds Agreement dated as of December 30, 1988 between AEGCo and AEP [Registration Statement No. 33-32752, Exhibit 28(a)]. 10(b)(1) -- Copy of Unit Power Agreement dated as of March 31, 1982 between AEGCo and I&M, as amended [Registration Statement No. 33-32752, Exhibits 28(b)(1)(A) and 28(b)(1)(B)]. 10(b)(2) -- Copy of Unit Power Agreement, dated as of August 1, 1984, among AEGCo, I&M and KEPCo [Registration Statement No. 33-32752, Exhibit 28(b)(2)]. 10(b)(3) -- Copy of Agreement, dated as of October 1, 1984, among AEGCo, I&M, APCo and Virginia Electric and Power Company [Registration Statement No. 33-32752, Exhibit 28(b)(3)]. 10(c) -- Copy of Lease Agreements, dated as of December 1, 1989, between AEGCo and Wilmington Trust Company, as amended [Registration Statement No. 33-32752, Exhibits 28(c)(1)(C), 28(c)(2)(C), 28(c)(3)(C), 28(c)(4)(C), 28(c)(5)(C) and 28(c)(6)(C); Annual Report on Form 10-K of AEGCo for the fiscal year ended December 31, 1993, File No. 0-18135, Exhibits 10(c)(1)(B), 10(c)(2)(B), 10(c)(3)(B), 10(c)(4)(B), 10(c)(5)(B) and 10(c)(6)(B)]. *13 -- Copy of those portions of the AEGCo 1996 Annual Report (for the fiscal year ended December 31, 1996) which are incorporated by reference in this filing. *24 -- Power of Attorney. *27 -- Financial Data Schedules. AEP 3(a) -- Copy of Restated Certificate of Incorporation of AEP, dated April 26, 1978 [Registration Statement No. 2-62778, Exhibit 2(a)]. 3(b)(1) -- Copy of Certificate of Amendment of the Restated Certificate of Incorporation of AEP, dated April 23, 1980 [Registration Statement No. 33-1052, Exhibit 4(b)]. 3(b)(2) -- Copy of Certificate of Amendment of the Restated Certificate of Incorporation of AEP, dated April 28, 1982 [Registration Statement No. 33-1052, Exhibit 4(c)]. 3(b)(3) -- Copy of Certificate of Amendment of the Restated Certificate of Incorporation of AEP, dated April 25, 1984 [Registration Statement No. 33-1052, Exhibit 4(d)]. 3(b)(4) -- Copy of Certificate of Change of the Restated Certificate of Incorporation of AEP, dated July 5, 1984 [Registration Statement No. 33-1052, Exhibit 4(e)]. 3(b)(5) -- Copy of Certificate of Amendment of the Restated Certificate of Incorporation of AEP, dated April 27, 1988 [Registration Statement No. 33-1052, Exhibit 4(f)]. 3(c) -- Composite copy of the Restated Certificate of Incorporation of AEP, as amended [Registration Statement No. 33-1052, Exhibit 4(g)]. *3(d) -- Copy of By-Laws of AEP, as amended through February 26, 1997. 10(a) -- Interconnection Agreement, dated July 6, 1951, among APCo, CSPCo, KEPCo, OPCo and I&M and with the Service Corporation, as amended [Registration Statement No. 2-52910, Exhibit 5(a); Registration Statement No. 2-61009, Exhibit 5(b); and Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1990, File No. 1-3525, Exhibit 10(a)(3)]. 10(b) -- Copy of Transmission Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KEPCo, OPCo and with the Service Corporation as agent, as amended [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(b); and Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1988, File No. 1-3525, Exhibit 10(b)(2)]. 10(c)(1) -- AEP Deferred Compensation Agreement for certain executive officers [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(e)]. 10(c)(2) -- Amendment to AEP Deferred Compensation Agreement for certain executive officers [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1986, File No. 1-3525, Exhibit 10(d)(2)]. 10(d) -- AEP Deferred Compensation Agreement for directors, as amended, effective October 24, 1984 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1984, File No. 1-3525, Exhibit 10(e)]. 10(e) -- AEP Accident Coverage Insurance Plan for directors [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(g)]. *10(f)(1) -- AEP Deferred Compensation and Stock Plan for Non-Employee Directors. *10(f)(2) -- AEP Stock Unit Accumulation Plan for Non-Employee Directors. 10(g)(1)(A) -- AEP Excess Benefit Plan, as amended through January 4, 1996 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1995, File No. 1-3525, Exhibit 10(g)(1)(A)]. 10(g)(1)(B) -- Guaranty by AEP of the Service Corporation Excess Benefits Plan [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1990, File No. 1-3525, Exhibit 10(h)(1)(B)]. *10(g)(2) -- AEP System Supplemental Savings Plan, as amended through November 15, 1995 (Non-Qualified). 10(g)(3) -- Service Corporation Umbrella Trust for Executives [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1993, File No. 1-3525, Exhibit 10(g)(3)]. 10(h)(1) -- Employment Agreement between E. Linn Draper, Jr. and AEP and the Service Corporation [Annual Report on Form 10-K of AEGCo for the fiscal year ended December 31, 1991, File No. 0-18135, Exhibit 10(g)(3)]. *10(i)(1) -- AEP System Senior Officer Annual Incentive Compensation Plan. *10(i)(2) -- American Electric Power System Performance Share Incentive Plan, as Amended and Restated through February 26, 1997. 10(j) -- Copy of Lease Agreements, dated as of December 1, 1989, between AEGCo or I&M and Wilmington Trust Company, as amended [Registration Statement No. 33-32752, Exhibits 28(c)(1)(C), 28(c)(2)(C), 28(c)(3)(C), 28(c)(4)(C), 28(c)(5)(C) and 28(c)(6)(C); Registration Statement No. 33-32753, Exhibits 28(a)(1)(C), 28(a)(2)(C), 28(a)(3)(C), 28(a)(4)(C), 28(a)(5)(C) and 28(a)(6)(C); and Annual Report on Form 10-K of AEGCo for the fiscal year ended December 31, 1993, File No. 0-18135, Exhibits 10(c)(1)(B), 10(c)(2)(B), 10(c)(3)(B), 10(c)(4)(B), 10(c)(5)(B) and 10(c)(6)(B); Annual Report on Form 10-K of I&M for the fiscal year ended December 31, 1993, File No. 1-3570, Exhibits 10(e)(1)(B), 10(e)(2)(B), 10(e)(3)(B), 10(e)(4)(B), 10(e)(5)(B) and 10(e)(6)(B)]. 10(k) -- Lease Agreement dated January 20, 1995 between OPCo and JMG Funding, Limited Partnership, and amendment thereto (confidential treatment requested) [Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1994, File No. 1-6543, Exhibit 10(l)(2)]. *10(l) -- Modification No. 1 to the AEP System Interim Allowance Agreement, dated July 28, 1994, among APCo, CSPCo, I&M, KEPCo, OPCo and the Service Corporation. *13 -- Copy of those portions of the AEP 1996 Annual Report (for the fiscal year ended December 31, 1996) which are incorporated by reference in this filing. *21 -- List of subsidiaries of AEP. *23 -- Consent of Deloitte & Touche LLP. *24 -- Power of Attorney. *27 -- Financial Data Schedules. APCo 3(a) -- Copy of Restated Articles of Incorporation of APCo, and amendments thereto to November 4, 1993 [Registration Statement No. 33-50163, Exhibit 4(a); Registration Statement No. 33-53805, Exhibits 4(b) and 4(c)]. 3(b) -- Copy of Articles of Amendment to the Restated Articles of Incorporation of APCo, dated June 6, 1994 [Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1994, File No. 1-3457, Exhibit 3(b)]. *3(c) -- Copy of Articles of Amendment to the Restated Articles of Incorporation of APCo, dated March 6, 1997. *3(d) -- Composite copy of the Restated Articles of Incorporation of APCo (amended as of March 7, 1997). 3(e) -- Copy of By-Laws of APCo (amended as of January 1, 1996) [Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1995, File No. 1-3457, Exhibit 3(d)]. 4(a) -- Copy of Mortgage and Deed of Trust, dated as of December 1, 1940, between APCo and Bankers Trust Company and R. Gregory Page, as Trustees, as amended and supplemented [Registration Statement No. 2-7289, Exhibit 7(b); Registration Statement No. 2-19884, Exhibit 2(1); Registration Statement No. 2-24453, Exhibit 2(n); Registration Statement No. 2-60015, Exhibits 2(b)(2), 2(b)(3), 2(b)(4), 2(b)(5), 2(b)(6), 2(b)(7), 2(b)(8), 2(b)(9), 2(b)(10), 2(b)(12), 2(b)(14), 2(b)(15), 2(b)(16), 2(b)(17), 2(b)(18), 2(b)(19), 2(b)(20), 2(b)(21), 2(b)(22), 2(b)(23), 2(b)(24), 2(b)(25), 2(b)(26), 2(b)(27) and 2(b)(28); Registration Statement No. 2-64102, Exhibit 2(b)(29); Registration Statement No. 2-66457, Exhibits (2)(b)(30) and 2(b)(31); Registration Statement No. 2-69217, Exhibit 2(b)(32); Registration Statement No. 2-86237, Exhibit 4(b); Registration Statement No. 33-11723, Exhibit 4(b); Registration Statement No. 33-17003, Exhibit 4(a)(ii), Registration Statement No. 33-30964, Exhibit 4(b); Registration Statement No. 33-40720, Exhibit 4(b); Registration Statement No. 33-45219, Exhibit 4(b); Registration Statement No. 33-46128, Exhibits 4(b) and 4(c); Registration Statement No. 33-53410, Exhibit 4(b); Registration Statement No. 33-59834, Exhibit 4(b); Registration Statement No. 33-50229, Exhibits 4(b) and 4(c); Registration Statement No. 33-58431, Exhibits 4(b), 4(c), 4(d) and 4(e); Registration Statement No. 333-01049, Exhibits 4(b) and 4(c); Registration Statement No. 333-20305, Exhibits 4(b) and 4(c)]. *4(b) -- Copy of Indenture Supplemental, dated as of February 1, 1997, to Mortgage and Deed of Trust. 10(a)(1) -- Copy of Power Agreement, dated October 15, 1952, between OVEC and United States of America, acting by and through the United States Atomic Energy Commission, and, subsequent to January 18, 1975, the Administrator of the Energy Research and Development Administration, as amended [Registration Statement No. 2-60015, Exhibit 5(a); Registration Statement No. 2-63234, Exhibit 5(a)(1)(B); Registration Statement No. 2-66301, Exhibit 5(a)(1)(C); Registration Statement No. 2-67728, Exhibit 5(a)(1)(D); Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1989, File No. 1-3457, Exhibit 10(a)(1)(F); and Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1992, File No. 1-3457, Exhibit 10(a)(1)(B)]. 10(a)(2) -- Copy of Inter-Company Power Agreement, dated as of July 10, 1953, among OVEC and the Sponsoring Companies, as amended [Registration Statement No. 2-60015, Exhibit 5(c); Registration Statement No. 2-67728, Exhibit 5(a)(3)(B); and Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1992, File No. 1-3457, Exhibit 10(a)(2)(B)]. 10(a)(3) -- Copy of Power Agreement, dated July 10, 1953, between OVEC and Indiana-Kentucky Electric Corporation, as amended [Registration Statement No. 2-60015, Exhibit 5(e)]. 10(b) -- Copy of Interconnection Agreement, dated July 6, 1951, among APCo, CSPCo, KEPCo, OPCo and I&M and with the Service Corporation, as amended [Registration Statement No. 2-52910, Exhibit 5(a); Registration Statement No. 2-61009, Exhibit 5(b); Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1990, File No. 1-3525, Exhibit 10(a)(3)]. 10(c) -- Copy of Transmission Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KEPCo, OPCo and with the Service Corporation as agent, as amended [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(b); Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1988, File No. 1-3525, Exhibit 10(b)(2)]. 10(d) -- Copy of Modification No. 1 to the AEP System Interim Allowance Agreement, dated July 28, 1994, among APCo, CSPCo, I&M, KEPCo, OPCo and the Service Corporation [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(l)]. 10(e)(1) -- AEP Deferred Compensation Agreement for certain executive officers [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(e)]. 10(e)(2) -- Amendment to AEP Deferred Compensation Agreement for certain executive officers [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1986, File No. 1-3525, Exhibit 10(d)(2)]. 10(f)(1) -- AEP System Senior Officer Annual Incentive Compensation Plan [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(i)(1)]. 10(f)(2) -- American Electric Power System Performance Share Incentive Plan as Amended and Restated through February 26, 1997 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(i)(2)]. 10(g)(1) -- Excess Benefits Plan [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1995, File No. 1-3525, Exhibit 10(g)(1)(A)]. 10(g)(2) -- AEP System Supplemental Savings Plan (Non-Qualified) [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(g)(2)]. 10(g)(3) -- Umbrella Trust for Executives [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1993, File No. 1-3525, Exhibit 10(g)(3)]. 10(h)(1) -- Employment Agreement between E. Linn Draper, Jr. and AEP and the Service Corporation [Annual Report on Form 10-K of AEGCo for the fiscal year ended December 31, 1991, File No. 0-18135, Exhibit 10(g)(3)]. *12 -- Statement re: Computation of Ratios. *13 -- Copy of those portions of the APCo 1996 Annual Report (for the fiscal year ended December 31, 1996) which are incorporated by reference in this filing. 21 -- List of subsidiaries of APCo [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 21]. *23 -- Consent of Deloitte & Touche LLP. *24 -- Power of Attorney. *27 -- Financial Data Schedules. CSPCo 3(a) -- Copy of Amended Articles of Incorporation of CSPCo, as amended to March 6, 1992 [Registration Statement No. 33-53377, Exhibit 4(a)]. 3(b) -- Copy of Certificate of Amendment to Amended Articles of Incorporation of CSPCo, dated May 19, 1994 [Annual Report on Form 10-K of CSPCo for the fiscal year ended December 31, 1994, File No. 1-2680, Exhibit 3(b)]. 3(c) -- Composite copy of Amended Articles of Incorporation of CSPCo, as amended [Annual Report on Form 10-K of CSPCo for the fiscal year ended December 31, 1994, File No. 1-2680, Exhibit 3(c)]. 3(d) -- Copy of Code of Regulations and By-Laws of CSPCo [Annual Report on Form 10-K of CSPCo for the fiscal year ended December 31, 1987, File No. 1-2680, Exhibit 3(d)]. 4(a) -- Copy of Indenture of Mortgage and Deed of Trust, dated September 1, 1940, between CSPCo and City Bank Farmers Trust Company (now Citibank, N.A.), as trustee, as supplemented and amended [Registration Statement No. 2-59411, Exhibits 2(B) and 2(C); Registration Statement No. 2-80535, Exhibit 4(b); Registration Statement No. 2-87091, Exhibit 4(b); Registration Statement No. 2-93208, Exhibit 4(b); Registration Statement No. 2-97652, Exhibit 4(b); Registration Statement No. 33-7081, Exhibit 4(b); Registration Statement No. 33-12389, Exhibit 4(b); Registration Statement No. 33-19227, Exhibits 4(b), 4(e), 4(f), 4(g) and 4(h); Registration Statement No. 33-35651, Exhibit 4(b); Registration Statement No. 33-46859, Exhibits 4(b) and 4(c); Registration Statement No. 33-50316, Exhibits 4(b) and 4(c); Registration Statement No. 33-60336, Exhibits 4(b), 4(c) and 4(d); Registration Statement No. 33-50447, Exhibits 4(b) and 4(c); Annual Report on Form 10-K of CSPCo for the fiscal year ended December 31, 1993, File No. 1-2680, Exhibit 4(b)]. 10(a)(1) -- Copy of Power Agreement, dated October 15, 1952, between OVEC and United States of America, acting by and through the United States Atomic Energy Commission, and, subsequent to January 18, 1975, the Administrator of the Energy Research and Development Administration, as amended [Registration Statement No. 2-60015, Exhibit 5(a); Registration Statement No. 2-63234, Exhibit 5(a)(1)(B); Registration Statement No. 2-66301, Exhibit 5(a)(1)(C); Registration Statement No. 2-67728, Exhibit 5(a)(1)(B); Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1989, File No. 1-3457, Exhibit 10(a)(1)(F); and Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1992, File No. 1-3457, Exhibit 10(a)(1)(B)]. 10(a)(2) -- Copy of Inter-Company Power Agreement, dated July 10, 1953, among OVEC and the Sponsoring Companies, as amended [Registration Statement No. 2-60015, Exhibit 5(c); Registration Statement No. 2-67728, Exhibit 5(a)(3)(B); and Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1992, File No. 1-3457, Exhibit 10(a)(2)(B)]. 10(a)(3) -- Copy of Power Agreement, dated July 10, 1953, between OVEC and Indiana-Kentucky Electric Corporation, as amended [Registration Statement No. 2-60015, Exhibit 5(e)]. 10(b) -- Copy of Interconnection Agreement, dated July 6, 1951, among APCo, CSPCo, KEPCo, OPCo and I&M and the Service Corporation, as amended [Registration Statement No. 2-52910, Exhibit 5(a); Registration Statement No. 2-61009, Exhibit 5(b); and Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1990, File No. 1-3525, Exhibit 10(a)(3)]. 10(c) -- Copy of Transmission Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KEPCo, OPCo, and with the Service Corporation as agent, as amended [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(b); and Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1988, File No. 1-3525, Exhibit 10(b)(2)]. 10(d) -- Copy of Modification No. 1 to the AEP System Interim Allowance Agreement, dated July 28, 1994, among APCo, CSPCo, I&M, KEPCo, OPCo and the Service Corporation [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(l)]. *12 -- Statement re: Computation of Ratios. *13 -- Copy of those portions of the CSPCo 1996 Annual Report (for the fiscal year ended December 31, 1996) which are incorporated by reference in this filing. *23 -- Consent of Deloitte & Touche LLP. *24 -- Power of Attorney. *27 -- Financial Data Schedules. I&M 3(a) -- Copy of the Amended Articles of Acceptance of I&M and amendments thereto [Annual Report on Form 10-K of I&M for fiscal year ended December 31, 1993, File No. 1-3570, Exhibit 3(a)]. *3(b) -- Copy of Articles of Amendment to the Amended Articles of Acceptance of I&M, dated March 6, 1997. *3(c) -- Composite Copy of the Amended Articles of Acceptance of I&M (amended as of March 7, 1997). 3(d) -- Copy of the By-Laws of I&M (amended as of January 1, 1996) [Annual Report on Form 10-K of I&M for fiscal year ended December 31, 1995, File No. 1-3570, Exhibit 3(c)]. 4(a) -- Copy of Mortgage and Deed of Trust, dated as of June 1, 1939, between I&M and Irving Trust Company (now The Bank of New York) and various individuals, as Trustees, as amended and supplemented [Registration Statement No. 2-7597, Exhibit 7(a); Registration Statement No. 2-60665, Exhibits 2(c)(2), 2(c)(3), 2(c)(4), 2(c)(5), 2(c)(6), 2(c)(7), 2(c)(8), 2(c)(9), 2(c)(10), 2(c)(11), 2(c)(12), 2(c)(13), 2(c)(14), 2(c)(15), (2)(c)(16), and 2(c)(17); Registration Statement No. 2-63234, Exhibit 2(b)(18); Registration Statement No. 2-65389, Exhibit 2(a)(19); Registration Statement No. 2-67728, Exhibit 2(b)(20); Registration Statement No. 2-85016, Exhibit 4(b); Registration Statement No. 33-5728, Exhibit 4(c); Registration Statement No. 33-9280, Exhibit 4(b); Registration Statement No. 33-11230, Exhibit 4(b); Registration Statement No. 33-19620, Exhibits 4(a)(ii), 4(a)(iii), 4(a)(iv) and 4(a)(v); Registration Statement No. 33-46851, Exhibits 4(b)(i), 4(b)(ii) and 4(b)(iii); Registration Statement No. 33-54480, Exhibits 4(b)(i) and 4(b)(ii); Registration Statement No. 33-60886, Exhibit 4(b)(i); Registration Statement No. 33-50521, Exhibits 4(b)(i), 4(b)(ii) and 4(b)(iii); Annual Report on Form 10-K of I&M for fiscal year ended December 31, 1993, File No. 1-3570, Exhibit 4(b); Annual Report on Form 10-K of I&M for fiscal year ended December 31, 1994, File No. 1-3570, Exhibit 4(b)]. *4(b) -- Copy of Indenture Supplemental, dated as of February 1, 1997, to Mortgage and Deed of Trust. 10(a)(1) -- Copy of Power Agreement, dated October 15, 1952, between OVEC and United States of America, acting by and through the United States Atomic Energy Commission, and, subsequent to January 18, 1975, the Administrator of the Energy Research and Development Administration, as amended [Registration Statement No. 2-60015, Exhibit 5(a); Registration Statement No. 2-63234, Exhibit 5(a)(1)(B); Registration Statement No. 2-66301, Exhibit 5(a)(1)(C); Registration Statement No. 2-67728, Exhibit 5(a)(1)(D); Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1989, File No. 1-3457, Exhibit 10(a)(1)(F); and Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1992, File No. 1-3457, Exhibit 10(a)(1)(B)]. 10(a)(2) -- Copy of Inter-Company Power Agreement, dated as of July 10, 1953, among OVEC and the Sponsoring Companies, as amended [Registration Statement No. 2-60015, Exhibit 5(c); Registration Statement No. 2-67728, Exhibit 5(a)(3)(B); Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1992, File No. 1-3457, Exhibit 10(a)(2)(B)]. 10(a)(3) -- Copy of Power Agreement, dated July 10, 1953, between OVEC and Indiana-Kentucky Electric Corporation, as amended [Registration Statement No. 2-60015, Exhibit 5(e)]. 10(b) -- Copy of Interconnection Agreement, dated July 6, 1951, between APCo, CSPCo, KEPCo, I&M, and OPCo and with the Service Corporation, as amended [Registration Statement No. 2-52910, Exhibit 5(a); Registration Statement No. 2-61009, Exhibit 5(b); and Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1990, File No. 1-3525, Exhibit 10(a)(3)]. 10(c) -- Copy of Transmission Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KEPCo, OPCo and with the Service Corporation as agent, as amended [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(b); and Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1988, File No. 1-3525, Exhibit 10(b)(2)]. 10(d) -- Copy of Modification No. 1 to the AEP System Interim Allowance Agreement, dated July 28, 1994, among APCo, CSPCo, I&M, KEPCo, OPCo and the Service Corporation [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(l)]. 10(e) -- Copy of Nuclear Material Lease Agreement, dated as of December 1, 1990, between I&M and DCC Fuel Corporation [Annual Report on Form 10-K of I&M for the fiscal year ended December 31, 1993, File No. 1-3570, Exhibit 10(d)]. 10(f) -- Copy of Lease Agreements, dated as of December 1, 1989, between I&M and Wilmington Trust Company, as amended [Registration Statement No. 33-32753, Exhibits 28(a)(1)(C), 28(a)(2)(C), 28(a)(3)(C), 28(a)(4)(C), 28(a)(5)(C) and 28(a)(6)(C); Annual Report on Form 10-K of I&M for the fiscal year ended December 31, 1993, File No. 1-3570, Exhibits 10(e)(1)(B), 10(e)(2)(B), 10(e)(3)(B), 10(e)(4)(B), 10(e)(5)(B) and 10(e)(6)(B)]. *12 -- Statement re: Computation of Ratios *13 -- Copy of those portions of the I&M 1996 Annual Report (for the fiscal year ended December 31, 1996) which are incorporated by reference in this filing. 21 -- List of subsidiaries of I&M [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 21]. *23 -- Consent of Deloitte & Touche LLP. *24 -- Power of Attorney. *27 -- Financial Data Schedules. KEPCo 3(a) -- Copy of Restated Articles of Incorporation of KEPCo [Annual Report on Form 10-K of KEPCo for the fiscal year ended December 31, 1991, File No. 1-6858, Exhibit 3(a)]. 3(b) -- Copy of By-Laws of KEPCo (amended as of January 1, 1996) [Annual Report on Form 10-K of KEPCo for the fiscal year ended December 31, 1995, File No. 1-6858, Exhibit 3(b)]. 4(a) -- Copy of Mortgage and Deed of Trust, dated May 1, 1949, between KEPCo and Bankers Trust Company, as supplemented and amended [Registration Statement No. 2-65820, Exhibits 2(b)(1), 2(b)(2), 2(b)(3), 2(b)(4), 2(b)(5), and 2(b)(6); Registration Statement No. 33-39394, Exhibits 4(b) and 4(c); Registration Statement No. 33-53226, Exhibits 4(b) and 4(c); Registration Statement No. 33-61808, Exhibits 4(b) and 4(c), Registration Statement No. 33-53007, Exhibits 4(b), 4(c) and 4(d)]. 10(a) -- Copy of Interconnection Agreement, dated July 6, 1951, among APCo, CSPCo, KEPCo, I&M and OPCo and with the Service Corporation, as amended [Registration Statement No. 2-52910, Exhibit 5(a); Registration Statement No. 2-61009, Exhibit 5(b); and Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1990, File No. 1-3525, Exhibit 10(a)(3)]. 10(b) -- Copy of Transmission Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KEPCo, OPCo and with the Service Corporation as agent, as amended [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(b); and Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1988, File No. 1-3525, Exhibit 10(b)(2)]. 10(c) -- Copy of Modification No. 1 to the AEP System Interim Allowance Agreement, dated July 28, 1994, among APCo, CSPCo, I&M, KEPCo, OPCo and the Service Corporation [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(l)]. *12 -- Statement re: Computation of Ratios. *13 -- Copy those portions of the KEPCo 1996 Annual Report (for the fiscal year ended December 31, 1996) which are incorporated by reference in this filing. *23 -- Consent of Deloitte & Touche LLP. *24 -- Power of Attorney. *27 -- Financial Data Schedules. OPCo 3(a) -- Copy of Amended Articles of Incorporation of OPCo, and amendments thereto to December 31, 1993 [Registration Statement No. 33-50139, Exhibit 4(a); Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1993, File No. 1-6543, Exhibit 3(b)]. 3(b) -- Certificate of Amendment to Amended Articles of Incorporation of OPCo, dated May 3, 1994 [Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1994, File No. 1-6543, Exhibit 3(b)]. *3(c) -- Copy of Certificate of Amendment to Amended Articles of Incorporation of OPCo, dated March 6, 1997. *3(d) -- Composite copy of the Amended Articles of Incorporation of OPCo (amended as of March 7, 1997). 3(e) -- Copy of Code of Regulations of OPCo [Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1990, File No. 1-6543, Exhibit 3(d)]. 4(a) -- Copy of Mortgage and Deed of Trust, dated as of October 1, 1938, between OPCo and Manufacturers Hanover Trust Company (now Chemical Bank), as Trustee, as amended and supplemented [Registration Statement No. 2-3828, Exhibit B-4; Registration Statement No. 2-60721, Exhibits 2(c)(2), 2(c)(3), 2(c)(4), 2(c)(5), 2(c)(6), 2(c)(7), 2(c)(8), 2(c)(9), 2(c)(10), 2(c)(11), 2(c)(12), 2(c)(13), 2(c)(14), 2(c)(15), 2(c)(16), 2(c)(17), 2(c)(18), 2(c)(19), 2(c)(20), 2(c)(21), 2(c)(22), 2(c)(23), 2(c)(24), 2(c)(25), 2(c)(26), 2(c)(27), 2(c)(28), 2(c)(29), 2(c)(30), and 2(c)(31); Registration Statement No. 2-83591, Exhibit 4(b); Registration Statement No. 33-21208, Exhibits 4(a)(ii), 4(a)(iii) and 4(a)(vi); Registration Statement No. 33-31069, Exhibit 4(a)(ii); Registration Statement No. 33-44995, Exhibit 4(a)(ii); Registration Statement No. 33-59006, Exhibits 4(a)(ii), 4(a)(iii) and 4(a)(iv); Registration Statement No. 33-50373, Exhibits 4(a)(ii), 4(a)(iii) and 4(a)(iv); Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1993, File No. 1-6543, Exhibit 4(b)]. 10(a)(1) -- Copy of Power Agreement, dated October 15, 1952, between OVEC and United States of America, acting by and through the United States Atomic Energy Commission, and, subsequent to January 18, 1975, the Administrator of the Energy Research and Development Administration, as amended [Registration Statement No. 2-60015, Exhibit 5(a); Registration Statement No. 2-63234, Exhibit 5(a)(1)(B); Registration Statement No. 2-66301, Exhibit 5(a)(1)(C); Registration Statement No. 2-67728, Exhibit 5(a)(1)(D); Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1989, File No. 1-3457, Exhibit 10(a)(1)(F); Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1992, File No. 1-3457, Exhibit 10(a)(1)(B)]. 10(a)(2) -- Copy of Inter-Company Power Agreement, dated July 10, 1953, among OVEC and the Sponsoring Companies, as amended [Registration Statement No. 2-60015, Exhibit 5(c); Registration Statement No. 2-67728, Exhibit 5(a)(3)(B); Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1992, File No. 1-3457, Exhibit 10(a)(2)(B)]. 10(a)(3) -- Copy of Power Agreement, dated July 10, 1953, between OVEC and Indiana-Kentucky Electric Corporation, as amended [Registration Statement No. 2-60015, Exhibit 5(e)]. 10(b) -- Copy of Interconnection Agreement, dated July 6, 1951, between APCo, CSPCo, KEPCo, I&M and OPCo and with the Service Corporation, as amended [Registration Statement No. 2-52910, Exhibit 5(a); Registration Statement No. 2-61009, Exhibit 5(b); Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1990, File 1-3525, Exhibit 10(a)(3)]. 10(c) -- Copy of Transmission Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KEPCo, OPCo and with the Service Corporation as agent [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(b); Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1988, File No. 1-3525, Exhibit 10(b)(2)]. 10(d) -- Copy of Modification No. 1 to the AEP System Interim Allowance Agreement, dated July 28, 1994, among APCo, CSPCo, I&M, KEPCo, OPCo and the Service Corporation [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(l)]. 10(e) -- Copy of Amendment No. 1, dated October 1, 1973, to Station Agreement dated January 1, 1968, among OPCo, Buckeye and Cardinal Operating Company, and amendments thereto [Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1993, File No. 1-6543, Exhibit 10(f)]. 10(f)(1) -- AEP Deferred Compensation Agreement for certain executive officers [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(e)]. 10(f)(2) -- Amendment to AEP Deferred Compensation Agreement for certain executive officers [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1986, File No. 1-3525, Exhibit 10(d)(2)]. 10(g)(1) -- AEP System Senior Officer Annual Incentive Compensation Plan [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(i)(1)]. 10(g)(2) -- American Electric Power System Performance Share Incentive Plan, as Amended and Restated through February 26, 1997 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(i)(2)]. 10(h)(1) -- Excess Benefits Plan [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1995, File No. 1-3525, Exhibit 10(g)(1)(A)]. 10(h)(2) -- AEP System Supplemental Savings Plan (Non-Qualified) [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(g)(2)]. 10(h)(3) -- Umbrella Trust for Executives [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1993, File No. 1-3525, Exhibit 10(g)(3)]. 10(i)(1) -- Employment Agreement between E. Linn Draper, Jr. and AEP and the Service Corporation [Annual Report on Form 10-K of AEGCo for the fiscal year ended December 31, 1991, File No. 0-18135, Exhibit 10(g)(2)]. 10(j) -- Lease Agreement dated January 20, 1995 between OPCo and JMG Funding, Limited Partnership, and amendment thereto (confidential treatment requested) [Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1994, File No. 1-6543, Exhibit 10(l)(2)]. *12 -- Statement re: Computation of Ratios. *13 -- Copy of those portions of the OPCo 1996 Annual Report (for the fiscal year ended December 31, 1996) which are incorporated by reference in this filing. 21 -- List of subsidiaries of OPCo [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 21]. *23 -- Consent of Deloitte & Touche LLP. *24 -- Power of Attorney. *27 -- Financial Data Schedules. Certain instruments defining the rights of holders of long-term debt of the registrants included in the financial statements of registrants filed herewith have been omitted because the total amount of securities authorized thereunder does not exceed 10% of the total assets of registrants. The registrants hereby agree to furnish a copy of any such omitted instrument to the SEC upon request. EX-3.D 2 AEP AMENDED BYLAWS 10K EX3D Exhibit 3(d) As of 2/26/97 AMERICAN ELECTRIC POWER COMPANY, INC. (Formerly American Gas and Electric Company) BY-LAWS Section 1. The annual meeting of the stockholders of the Company shall be held on the fourth Wednesday of April in each year, at an hour and place within or without the State of New York designated by the Board of Directors, or if not so fixed, at twelve o'clock noon at the office of the Company in the City of New York. (As amended October 30, 1963.) Section 2. Special meetings of the stockholders of the Company may be held upon call of the Board of Directors or of the Executive Committee, or of stockholders holding one-fourth of the capital stock, at such time and at such place within or without the State of New York as may be stated in the call and notice. (As amended July 26, 1989.) Section 3. Notice of time and place of every meeting of stockholders shall be mailed at least ten days previous thereto to each stockholder of record who shall have furnished a written address to the Secretary of the Company for the purpose. Such further notice shall be given as may be required by law. But meetings may be held without notice if all stockholders are present, or if notice is waived by those not present. Section 4. Except as otherwise provided by law, the holders of a majority of the outstanding capital stock of the Company entitled to vote at any meeting of the stockholders of the Company must be present in person or by proxy at such meeting of the stockholders of the Company to constitute a quorum. If, however, such majority shall not be represented at any meeting of the stockholders of the Company regularly called, the holders of a majority of the shares present or represented and entitled to vote thereat shall have power to adjourn such meeting to another time without notice other than announcement of adjournment at the meeting, and there may be successive adjournments for like cause and in like manner until the requisite amount of shares entitled to vote at such meeting shall be represented. (As amended May 20, 1952.) Section 5. As soon as may be after their election in each year, the Board of Directors or the Executive Committee shall appoint three inspectors of stockholders' votes and elections to serve until the final adjournment of the next annual stockholders' meeting. If they fail to make such appointment, or if their appointees, or any of them, fail to appear at any meeting of stockholders, the Chairman of the meeting may appoint inspectors, or an inspector, to act at that meeting. Section 6. Meetings of the stockholders shall be presided over by the Chairman of the Board, or if he is not present, by the President, or, if neither the Chairman of the Board nor the President is present, by a Vice President, and in his absence, by a Chairman to be elected at the meeting. The Secretary of the Company shall act as Secretary of such meetings, if present. (As amended January 23, 1979.) Section 7. The Board of Directors shall consist of such number of directors, within the limits prescribed in the Certificate of Consolidation forming the Company, as amended, as shall be determined from time to time as herein provided. Directors shall be elected at each annual meeting of stockholders and each director so elected shall hold office until the next annual meeting of stockholders and until his successor is elected and qualified. The number of directors to be elected at any annual meeting of stockholders shall, except as otherwise provided herein, be the number fixed in the latest resolution of the Board of Directors adopted pursuant to the authority contained in the next succeeding sentence and not subsequently rescinded. The Board of Directors shall have power from time to time and at any time when the stockholders are not assembled as such in an annual or special meeting, by resolution adopted by a majority of the directors then in office, to fix, within the limits prescribed by the Certificate of Consolidation forming the Company, as amended, the number of directors of the Company. If the number of directors is increased, the additional directors may, to the extent permitted by law, be elected by a majority of the directors in office at the time of the increase, or, if not so elected prior to the next annual meeting of stockholders, such additional directors shall be elected at such annual meeting. If the number of directors is decreased, then to the extent that the decrease does not exceed the number of vacancies in the Board then existing, such resolution may provide that it shall become effective forthwith, and to the extent that the decrease exceeds such number of vacancies such resolution shall provide that it shall not become effective until the next election of directors by the stockholders. If the Board of Directors shall fail to adopt a resolution which fixes initially the number of directors, the number of directors shall be twelve (12). If, after the number of directors shall have been fixed by such resolution, such resolution shall cease to be in effect other than by being superseded by another such resolution, or it shall become necessary that the number of directors be fixed by these By-Laws, the number of directors shall be that number specified in the latest of such resolutions, whether or not such resolution continues in effect. (As amended May 1, 1959.) Section 8. Vacancies in the Board of Directors may be filled by the Board at any meeting. Section 9. Meetings of the Board of Directors shall be held at times fixed by resolution of the Board, or upon the call of the Executive Committee, the Chairman of the Board, or the President, and the Secretary or officer performing his duties shall give reasonable notice of all meetings of directors; provided, that a meeting may be held without notice immediately after the annual election at the same place, and notice need not be given of regular meetings held at times fixed by resolution of the Board. Meetings may be held at any time without notice if all the directors are present, or if those not present waive notice either before or after the meeting. The number of directors necessary to constitute a quorum for the transaction of business shall be any number, which may be less than a majority of the Board but not less than one-third of its number, duly assembled at a meeting of such directors. Any one or more members of the Board or of any committee thereof may participate in a meeting of the Board or such committee by means of a conference telephone or similar communications equipment allowing all persons participating in the meeting to hear each other at the same time. Participation by such means constitute presence in person at a meeting. (As amended February 26, 1997.) Section 10. The Board of Directors, by resolution adopted by a majority of the entire Board, may designate among its members an Executive Committee and one or more other committees, each consisting of three (3) or more directors, and each of which, to the extent provided in such resolution, shall have all the authority of the Board. However, no such committee shall have authority as to any of the following matters: (a) The submission to shareholders of any action as to which shareholders' authorization is required by law; (b) The filling of vacancies in the Board of Directors or in any committee; (c) The fixing of compensation of any director for serving on the Board or on any committee; (d) The amendment or repeal of these By-Laws or the adoption of new By-Laws; or (e) The amendment or repeal of any resolution of the Board which by its terms shall not be so amendable or repealable. The Board of Directors shall have the power at any time to increase or decrease the number of members of any committee (provided that no such decrease shall reduce the number of members to less than three), to fill vacancies on it, to remove any member of it, and to change its functions or terminate its existence. Each committee may make such rules for the conduct of its business as it may deem necessary. A majority of the members of a committee shall constitute a quorum. The Board of Directors shall also have the power to designate or appoint at any time and from time to time one or more individuals who have acquired as a former director or officer of the Company substantial experience with the Company's affairs as an Honorary Director, such individual or individuals to meet with the Board of Directors, or certain of the directors, at the invitation of the Chairman of the Board, from time to time for the purpose of rendering advice to the Board of Directors or such directors with respect to the Company's affairs for such compensation as shall be payable to directors of the Company who are not serving, at the time in question, as officers or employees of the Company or of American Electric Power Service Corporation; provided, however, that under no circumstances shall such individual or individuals be authorized or empowered to participate in the management or direction of the affairs of the Company or to perform the functions of a director or officer of the Company (as each such term is defined by the provisions of Rule 70 promulgated by the Securities and Exchange Commission under the provisions of Section 17(c) of the Public Utility Holding Company Act of 1935, as such definition shall be in effect at any time in question) or any similar function. (As amended April 26, 1978.) Section 11. The Board of Directors, as soon as may be after the election each year, shall appoint one of their number Chairman of the Board and one of their number President of the Company, and shall appoint one or more Vice Presidents, a Secretary and a Treasurer, and from time to time shall appoint such other officers as they deem proper. The same person may be appointed to more than one office. (As amended January 23, 1979.) Section 12. The term of office of all officers shall be one year, or until their respective successors are elected but any officer may be removed from office at any time by the Board of Directors, unless otherwise agreed by agreement in writing duly authorized by the Board of Directors; and no agreement for the employment of any officer for a longer period than one year shall be so authorized. Section 13. The officers of the Company shall have such powers and duties as generally pertain to their offices, respectively, as well as such powers and duties as from time to time shall be conferred by the Board of Directors or the Executive Committee. Section 14. The stock of the Company shall be transferable or assignable only on the books of the Company by the holders, in person or by attorney, on the surrender of the certificate therefor. The Board of Directors may appoint such Transfer Agents and Registrars of stock as to them may seem expedient. Section 15. To the fullest extent permitted by law, the Company shall indemnify any person made, or threatened to be made, a party to any action or proceeding (formal or informal), whether civil, criminal, administrative or investigative and whether by or in the right of the Company or otherwise, by reason of the fact that such person, such person's testator or intestate, is or was a director, officer or employee of the Company, or of any subsidiary or affiliate of the Company, or served any other corporation, partnership, joint venture, trust, employee benefit plan or other enterprise in any capacity at the request of the Company, against all loss and expense including, without limiting the generality of the foregoing, judgments, fines (including excise taxes), amounts paid in settlement and attorneys' fees and disbursements actually and necessarily incurred as a result of such action or proceeding, or any appeal therefrom, and all legal fees and expenses incurred in successfully asserting a claim for indemnification pursuant to this Section 15; provided, however, that no indemnification may be made to or on behalf of any director, officer or employee if a judgment or other final adjudication adverse to the director, officer or employee establishes that such person's acts were committed in bad faith or were the result of active and deliberate dishonesty and were material to the cause of action so adjudicated, or that such person personally gained in fact a financial profit or other advantage to which such person was not legally entitled. In any case in which a director, officer or employee of the Company (or a representative of the estate of such director, officer or employee) requests indemnification, upon such person's request the Board of Directors shall meet within sixty days thereof to determine whether such person is eligible for indemnification in accordance with the standard set forth above. Such a person claiming indemnification shall be entitled to indemnification upon a determination that no judgment or other final adjudication adverse to such person has established that such person's acts were committed in bad faith or were the result of active and deliberate dishonesty and were material to the cause of action so adjudicated, or that such person personally gained in fact a financial profit or other advantage to which such person was not legally entitled. Such determination shall be made: (a) by the Board of Directors acting by a quorum consisting of directors who are not parties to the action or proceeding in respect of which indemnification is sought; or (b) if such quorum is unobtainable or if directed by such quorum, then by either (i) the Board of Directors upon the opinion in writing of independent legal counsel that indemnification is proper in the circumstances because such person is eligible for indemnification in accordance with the standard set forth above, or (ii) by the stockholders upon a finding that such person is eligible for indemnification in accordance with the standard set forth above. Notwithstanding the foregoing, a determination of eligibility for indemnification may be made in any manner permitted by law. To the fullest extent permitted by law, the Company shall promptly advance to any person made, or threatened to be made, a party to any action or proceeding (formal or informal), whether civil, criminal, administrative or investigative and whether by or in the right of the Company or otherwise, by reason of the fact that such person, such person's testator or intestate, is or was a director, officer or employee of the Company, or of any subsidiary or affiliate of the Company, or served any other corporation or any partnership, joint venture, trust, employee benefit plan or other enterprise in any capacity at the request of the Company, expenses incurred in defending such actions or proceedings, upon request of such person and receipt of an undertaking by or on behalf of such director, officer or employee to repay amounts advanced to the extent that it is ultimately determined that such person was not eligible for indemnification in accordance with the standard set forth above. The foregoing provisions of this Section 15 shall be deemed to be a contract between the Company and each director, officer or employee of the Company, or its subsidiaries or affiliates, and any modification or repeal of this Section 15 or such provisions of the New York Business Corporation Law shall not diminish any rights or obligations existing prior to such modification or repeal with respect to any action or proceeding theretofore or thereafter brought; provided, however, that the right of indemnification provided in this Section 15 shall not be deemed exclusive of any other rights to which any director, officer or employee of the Company may now be or hereafter become entitled apart from this Section 15, under any applicable law including the New York Business Corporation Law. Irrespective of the provisions of this Section 15, the Board of Directors may, at any time or from time to time, approve indemnification of directors, officers, employees or agents to the full extent permitted by the New York Business Corporation Law at the time in effect, whether on account of past or future actions or transactions. Notwithstanding the foregoing, the Company shall enter into such additional contracts providing for indemnification and advancement of expenses with directors, officers or employees of the Company or its subsidiaries or affiliates as the Board of Directors shall authorize, provided that the terms of any such contract shall be consistent with the provisions of the New York Business Corporation Law. As used in this Section 15, the term "employee" shall include, without limitation, any employee, including any professionally licensed employee, of the Company. Such term shall also include, without limitation, any employee, including any professionally licensed employee, of a subsidiary or affiliate of the Company who is acting on behalf of the Company. The indemnification provided by this Section 15 shall be limited with respect to directors, officers and controlling persons to the extent provided in any undertaking entered into by the Company or its subsidiaries or affiliates, as required by the Securities and Exchange Commission pursuant to any rule or regulation of the Securities and Exchange Commission now or hereafter in effect. If any action with respect to indemnification of directors or officers is taken by way of amendment to these By-Laws, resolution of the Board of Directors, or by agreement, then the Company shall give such notice to the stockholders as is required by law. The Company may purchase and maintain insurance on behalf of any person described in this Section 15 against any liability which may be asserted against such person whether or not the Company would have the power to indemnify such person against such liability under the provisions of this Section 15 or otherwise. If any provision of this Section 15 shall be found to be invalid or limited in application by reason of any law, regulation or proceeding, it shall not affect any other provision or the validity of the remaining provisions hereof. The provisions of this Section 15 shall be applicable to claims, actions, suits or proceedings made, commenced or pending after the adoption hereof, whether arising from acts or omissions to act occurring before or after the adoption hereof. (As amended October 29, 1986.) Section 16. These By-Laws may be amended or added to at any meeting of the Board of Directors by affirmative vote of a majority of all of the directors, if notice of the proposed change has been delivered or mailed to the directors five days before the meeting, or if all the directors are present, or if all not present assent in writing to such change; provided, however, that the provisions of Section 7 relating to the number of directors constituting the Board of Directors may be amended only by the affirmative vote, in person or by proxy, of the holders of a majority of the outstanding shares of capital stock entitled to vote at any meeting of the stockholders of the Company; and provided further that the provisions of Section 7 other than those relating to the number of directors constituting the Board of Directors, and the provisions of this Section 16 may be amended or added to only by the affirmative vote, in person or by proxy, of the holders of two-thirds of the outstanding shares of capital stock entitled to vote at any meeting of the stockholders of the Company; and provided further, in the event of any such amendment or addition pursuant to vote by the stockholders of the Company, that such amendment or addition, or a summary thereof, shall have been set forth or referred to in the notice of such meeting. (As renumbered and amended October 29, 1986.) EX-10.F1 3 AEP DEFERRED COMP AND STOCK PLAN 10K EX10F1 Exhibit 10(f)(1) American Electric Power Company, Inc. Deferred Compensation and Stock Plan for Non-Employee Directors Article 1 Purpose The purposes of this American Electric Power Company, Inc. Deferred Compensation and Stock Plan For Non-Employee Directors (the "Plan") are to enable the Company to attract and retain qualified persons to serve as Non-Employee Directors, to provide Non-Employee Directors with an opportunity to defer some or all of their Retainer as a means of saving for retirement or other purposes, to solidify the common interests of its Non-Employee Directors and shareholders by enhancing the equity interest of Non-Employee Directors in the Company, and to encourage the highest level of Non-Employee Director performance by providing such Non-Employee Directors with a proprietary interest in the Company's performance and progress by permitting Non-Employee Directors to receive all or a portion of their Retainer in Common Stock and/or to defer all or a portion of their Retainer in Stock Units. Article 2 Effective Date The Plan is subject to the approval of a majority of the holders of the Company's Common Stock entitled to vote thereon at the Annual Meeting of Shareholders to be held on April 23, 1997, or such other date fixed for the next meeting of shareholders or any adjournment or postponement thereof. Subject to the receipt of such approval, the Plan shall be effective as of January 1, 1997. Article 3 Definitions Whenever used in the Plan, the following terms shall have the respective meanings set forth below: 3.1 "Account" means, with respect to each Participant, the Participant's separate individual account established and maintained for the exclusive purpose of accounting for the Participant's deferred Retainer which is accrued in terms of Stock Units. 3.2 "Beneficiary" means, with respect to each Participant, the recipient or recipients designated by the Participant who are, upon the Participant's death, entitled in accordance with the Plan's terms to receive the benefits to be paid with respect to the Participant. 3.3 "Board" means the Board of Directors of the Company. 3.4 "Committee" means the Human Resources Committee of the Board. 3.5 "Common Stock" means the common stock, $6.50 par value, of the Company. 3.6 "Company" means American Electric Power Company, Inc., a New York corporation, and any successor thereto. 3.7 "Director" means an individual who is a member of the Board. 3.8 "Market Value" means the closing price of the Common Stock, as published in The Wall Street Journal report of the New York Stock Exchange - Composite Transactions on the date in question or, if the Common Stock shall not have been traded on such date or if the New York Stock Exchange is closed on such date, then the first day prior thereto on which the Common Stock was so traded. 3.9 "Non-Employee Director" means any person who serves on the Board and who is not an officer of the Company or employee of its Subsidiaries. 3.10 "Participant" means any Non-Employee Director who has made an election to receive all or a portion of such person's Retainer in shares of Common Stock and/or to defer payment of all or a portion of such Retainer in Stock Units. 3.11 "Retainer" means the designated annual cash retainer, currently paid quarterly, for Non-Employee Directors established from time to time by the Board as annual compensation for services rendered, exclusive of compensation for service as a member of any committee designated by the Board or in connection with any meeting of the Board or special assignment, and exclusive of reimbursements for expenses incurred in performance of service as a Director. 3.12 "Stock Unit" means a measure of value, expressed as a share of Common Stock, credited to a Participant under this Plan. No certificates shall be issued with respect to such Stock Units, but the Company shall maintain a bookkeeping Account in the name of the Participant to which the Stock Units shall relate. 3.13 "Subsidiary" means any corporation in which the Company owns directly or indirectly through its Subsidiaries, at least 50 percent of the total combined voting power of all classes of stock, or any other entity (including, but not limited to, partnerships and joint ventures) in which the Company owns at least 50 percent of the combined equity thereof. 3.14 "Termination" means retirement from the Board or termination of service as a Director for any other reason. Article 4 Election to Receive Common Stock for Retainer and/or to Defer Retainer in Stock Units 4.1 Election On or before December 31 of any year, for calendar years subsequent to 1997, a Non-Employee Director may elect, by filing with the Company an election, (a) to receive all or a specified portion of the Director's Retainer in shares of Common Stock and/or (b) to defer receipt of all or a specified portion of the Director's Retainer in Stock Units until the Director's Termination or for a period that results in payment commencing not later than five years thereafter as elected by the Participant. The election to defer payment beyond the Participant's Termination must be made at least one year prior to such Termination. Notwithstanding the foregoing, a Non-Employee Director may choose to participate in the Plan beginning with the Retainer payable on June 30, 1997, by filing an election to so participate on or before March 31, 1997. A Non-Employee Director elected to fill a vacancy on the Company's Board and who was not a Director on the preceding December 31, or whose term of office did not begin until after that date, may file an election to receive Common Stock and/or to defer, for all or a specified portion of the Director's Retainer, commencing not less than three months after the date of the election. 4.2 Revocation of Election An effective election pursuant to Section 4.1 may not be revoked or modified (except as otherwise stated herein) with respect to the Retainer payable for a calendar year or portion of a calendar year for which such election is effective. An effective election may be terminated or modified for any subsequent calendar year by the filing of an election, on or before December 31 of the preceding calendar year for which such modification or termination is to be effective. 4.3 Common Stock Election When a Participant elects pursuant to Section 4.1 to receive all or a portion of the Participant's Retainer in shares of Common Stock, the number of whole shares to be distributed to the Participant, with any fractional shares to be paid in cash, as of the date the Retainer would otherwise have been payable to the Participant, shall be equal to the dollar amount of the Retainer which otherwise would have been payable to the Participant divided by the Market Value on such date. 4.4 Deferred Retainer Election When a Participant elects pursuant to Section 4.1 to defer all or a portion of the Participant's Retainer in Stock Units, the number of whole and fractional Stock Units, computed to three decimal places, to be credited to the Participant's Account, on the date the deferred Retainer would otherwise have been payable to the Participant, shall be equal to the dollar amount of the deferred Retainer which otherwise would have been payable to the Participant divided by the Market Value on such date. Article 5 Dividends and Adjustments 5.1 Reinvestment of Dividends On each dividend payment date with respect to the Common Stock, the Account of a Participant, with Stock Units held pursuant to Article 4, shall be credited with an additional number of whole and fractional Stock Units, computed to three decimal places, equal to the product of the dividend per share then payable, multiplied by the number of Stock Units then credited to such Account, divided by the Market Value on the dividend payment date. 5.2 Adjustments The number of Stock Units credited to a Participant's Account pursuant to Article 4 shall be appropriately adjusted for any change in the Common Stock by reason of any merger, reclassification, consolidation, recapitalization, stock dividend, stock split or any similar change affecting the Common Stock. Article 6 Payment of Stock Units 6.1 Manner of Payment Upon Termination In accordance with the Participant's election, filed with the Company, all Stock Units held in a Participant's Account shall be paid to the Participant either as (a) a lump sum distribution within 10 days after the Participant's deferred distribution date, or (b) up to 10 annual installments commencing within 10 days after the Participant's deferred distribution date. This election shall be made at the same time the Participant makes a deferral election as provided in Section 4.1. Payment may be made in cash, shares of Common Stock, or a combination of both as elected by the Participant. The election to be paid in cash or Common Stock must be filed with the Company at least 30 days prior to the payment date and, in the event an election is not made, payment will be made in cash. 6.2 Manner of Payment Upon Death Notwithstanding the Participant's election, if a Participant dies while Stock Units are held in the Participant's Account, such Stock Units will be paid in a lump sum in cash within 90 days from the date of the Participant's death to the Beneficiary or the Participant's estate, as the case may be. Upon application by the Beneficiary or the legal representative for the Participant's estate, the lump sum payment may be deferred beyond 90 days for good cause if the Committee consents to such deferral. 6.3 Determination Any cash payments of Stock Units shall be calculated on the basis of the average of the Market Value of the Common Stock for the last 20 trading days prior to the Participant's deferred distribution date, respective installment payment dates or the date of the Participant's death, as the case may be. Payment in Common Stock shall be at the rate of one share of Common Stock for each Stock Unit, with any fractional shares to be paid in cash. Article 7 Beneficiary Designation Each Participant shall be entitled to designate a Beneficiary or Beneficiaries (which may be an entity other than a natural person) who, following the Participant's death, will be entitled to receive any payments to be made under Section 6.2. At any time, and from time to time, any designation may be changed or cancelled by the Participant without the consent of any Beneficiary. Any designation, change, or cancellation must be by written notice filed with the Company and shall not be effective until received by the Company. Payment shall be made in accordance with the last unrevoked written designation of Beneficiary that has been signed by the Participant and delivered by the Participant to the Company prior to the Participant's death. If the Participant designates more than one Beneficiary, any payments under Section 6.2 to the Beneficiaries shall be made in equal shares unless the Participant has designated otherwise, in which case the payments shall be made in the proportions designated by the Participant. If no Beneficiary has been named by the Participant or if all Beneficiaries predecease the Participant, payment shall be made to the Participant's estate. Article 8 Transferability Restrictions The Plan shall not in any manner be liable for, or subject to, the debts and liabilities of any Participant or Beneficiary. No payee may assign any payment due such party under the Plan. No benefits at any time payable under the Plan shall be subject in any manner to anticipation, alienation, sale, transfer, assignment, pledge, attachment, garnishment, levy, execution, or other legal or equitable process, or encumbrance of any kind. Article 9 Funding Policy The Company's obligations under the Plan shall be totally unfunded so that the Company or any Subsidiary is under merely a contractual duty to make payments when due under the Plan. The promise to pay shall not be represented by notes and shall not be secured in any way. Article 10 Change in Control Notwithstanding any provision of this Plan to the contrary, if a "Change in Control" (as defined below) of the Company occurs, Stock Units held in a Participant's Account will be paid in a lump sum in cash, shares of Common Stock, or a combination of both, to the Participant, as elected by the Participant, not later than 15 days after the date of the Change in Control. For this purpose, the balance in the Account shall be determined by the higher of (a) the average of the Market Value of the Common Stock for the last 20 trading days prior to such Change in Control or (b) if the Change in Control of the Company occurs as a result of a tender or exchange offer or consummation of a corporate transaction, then the highest price paid per share of Common Stock pursuant thereto. Any consideration other than cash forming a part or all of the consideration for the Common Stock to be paid pursuant to the applicable transaction shall be valued at the valuation price thereon determined by the Board. In addition, the Company shall reimburse a Participant for the legal fees and expenses incurred if the Participant is required to seek to obtain or enforce any right to distribution. In the event that it is determined that such Participant is properly entitled to a cash distribution hereunder, such Participant shall also be entitled to interest thereon at the prime rate of interest as published in The Wall Street Journal plus two percent from the date such distribution should have been made to and including the date it is made. Notwithstanding any provisions of this Plan to the contrary, the provisions of this Article may not be amended by an amendment effected within three years following a Change in Control. A "Change in Control" of the Company shall be deemed to have occurred if (a) any "person" or "group" (as such terms are used in Sections 13(d) and 14(d) of the Securities Exchange Act of 1934, as amended ("Exchange Act")), other than a trustee or other fiduciary holding securities under an employee benefit plan of the Company, becomes the "beneficial owner" (as defined in Rule 13d-3 under the Exchange Act), directly or indirectly, of more than 25 percent of the then outstanding voting stock of the Company; (b) during any period of two consecutive years, individuals who at the beginning of such period constitute the Board, together with any new Directors whose election or nomination for election was approved by a vote of at least two-thirds of the Directors then still in office who were either Directors at the beginning of the period or whose election or nomination for election was previously so approved, cease for any reason to constitute at least a majority of the Board; or (c) the Company's shareholders approve a merger or consolidation of the Company with any other corporation, other than a merger or consolidation which would result in the voting securities of the Company outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity) at least 75 percent of the total voting power represented by the voting securities of the Company or such surviving entity outstanding immediately after such merger or consolidation; or (d) the shareholders of the Company approve a plan of complete liquidation of the Company, or an agreement for the sale or disposition by the Company (in one transaction or a series of transactions) of all or substantially all of the Company's assets. Notwithstanding the foregoing, a Change in Control shall not be deemed to occur as a result of any event described in (a) or (c) above, if Directors who were a majority of the members of the Board prior to such event and who continue to serve as Directors after such event determine that the event shall not constitute a Change in Control. Article 11 Administration The Plan shall be administered by the Committee. The Committee shall have authority to interpret the Plan, and to prescribe, amend and rescind rules and regulations relating to the administration of the Plan, and all such interpretations, rules and regulations shall be conclusive and binding on all Participants. The Committee may employ agents, attorneys, accountants, or other persons (who also may be employees of a Subsidiary) and allocate or delegate to them powers, rights, and duties, all as the Committee may consider necessary or advisable to properly carry out the administration of the Plan. Article 12 Amendment and Termination The Company, by resolution duly adopted by the Board, shall have the right, authority and power to alter, amend, modify, revoke, or terminate the Plan; except as provided in Article 10; and provided further, that no amendment or termination of the Plan shall adversely affect the rights of any Participant with respect to any Stock Units held in such Participant's Account, unless the Participant shall consent thereto in writing. Article 13 Miscellaneous 13.1 No Right to Continue as a Director Nothing in this Plan shall be construed as conferring upon a Participant any right to continue as a member of the Board. 13.2 No Interest as a Shareholder Stock Units do not give a Participant any rights whatsoever with respect to shares of Common Stock until such time and to such extent that payment of Stock Units is made in shares of Common Stock as requested by the Participant. 13.3 No Right to Corporate Assets Nothing in this Plan shall be construed as giving the Participant, the Participant's designated Beneficiaries or any other person any equity or interest of any kind in the assets of the Company or any Subsidiary or creating a trust of any kind or a fiduciary relationship of any kind between the Company or any Subsidiary and any person. As to any claim for payments due under the provisions of the Plan, a Participant, Beneficiary and any other persons having a claim for payments shall be unsecured creditors of the Company or any Subsidiary. 13.4 Payment to Legal Representative for Participant In the event the Committee shall find that a Participant is unable to care for his or her affairs because of illness or accident, the Committee may direct that any payment due the Participant be paid to the Participant's duly appointed legal representative, and any such payment so made shall be a complete discharge of the liabilities of the Plan. 13.5 No Limit on Further Corporate Action Nothing contained in the Plan shall be construed so as to prevent the Company or any Subsidiary from taking any corporate action which is deemed by the Company or any Subsidiary to be appropriate or in its best interest. 13.6 Governing Law The Plan shall be construed and administered according to the laws of the State of New York to the extent that those laws are not preempted by the laws of the United States of America. 13.7 Headings The headings of articles, sections, subsections, paragraphs or other parts of the Plan are for convenience of reference only and do not define, limit, construe, or otherwise affect its contents. EX-10.F2 4 AEP STOCK UNIT ACCUMULATION 10K EX10F2 Exhibit 10(f)(2) AMERICAN ELECTRIC POWER COMPANY, INC. STOCK UNIT ACCUMULATION PLAN FOR NON-EMPLOYEE DIRECTORS ARTICLE 1 PURPOSE The purposes of this American Electric Power Company, Inc. Stock Unit Accumulation Plan For Non-Employee Directors (the "Plan") are to enable the Company to attract and retain qualified persons to serve as Non-Employee Directors, to solidify the common interests of its Non-Employee Directors and shareholders by enhancing the equity interest of Non-Employee Directors in the Company, and to encourage the highest level of Non-Employee Director performance by providing such Non-Employee Directors with a proprietary interest in the Company's performance and progress by paying a portion of the compensation of the Non- Employee Directors in deferred Stock Units. ARTICLE 2 EFFECTIVE DATE The Plan shall be effective as of January 1, 1997. ARTICLE 3 DEFINITIONS Whenever used in the Plan, the following terms shall have the respective meanings set forth below: 3.1 "Account" means, with respect to each Participant, the Participant's separate individual account established and maintained for the exclusive purpose of accounting for the Participant's award of Stock Units. 3.2 "Beneficiary" means, with respect to each Participant, the recipient or recipients designated by the Participant who are, upon the Participant's death, entitled in accordance with the Plan's terms to receive the benefits to be paid with respect to the Participant. 3.3 "Board" means the Board of Directors of the Company. 3.4 "Committee" means the Human Resources Committee of the Board. 3.5 "Common Stock" means the common stock, $6.50 par value, of the Company. 3.6 "Company" means American Electric Power Company, Inc., a New York corporation, and any successor thereto. 3.7 "Director" means an individual who is a member of the Board. 3.8 "Market Value" means the closing price of the Common Stock, as published in The Wall Street Journal report of the New York Stock Exchange - Composite Transactions on the date in question or, if the Common Stock shall not have been traded on such date or if the New York Stock Exchange is closed on such date, then the first day prior thereto on which the Common Stock was so traded. 3.9 "Non-Employee Director" means any person who serves on the Board and who is not an officer of the Company or employee of its Subsidiaries. 3.10 "Participant" means any Non-Employee Director who has received an award of Stock Units. 3.11 "Retainer" means the designated annual cash retainer, currently paid quarterly, for Non-Employee Directors established from time to time by the Board as annual compensation for services rendered, exclusive of compensation for service as a member of any committee designated by the Board or in connection with any meeting of the Board or special assignment, and exclusive of reimbursements for expenses incurred in performance of service as a Director. 3.12 "Stock Unit" means a measure of value, expressed as a share of Common Stock, credited to a Participant under this Plan. No certificates shall be issued with respect to such Stock Units, but the Company shall maintain a bookkeeping Account in the name of the Participant to which the Stock Units shall relate. 3.13 "Subsidiary" means any corporation in which the Company owns directly or indirectly through its Subsidiaries, at least 50 percent of the total combined voting power of all classes of stock, or any other entity (including, but not limited to, partnerships and joint ventures) in which the Company owns at least 50 percent of the combined equity thereof. 3.14 "Termination" means retirement from the Board or termination of service as a Director for any other reason. ARTICLE 4 STOCK UNIT AWARDS 4.1 ANNUAL AWARDS Each Non-Employee Director's Account shall be credited with 300 Stock Units as of the first day of the month in which the Director becomes a member of the Board, and on the first day of such month for each year thereafter, up to a maximum of 3,000 Stock Units for each Participant. In the event of a change in the Retainer, the Committee may reconsider the amount of the annual awards and may recommend to the Board changes in the number of Stock Units to be awarded. 4.2 VESTING AND FORFEITURE If a Participant's Termination occurs prior to the completion of five years of service on the Board, the Participant shall forfeit an amount of Stock Units equal to the product of all Stock Units awarded pursuant to Section 4.1 and associated dividends credited pursuant to Section 5.1, held in the Participant's Account, multiplied by the difference of 60 minus the Participant's number of months of service (with service for a partial month counted as service for the entire month), divided by 60, computed to three decimal places. If a Participant's Termination occurs after five years of service, all such Stock Units shall be vested and nonforfeitable. 4.3 RETIREMENT PROGRAM TERMINATION AWARDS On and as of December 31, 1996, each Non-Employee Director serving as such on such date who makes or has made an irrevocable election by January 31, 1997 to waive participation in, and any and all benefits under, the Company's Retirement Plan For Directors, shall have credited to the Account of such Participant, as of January 1, 1997, the number of vested and nonforfeitable Stock Units as follows: R. M. Duncan 3,000; R. W. Fri 600; A. G. Hansen 3,000; L. A. Hudson, Jr. 3,000; A. E. Peyton 3,000; D. G. Smith 900; L. G. Stuntz 1,200; M. Tanenbaum 2,400; and A. H. Zwinger 3,000. Stock Units awarded pursuant to this Section 4.3 will be included for purposes of determining the application of the limitation on annual awards specified in Section 4.1. ARTICLE 5 DIVIDENDS AND ADJUSTMENTS 5.1 REINVESTMENT OF DIVIDENDS On each dividend payment date with respect to the Common Stock, the Account of a Participant, with Stock Units held pursuant to Article 4, shall be credited with an additional number of whole and fractional Stock Units, computed to three decimal places, equal to the product of the dividend per share then payable, multiplied by the number of Stock Units then credited to such Account, divided by the Market Value on the dividend payment date. 5.2 ADJUSTMENTS The number of Stock Units credited to a Participant's Account pursuant to Article 4 shall be appropriately adjusted for any change in the Common Stock by reason of any merger, reclassification, consolidation, recapitalization, stock dividend, stock split or any similar change affecting the Common Stock. ARTICLE 6 PAYMENT OF STOCK UNITS 6.1 MANNER OF PAYMENT UPON TERMINATION Stock Units held in a Participant's Account shall be paid to the Participant in a lump sum in cash within 10 days after the Participant's Termination unless the Participant has filed an election with the Company to defer such payment as provided in the following sentence. The Participant may elect (a) to defer the lump sum payment for one or more years up to a maximum of five years following Termination or (b) to receive payment of the Stock Units in up to 10 annual installments commencing within 10 days after Termination or the deferred payment date elected by the Participant pursuant to part (a) of this sentence. The election to defer payment beyond the Participant's Termination must be made at least one year prior to such Termination. 6.2 MANNER OF PAYMENT UPON DEATH Notwithstanding the Participant's election, if a Participant dies while Stock Units are held in the Participant's Account, such Stock Units, whether vested or unvested and forfeitable, will be paid in a lump sum in cash within 90 days from the date of the Participant's death to the Beneficiary or the Participant's estate, as the case may be. Upon application of the Beneficiary or the legal representative of the Participant's estate, the lump sum payment may be deferred beyond 90 days for good cause if the Committee consents to such deferral. 6.3 DETERMINATION Any cash payments of Stock Units shall be calculated on the basis of the average of the Market Value of the Common Stock for the last 20 trading days prior to the Participant's Termination, deferred distribution date, respective installment payment dates or the date of the Participant's death, as the case may be. ARTICLE 7 BENEFICIARY DESIGNATION Each Participant shall be entitled to designate a Beneficiary or Beneficiaries (which may be an entity other than a natural person) who, following the Participant's death, will be entitled to receive any payments to be made under Section 6.2. At any time, and from time to time, any designation may be changed or cancelled by the Participant without the consent of any Beneficiary. Any designation, change, or cancellation must be by written notice filed with the Company and shall not be effective until received by the Company. Payment shall be made in accordance with the last unrevoked written designation of Beneficiary that has been signed by the Participant and delivered by the Participant to the Company prior to the Participant's death. If the Participant designates more than one Beneficiary, any payments under Section 6.2 to the Beneficiaries shall be made in equal shares unless the Participant has designated otherwise, in which case the payments shall be made in the proportions designated by the Participant. If no Beneficiary has been named by the Participant or if all Beneficiaries predecease the Participant, payment shall be made to the Participant's estate. ARTICLE 8 TRANSFERABILITY RESTRICTIONS The Plan shall not in any manner be liable for, or subject to, the debts and liabilities of any Participant or Beneficiary. No payee may assign any payment due such party under the Plan. No benefits at any time payable under the Plan shall be subject in any manner to anticipation, alienation, sale, transfer, assignment, pledge, attachment, garnishment, levy, execution, or other legal or equitable process, or encumbrance of any kind. ARTICLE 9 FUNDING POLICY The Company's obligations under the Plan shall be totally unfunded so that the Company or any Subsidiary is under merely a contractual duty to make payments when due under the Plan. The promise to pay shall not be represented by notes and shall not be secured in any way. ARTICLE 10 CHANGE IN CONTROL Notwithstanding any provision of this Plan to the contrary, if a "Change in Control" (as defined below) of the Company occurs, Stock Units held in a Participant's Account, whether vested or unvested and forfeitable, will be paid in a lump sum in cash to the Participant not later than 15 days after the date of the Change in Control. For this purpose, the balance in the Account shall be determined by the higher of (a) the average of the Market Value of the Common Stock for the last 20 trading days prior to such Change in Control or (b) if the Change in Control of the Company occurs as a result of a tender or exchange offer or consummation of a corporate transaction, then the highest price paid per share of Common Stock pursuant thereto. Any consideration other than cash forming a part or all of the consideration for the Common Stock to be paid pursuant to the applicable transaction shall be valued at the valuation price thereon determined by the Board. In addition, the Company shall reimburse a Participant for the legal fees and expenses incurred if the Participant is required to seek to obtain or enforce any right to distribution. In the event that it is determined that such Participant is properly entitled to a cash distribution hereunder, such Participant shall also be entitled to interest thereon at the prime rate of interest as published in The Wall Street Journal plus two percent from the date such distribution should have been made to and including the date it is made. Notwithstanding any provisions of this Plan to the contrary, the provisions of this Article may not be amended by an amendment effected within three years following a Change in Control. A "Change in Control" of the Company shall be deemed to have occurred if (a) any "person" or "group" (as such terms are used in Sections 13(d) and 14(d) of the Securities Exchange Act of 1934, as amended ("Exchange Act")), other than a trustee or other fiduciary holding securities under an employee benefit plan of the Company, becomes the "beneficial owner" (as defined in Rule 13d-3 under the Exchange Act), directly or indirectly, of more than 25 percent of the then outstanding voting stock of the Company; (b) during any period of two consecutive years, individuals who at the beginning of such period constitute the Board, together with any new Directors whose election or nomination for election was approved by a vote of at least two- thirds of the Directors then still in office who were either Directors at the beginning of the period or whose election or nomination for election was previously so approved, cease for any reason to constitute at least a majority of the Board; or (c) the Company's shareholders approve a merger or consolidation of the Company with any other corporation, other than a merger or consolidation which would result in the voting securities of the Company outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity) at least 75 percent of the total voting power represented by the voting securities of the Company or such surviving entity outstanding immediately after such merger or consolidation; or (d) the shareholders of the Company approve a plan of complete liquidation of the Company, or an agreement for the sale or disposition by the Company (in one transaction or a series of transactions) of all or substantially all of the Company's assets. Notwithstanding the foregoing, a Change in Control shall not be deemed to occur as a result of any event described in (a) or (c) above, if Directors who were a majority of the members of the Board prior to such event and who continue to serve as Directors after such event determine that the event shall not constitute a Change in Control. ARTICLE 11 ADMINISTRATION The Plan shall be administered by the Committee. The Committee shall have authority to interpret the Plan, and to prescribe, amend and rescind rules and regulations relating to the administration of the Plan, and all such interpretations, rules and regulations shall be conclusive and binding on all Participants. The Committee may employ agents, attorneys, accountants, or other persons (who also may be employees of a Subsidiary) and allocate or delegate to them powers, rights, and duties, all as the Committee may consider necessary or advisable to properly carry out the administration of the Plan. ARTICLE 12 AMENDMENT AND TERMINATION The Company, by resolution duly adopted by the Board, shall have the right, authority and power to alter, amend, modify, revoke, or terminate the Plan; except as provided in Article 10; and provided further, that no amendment or termination of the Plan shall adversely affect the rights of any Participant with respect to any Stock Units held in such Participant's Account, unless the Participant shall consent thereto in writing. ARTICLE 13 MISCELLANEOUS 13.1 NO RIGHT TO CONTINUE AS A DIRECTOR Nothing in this Plan shall be construed as conferring upon a Participant any right to continue as a member of the Board. 13.2 NO INTEREST AS A SHAREHOLDER Stock Units do not give a Participant any rights whatsoever with respect to shares of Common Stock. 13.3 NO RIGHT TO CORPORATE ASSETS Nothing in this Plan shall be construed as giving the Participant, the Participant's designated Beneficiaries or any other person any equity or interest of any kind in the assets of the Company or any Subsidiary or creating a trust of any kind or a fiduciary relationship of any kind between the Company or any Subsidiary and any person. As to any claim for payments due under the provisions of the Plan, a Participant, Beneficiary and any other persons having a claim for payments shall be unsecured creditors of the Company or any Subsidiary. 13.4 PAYMENT TO LEGAL REPRESENTATIVE FOR PARTICIPANT In the event the Committee shall find that a Participant is unable to care for his or her affairs because of illness or accident, the Committee may direct that any payment due the Participant be paid to the Participant's duly appointed legal representative, and any such payment so made shall be a complete discharge of the liabilities of the Plan. 13.5 NO LIMIT ON FURTHER CORPORATE ACTION Nothing contained in the Plan shall be construed so as to prevent the Company or any Subsidiary from taking any corporate action which is deemed by the Company or any Subsidiary to be appropriate or in its best interest. 13.6 GOVERNING LAW The Plan shall be construed and administered according to the laws of the State of New York to the extent that those laws are not preempted by the laws of the United States of America. 13.7 HEADINGS The headings of articles, sections, subsections, paragraphs or other parts of the Plan are for convenience of reference only and do not define, limit, construe, or otherwise affect its contents. EX-10.G2 5 AEP SYSTEM SUPPLEMENTAL SAVINGS PLAN 10K EX10G2 Exhibit 10(g)(2) AMERICAN ELECTRIC POWER SYSTEM SUPPLEMENTAL SAVINGS PLAN (NON-QUALIFIED) Amended as of November 15, 1995 The American Electric Power Service Corporation (AEPS) hereby establishes effective as of the 1st day of January, 1994, the American Electric Power System Supplemental Savings Plan (Plan). The purpose of this Plan is to provide to eligible management employees a tax-deferred savings opportunity otherwise not available under the American Electric Power System Employees Savings Plan because of restrictions imposed by the Internal Revenue Code. ARTICLE 1 DEFINITIONS 1.1 "Applicable Federal Rate" means 120% of the applicable Federal long-term rate, with monthly compounding (as prescribed under Section 1274(d) of the Code), published for the December immediately prior to the Plan Year. 1.2 "Book Reserve Account" means the separate account established and maintained by AEPS to record Participant and AEPS Supplemental Contributions for each Participant and to record interest credited to the balances in each such account. 1.3 "Code" means the Internal Revenue Code of 1986, as amended from time to time. 1.4 "Committee" means the Employee Benefit Trusts Committee established pursuant to a resolution adopted by the AEPS Board of Directors as in effect from time to time. 1.5 "Compensation" means the remuneration paid to a Participant by AEPS and determined prior to any deferrals under this Plan or the Savings Plan or under the American Electric Power System Medical and Dental Plans, but excluding any bonuses, pay for overtime, award amounts and other discretionary remuneration paid to the Participant by AEPS and excluding AEPS' cost for any public or private employee benefit plan (including this Plan) under rules uniformly applicable to all employees similarly situated. 1.6 "ERISA" means the Employee Retirement Income Security Act of 1974, as amended from time to time. 1.7 "Participant" means an individual who is an employee of AEPS, and is covered under the American Electric Power System Excess Benefits Plan and who is confirmed by the Committee as eligible to participate in the Plan and to receive book entry credits associated with Supplemental Contributions. 1.8 "Plan Year" means (i) January 1, 1994 through December 31, 1994 and (ii) each and every calendar year thereafter. 1.9 "Salary Reduction Agreement" means an agreement between AEPS and the Participant in which the Participant elects to reduce his Compensation for the Plan Year and AEPS agrees to treat the amount of the reduction as Participant contributions to this Plan. 1.10 "Savings Plan" means the American Electric Power System Employees Savings Plan, as in effect from time to time. 1.11 "Supplemental Contributions" mean Participant or AEPS Contributions credited to a Participant's Book Reserve Account pursuant to Sections 3.1 and 3.2 of this Plan. ARTICLE 2 TERM This Plan shall commence as of January 1, 1994, and shall be effective until terminated by the AEPS Board of Directors as herein provided. ARTICLE 3 BOOK RESERVE FOR ACCRUED SUPPLEMENTAL CONTRIBUTIONS 3.1 PARTICIPANT SUPPLEMENTAL CONTRIBUTIONS. For any Plan Year in which a Participant's contributions to the Savings Plan will be restricted due to the contribution or account balance limits imposed by the Code, the Participant may make Participant Supplemental Contributions to the Plan. Participant Supplemental Contributions shall not exceed the difference between (a) the Participant's Compensation for the Plan Year times the maximum Savings Plan Contribution percentage for highly-compensated employees for the prior Plan Year and (b) the aggregate amount of the Participant's pre-tax and after-tax contributions to the Savings Plan for the Plan Year. The Participant's election to make Participant Supplemental Contributions pursuant to a Salary Reduction Agreement shall be made as provided in Section 4.1 of this Plan. 3.2 EMPLOYER SUPPLEMENTAL CONTRIBUTIONS. For each Participant electing to make (a) Participant Supplemental Contributions or (b) Savings Plan contributions, AEPS shall, at the time the Participant Supplemental Contributions are credited to the Participant's Book Reserve Account or at the time contributions are credited to the Participant's Savings Plan account, credit the Participant's Book Reserve Account with Employer Supplemental Contributions. Employer Supplemental Contributions, in combination with contributions made by AEPS to the Savings Plan, shall, in the aggregate, be equal to the lesser of (a) fifty percent of the Participant's contributions to the Savings Plan and this Plan, or (b) three percent of the Participant's Compensation. If the aggregate contributions made by AEPS exceed three percent of the Participant's Compensation, Employer Supplemental Contributions credited to the Participant's Book Reserve Account shall be reduced until the aggregate AEPS contributions made under both plans do not exceed three percent of the Participant's Compensation. 3.3 Interest Accruals. The Book Reserve Account balances, comprising prior interest credits and all Participant or Employer Supplemental Contributions credited to a Participant's Book Reserve Account, shall be credited with interest. All interest credits pursuant to this Section shall be based on the Book Reserve Account balance as of the beginning of the month and computed at an annual rate equal to the Applicable Federal Rate in effect in December of the prior Plan Year. The Committee reserves the right to change the rate, method and frequency of interest credit to the Participants' Book Reserve Accounts. 3.4 AEPS' LIABILITY FOR THE BOOK RESERVE ACCOUNTS. The amounts credited to the Book Reserve Accounts shall represent entries made on AEPS' books solely for record keeping purposes under the Plan. All amounts so credited shall at all times constitute general, unsecured liabilities of AEPS payable exclusively out of its general assets, and in no event and under no circumstance shall AEPS be obligated or required to segregate from its general assets (whether by trust or otherwise) funds sufficient to pay any of the amounts from time to time credited to the Book Reserve Accounts. 3.5 RIGHTS OF PARTICIPANTS IN THE BOOK RESERVE ACCOUNTS. Nothing contained in the Plan shall be deemed to confer upon any Participant any right, title or vested interest in and to his Book Reserve Accounts or the amounts from time to time credited thereto. Each Participant agrees as a condition of participation hereunder that (1) AEPS shall only have a contractual obligation to accrue Participant Supplemental Contributions, Employer Supplemental Contributions and interest and to distribute the Book Reserve Account as provided herein, and the rights of the Participant under the Plan are no greater than the rights of any unsecured creditor of AEPS, (2) to the extent that any person other than a Participant acquires a right to receive distributions from AEPS under the Plan, such right is not greater than the rights of any general unsecured creditor of AEPS, (3) nothing contained in the Plan shall create or be construed to create a trust of any kind or a fiduciary relationship between AEPS and the Participant, (4) the rights of the Participant may not be sold, assigned, transferred, pledged, or encumbered, nor shall any interest of the Participant be liable for the claim of any creditor of the Participant or subject to any judicial process involving the Participant, and (5) no Participant shall have any rights in any specific assets of AEPS, and any Book Reserve Account established under the Plan only reflects a contractual obligation of AEPS on its books of accounting and does not constitute a segregated fund of assets or separation of assets. ARTICLE 4 TIME AND METHOD OF ELECTION AND DISTRIBUTION 4.1 TIME AND METHOD OF PARTICIPANT CONTRIBUTION ELECTION. In order for an election to make Participant Supplemental Contributions to be effective under Section 3.1 for any given Plan Year, the Participant must deliver a signed Salary Reduction Agreement to the Committee no later than December 31 of the year preceding the Plan Year as to which the election is to take effect. Upon receipt of the written signed Salary Reduction Agreement by the Committee, the election shall remain in force as to the Plan Year for which it is delivered and for each subsequent Plan Year until it is revoked by a new Salary Reduction Agreement. Notwithstanding any other provision of the Plan to the contrary, no election shall be effective to defer under the Plan any Compensation which is earned by the Participant on or before the date upon which the signed Salary Reduction Agreement is delivered to the Committee. The Salary Reduction Agreement and any revocation thereof shall contain such information as may be reasonably required by the Committee, shall be executed at the time and in the manner prescribed, and shall be delivered to the Committee, attention of the Chairman. 4.2 TIME OF DISTRIBUTION. Following a Participant's termination of service with AEPS or one of its affiliates or subsidiaries for any reason other than death, all amounts which are credited to the Participant's Book Reserve account shall be distributed to the Participant in the form of (1) a single lump- sum payment payable as soon as practicable or, alternatively, at the end of a post-termination deferral period of up to five years, or (2) in approximately equal annual or semi-annual installment payments over not less than two or more than ten years as elected by the Participant. The Participant's distribution election shall be made when the Participant first elects to participate in the Plan. The Participant may amend or revoke the distribution election at any time prior to termination of service, but any such amendment or revocation must be made at least twelve months prior to the initial distribution. The distribution of a lump-sum payment, if the Participant does not elect to defer the payment of the lump-sum amount, or the first installment payment shall be made within 120 days after the Participant's termination of service. If the Participant elected to defer the payment of the lump-sum payment, the distribution shall be made within 120 days after the end of the deferral period. For purposes of this Section 4.2, Participant employment transfers between AEPS and its affiliates and subsidiaries shall not be treated as a termination of service with AEPS. If the Participant elects deferral of the lump-sum payment or elects installment payments, interest shall continue to accrue on the remaining Book Reserve Account in accordance with Section 3.3 of this Plan. Upon a Participant's death prior to termination of service, all amounts which are credited to the Participant's Book Reserve Account shall be distributed to (a) the Participant's estate in a single lump-sum if the Participant did not name a beneficiary or if the named beneficiary predeceases the Participant, or (b) to the Participant's named beneficiary. Distributions to the beneficiary shall be in the form of (1) a single lump-sum payment or (2) in approximately equal annual or semi-annual installment payments over not less than two or more than ten years as elected by the beneficiary. The beneficiary's distribution election must be made within 90 days after the Participant's date of death. If an election is not made, the beneficiary shall receive a lump-sum payment. The distribution of a lump-sum payment to the Participant's estate shall be made within 120 days after the Participant's date of death. The distribution of a lump-sum payment or the first installment payment to a beneficiary shall be made within 90 days after the beneficiary makes the distribution election. If the beneficiary elects installment payments, interest shall continue to accrue on the remaining balance in the Book Reserve Account in accordance with Section 3.3 of this Plan. In the event a beneficiary receiving installment payments shall die prior to a complete distribution of the Participant's Book Reserve Account, the remaining balance in the Participant's Book Reserve Account shall be paid to the beneficiary's estate within 120 days after the Committee is notified of the beneficiary's death. 4.3 DESIGNATION OF BENEFICIARY. Each Participant shall have the right to designate a beneficiary or beneficiaries who shall receive the balance of the Participant's Book Reserve Account if the Participant dies before the complete distribution of the Participant's Book Reserve Account. Any designation, or change or rescission thereof, shall be made in writing by completing and furnishing to the Committee the appropriate beneficiary form prescribed by the Committee. The last designation of beneficiary received by the Committee prior to the death of the Participant shall control. 4.4 SOCIAL SECURITY AND INCOME TAX WITHHOLDING. Each Participant agrees that as a condition of participation in the Plan, AEPS may withhold federal, state and local income taxes and social security taxes from any distribution hereunder to the extent that such taxes are then payable. 4.5 FACILITY OF PAYMENT. In the event that the Committee shall find that a Participant is unable to care for his affairs because of illness or accident, the Committee may direct that any benefit payment due him be paid to his duly appointed legal representative, and any such payment so made shall be a complete discharge of the liabilities of the Plan therefore. ARTICLE 5 TAX TREATMENT The adoption and maintenance of the Plan is conditioned upon (1) the applicability of Section 451(a) of the Code to the Participants' recognition of gross income as a result of participation herein, (2) the fact that the Participants will not recognize gross income as a result of participation in the Plan unless and until and then only to the extent that distributions are received, (3) the applicability of Section 404(a)(5) of the Code to the deductibility of the amounts distributed to the Participants hereunder, (4) the fact that AEPS will not receive a deduction for amounts credited to any Book Reserve unless and until and then only to the extent that amounts are actually distributed and (5) the inapplicability of the provisions of Titles 2, 3, and 4 of ERISA. If the Internal Revenue Service, the Department of Labor or any court of competent jurisdiction determines or finds as a fact or legal conclusion that any of the above conditions is untrue and issues an assessment, determination, opinion or report to such effect, or if in the opinion of counsel to AEPS any one of the above assumptions is incorrect, then AEPS shall have the option to terminate this Plan as provided in Section 7.2 below. ARTICLE 6 ADMINISTRATION OF THE PLAN 6.1 RESPONSIBILITY OF COMMITTEE. The Committee shall (i) administer and interpret the terms and conditions of the Plan, (ii) establish reasonable procedures with which Participants must comply to exercise any right established hereunder, and (iii) be permitted to delegate its responsibilities or duties hereunder to any person or entity. The rights and duties of the Participants and all other persons and entities claiming an interest under the Plan are subject to, and governed by, such acts of administration, interpretation, procedure and delegation. 6.2 BOOK RESERVE ACCOUNT. AEPS shall maintain, or cause to be maintained, records showing the individual credit balances of each Participant's Book Reserve Account. Each Participant shall be furnished with semi-annual statements setting forth the value of the total credits to his Book Reserve Account. 6.3 PRESENTATION OF CLAIMS. A Participant, or any other person or entity claiming under a Participant, may present a written request to the Committee for distribution of any amounts due or alleged to be due from the Participant's Book Reserve. Within 30 days following receipt of the request, the Committee shall advise the Participant or other person or entity in writing as to the amount and method of distribution if any. 6.4 APPEAL OF DENIED CLAIMS. If the Committee shall deny a claim for distribution under the Plan, the Committee shall set forth in writing in a manner calculated to be understood by the Participant or other person or entity (1) the specific reason or reasons for the denial, (2) specific reference to the pertinent provisions of the Plan upon which the denial is based, (3) a description of any additional material or information necessary for the claimant to perfect the claim and an explanation of why such material or information is necessary, and (4) an explanation of the Committee's review procedure. The Committee shall afford the Participant or the person or entity a reasonable opportunity for a full and fair review by the Committee of its decision to deny the claim if the claimant requests such a review within 30 days after receipt of the written denial. ARTICLE 7 MISCELLANEOUS 7.1 EFFECT OF PLAN. The establishment and continuance of the Plan by AEPS shall not constitute a contract of employment between any Participant and AEPS, and shall not be deemed to be consideration for, inducement to or a condition of employment of any Participant. The making of Salary Cap Contributions pursuant to the provisions of the Plan shall not be construed to give any Participant the right to be retained in the employ of AEPS or to interfere with the right of AEPS to terminate such employment at any time. 7.2 AMENDMENT AND TERMINATION. AEPS intends to continue the Plan indefinitely but reserves the right to modify the Plan from time to time, or to terminate the Plan entirely or to direct the permanent discontinuance or temporary suspension of Supplemental Contributions under the Plan; provided that no such modification, termination, discontinuance or suspension shall interrupt the interest accruals under Section 3.3 or shall affect or otherwise deprive the Participants of any distributions to which they may be entitled under the Plan. 7.3 PROHIBITION AGAINST ASSIGNMENT. The right of any Participant (or any designated beneficiary) to receive any payment or installment under the Plan shall not be subject in any manner to attachment or other legal process or proceedings for discharge of the debts of the Participant or beneficiary, and any such payment or installment shall not be subject to anticipation, alienation, sale, transfer, assignment, pledge, mortgage or encumbrance. 7.4 GOVERNING LAW. Except to the extent preempted or superseded by the federal laws of the United States of America, the laws of the state of Ohio will govern the Plan. 7.5 NOTICES. All notices, reports, statements, distributions or payments given, made, delivered, or transmitted to a Participant or his designated beneficiary shall be deemed to be duly given, made, delivered or transmitted when mailed, by first class mail, postage prepaid, addressed to the Participant or beneficiary at the address appearing on the books of AEPS. Written directions, notices and other communications to AEPS or the Committee shall be deemed to be duly given, made or delivered when received by the Committee at such location as it may from time to time specify. 7.6 GENDER AND NUMBER. Whenever appropriate in the Plan, the masculine gender shall be construed to include the feminine and neuter gender, and the feminine gender shall be construed to include the masculine and neuter gender. Words used in the singular shall be construed to include the plural, and the plural to include the singular. 7.7 HEADINGS. The headings of the Articles and Sections of the Plan are intended solely for convenience of reference, and if there is any conflict between the headings and the text of the Plan, the text shall control. EX-10.I1 6 AEP SENIOR OFFICER INCENTIVE COMP PLAN 10K EX10I1 Exhibit 10(i)(1) AMERICAN ELECTRIC POWER SYSTEM SENIOR OFFICER ANNUAL INCENTIVE COMPENSATION PLAN ARTICLE 1 ESTABLISHMENT, PURPOSE AND EFFECTIVE DATE 1.1 The Company hereby establishes the "American Electric Power System Senior Officer Annual Incentive Compensation Plan" (the "Plan"). 1.2 The purposes of the Plan are to improve corporate performance and enhance shareholder value by providing senior officers incentives to earn annual incentive compensation through the achievement of performance goals and to assist the Company in retaining and recruiting key employees. 1.3 The Plan is effective as of January 1, 1997. ARTICLE 2 DEFINITIONS 2.1 "Account" means, with respect to each Participant, the Participant's separate individual account established and maintained for the exclusive purpose of accounting for the incentive compensation deferred by the Participant in the form of Stock Units pursuant to Section 3.3 of the Plan. 2.2 "Board" means the Board of Directors of the Company. 2.3 "Committee" means the Human Resources Committee of the Board. 2.4 "Common Stock" means the common stock, $6.50 par value, of the Company. 2.5 "Company" means American Electric Power Company, Inc., a New York corporation, and any successor thereto. 2.6 "Incentive Award" means the amount of incentive compensation, as determined by the Committee, payable to a Participant upon the attainment of the Performance Goals for the Plan Year. 2.7 "Market Value" means the closing price of the Common Stock, as published in The Wall Street Journal report of the New York Stock Exchange - Composite Transactions on the date in question or, if the Common Stock shall not have been traded on such date or if the New York Stock Exchange is closed on such date, then the first day prior thereto on which the Common Stock was so traded. 2.8 "Participant" means persons holding the positions of Chairman of the Board, President, Chief Executive Officer and Executive Vice President of American Electric Power Service Corporation, a Subsidiary of the Company, and any other senior officer of the Company or its Subsidiaries selected by the Committee. 2.9 "Performance Goals" means performance goals as shall be established in writing by the Committee which may be based on, but are not limited to, earnings, stock price, return on equity, return on investment, total return to shareholders, economic value added, debt rating and/or achievement of business or operational goals, such as safety, customer satisfaction, market share and/ or business development. Such goals may be absolute in their terms or measured against or in relationship to other companies. 2.10 "Plan Year" means the Company's fiscal year commencing January 1 and ending December 31. 2.11 "Stock Unit" means a measure of value, expressed as a share of Common Stock. No certificates shall be issued with respect to such Stock Units, but the Company shall maintain a bookkeeping Account in the name of the Participant to which the Stock Units shall relate. 2.12 "Subsidiary" means any corporation in which the Company owns directly or indirectly through it Subsidiaries, at least 50 percent of the total combined voting power of all classes of stock, or any other entity (including, but not limited to, partnerships and joint ventures) in which the Company owns at least 50 percent of the combined equity thereof. ARTICLE 3 AWARD DETERMINATION AND PAYMENT 3.1 Within 90 days after the commencement of each Plan Year, the Committee shall establish Performance Goals for such Plan Year. 3.2 The Incentive Award payable to a Participant shall be determined by the Committee as soon as practicable after the determination of the achieved Performance Goals. A Participant's Incentive Award may range from zero to 60 percent of the Participant's base salary or compensation in effect at the beginning of the Plan Year depending upon the level of the Performance Goal achievement. An increase in a Participant's base salary or compensation during the Plan Year will not be considered when calculating the Participant's Incentive Award. The Committee may, in its sole discretion, reduce or eliminate for any reason the Incentive Award that would otherwise be payable to a Participant. 3.3 Incentive Award payments shall be made in cash as soon as practicable after the end of the Plan Year. However, a Participant may elect to defer payment of all or part of the Incentive Award for one or more years with a maximum deferral period that results in payment commencing no later than five years after the Participant's termination of employment. The deferral election must be filed with the Company on or before December 31 of the preceding Plan Year and may be effective for the immediately following Plan Year or all subsequent Plan Years. A deferral election may be terminated or modified for any subsequent Plan Year by the filing of a new deferral election on or before December 31 of the preceding Plan Year. 3.4 If a Participant elects to defer all or a portion of the Participant's Incentive Award, Stock Units shall be credited to the Participant's Account effective January 1 immediately following the completion of the Plan Year. The number of whole and fractional Stock Units, computed to three decimal places, to be credited to the Participant's Account shall be equal to the dollar amount of the Incentive Award which otherwise would have been payable to the Participant divided by the average of the Market Value for the last 20 trading days of the associated Plan Year. On each dividend payment date with respect to the Common Stock, the Account of a Participant shall be credited with an additional number of whole and fractional Stock Units equal to the product of the dividend per share then payable, multiplied by the number of Stock Units then credited to such Account, divided by the Market Value on the dividend payment date. The number of a Participant's Stock Units shall be appropriately adjusted for any change in the Common Stock by reason of any merger, reclassification, consolidation, recapitalization, stock dividend, stock split or any similar change affecting the Common Stock. 3.5 If a Participant's participation in the Plan terminates during a Plan Year due to the Participant's death, total disability, retirement or other reasons or causes as approved by the Committee, the Participant's Incentive Award for the Plan Year shall be pro-rated based upon the Participant's period of employment with the Subsidiaries. Such Incentive Award shall be paid to the Participant or the Participant's beneficiary when the Incentive Awards for such Plan Year are paid to the other Participants. ARTICLE 4 PAYMENT OF DEFERRED INCENTIVE AWARDS 4.1 In accordance with the Participant's election, filed with the Company, all Stock Units held in a Participant's Account shall be paid to the Participant either as (a) a lump sum cash distribution within 10 days after the Participant's deferred distribution date, or (b) up to 10 annual installments commencing within 10 days after the Participant's deferred distribution date. This election shall be made at the same time the Participant makes a deferral election as provided in Section 3.3. The amount attributable to the Stock Units shall be calculated on the basis of the average of the Market Value of the Common Stock for the last 20 trading days prior to the Participant's deferred distribution date or respective installment payment dates, as the case may be. 4.2 If a Participant dies while Stock Units are held in the Participant's Account, such Stock Units will be paid in a lump sum in cash within 90 days from the date of the Participant's death to the Participant's designated beneficiary or the Participant's estate, as the case may be. The amount of the lump sum cash distribution attributable to the Stock Units shall be calculated on the basis of the average of the Market Value of the Common Stock for the last 20 trading days prior to the Participant's death. Upon application by the beneficiary or the legal representative for the Participant's estate, the lump sum payment may be deferred beyond 90 days for good cause if the Committee consents to such deferral. 4.3 Each Participant shall have the right to designate a beneficiary or beneficiaries who shall receive the balance of the Participant's Account if the Participant dies before the complete distribution of the Account. Any designation, or change or rescission thereof, shall be made in writing by completing and furnishing to the Committee the appropriate beneficiary form prescribed by the Committee. The last designation of beneficiary received by the Committee prior to the death of the Participant shall control. ARTICLE 5 ADMINISTRATION 5.1 The Plan shall be administered by the Committee. The Committee shall have the authority to interpret the Plan and to prescribe, amend and rescind rules and regulations relating to the administration of the Plan, and all such interpretations, rules and regulations shall be conclusive and binding on all Participants. 5.2 The Committee may employ agents, attorneys, accountants, or other persons (who also may be employees of a Subsidiary) and allocate or delegate to them powers, rights, and duties, all as the Committee may consider necessary or advisable to properly carry out the administration of the Plan. ARTICLE 6 MISCELLANEOUS 6.1 The Committee shall have the right, authority and power to alter, amend, modify, revoke or terminate the Plan; except as provided in Article 7; and provided further, that no amendment or termination of the Plan shall adversely affect the rights of any Participant with respect to any Stock Units held in such Participant's Account, unless the Participant shall consent thereto in writing. 6.2 No benefits at any time payable under this Plan to a Participant or beneficiary shall be subject in any manner to anticipation, alienation, sale, transfer, assignment, pledge, attachment, garnishment, levy, execution, or other legal or equitable process, or encumbrance of any kind. 6.3 A Participant's deferred Incentive Award shall be totally unfunded so that the Company or any Subsidiary is under merely a contractual duty to make payments when due under the Plan. The promise to pay shall not be represented by notes and shall not be secured in any way. 6.4 Nothing in this Plan shall interfere with or limit in any way the right of the Company or any Subsidiary to terminate any Participant's employment at any time, nor confer upon any Participant any right to continue in the employ of the Company or Subsidiary. 6.5 The Plan shall be construed and administered according to the laws of the State of New York to the extent that those laws are not preempted by the laws of the United States of America. 6.6 The Company or its Subsidiaries may withhold federal, state and local income taxes and social security taxes from any distribution hereunder to the extent that such taxes are then payable. 6.7 In the event the Committee shall find that a Participant is unable to care for his or her affairs because of illness or accident, the Committee may direct that any payment due the Participant be paid to the Participant's duly appointed legal representative, and any such payment so made shall be a complete discharge of the liabilities of the Plan. ARTICLE 7 CHANGE IN CONTROL Notwithstanding any provision of this Plan to the contrary, if a "Change in Control" (as defined below) of the Company occurs, Stock Units held in a Participant's Account shall be paid to the Participant in a lump sum in cash not later than 15 days after the date of the Change in Control. For this purpose, the balance in the Account shall be determined by the higher of (a) the average of the Market Value of the Common Stock for the last 20 trading days prior to such Change in Control or (b) if the Change in Control of the Company occurs as a result of a tender or exchange offer or consummation of a corporate transaction, then the highest price paid per share of Common Stock pursuant thereto. Any consideration other than cash forming a part or all of the consideration for the Common Stock to be paid pursuant to the applicable transaction shall be valued at the valuation price thereon determined by the Board. In addition, the Company shall reimburse a Participant for the legal fees and expenses incurred if the Participant is required to seek to obtain or enforce any right to distribution. In the event that it is determined that such Participant is properly entitled to a cash distribution hereunder, such Participant shall also be entitled to interest thereon at the prime rate of interest as published in The Wall Street Journal plus two percent from the date such distribution should have been made to and including the date it is made. Notwithstanding any provisions of this Plan to the contrary, the provisions of this Article may not be amended by an amendment effected within three years following a Change in Control. A "Change in Control" of the Company shall be deemed to have occurred if (a) any "person" or "group" (as such terms are used in Sections 13(d) and 14(d) of the Securities Exchange Act of 1934, as amended ("Exchange Act")), other than a trustee or other fiduciary holding securities under an employee benefit plan of the Company, becomes the "beneficial owner" (as defined in Rule 13d-3 under the Exchange Act), directly or indirectly, of more than 25 percent of the then outstanding voting stock of the Company; (b) during any period of two consecutive years, individuals who at the beginning of such period constitute the Board, together with any new directors whose election or nomination for election was approved by a vote of at least two-thirds of the directors then still in office who were either directors at the beginning of the period or whose election or nomination for election was previously so approved, cease for any reason to constitute at least a majority of the Board; or (c) the Company's shareholders approve a merger or consolidation of the Company with any other corporation, other than a merger or consolidation which would result in the voting securities of the Company outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity) at least 75 percent of the total voting power represented by the voting securities of the Company or such surviving entity outstanding immediately after such merger or consolidation; or (d) the shareholders of the Company approve a plan of complete liquidation of the Company, or an agreement for the sale or disposition by the Company (in one transaction or a series of transactions) of all or substantially all of the Company's assets. Notwithstanding the foregoing, a Change in Control shall not be deemed to occur as a result of any event described in (a) or (c) above, if Directors who were a majority of the members of the Board prior to such event and who continue to serve as Directors after such event determine that the event shall not constitute a Change in Control. EX-10.I2 7 AEP PERFORMANCE SHARE INCENTIVE PLAN 10K EX10I2 Exhibit 10(i)(2) American Electric Power System Performance Share Incentive Plan as Amended and Restated through February 26, 1997 Article 1. Establishment and Purpose 1.1 Establishment of the Plan. The Company hereby establishes an incentive compensation plan to be known as the "American Electric Power System Performance Share Incentive Plan" (the "Plan"), as set forth in this document. 1.2 Purposes. The Purposes of the Plan are to provide competitive, longer-term, performance driven, incentive compensation opportunities to Participants, which are directly related to and dependent upon the competitiveness of the longer-term returns realized by the Company's shareholders; and to facilitate ownership of Restricted Stock Units by Participants so as to equate further their long-term financial interests with those of the shareholders. Article 2. Effective Date and Term of Plan The Plan was approved by the Company's shareholders and the Securities and Exchange Commission effective January 1, 1994. While the Board may suspend or terminate the Plan at any time, no such suspension or termination shall adversely affect any outstanding Performance Share Units without the Participant's written consent as specified in Section 12.2. No Performance Share Units shall be granted for Performance Periods commencing after December 31, 2003. Article 3. Definitions Whenever used in the Plan, the following terms shall have the meanings set forth below and, when the meaning is intended, the initial letter of the word is capitalized: (a) "Award Certificate" means a certificate setting forth the terms and provisions applicable to each grant of Performance Share Units, which shall include, but shall not be limited to, the number of Performance Share Units granted to the Participant, the Performance Measure, the levels of Performance Share Unit payment opportunities based on the Performance Measure, the method of determining earned Performance Share Units pursuant to Section 8.1 and the length of the Performance Period. (b) "Board" means the Board of Directors of the Company. (c) "Committee" shall mean the Human Resources Committee of the Board. (d) "Common Stock" shall mean the common stock of the Company. (e) "Company" means American Electric Power Company, Inc., a New York corporation, and any successor thereto. (f) "Director" means an individual who is a member of the Board. (g) "Disability" shall have the definition set forth in the American Electric Power System Retirement Plan. (h) "Equivalent Stock Ownership Target" means a stock ownership target for each Participant established by the Board which is a combination of Common Stock and Common Stock equivalents held by a Participant. (i) "Fair Market Value" means the closing sale price of the Common Stock, as published in The Wall Street Journal report of New York Stock Exchange -- Composite Transactions on the date in question or, if the Common Stock shall not have been traded on such date or if the New York Stock Exchange is closed on such date, then the first day prior thereto on which the Common Stock was so traded. (j) "Participant" means any full-time, nonunion employee of any Subsidiary, who has been selected to participate in the Plan for a stipulated Performance Period by the Committee. (k) "Performance Measure" means, for a period of at least three years, the financial objective to be applied to the Performance Period in which Performance Share Units held by a Participant for a Performance Period are earned, based on the relative ranking of the Company's TSR compared to the TSR's of the companies comprising the S&P Electric Utility Index. (l) "Performance Period" means the period established by the Committee, during which the number of Performance Share Units earned by Participants shall be determined. (m) "Performance Share Unit" means a measure of participation, expressed as a share of Common Stock, received as a grant under Section 7.1 or as a dividend under Section 7.2. (n) "Restricted Stock Unit" means a measure of value, expressed as a share of Common Stock, allocated to a Participant under Section 8.1. No certificates shall be issued with respect to such Restricted Stock Units, but the Company shall maintain a bookkeeping account in the name of the Participant to which the Restricted Stock Units shall relate. (o) "Retirement" means termination of employment with any Subsidiary other than for cause after attaining age 55 and at least five (5) years of service. (p) "Section 162(m)" means Section 162(m) of the Internal Revenue Code of 1986, as amended and applicable interpretive authority thereunder. (q) "Subsidiary" shall mean any corporation in which the Company owns directly or indirectly through its Subsidiaries, at least fifty percent (50%) of the total combined voting power of all classes of stock, or any other entity (including, but not limited to, partnerships and joint ventures) in which the Company owns at least fifty percent (50%) of the combined equity thereof. (r) "Transition Performance Period" means the one (1) and two (2) year Performance Periods that may be made available on a one-time basis to Participants receiving Performance Share Units at the commencement of the Plan and Participants receiving their first grant of Performance Share Units for a Performance Period at any time during the term of the Plan. (s) "TSR" means total shareholder return and is the compound product of the annual TSR amounts obtained by dividing: (1) the sum of: (i) the annual amount of dividends for each year of the Performance Period, assuming dividend reinvestment, and (ii) the difference between the share price at the end and the beginning of each year of the Performance Period; by (2) the share price at the beginning of each year of the Performance Period. Article 4. Administration 4.1 The Committee. The Plan shall be administered by the Committee consisting of not less than three (3) Directors. Each member of the Committee shall at all times while serving be an "outside director" within the meaning of Section 162(m). 4.2 Authority of the Committee. Subject to the provisions herein and to the approval of the Board, the Committee shall have full power for the following: (a) Selecting Participants to whom Performance Share Units are granted. (b) Determining the size and frequency of grants (which need not be the same for each Participant), except as limited by Article 5. (c) Construing and interpreting the Plan and any agreement or instrument entered into under the Plan. (d) Establishing, amending, rescinding or waiving rules and regulations for the Plan's administration. (e) Amending, modifying, and/or terminating the Plan, subject to the provisions of Article 12 herein. Further, the Committee shall have the full power to make all other determinations which may be necessary or advisable for the administration of the Plan, to the extent consistent with the provisions of the Plan, and subject to the approval of the Board. As permitted by law, the Committee may delegate its authority as identified hereunder; provided, however, that the Committee may not delegate certain of its responsibilities hereunder if such delegation may jeopardize compliance with the "outside directors" provision of Section 162(m). 4.3 Decisions Binding. All determinations and decisions made by the Committee pursuant to the provisions of the Plan, and all related orders or resolutions of the Board shall be final, conclusive, and binding on all persons, including the Company, its shareholders, Participants and their estates, and beneficiaries. Article 5. Maximum Awards and Adjustments 5.1 Maximum Amount Available for Awards. The maximum number of Performance Share Units which may be earned during the term of the Plan on an aggregate basis is 1,000,000 and, for one Performance Period, the maximum number of Performance Share Units which may be earned by a Participant is 25,000. Not more than 1,000,000 shares of Common Stock will be available for delivery upon payment for Performance Share Units earned under the Plan. The shares to be delivered under the Plan will be made available from shares reacquired by the Company. The limitations in this Section 5.1 on the maximum amount of Performance Share Units and shares of Common Stock available under the Plan are subject to adjustment as provided in Section 5.2. 5.2 Adjustments. If the Committee determines that the occurrence of any merger, reclassification, consolidation, recapitalization, stock dividend or stock split requires an adjustment in order to preserve the benefits intended under the Plan, then the Committee may, in its discretion, make equitable proportionate adjustments in the maximum number of Performance Share Units which may be earned on an aggregate basis or by a Participant, the maximum number of shares of Common Stock which may be delivered, as specified in Section 5.1, and the number of Restricted Stock Units held by a Participant. Article 6. Eligibility and Participation 6.1 Eligibility. Eligibility for participation in the Plan shall be limited to senior officers of the Company and/or its Subsidiaries who, in the opinion of the Committee, have the capacity for contributing in a substantial measure to the successful performance of the Company. 6.2 Actual Participation. Participation in the Plan shall begin on the first day of each Performance Period. At the beginning of each Performance Period, the Committee will identify which, if any, Participants shall receive a grant of Performance Share Units for that Performance Period. As soon as practicable following selection, a Participant shall receive an Award Certificate. Article 7. Grants of Performance Share Units 7.1 Grant Timing, Frequency and Number. Performance Share Units may be granted to Participants as of the first day of each Performance Period on an annual basis. It is intended that Performance Periods will overlap. However, grants do not necessarily have to be on an annual basis. The number of Performance Share Units to be granted to each Participant shall be determined by the Committee in its sole discretion. 7.2 Dividends. During the Performance Period, Participants will be credited with dividends, equivalent in value to those declared and paid on shares of the Common Stock, on all Performance Share Units granted to them. These dividends will be regarded as having been reinvested in Performance Share Units on the date of the Common Stock dividend payments based on the then Fair Market Value of the Common Stock, thereby increasing the number of Performance Share Units held by a Participant. Participants will be credited with dividend equivalents, equal in value to those declared and paid on shares of Common Stock, on all Restricted Stock Units allocated to the Participants. Dividend equivalents on Restricted Stock Units required to be held pursuant to Section 8.2 or deferred pursuant to Section 8.4 will be regarded as having been reinvested in Restricted Stock Units on the date of the Common Stock dividend payments based on the then Fair Market Value of the Common Stock, thereby increasing the number of Restricted Stock Units held by a Participant. 7.3 Performance Periods. Subject to the next sentence, the Committee shall establish Performance Periods in its discretion. Performance Periods shall, in all cases, be at least three (3) years in length, except for the Transition Performance Periods. The first Performance Periods shall be the one (1) and two (2) year Transition Performance Periods ending December 31, 1994 and December 31, 1995, respectively, and the three-year period beginning January 1, 1994 and ending December 31, 1996. Performance Share Units granted as part of the initial grant of Performance Share Units for such Performance Periods shall be deemed to be granted as of the first day of such Performance Periods. Article 8. Determination and Payment 8.1 Determination. The number of Performance Share Units earned by a Participant for a Performance Period shall be determined by multiplying the number of Performance Share Units held by the Participant at the end of the Performance Period by a factor based upon the Performance Measure. No Performance Share Units shall be earned by any Participant if, at the end of the Performance Period, shareholders do not realize a positive TSR under the Performance Measure. In any event, the Committee may, at its discretion, reduce the number of Performance Share Units earned by any Participant for a Performance Period. Earned Performance Share Units shall be converted to Restricted Stock Units if the Participant has not met the Equivalent Stock Ownership Target. A Participant shall receive one Restricted Stock Unit for each earned Performance Share Unit. Once a Participant has attained the Equivalent Stock Ownership Target, earned Performance Share Units shall be paid to the Participant at the end of the Performance Period as provided in Section 8.3 or may be deferred by the Participant as provided in Section 8.4. 8.2 Holding of Restricted Stock Units. Restricted Stock Units required to meet the Equivalent Stock Ownership Target will be held until the Participant terminates employment at which time the Participant shall receive payment for the Restricted Stock Units unless the Participant has elected deferral of such payment in accordance with Section 8.4. 8.3 Payment of Restricted Stock Units and Earned Performance Share Units. The payment of Restricted Stock Units that were required to be held pursuant to Section 8.2 shall be made in cash, shares of Common Stock, or a combination of both as then elected by the Participant. Cash payments of Restricted Stock Units shall be calculated on the basis of the average of the Fair Market Value of the Common Stock for the last 20 trading days prior to the Participant's employment termination date or the date of the Participant's death, as the case may be. The payment of earned Performance Share Units not required to be converted to Restricted Stock Units pursuant to Section 8.1 shall be made in cash, shares of Common Stock, or a combination of both as then elected by the Participant. Cash payments of earned Performance Share Units shall be calculated on the basis of the average of the Fair Market Value of the Common Stock for the last 20 trading days of the Performance Period for which the Performance Share Units were earned. 8.4 Deferrals. Once the Participant attains the Equivalent Stock Ownership Target, the Participant may make annual elections to defer the payment of subsequent earned Performance Share Units for one or more years; however, if the Participant's deferral period extends beyond the Participant's employment termination date, payment must commence no later than five years after the Participant's termination of employment. The deferral election must be made at least one year prior to the end of the Performance Period for which the Participant has received an allocation with regard to a Performance Period and each earned Performance Share Unit shall be converted into a Restricted Stock Unit. The Participant may also elect to defer the payment of Restricted Stock Units provided under Section 8.2 for a period of one or more years with a maximum deferral period that results in payment commencing no later than five years following termination of employment, but such election must be made at least one year prior to termination of employment. As elected by the Participant, payment of the Participant's elective deferrals will be made at the end of the deferral period as a lump sum distribution or up to 10 annual installments. Payments may be made in cash, shares of Common Stock, or a combination of both as then elected by the Participant. Cash payments of Restricted Stock Units shall be calculated on the basis of the average of the Fair Market Value of the Common Stock for the last 20 trading days prior to the Participant's deferred distribution date, respective installment payment dates or the date of the Participant's death, as the case may be. 8.5 Manner of Payment. Payment in Common Stock shall be at the rate of one share of Common Stock for each Restricted Stock Unit or earned Performance Share Unit, with any fractional shares paid in cash. The election to be paid in cash or Common Stock must be filed with the Company at least 30 days prior to the payment date and, in the event an election is not made, payment will be made in cash. 8.6 Payment Upon Death Notwithstanding the Participant's election, if a Participant dies while Restricted Stock Units are held by the Participant, such Restricted Stock Units will be paid in a lump sum in cash within 90 days from the date of the Participant's death to the Participant's designated beneficiary or the Participant's estate, as the case may be. Upon application by the beneficiary or the legal representative for the Participant's estate, the lump sum payment may be deferred beyond 90 days for good cause if the Committee consents to such deferral. 8.7 Performance Share Units Granted in 1994. Performance Share Units granted in 1994 for the two Transition Performance Periods ending December 31, 1994 and December 31, 1995 and for the Performance Period ending December 31, 1996 shall be paid 50% in cash and 50% in Common Stock unless the Participant consents to have the Performance Share Units earned for the Transition Performance Period ending December 31, 1995 and the Performance Share Units earned for the Performance Period ending December 31, 1996 paid in accordance with the provisions of Sections 8.1 through 8.4. The payment in cash and Common Stock shall be as provided in the second paragraph of Section 8.3. 8.8 Limitations on Sales of Common Stock. A Participant shall not be permitted to sell the shares of Common Stock distributed to such Participant pursuant to Section 8.7 until the Participant has attained the Equivalent Stock Ownership Target without counting such shares towards the attainment of the Target. In order to enforce the limitations imposed upon the shares of Common Stock distributed pursuant to Section 8.7, the Committee may (a) direct the delivery of stock certificates to Participants to be withheld until the shares of Common Stock covered by such certificates may be sold by the Participant, (b) cause a legend or legends to be placed on any such certificates, and/or (c) issue "stop transfer" instructions as it deems necessary or appropriate. Holders of shares of Common Stock limited as to sale under this Section 8.8 shall have rights as a shareholder with respect to such shares to receive dividends in cash or other property or other distribution or rights in respect of such shares and to vote such shares as the record owner thereof. Article 9. Termination of Employment 9.1 Termination of Employment Due to Death, Disability, Retirement or Involuntary Termination Other Than for Cause. In the event of a Participant's termination of employment with the Subsidiaries, prior to the end of a Performance Period but after the first six months of such Performance Period, by reason of the Participant's death, Disability, Retirement or involuntary termination other than for cause, the Participant will be eligible to earn prorated Performance Share Units for each such Performance Period which has not yet ended, determined pursuant to Section 8.1 for such period and the number of days of participation during such Performance Period. In the case of the Transition Performance Periods, the Performance Share Units earned would not be subject to proration if the employment period and termination conditions specified in this Section 9.1 were met. 9.2 Termination for Reasons Other Than Death, Disability, Retirement or Involuntary Termination Other Than for Cause. In the event a Participant's employment is terminated for reasons other than death, Disability, Retirement or involuntary termination other than for cause, all rights to any unearned Performance Share Units under the Plan shall be forfeited. Article 10. Beneficiary Designation 10.1 Designation of Beneficiary. Each Participant shall be entitled to designate a beneficiary or beneficiaries who, following the Participant's death, will be entitled to receive any payments to be made under Section 8.6. All designations shall be signed by the Participant, and shall be in such form as prescribed by the Committee. Each designation shall be effective as of the date delivered to the Company by the Participant. The Participant may change his or her designation of beneficiary on such form as prescribed by the Committee. The payment of any amounts owing to a Participant pursuant to such Participant's outstanding Performance Share Units or Restricted Stock Units held under the Plan shall be in accordance with the last unrevoked written designation of beneficiary that has been signed by the Participant and delivered by the Participant to the Company prior to the Participant's death. 10.2 Death of Beneficiary. In the event that all of the beneficiaries named by a Participant pursuant to Section 10.1 herein predecease the Participant, any amounts that would have been paid to the Participant or the Participant's beneficiaries under the Plan shall be paid to the Participant's estate. Article 11. Rights of Participants 11.1 Employment. Nothing in the Plan shall interfere with or limit in any way the right of the Company or any Subsidiary to terminate any Participant's employment at any time, nor confer upon any Participant any right to continue in the employ of the Company or Subsidiary. 11.2 Participation. No Participant shall at any time have a right to be selected for participation in the Plan for any Performance Period, despite having been selected for participation in a previous Performance Period. 11.3 Nontransferability. No Performance Share Units held by a Participant or Restricted Stock Units held pursuant to Sections 8.2 or 8.4 may be sold, transferred, pledged, assigned, or otherwise alienated or hypothecated, other than by will or by the laws of descent and distribution. 11.4 Rights to Common Stock. Performance Share Units or Restricted Stock Units do not give a Participant any rights whatsoever with respect to shares of Common Stock until such time and to such extent that payment of earned Performance Share Units or Restricted Stock Units is made in shares of Common Stock as requested by the Participant. Article 12. Amendment, Modification and Termination 12.1 Amendment, Modification and Termination. The Committee may amend or modify the Plan at any time, with the approval of the Board. However, without the approval of the shareholders of the Company, no such amendment or modification may: (a) Materially modify the eligibility requirements of the Plan. (b) Materially increase the benefits accruing to Participants under the Plan. (c) Materially increase the number of Performance Share Units which may be earned on an aggregate basis or by a Participant (except as provided in Section 5.2). (d) Materially increase the maximum number of shares of Common Stock available for payment under the Plan (except as provided in Section 5.2). (e) Modify the Performance Measure and the method of determining Performance Share Units earned pursuant to Section 8.1, except as may be permitted by Section 162(m). 12.2 Performance Share Units Previously Granted. No termination, amendment or modification of the Plan shall in any manner adversely affect any outstanding Performance Share Units or Restricted Stock Units under the Plan, without the written consent of the Participant holding such Performance Share Units or Restricted Stock Units. Article 13. Miscellaneous Provisions 13.1 Costs of the Plan. The costs of the Plan awards shall be paid directly by the Subsidiary that pays each Participant's base salary during the Performance Period. Although not prohibited from doing so, the Subsidiary is not required in any way to segregate assets in any manner or to specifically fund the benefits provided under the Plan. 13.2 Relationship to Other Benefits. No payment under the Plan shall be taken into account in determining any benefits under any pension, retirement, group insurance, or other benefit plan of the Company and/or its Subsidiaries. 13.3 Governing Law. To the extent not preempted by Federal law, the Plan, and all agreements hereunder, shall be construed in accordance with and governed by the laws of the State of New York. Article 14. Change in Control Notwithstanding any provision of this Plan to the contrary, if a "Change in Control" (as defined below) of the Company occurs, Restricted Stock Units held by a Participant will be paid in a lump sum in cash, shares of Common Stock, or a combination of both, to the Participant, as elected by the Participant, not later than 15 days after the date of the Change in Control. For this purpose, the Restricted Stock Units shall be determined by the higher of (a) the average of the Market Value of the Common Stock for the last 20 trading days prior to such Change in Control or (b) if the Change in Control of the Company occurs as a result of a tender or exchange offer or consummation of a corporate transaction, then the highest price paid per share of Common Stock pursuant thereto. Any consideration other than cash forming a part or all of the consideration for the Common Stock to be paid pursuant to the applicable transaction shall be valued at the valuation price thereon determined by the Board. In addition, the Company shall reimburse a Participant for the legal fees and expenses incurred if the Participant is required to seek to obtain or enforce any right to distribution. In the event that it is determined that such Participant is properly entitled to a cash distribution hereunder, such Participant shall also be entitled to interest thereon at the prime rate of interest as published in The Wall Street Journal plus two percent from the date such distribution should have been made to and including the date it is made. Notwithstanding any provisions of this Plan to the contrary, the provisions of this Article may not be amended by an amendment effected within three years following a Change in Control. A "Change in Control" of the Company shall be deemed to have occurred if (a) any "person" or "group" (as such terms are used in Sections 13(d) and 14(d) of the Securities Exchange Act of 1934 ("Exchange Act")), other than a trustee or other fiduciary holding securities under an employee benefit plan of the Company, becomes the "beneficial owner" (as defined in Rule 13d-3 under the Exchange Act), directly or indirectly, of more than 25 percent of the then outstanding voting stock of the Company; (b) during any period of two consecutive years, individuals who at the beginning of such period constitute the Board, together with any new Directors whose election or nomination for election was approved by a vote of at least two-thirds of the Directors then still in office who were either Directors at the beginning of the period or whose election or nomination for election was previously so approved, cease for any reason to constitute at least a majority of the Board; or (c) the Company's shareholders approve a merger or consolidation of the Company with any other corporation, other than a merger or consolidation which would result in the voting securities of the Company outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity) at least 75 percent of the total voting power represented by the voting securities of the Company or such surviving entity outstanding immediately after such merger or consolidation; or (d) the shareholders of the Company approve a plan of complete liquidation of the Company, or an agreement for the sale or disposition by the Company (in one transaction or a series of transactions) of all or substantially all of the Company's assets. Notwithstanding the foregoing, a Change in Control shall not be deemed to occur as a result of any event described in (a) or (c) above, if Directors who were a majority of the members of the Board prior to such event and who continue to serve as Directors after such event determine that the event shall not constitute a Change in Control. EX-10.1 8 INTERIM ALLOWANCE AGREEMENT 10K EX101 Exhibit 10(l) MODIFICATION NO. 1 TO THE AEP SYSTEM INTERIM ALLOWANCE AGREEMENT BY AND AMONG APPALACHIAN POWER COMPANY COLUMBUS SOUTHERN POWER COMPANY INDIANA MICHIGAN POWER COMPANY KENTUCKY POWER COMPANY OHIO POWER COMPANY AND WITH AMERICAN ELECTRIC POWER SERVICE CORPORATION AS AGENT CONTENTS PREAMBLE . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 ARTICLE 1 - Definitions. . . . . . . . . . . . . . . . . . . 4 ARTICLE 2 - Emission Allowance Management. . . . . . . . . . 9 ARTICLE 3 - Agent's Responsibilities . . . . . . . . . . . . 10 ARTICLE 4 - Settlements. . . . . . . . . . . . . . . . . . . 11 ARTICLE 5 - Billings and Payments. . . . . . . . . . . . . . 15 ARTICLE 6 - Taxes. . . . . . . . . . . . . . . . . . . . . . 15 ARTICLE 7 - Modifications. . . . . . . . . . . . . . . . . . 16 ARTICLE 8 - Effective Date and Terms of this Agreement . . . 16 ARTICLE 9 - Regulatory Authorities . . . . . . . . . . . . . 17 ARTICLE 10 - Assignment . . . . . . . . . . . . . . . . . . . 17 0.1 THIS AGREEMENT, made and entered into as of the 28th day of July, 1994 by and among APPALACHIAN POWER COMPANY (APCo), a Virginia corporation, COLUMBUS SOUTHERN POWER COMPANY (CSP), an Ohio corporation, INDIANA MICHIGAN POWER COMPANY (I&M), an Indiana corporation, KENTUCKY POWER COMPANY (KPCo), a Kentucky corporation, OHIO POWER COMPANY (OPCo), an Ohio corporation, said companies (herein sometimes called 'Members' when referred to collectively and 'Member' when referred to individually) being affiliated companies of the integrated public utility electric system known as the American Electric Power System (AEP), and AMERICAN ELECTRIC POWER SERVICE CORPORATION (Agent), a New York corporation, being a service company engaged solely in the business of furnishing essential services to the aforesaid companies and the other affiliated companies. W I T N E S S E T H T H A T: 0.2 WHEREAS, the Members own and operate electric facilities in the states herein indicated, (i) APCo in Virginia, West Virginia and Tennessee, (ii) CSP in Ohio, (iii) I&M in Indiana and Michigan, (iv) KPCo in Kentucky, and (v) OPCo in Ohio and West Virginia; and 0.3 WHEREAS, the Members have entered into an Interconnection Agreement, dated July 6, 1951, with modifications thereto, which provides for certain understandings, conditions, and procedures designed to achieve the full benefits and advantages available through the coordinated planning and operation of their electric power supply facilities; and 0.4 WHEREAS, Congress in 1990 enacted amendments to the Clean Air Act, including Title IV, 104 Stat. 2584, 42 U.S.C.A. Section 7651, et seq. ("the 1990 Amendments") which limit emissions of sulfur dioxide (SO2) by electric utilities; and 0.5 WHEREAS, under the 1990 Amendments, compliance is to be achieved in two stages -- Phase I, which begins January 1, 1995 and Phase II which begins January 1, 2000; and reductions in sulfur dioxide emissions are to be effected by a system in which a limited number of "emission allowances" have been allocated by the United States Environmental Protection Agency (EPA) to individual utility generating units; and 0.6 WHEREAS, twenty-one (21) of the Members' generating units have been designated by the 1990 Amendments as Phase I affected units, and fifty-one (51) of the Members' generating units have been designated as Phase II affected units, and as such, have been awarded emission allowances by the EPA; and 0.7 WHEREAS, the Members may have ownership or entitlement to emission allowances through several means, including: (i) EPA- AWARDED ALLOWANCES based on emission levels experienced during a base-line period, (ii) EPA bonus allowances awarded for various compliance strategies, primarily through the installation of FGD systems, and (iii) the purchase of allowances. Generally, Members are permitted to emit SO2 only to the extent they have allowances to cover such emissions. 0.8 WHEREAS, compliance with the 1990 Amendments has been and will continue to be planned by the Members on an integrated and coordinated basis, consistent with the integrated and coordinated planning and operation of the Members' electric systems; and 0.9 WHEREAS, the Members desire to arrive at an equitable methodology of allocating emission allowances and associated costs and benefits between and among the Members; and 0.10 WHEREAS, the Members have entered into the Interim Allowance Agreement to establish, on an interim basis, a methodology and transfer price for the transfer of SO2 emission allowances; and 0.11 WHEREAS, the Members believe that an agreement which provides for an equitable assignment of cost and benefits among the Members can best be realized if administered by a single clearing agent; and 0.12 WHEREAS, the Members believe that the Agent designated herein for such purpose is qualified to perform such services; 0.13 NOW, THEREFORE, in consideration of the premises and of the mutual covenants and agreements hereinafter contained, the parties hereto, hereby agree as follows: ARTICLE 1 - DEFINITIONS 1.1 The following terms and factors associated with settlements under this Agreement are defined in alphabetic order as follows: 1.2 DELIVERING MEMBER -- a Member which sells PRIMARY ENERGY and/or ECONOMY ENERGY to the POOL. 1.3 ECONOMY ENERGY -- electric energy delivered to the POOL from the MEMBER PRIMARY CAPACITY of a particular Member to displace energy that otherwise would be supplied by less efficient MEMBER PRIMARY CAPACITY of another Member to meet its MEMBER LOAD OBLIGATION. 1.4 EPA-AWARDED ALLOWANCES -- the allowances awarded to each generating unit by the EPA as defined in Section 404(a) of the 1990 Amendments. 1.5 FERC -- the Federal Energy Regulatory Commission or any successor agency. 1.6 GAVIN BONUS ALLOWANCES -- 184.7, 184.0, 44.6, 44.6 and 44.6 thousand allowances, excluding transfer allowances, for the years 1995, 1996, 1997, 1998 and 1999, respectively, awarded by the EPA to OPCo's Gavin Plant pursuant to Section 404(d) of the 1990 Amendments. 1.7 GAVIN EPA-AWARDED ALLOWANCES -- the allowances awarded to the Gavin Plant by the EPA pursuant to Section 404(a) of the 1990 Amendments. 1.8 GAVIN SCRUBBER SO2 REDUCTION -- the difference between actual SO2 emissions at OPCo's Gavin Plant operating with scrubbers and GAVIN UNCONTROLLED EMISSIONS for a given year. 1.9 GAVIN UNCONTROLLED EMISSIONS -- an estimated amount of SO2 emissions that would result from operating the Gavin Plant without scrubbers. The estimate of GAVIN UNCONTROLLED EMISSIONS is calculated by dividing the scrubbed Gavin SO2 EMISSIONS by (1.00 minus the scrubber SO2 removal efficiency rate). 1.10 INTERCONNECTION AGREEMENT -- the Interconnection Agreement among the Members dated July 6, 1951, as amended. 1.11 MEMBER AFFECTED UNITS -- a Member's generating units that are required to meet the emission standards established by the 1990 Amendments. 1.12 MEMBER CAPACITY DEFICIT FACTOR -- for any Member, the average for the calendar year of its MEMBER PRIMARY CAPACITY DEFICIT divided by the sum of all members' average MEMBER PRIMARY CAPACITY DEFICITS. 1.13 MEMBER DEMAND -- MEMBER LOAD OBLIGATION determined on a clock-hour integrated kilowatt basis. 1.14 MEMBER GENERATION -- the total of a Member's net generation from its MEMBER PRIMARY CAPACITY. 1.15 MEMBER LOAD OBLIGATION -- a Member's internal load plus any firm power sales to Foreign Companies and to affiliated companies other than Members. 1.16 MEMBER LOAD RATIO -- the ratio of a particular Member's MEMBER MAXIMUM DEMAND in effect for a calendar month to the sum of the five MEMBER MAXIMUM DEMANDS in effect for such month. 1.17 MEMBER MAXIMUM DEMAND -- the MEMBER MAXIMUM DEMAND in effect for a calendar month for a particular Member shall be equal to the maximum MEMBER DEMAND experienced by said Member during the twelve consecutive calendar months next preceding such calendar month. 1.18 MEMBER PRIMARY CAPACITY -- the aggregate capacity of the electric power sources of a particular Member, in kilowatts, that is normally expected to be available to carry load. Such capacity shall include (i) the capacity installed at the generating stations owned by the Member and (ii) the capacity available to that Member through interconnection arrangements with affiliated companies or Foreign Companies. 1.19 MEMBER PRIMARY CAPACITY DEFICIT -- difference between the MEMBER PRIMARY CAPACITY and MEMBER PRIMARY CAPACITY RESERVATION of a particular Member, when such MEMBER PRIMARY CAPACITY is less than such MEMBER PRIMARY CAPACITY RESERVATION. 1.20 MEMBER PRIMARY CAPACITY RESERVATION -- SYSTEM PRIMARY CAPACITY multiplied by the MEMBER LOAD RATIO of a particular Member. 1.21 OPCo CAPACITY SURPLUS FACTOR -- the weighted average for the calendar year of (OPCo's MEMBER PRIMARY CAPACITY minus OPCo's MEMBER PRIMARY CAPACITY RESERVATION) divided by OPCo's MEMBER PRIMARY CAPACITY. 1.22 OVER-COMPLIANCE -- the amount by which a Member's SO2 EMISSIONS are less than its EPA-AWARDED ALLOWANCES for the current year; provided, however, that in determining OPCo's OVER- COMPLIANCE, its emissions shall be deemed to include, in lieu of actual emissions from the Gavin Plant, 50% of GAVIN UNCONTROLLED EMISSIONS, and its allowances shall be deemed to include, in lieu of actual GAVIN EPA-AWARDED ALLOWANCES, only 50% of GAVIN EPA- AWARDED ALLOWANCES. 1.23 POOL -- electric energy delivered by one Member, from its MEMBER PRIMARY CAPACITY, to another Member shall be considered to be energy delivered to the POOL by the former Member and delivered from the POOL by the latter Member. 1.24 POWER SALES TO FOREIGN COMPANIES -- sales of electric power and energy to Foreign Companies, made by a Member on behalf of the System, where the revenue and cost of such sales are allocated to the Members in proportion to their respective MEMBER LOAD RATIOS. 1.25 PRIMARY AND ECONOMY ENERGY RECEIPT FACTOR -- the ratio of PRIMARY ENERGY and ECONOMY ENERGY receipts by a receiving Member from a DELIVERING MEMBER to the total sales of PRIMARY ENERGY and ECONOMY ENERGY by the DELIVERING MEMBER. 1.26 PRIMARY AND ECONOMY ENERGY SUPPLY FACTOR -- the sum of the Member's PRIMARY ENERGY and ECONOMY ENERGY deliveries divided by the MEMBER'S GENERATION. 1.27 PRIMARY ENERGY -- electric energy delivered to the POOL from the MEMBER PRIMARY CAPACITY of a particular Member to meet another Member's deficiency in capacity. 1.28 RECEIVING MEMBER -- a Member which buys PRIMARY ENERGY and/or ECONOMY ENERGY from the POOL. 1.29 SO2 EMISSIONS -- the total of the Member's SO2 EMISSIONS from the MEMBER'S AFFECTED UNITS. 1.30 SURPLUS ALLOWANCES -- the excess of a Member's current year EPA-AWARDED ALLOWANCES, plus allowances transferred to the Member pursuant to Sections 4.1, 4.2, 4.3 and 4.4 of this Agreement, over the Member's annual SO2 EMISSIONS and its MLR share of the SYSTEM ALLOWANCE BANK. 1.31 SYSTEM ALLOWANCE BANK -- the sum of all the Members' allowances in excess of all the Members' SO2 emissions. 1.32 SYSTEM COST OF COMPLIANCE -- for calendar year 1995 is $115.43/ton of SO2. For each subsequent year, the SYSTEM COST OF COMPLIANCE shall be $115.43/ton of SO2 escalated annually at a rate of 10.56%. 1.33 SYSTEM PRIMARY CAPACITY -- the sum of the MEMBER PRIMARY CAPACITY of all the Members. 1.34 UNDER-COMPLIANCE -- the amount by which a Member's SO2 EMISSIONS are greater than its EPA-AWARDED ALLOWANCES for the current year; provided, however, that in determining OPCo's UNDER- COMPLIANCE, its emissions shall be deemed to include, in lieu of actual emissions from the Gavin Plant, 50% of GAVIN UNCONTROLLED EMISSIONS, and its allowances shall be deemed to include, in lieu of actual GAVIN EPA-AWARDED ALLOWANCES, only 50% of GAVIN EPA- AWARDED ALLOWANCES. ARTICLE 2 - EMISSION ALLOWANCE MANAGEMENT 2.1 In determining the transfer of costs and benefits related to emission allowances among Members, settlements for the following transactions will be governed by this Agreement: 1) an annual reallocation of Gavin allowances, described in Section 4.1, 2) an annual cash settlement for the transfer of allowances associated with PRIMARY ENERGY and ECONOMY ENERGY, described in Section 4.2, 3) a monthly cash settlement for allowances consumed for POWER SALES TO FOREIGN COMPANIES, described in Section 4.3, 4) sales and purchases of allowances to/from non-affiliated parties, described in Section 4.4, and 5) an annual transfer of allowances for current period compliance and allocation of the SYSTEM ALLOWANCE BANK, described in Section 4.5. 2.2 Agent shall have the authority to make any and all decisions relating to the use, management, purchase, sale and transfer of emission allowances. Except as provided in this Agreement or any superseding agreement, no other payment or compensation shall be made between or among the Members with respect to any such use, management, purchase, sale or transfer. ARTICLE 3 - AGENT'S RESPONSIBILITIES 3.1 For the purpose of carrying out the provisions of this Agreement, the Members hereby delegate to Agent, and Agent hereby accepts, the responsibility of administration of this Agreement, and in furtherance thereof Agent hereby agrees: 3.11 To render to each Member as promptly as possible after the end of each month a statement setting forth the settlements hereunder for such preceding calendar month, in such detail and with such segregation as may be needed for accounting, operating, or other proper purposes. 3.12 To carry out allowance transfer settlements under this Agreement. Settlement for the Gavin Allowance Reallocation shall be recorded annually in December for each calendar year. 3.13 To carry out cash settlements under this Agreement through an account (hereby designated and hereinafter called the SYSTEM ALLOWANCE ACCOUNT) to be administered by Agent. Payments to or from such account shall be made to or by Agent as clearing agent of the account. The total amount of the payments made by the Members to the SYSTEM ALLOWANCE ACCOUNT each month shall be equal to the total amount of the payments made from the SYSTEM ALLOWANCE ACCOUNT for the same period. 3.131 Monthly settlements by the Members shall be determined for Allowances Consumed for Power Sales to Foreign Companies. 3.132 Annual settlements by the Members shall be determined in December of each calendar year for Allowance Transfers for Primary and Economy Energy Transactions. 3.133 Settlements by the Members shall be determined for allowances sold and purchased to/from non- affiliated parties as they occur. 3.134 Annual settlements by the Members shall be determined in December of each calendar year for the Transfer of Allowances for Current Period Compliance and Allocation of the System Allowance Bank. ARTICLE 4 - SETTLEMENTS 4.1 GAVIN ALLOWANCE REALLOCATION - In December of 1995 and each subsequent calendar year, the allowance inventory accounts of the Members will be adjusted to recognize the Gavin Allowance Reallocation. The number of Gavin allowances available for reallocation is determined by multiplying the OPCo CAPACITY SURPLUS FACTOR by the sum of (i) GAVIN BONUS ALLOWANCES and (ii) 50% of the sum of the GAVIN EPA-AWARDED ALLOWANCES and the GAVIN SCRUBBER SO2 REDUCTION. The Gavin allowances available for reallocation shall be transferred, at zero cost, to the Members having a MEMBER PRIMARY CAPACITY DEFICIT. Each deficit Member's share of the Gavin Allowance Reallocation is determined by multiplying the Gavin Allowances to Reallocate by the MEMBER'S CAPACITY DEFICIT FACTOR. 4.2 ALLOWANCE TRANSFERS ASSOCIATED WITH PRIMARY AND ECONOMY ENERGY TRANSACTIONS - In December of each year, the DELIVERING MEMBERS shall transfer allowances to or receive allowances from the RECEIVING MEMBERS, according to this Section. A DELIVERING MEMBER shall be transferred allowances from a RECEIVING MEMBER if the DELIVERING MEMBER is in an UNDER-COMPLIANCE position. A DELIVERING MEMBER shall transfer allowances to a RECEIVING MEMBER if the DELIVERING MEMBER is in an OVER-COMPLIANCE position. Members supplying allowances shall be compensated by the Members receiving allowances based on the supplying Member's average allowance inventory cost. For the year, a Member may be both a DELIVERING MEMBER and a RECEIVING MEMBER. 4.21 In December of each year, the Member's annual OVER- COMPLIANCE or UNDER-COMPLIANCE shall be determined. 4.22 The PRIMARY AND ECONOMY ENERGY SUPPLY FACTOR of each DELIVERING MEMBER shall be multiplied by that Member's over/(under) compliance to determine its incremental OVER- COMPLIANCE or incremental UNDER-COMPLIANCE position. The incremental over/(under) compliance position represents the total number of allowances to be transferred from or received by the DELIVERING MEMBER. 4.23 If the DELIVERING MEMBER is in an UNDER-COMPLIANCE position, the number of allowances to be transferred from the RECEIVING MEMBER is calculated by multiplying the DELIVERING MEMBER'S incremental UNDER-COMPLIANCE by the respective PRIMARY AND ECONOMY ENERGY RECEIPT FACTOR. If the DELIVERING MEMBER is in an OVER-COMPLIANCE position, the number of allowances to be transferred to the RECEIVING MEMBERS is calculated by multiplying the incremental OVER-COMPLIANCE of the DELIVERING MEMBER by the respective PRIMARY AND ECONOMY ENERGY RECEIPT FACTORS. 4.24 The net allowances transferred from the supplying Member during the year are priced at their individual weighted average inventory cost computed at the end of December. The net allowances transferred to the receiving Members shall be based on the weighted average inventory cost of all Members supplying allowances. The average inventory cost of a supplying Member is computed by taking the total book cost of allowances available for transfer divided by the number of allowances available for transfer at the end of December. 4.3 ALLOWANCES CONSUMED FOR POWER SALES TO FOREIGN COMPANIES - - When allowances are consumed for power sales to foreign companies, the customer has the option of reimbursing the supplying company with allowances in kind, or paying cash for the allowances at the current market rate. If the customer reimburses in kind, the allowances shall be retained by the supplying Member (Member company that generated the energy and consumed the allowances); and a cash settlement shall be made to each Member based on its MLR- share of the current value of the allowances received. If cash is received, in lieu of allowances, it shall be shared by each member based on its current MLR. The supplying Member's consumed cost of allowances for sale to foreign companies shall be allocated to each Member based on its current MLR. The method for determining the allowances consumed in generating the energy for POWER SALES TO FOREIGN COMPANIES is set forth in Appendix E to this Agreement. 4.4 ALLOWANCE TRANSACTIONS WITH NON-AFFILIATED PARTIES - Participation in the allowance market could involve either the sale or purchase of allowances to or from non-affiliated parties. 4.41 SALE OF ALLOWANCES - Except as provided in Section 4.43, in the event allowances are sold to non-affiliated parties, each Member shall contribute its MLR share of the total quantity sold. To the extent a Member cannot provide its MLR share due to a shortfall, that Member shall purchase an amount of allowances necessary to cover the shortfall from other Members having a surplus, at the System Cost of Compliance. Each Member shall receive its MLR share of the total proceeds. 4.42 PURCHASE OF ALLOWANCES - In the event allowances are purchased from non-affiliated parties, each Member shall take ownership of its MLR share of the total quantity purchased and pay its MLR share of the total cost. 4.43 SALE OF WITHHELD ALLOWANCES AT EPA AUCTIONS - The proceeds from sales of allowances withheld by the EPA, pursuant to Section 416 of Title IV of the 1990 Amendments, shall be retained by the Member owning the generating units from which the allowances were withheld. 4.44 NET PROCEEDS AND COSTS FROM PREVIOUS ALLOWANCE TRANSACTIONS - The net proceeds from sales of allowances to non-affiliated parties which occurred prior to the effective date of Modification No. 1 to this Agreement, the cost of allowances purchased from non-affiliated parties which occurred prior to the effective date of Modification No. 1 to this Agreement and all carrying charges accrued on such proceeds and costs, shall be shared by each Member based on its MLR. 4.5 TRANSFERS OF ALLOWANCES FOR CURRENT PERIOD COMPLIANCE AND ALLOCATION OF THE SYSTEM ALLOWANCE BANK - At the end of December of each calendar year, each Member shall own a share of the SYSTEM ALLOWANCE BANK, based on its current MEMBER LOAD RATIO. A Member whose annual SO2 EMISSIONS exceed its available allowance inventory, after intercompany settlements described in Section 4.1, 4.2, 4.3 and 4.4 of this Agreement, will purchase allowances to eliminate its shortfall in that calendar year and to provide for its MLR share of the SYSTEM ALLOWANCE BANK. These purchases will be made from Members having SURPLUS ALLOWANCES and will be priced at the SYSTEM COST OF COMPLIANCE. If more than one Member has SURPLUS ALLOWANCES, the buying Member will purchase a proportionate share from the surplus Members. ARTICLE 5 - BILLINGS AND PAYMENTS 5.1 All bills for amounts owing hereunder shall be due and payable on the fifteenth day of the month next following the month to which a settlement has been rendered, or on the tenth day following the receipt of the bill, whichever date is later. Interest on unpaid amounts shall accrue daily at the prime interest rate per annum in effect on the due date at Citibank, plus 2% per annum, from the due date until the date upon which payment is made. Unless otherwise agreed upon, the calendar month shall be the standard period for the purpose of settlements under this Agreement. If bills cannot be accurately determined at any time, they shall be rendered on an estimated basis and subsequently adjusted to conform to the terms of this Agreement. ARTICLE 6 - TAXES 6.1 If at any time during the duration of this Agreement there should be levied and/or assessed by any governmental authority against any Member any tax related to the receipt of settlements calculated pursuant to Article 5 of this Agreement (including, but not limited to sales, excise, etc.), the tax expense incurred by such Member that would not have been incurred were the allowance settlements hereunder not being made, such Member shall be entitled to reimbursement of the tax expense from the Member generating the tax expense. ARTICLE 7 - MODIFICATIONS 7.1 Any Member, by written notice given to the other Members and Agent, may call for a reconsideration of the terms and conditions herein provided. If such reconsideration is called for, the Members shall take into account any changed conditions, any results from the application of said terms and conditions, and any other facts that might cause said terms and conditions to result in an inequitable sharing of costs and benefits under this Agreement. Any modification in terms and conditions agreed to by the Members shall be subject to appropriate regulatory approval and become effective the first day of the month following regulatory authorization. ARTICLE 8 - EFFECTIVE DATE AND TERMS OF THIS AGREEMENT 8.1 This Agreement shall become effective and shall become a binding obligation of the Parties on January 1, 1995, or such other effective date determined by FERC. 8.2 This Agreement shall continue in effect from the effective date until the effective date of any subsequent agreement. ARTICLE 9 - REGULATORY AUTHORITIES 9.1 The Members recognize that this Agreement, and any tariff or rate schedule which shall embody or supersede this Agreement or any part thereof, are in certain respects subject to the jurisdiction of the FERC under the Federal Power Act, and are also subject to such lawful action as any regulatory authority having jurisdiction shall hereinafter take with respect thereto. The performance of any obligation of the Members shall be subject to the receipt of such authorizations, approvals or actions of regulatory authorities having jurisdiction as shall be required by law. 9.2 It is expressly understood that the Members shall be entitled, at any time unilaterally, to make application to the FERC for a change in the rates, charges, classification of service, or any rule, regulation or contract relating thereto, or to make any change in or supersede in whole or in part any provision of the this Agreement, under Section 205 of the Federal Power Act and pursuant to the FERC's Rules and Regulations promulgated thereunder. ARTICLE 10 - ASSIGNMENT 10.1 This Agreement shall accrue to the benefit of and be binding upon the successors and assigns of the respective parties. IN WITNESS WHEREOF, the parties hereto have caused the Agreement to be executed in their respective corporate names and on their behalf by their proper officers thereunto duly authorized as of the day and year first above written. APPALACHIAN POWER COMPANY By: (Signature on Original Document) -------------------------------- COLUMBUS SOUTHERN POWER COMPANY OHIO POWER COMPANY By: (Signature on Original Document) -------------------------------- INDIANA MICHIGAN POWER COMPANY By: (Signature on Original Document) -------------------------------- KENTUCKY POWER COMPANY By: (Signature on Original Document) -------------------------------- AMERICAN ELECTRIC POWER SERVICE CORPORATION By: (Signature on Original Document) -------------------------------- WHEREAS, APPALACHIAN POWER COMPANY (APCO), a Virginia corporation, COLUMBUS SOUTHERN POWER COMPANY (CSP), an Ohio corporation, INDIANA MICHIGAN POWER COMPANY (I&M), an Indiana corporation, KENTUCKY POWER COMPANY (KPCO), a Kentucky corporation, OHIO POWER COMPANY (OPCO), an Ohio corporation, said companies (herein sometimes called 'Members' when referred to collectively and 'Member' when referred to individually) being affiliated companies of the integrated public utility electric system known as the American Electric Power System (AEP), and AMERICAN ELECTRIC POWER SERVICE CORPORATION (Agent), a New York corporation, being a service company engaged solely in the business of furnishing essential services to the aforesaid companies and the other affiliated companies, all of whom are currently doing business as American Electric Power, desire to establish a mechanism for the allocation of emission allowance costs and proceeds associated with purchases and sales with non-affiliated entities; and WHEREAS, the Members desire to amend the AEP System Interim Allowance Agreement dated July 28, 1994 to reflect this mechanism and to effect certain other changes to the Agreement; and WHEREAS, except as changed by amendments, the AEP System Interim Allowance Agreement remains in full force and effect. NOW THEREFORE, the Members adopt the document attached hereto showing the proposed amendments to the AEP System Interim Allowance Agreement in a form in which deletions appear as struck-through text and additions appear as shaded text, as "Modification No. 1 to the AEP System Interim Allowance Agreement By and Among Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company, Ohio Power Company and With American Electric Power Service Corporation As Agent." Agreed to this ______ day of June, 1996. By: /s/ William J. Lhota --------------------------------- William J. Lhota Title: President and Chief Operating Officer of Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company, and Ohio Power Company; and Executive Vice President of American Electric Power Service Corporation, collectively doing business as American Electric Power EX-13 9 AEPCO 1996 ANNUAL REPORT AMERICAN ELECTRIC POWER 1 Riverside Plaza Columbus, Ohio 43215-2373 CONTENTS Selected Consolidated Financial Data Management's Discussion and Analysis of Financial Condition and Results of Operations Consolidated Statements of Income and Consolidated Statements of Retained Earnings Consolidated Statements of Cash Flows Consolidated Balance Sheets Notes to Consolidated Financial Statements Schedule of Consolidated Cumulative Preferred Stocks of Subsidiaries Schedule of Consolidated Long-term Debt of Subsidiaries Management's Responsibility Independent Auditors' Report AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES SELECTED CONSOLIDATED FINANCIAL DATA
Year Ended December 31, 1996 1995 1994 1993 1992 INCOME STATEMENTS DATA (in millions): Operating Revenues $5,849 $5,670 $5,505 $5,269 $5,045 Operating Income 1,008 965 932 929 883 Net Income 587 530 500 354 468 December 31, 1996 1995 1994 1993 1992 BALANCE SHEETS DATA (in millions): Electric Utility Plant $18,970 $18,496 $18,175 $17,712 $17,509 Accumulated Depreciation and Amortization 7,550 7,111 6,827 6,612 6,281 Net Electric Utility Plant $11,420 $11,385 $11,348 $11,100 $11,228 Total Assets $15,886 $15,902 $15,739 $15,362 $14,217 Common Shareholders' Equity 4,545 4,340 4,229 4,151 4,245 Cumulative Preferred Stocks of Subsidiaries: Not Subject to Mandatory Redemption 90 148 233 268 535 Subject to Mandatory Redemption* 510 523 590 501 234 Long-term Debt* 4,884 5,057 4,980 4,995 5,311 Obligations Under Capital Leases* 414 405 400 284 300 *Including portion due within one year Year Ended December 31, 1996 1995 1994 1993 1992 COMMON STOCK DATA: Earnings per Share $3.14 $2.85 $2.71 $1.92 $2.54 Average Number of Shares Outstanding (in thousands) 187,321 185,847 184,666 184,535 184,535 Market Price Range: High $44-3/4 $40-5/8 $37-3/8 $40-3/8 $35-1/4 Low 38-5/8 31-1/4 27-1/4 32 30-3/8 Year-end Market Price 41-1/8 40-1/2 32-7/8 37-1/8 33-1/8 Cash Dividends Paid $2.40 $2.40 $2.40 $2.40 $2.40 Dividend Payout Ratio 76.5% 84.1% 88.6% 125.2% 94.6% Book Value per Share $24.15 $23.25 $22.83 $22.50 $23.01
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Business Outlook With the issuance of two Federal Energy Regulatory Commission (FERC) orders and the commencement of planning for retail competition at the state level, we are in a better position to identify and develop strategies for addressing the issues that face American Electric Power (AEP) and our changing industry. We recognize that the conventional ways of maintaining and enhancing shareholder value are becoming less effective as the industry moves towards greater competition in the generation and sale of electricity. The industry's transition to competition and customer choice and the ability to fully recover costs are probably the most significant factors affecting AEP's future profitability. Although AEP has the financial strength, geographic reach, location and cost structure to be an able competitor, no assurance can be given that AEP can maintain this position in the future. However, we intend to make every effort to maintain and strengthen our competitive position. We see a link between a smooth transition to a competitive marketplace and the maintaining and enhancing of shareholder value. The new FERC orders facilitate increased competition in both the generation and sale of bulk power to wholesale customers. They provide, among other things, for open access to transmission facilities. AEP's support of the FERC's open access transmission rule is evidenced by our being among the first to file a comparability tariff, offering access to our transmission grid at 143 interconnections to all parties under the same terms and conditions available to AEP. This has provided AEP with greater opportunities for transmission service revenues. Although customer choice proposals and discussions are under way in the states in which we operate, it is difficult to predict their result and the timing of any resultant changes. We are actively involved in discussions on the state and federal level regarding how best to transition to competition in order to represent the best interests of our customers, shareholders and employees. We favor a transition because we believe that AEP will in the long-term fare better in a competitive market than under continued regulation. As the electric energy market evolves from cost-of-service ratemaking to market-based pricing, many complex issues must be resolved, including the recovery of stranded costs. While the new FERC orders provide, under certain conditions, for recovery of stranded costs at the wholesale level, the issue of stranded cost remains open at the much larger state retail level. Stranded Costs Stranded costs occur when a customer switches to a new supplier for its electric energy needs or when a component of the business, for example generation, is no longer subject to cost-based regulation, creating the issue of who pays for plant investment, purchased power or fuel contracts both non-affiliated and affiliated, inventories, construction work in progress, nuclear decommissioning, plant removal and shutdown costs, previously deferred costs (regulatory assets) and other investments and commitments that are no longer needed, economic or recoverable in a competitive market. The amount of any stranded costs AEP may experience depends on the timing of and the extent to which direct competition is introduced to our business and the then-existing market price of energy. Under the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation," assets (deferred expenses) and liabilities (deferred revenues) are included in the consolidated financial statements in accordance with regulatory actions to match expenses and revenues in cost-based rates. In the event a portion of the business no longer met the requirements of SFAS 71, net regulatory assets would have to be written off for that portion of the business. Among other requirements SFAS 71 requires that the rates charged customers be cost based. Our generation business is still cost-based regulated and should remain so for at least three to five years as the industry transitions to full competition. Although the recent FERC orders provide for competition in the firm wholesale market, that market is a relatively small part of our business and many of our firm wholesale sales are still under cost-of-service contracts. We believe that enabling state legislation should provide for a sufficient transition period to allow for the recovery of any generation-related stranded costs and we are dedicating ourselves to work with regulators, customers and legislators to accomplish both an orderly transition and a reasonable and fair disposition of the stranded cost issue. We favor the recovery of stranded costs during a transition period in which rates would be fixed or frozen and electric utilities would take steps to achieve cost savings which would be used to reduce or eliminate stranded costs. However, if electric utilities were to no longer be cost-based regulated and it were not possible to recover stranded costs, the results of operations and financial condition of AEP and other electric utilities would be adversely affected. Since state commissions have jurisdiction over the sale and distribution of electricity to retail customers, we believe that state legislation and regulation should shape the future competitive market for electricity while federal legislation should seek to ensure reciprocity among the states and a level playing field for all power suppliers. Presently states with higher cost power, like California and Massachusetts, are aggressively pursuing deregulation. The states AEP operates in, however, are generally addressing the call for customer choice more cautiously and the transition to competition is expected to evolve at an uneven pace across the states. Restructuring/Functional Unbundling In 1996 we took some major steps to maintain and enhance AEP's competitive strength and made progress towards our long-term goal of becoming the world's premier supplier of energy and related services. We restructured our management and operations to allow us to comply with the new FERC orders by separating our generation and energy sales operations from our energy transmission delivery operations and to address increasing competition among electric suppliers through distinct functional business units. This has achieved and should continue to achieve staffing, managerial and operating efficiencies. The generation and marketing business units expect to eventually compete in an open market for customers. Our energy delivery business will remain regulated and may ultimately be subject to some form of incentive or performance-based ratemaking while Corporate Development and Marketing will be working to cultivate new but related non-regulated business opportunities. Corporate Branding and Positioning We are enhancing our marketing and customer service efforts with programs like the Key Accounts Program which strives to build strong partnerships with key customers in order to build customer loyalty. In 1996 AEP also launched a series of new television commercials as part of a branding campaign to inform our customers that we will be operating under the name American Electric Power and that we are AEP: America's Energy Partner. The commercials are intended to position AEP as more than just a supplier of electricity. As we enter an increasingly competitive energy market we want to be the energy and energy services provider of choice. New Business Opportunities In the non-rate-regulated environment, AEP offers energy consulting and project management services both domestically and internationally and contracts with other public utilities and government agencies for the licensing of intellectual property and the delivery of energy services. In 1996 an AEP subsidiary and two Chinese companies formed a joint venture company to finance and build a 250-megawatt electric generating facility in China. AEP's share of the total cost of the facility is approximately $120 million and the project is expected to be operational in 1999. On February 24, 1997 AEP and Public Service Company of Colorado with equal interests in a joint venture announced a cash tender offer for Yorkshire Electricity Group plc in the United Kingdom. The joint venture proposes to pay $2.4 billion to acquire all of the stock of Yorkshire Electricity. AEP's equity invest-ment, estimated to be $360 million, will be made through its subsidiary AEP Resources Inc., initially using cash borrowed under a revolving credit agreement. We consider the China investment and Yorkshire tender offer as important steps in our long-term goal to become the premier provider of energy and energy services worldwide. In addition to pursuing foreign power generation, transmission and distribution investments we formed new subsidiaries in 1996 to explore other new complementary business opportunities including AEP Communications, Inc. which was formed to provide data transmission and related telecommunications products and services. In January 1997 AEP Communications, Inc. entered into an agreement with Sprint Communications, Inc. to construct jointly a 150 mile fiber optic line between Charleston, West Virginia and Roanoke, Virginia. Another new subsidiary AEP Power Marketing is presently seeking approval to market and broker power outside of our traditional service territory. Plans are also in place to commence gas marketing. We are pursuing non-regulated related business opportunities because we believe they offer the opportunity to earn enhanced returns as compared with our traditional regulated business. However, we recognize that these opportunities are generally riskier. Investments in new business opportunities may be made after management carefully assesses the risks versus the potential for enhanced shareholder value. Cost Containment In 1996 we continued our efforts to reduce costs in order to maintain our competitiveness. Reviews of our major processes led to decisions to consolidate the management and operations of internal service functions performed at multiple locations. Among the functions being consolidated are fossil generation plant maintenance, nuclear operations support staff, system operations, accounting and load research. A study of the Company's procurement and supply chain operations led to cost reductions through better inventory management, just-in-time delivery and the increased use of electronic purchasing. Also in 1996 we completed the installation of an activity based management budgeting system throughout the system. This tool will enable managers to better analyze work and control costs. While staff reductions and cost savings are being achieved in these and other areas, expenses for new marketing and customer services and modern efficient management information systems are being increased to prepare for competition. These expenditures for the future should produce further improvements and efficiencies, enabling AEP to maintain its position as a low-cost producer. Fuel Costs Coal is 70% of the production cost of electricity for AEP. Although our coal costs per unit of electricity (per Kwh) have declined by one-half in constant dollars in the last 10 years, we recognize that we must continue to manage our coal costs to continue to maintain our competitive position. Approximately 15% of the coal we burn is supplied by affiliated mines; the remainder is acquired under long-term contracts and in the spot market. As long-term contracts expire we are negotiating with non-affiliated suppliers to lower purchased coal costs. Efforts also continued in 1996 to reduce the cost of affiliated coal. We intend to continue to prudently supplement our long-term coal supplies with spot market purchases as long as favorable spot market prices exist. In recent years we have agreed in our Ohio jurisdiction to certain limitations on the recovery of affiliated coal costs. Our analysis shows that we should be able to recover over the term of the agreement (through 2009) the Ohio jurisdictional portion of the current and deferred costs of our affiliated mining operations including future mine closure costs. Management intends to seek recovery of its non-Ohio jurisdictional portion of the investment in and the liabilities and closing costs of our affiliated mines estimated at $180 million after tax. However, should it become apparent that the costs will not be recoverable from Ohio and/or non-Ohio jurisdictional customers, the mines may have to be closed and future earnings and possibly financial condition adversely affected. In addition compliance with Phase II requirements of the Clean Air Act, which become effective in January 2000, could also cause the mining operations to close. Unless the cost of any mine closure is recovered either in regulated rates or as a stranded cost in a transition to competition, future earnings and possibly financial condition could be adversely affected. Nuclear Costs Significant efforts have been made to enhance our competitiveness in nuclear power generation and to improve our nuclear organizational efficiency. Net generation in 1996 for the Company's only nuclear plant, the two-unit Donald C. Cook Nuclear Plant, located on the shores of Lake Michigan, was 16,396 gigawatts, the highest in the plant's 20-year history. The generation record was set in part due to Unit 2's best continuous run in its history, 226 days, reached in December 1996. Refueling costs and related outage time have been reduced. We also reduced nuclear staff support costs in 1996 by relocating our Columbus-based nuclear management and support staff to Michigan to consolidate it with the plant staff. It is difficult to reduce nuclear generation costs since certain major cost components are impacted by federal laws and Nuclear Regulatory Commission (NRC) regulations. The Nuclear Waste Policy Act of 1982 established federal responsibility for the permanent off-site disposal of spent nuclear fuel and high-level radioactive waste. By law we participate in the Department of Energy's (DOE's) Spent Nuclear Fuel (SNF) disposal program which is described in Note 4 of the Notes to Consolidated Financial Statements. Since 1983 our customers have paid $254 million for the disposal of spent nuclear fuel consumed at the Cook Nuclear Plant. Under the provisions of the Nuclear Waste Policy Act, collections from customers are to provide the DOE with money to build a repository for spent fuel. To date the federal government has not made sufficient progress towards a permanent repository or otherwise assuming responsibility for SNF. As long as there is a delay in the storage repository for SNF, the cost of both temporary and permanent storage will continue to increase. The cost to decommission the Cook Nuclear Plant is also affected by NRC regulations and the DOE's SNF disposal program. Studies completed in 1994 estimate the cost to decommission the Cook Nuclear Plant and dispose of low-level nuclear waste accumulation to range from $634 million to $988 million in 1993 dollars. This estimate could escalate due to uncertainty in the DOE's SNF disposal program and the length of time that SNF may need to be stored at the plant site delaying decommissioning. Presently we are recovering the estimated cost of decommissioning the Cook Nuclear Plant over its remaining life. However, AEP's future results of operations and possibly its financial condition could be adversely affected if the cost of spent nuclear fuel disposal and decommissioning continues to increase and cannot be recovered in regulated rates or as a stranded cost in a future competitive market. Environmental Concerns We take great pride in our efforts to economically produce and deliver electricity while minimizing the impact on the environment. AEP has spent millions of dollars to equip our facilities with the latest economical clean air and water technologies and to research possible new technologies. We are also proud of our award winning efforts to reclaim our mining properties. We intend to continue to take a leadership role to foster economically prudent efforts to protect and preserve the environment. Hazardous Material By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and spent nuclear fuel. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically disposed of or treated in captive disposal facilities or are beneficially utilized. In addition, our generating plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls (PCBs) and other hazardous and non-hazardous materials. We are currently incurring costs to safely dispose of such substances, and additional costs could be incurred to comply with new laws and regulations if enacted. The Comprehensive Environmental Response, Compensation and Liability Act (CERCLA or Superfund) addresses clean-up of hazardous substances at disposal sites and authorized the United States Environmental Protection Agency (Federal EPA) to administer the clean-up programs. As of year-end 1996, we are currently involved in litigation with respect to five sites being overseen by the Federal EPA and have been named by the Federal EPA as "Potentially Responsible Parties" (PRPs) for six other sites. There are eight additional sites for which AEP companies have received information requests which could lead to PRP designation. Also, an AEP subsidiary has received an information request with respect to one site administered by state authorities. Our liability has been resolved for a number of sites with no significant effect on results of operations. In those instances where we have been named a PRP or defendant, our disposal or recycling activity was in accordance with the then-applicable laws and regulations. Unfortunately, CERCLA does not recognize compliance as a defense, but imposes strict liability on parties who fall within its broad statutory categories. While the potential liability for each Superfund site must be evaluated separately, several general statements can be made regarding such potential liability. The disposal at a particular site by AEP is often unsubstantiated; the quantity of material we disposed of at a site was generally small; and the nature of the material we generally disposed of was non-hazardous. Typically, we are one of many parties named as PRPs for a site and, although liability is joint and several, generally some of the other parties are financially sound enterprises. Therefore, our present estimates do not anticipate material cleanup costs for identified sites for which we have been declared PRPs. However, if for reasons not currently identified significant costs are incurred for cleanup, future results of operations and possibly financial condition would be adversely affected unless the costs can be recovered from customers. Federal EPA Actions Federal EPA is required by the Clean Air Act Amendments of 1990 (CAAA) to issue rules to implement the law. In December 1996 Federal EPA issued final rules governing nitrogen oxide emissions that must be met after January 1, 2000 (Phase II of the CAAA). The final rules will require substantial reductions in nitrogen oxide emissions from certain types of power plant boilers including those in AEP's power plants. In December 1996 a group of utilities including AEP operating companies filed a petition for review of the rules in a U.S. Court of Appeals and requested expedited consideration of the appeal. The cost to comply with the emission reductions required by the final rules is expected to be substantial and could have a material adverse impact on results of operations and possibly financial condition if these costs are not recovered from customers. Federal EPA is considering proposals to revise the existing ambient air quality standard for ozone and to establish a new ambient air quality standard for fine particulate matter. The rules being considered could result in requirements for reductions of nitrogen oxides and sulfur dioxide emitted from coal fired power plants and could have a significant impact on AEP's operations. The proposals being considered are of particular concern because they do not appear to have a sound scientific basis. The cost of complying with any new emission reduction requirements imposed as a result of the adoption of revised ambient air quality standards can not be precisely determined but could be substantial. If Federal EPA ultimately promulgates stricter ambient air quality standards, they could have a material adverse impact on results of operations and possibly financial condition if these costs are not recovered from customers. Results of Operations 1996 was a good year for AEP with earnings the best since 1989 and total shareholder return placing us among the best in our industry. We continued to be well within our goal of being in the upper quartile of the companies in the Standard & Poor's electric utility index, based on cumulative three-year return. Earnings Increase In 1996 earnings increased 11% to $587 million or $3.14 per share from $530 million or $2.85 per share in 1995. The increase is mainly attributable to increased sales of energy and services and reduced interest charges and preferred stock dividends. Sales increased due to increased transmission and other services provided to power marketers and utilities and increased energy sales to non-affiliated utilities and industrial customers. The reduction in interest and preferred stock dividends resulted from the Company's refinancing program. Also contributing to the improvement in earnings were severance pay charges recorded in 1995 in connection with realigning operations and management and gains recorded in 1996 from emission allowance transactions. Earnings increased 6% in 1995 to $530 million or $2.85 per share from $500 million or $2.71 per share in 1994. The primary reason for the earnings improvement was increased retail energy sales reflecting increased usage and growth in the number of customers. Unseasonably warm weather in the summer of 1995 and colder weather in the fourth quarter of 1995, were the primary factors accounting for the increased usage. The positive earnings impact of the increased sales was partly offset by the unfavorable effect of severance pay. Revenues And Sales Increase Operating revenues increased 3% in 1996 and 1995. Increased wholesale energy sales and transmission and coal conversion service revenues were the primary reasons for the increase in 1996 revenues. In 1995 the revenue increase resulted primarily from an increase in retail customers' energy usage, growth in the number of retail customers and the effects of rate increases. The change in revenues can be analyzed as follows: Increase (Decrease) From Previous Year (Revenues in Millions) 1996 1995 Amount % Amount % Retail: Price Variance $ (42.9) $ 46.5 Volume Variance 63.7 173.0 Fuel Cost Recoveries 15.0 (22.9) 35.8 0.7 196.6 4.2 Wholesale: Price Variance (202.0) (39.3) Volume Variance 317.3 10.8 Fuel Cost Recoveries (3.6) (4.6) 111.7 16.4 (33.1) (4.6) Other Operating Revenues 31.4 2.2 Total $ 178.9 3.2 $165.7 3.0 In 1996 retail revenues increased slightly due to growth in the number of customers and the addition of a major new industrial customer in December 1995. Revenues from sales to residential customers, the most weather-sensitive customer class, were flat, increasing less than one percent, as the effect of cold winter weather in early 1996 was offset by mild summer and December temperatures. Revenues from commercial and industrial customers increased 1% reflecting growth in the number of customers. Wholesale revenues increased 16% in 1996 reflecting a 46% increase in wholesale sales attributable largely to new wholesale transactions with power marketers and other utilities. As the wholesale energy market evolves into a competitive marketplace the Company intends to take advantage of new ways to market and price electricity and related services. During 1996 the Company provided coal conversion services resulting in 6.8 billion kilowatthours of electricity generated for power marketers and certain other utilities under a new FERC-approved interruptible, contingent sales tariff. As a result of these new sales, the average price per kilowatthour was significantly less in 1996 than in 1995. Also contributing to the increased wholesale sales was a new long-term contract with an unaffiliated utility to supply 205 MW of energy for 15 years beginning January 1, 1996. An increased level of activity in the wholesale energy markets encouraged by the 1996 issuance of FERC open access transmission rules and AEP's aggressive efforts to provide flexible and competitively priced transmission services led to an increase in transmission service revenues. As a result transmission revenues, which are recorded in other operating revenues, increased by approximately $24 million. The increase in 1995 operating revenues resulted primarily from a 4% increase in energy sales to retail customers due mainly to increased usage and continued growth in the number of customers in all retail customer classes. Energy sales to residential customers, the most weather-sensitive customer class, rose more than 6% in 1995 mainly as a result of increased weather related usage in the last half of the year. Sales to commercial and industrial customers rose 5% and 2%, respectively, reflecting the effects of weather and the expanding economy. Although revenues from wholesale customers declined in 1995, wholesale energy sales increased by more than 1% largely due to increased short-term sales made on an hourly basis to unaffiliated utilities. This type of short-term sale is typically made when the unaffiliated utility can purchase energy at a lower cost than the cost at which that utility can generate the energy or when the customer is short on generating capacity. Such sales increase in periods of extreme weather. The increase in 1995 wholesale energy sales occurred during the last six months of the year when the summer was unseasonably warm and fall temperatures were colder compared with the prior year. While wholesale energy sales increased, wholesale revenues declined in 1995 reflecting increasing price related competition. The level of wholesale sales tends to fluctuate due to the highly competitive nature of the short-term energy market and other factors, such as unaffiliated generating plant availability, the weather and the economy. The recently adopted FERC rules which introduce a greater degree of competition into the wholesale energy market have had the effect of increasing short-term wholesale sales and transmission service revenues. The Company's sales and in turn its results of operations were impacted in 1996 and prior years by the quantities of energy and services sold in wholesale transactions. Future results of operations will be affected by the quantity and price of wholesale transactions which often depends on the weather and power plant availability. Operating Expenses Increase Operating expenses increased 3% in 1996 and 1995. The primary items accounting for the increase in 1996 were increased fuel costs, federal income taxes and expenditures for marketing, information systems and other items necessary to prepare for the transition to competition. In 1995 increased rent and related operating costs of the newly installed Gavin Plant flue gas desulfurization systems (scrubbers) and expenses related to severance pay charges were the main reasons for the increase in operating expenses. Changes in the components of operating expenses were as follows: Increase (Decrease) From Previous Year (Dollars in Millions) 1996 1995 Amount % Amount % Fuel and Purchased Power $ 61.2 3.8 $(119.7) (6.9) Other Operation 25.9 2.2 181.3 18.1 Maintenance (39.0) (7.2) (2.4) (0.5) Depreciation and Amortization 7.8 1.3 20.8 3.6 Taxes Other Than Federal Income Taxes 9.4 1.9 (5.0) (1.0) Federal Income Taxes 70.2 25.8 58.6 27.5 Total $135.5 2.9 $ 133.6 2.9 Fuel and purchased power expense increased in 1996 due to an increase in generation to meet the increase in industrial and wholesale customer demand. The effect of increased generation was partially offset by reduced average fossil fuel costs resulting from increased usage of lower cost spot market coal and lower cost nuclear fuel. Although generation increased 3% in 1995, fuel and purchased power expense declined as a result of a decrease in the average cost of fossil fuel resulting from reduced coal prices reflecting the renegotiation of certain long-term coal contracts and other lower priced purchases under existing and new contracts. Other factors which reduced fuel and purchased power expense in 1995 were increased utilization of low cost nuclear generation; decreased energy purchases due to the mild weather during the first half of 1995 and the operation of fuel clause mechanisms. Changes in fuel expense are generally deferred pending recovery in various fuel clause mechanisms, as such they generally do not affect earnings. The significant increase in other operation expense during 1995 was primarily due to rent and other operating costs of the Gavin Plant scrubbers which went into service in December 1994 and the first quarter of 1995; a $41 million ($27 million after-tax) provision for severance pay recorded in 1995 related mainly to a functional realignment of operations; and costs related to the development of a new activity based budgeting system. Maintenance expense decreased in 1996 due to the recovery of previously expensed storm damage costs and reduced nuclear plant maintenance expense due to workforce reductions and the reduction of contract labor at the Cook Nuclear Plant. The increases in federal income tax expense attributable to operations was primarily due to an increase in pre-tax operating income and changes in certain book/tax differences accounted for on a flow-through basis and in 1995 the effects of accrual adjustments for prior year tax returns. Nonoperating Income Nonoperating income decreased in 1996 due to the cost of the AEP branding program and startup costs of the new business ventures. The increase in nonoperating income in 1995 was mainly due to a 1994 loss of $8.2 million on a demand side management investment. Interest Charges and Preferred Stock Dividend Requirements In 1996 interest charges and preferred stock dividend requirements decreased as the Company's subsidiaries continued their refinancing programs. The programs reduced the average interest rate and the amount of long-term debt and preferred stock outstanding. The cost of short-term borrowings in 1996 increased slightly re-flecting an increased average balance of short-term debt outstanding. Interest charges increased in 1995 mainly due to an increase in interest on short-term debt resulting from a higher average interest rate in 1995 on larger levels of outstanding short-term debt. Common Dividend Remains Constant; Payout Ratio Decreases The Company paid a quarterly dividend in 1996 of 60 cents a share maintaining the annual dividend rate at $2.40 per share. The payout ratio continued an improving trend to 76% in 1996 from 84% in 1995 and 89% in 1994. It has been a management objective to reduce the payout ratio through efforts to increase earnings in order to enhance AEP's ability to invest in new business ventures that complement our core competencies and can maintain and improve shareholder value. Liquidity and Capital Resources Electric utility construction expenditures in the United States have been declining in recent years due to slow growth in the demand for electricity, environmental restrictions, and delays in obtaining approvals to construct transmission facilities. Demand-side management programs such as direct load control, interruptible load, energy efficiency, and other demand and load reduction programs have lessened the need for new plant expenditures. Also in some parts of the country substantial portions of new generation additions have been by non-utility entities. AEP's construction expenditures have followed the industry trend and have been generally declining since 1991 when we last completed a new generating facility. Our electric generating plant expenditures for 1996 accounted for only 27% of the total electric utility plant expenditures, as compared to the historic level of investment in electric generating plant of 49%. Transmission and distribution (T&D) expenditures, on the other hand, accounted for approximately 68% of expenditures, compared with the historic investment level of 46%. Construction expenditures for our domestic utility operations are estimated to be $2 billion over the next three years with no major plant construction planned for our service territory. Total T&D expenditures will be related to the improvement of and additions to delivery facilities. Approximately 88% of the domestic construction expenditures for the next three years will be financed internally. Allowance for funds used during construction (AFUDC) accruals also declined during this period. The decline in AFUDC in recent years is primarily due to the decrease in the level of generation plant construction combined with a decrease in interest rates. The operating subsidiaries generally issue short-term debt to provide for interim financing of capital expenditures that exceed internally generated funds. They periodically reduce their outstanding short-term debt through issuances of long-term debt and historically preferred stock and with additional capital contributions by the parent company. In 1996 short-term borrowing decreased by $45 million. At December 31, 1996 American Electric Power Co., Inc. (the parent company) and its utility subsidiaries had unused short-term lines of credit of $409 million, and several of AEP's subsidiaries engaged in providing non-regulated energy services had an unused line of credit of $100 million available under a revolving credit agreement. In February 1997 the credit available under the revolving credit agreement was increased to $500 million. The sources of funds available to the parent company are dividends from its subsidiaries, short-term and long-term borrowings and, when necessary, proceeds from the issuance of common stock. The parent company issued 1,600,000 shares in 1996, 1,400,000 shares in 1995 and 700,000 shares in 1994 of common stock through a Dividend Reinvestment Program raising $65 million, $49 million and $22 million, respectively. As a result of the common stock issuances and the reduction in long-term debt over the past several years, the common equity to capitalization ratio has steadily improved. At December 31, 1996 the ratio increased to 45.3% from 43.1% at year-end 1995 and from 42.1% at year-end 1994. The debt and preferred stock coverages of the principal operating subsidiaries remained strong in 1996. Coverages at December 31, 1996 Mortgage and Preferred Long-term Debt Stock Appalachian Power Co. 3.98 1.99 Columbus Southern Power Co. 4.44 N/A Indiana Michigan Power Co. 6.66 3.07 Kentucky Power Co. 3.22 N/A Ohio Power Co. 6.62 3.63 N/A = Not Applicable Unless the subsidiaries meet certain earnings or coverage tests, they cannot issue additional mortgage bonds or preferred stock. In order to issue mortgage bonds (without refunding existing debt), each subsidiary must have pre-tax earnings equal to at least two times the annual interest charges on mortgage bonds after giving effect to the issuance of the new debt. Generally, issuance of additional preferred stock requires after-tax gross income at least equal to one and one-half times annual interest and preferred stock dividend requirements after giving effect to the issuance of the new preferred stock. The subsidiaries presently exceed these minimum coverage requirements. In January 1997 the Company announced a tender offer for certain subsidiaries' preferred stock in conjunction with special meetings scheduled to be held on February 28, 1997. The special meetings' purpose is to consider amendments to the subsidiaries' articles of incorporation to remove certain capitalization ratio requirements. These restrictions limit the subsidiaries' financial flexibility and could place them at a competitive disadvantage in the future. The amount paid to redeem the preferred stock that is tendered could total as much as $514 million. The subsidiaries expect to use a combination of short-term debt and unsecured long-term debt to pay for the preferred stock tendered. Litigation AEP is involved in a number of legal proceedings and claims. While we are unable to predict the outcome of such litigation, it is not expected that the ultimate resolution of these matters will have a material adverse effect on the results of operations and/or financial condition. Effect of Inflation Inflation affects AEP's cost of replacing utility plant and the cost of operating and maintaining its plant. The rate-making process limits our recovery to the historical cost of assets resulting in economic losses when the effects of inflation are not recovered from customers on a timely basis. However, economic gains that results from the repayment of long-term debt with inflated dollars partly offset such losses. Corporate Owned Life Insurance In connection with the audit of AEP's 1991, 1992 and 1993 federal income tax returns the Internal Revenue Service agents sought a ruling from the IRS National Office that certain interest deductions relating to a corporate owned life insurance (COLI) program should not be allowed. The Company established the COLI program in 1990 as a part of its strategy to fund and reduce the cost of medical benefits for retired employees. AEP filed a brief with the IRS National Office refuting the agents' position. Although no adjustments have been proposed, a disallowance of the COLI interest deductions through December 31, 1996 would reduce earnings by approxiately $247 million (including interest). AEP believes it will ultimately prevail on this issue and will vigorously contest any disallowance that may be assessed. In 1996 Congress enacted legislation that prospectively phases out the tax benefits for COLI interest deductions over a three year period beginning in 1996. As a result the Company intends to restructure its COLI program. The restructuring of the COLI program is not expected to have a material impact on results of operations. New Accounting Rules In 1996 the Financial Accounting Standards Board (FASB) issued an exposure draft "Accounting for Certain Liabilities Related to Closure or Removal of Long-Lived Assets." The proposal suggests that the present value of decommissioning and certain other closure or removal obligations be recorded as a liability when the obligation is incurred. A corresponding asset would be recorded in the plant investment account and recovered through depreciation charges over the asset's life. A proposed transition rule would require that an entity report in income the cumulative effect of initially applying the new standard. The FASB is reconsidering the exposure draft proposal. It is unclear at this time in what manner the FASB will adopt the proposal. Until it becomes apparent what the FASB will decide and how certain questions raised by the exposure draft are resolved the Company cannot determine its impact. AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF INCOME (in thousands - except per share amounts)
Year Ended December 31, 1996 1995 1994 OPERATING REVENUES $5,849,234 $5,670,330 $5,504,670 OPERATING EXPENSES: Fuel and Purchased Power 1,686,754 1,625,531 1,745,245 Other Operation 1,210,027 1,184,158 1,002,822 Maintenance 502,841 541,825 544,312 Depreciation and Amortization 600,851 593,019 572,189 Taxes Other Than Federal Income Taxes 498,567 489,223 494,210 Federal Income Taxes 342,222 272,027 213,399 TOTAL OPERATING EXPENSES 4,841,262 4,705,783 4,572,177 OPERATING INCOME 1,007,972 964,547 932,493 NONOPERATING INCOME 2,212 20,204 11,485 INCOME BEFORE INTEREST CHARGES AND PREFERRED DIVIDENDS 1,010,184 984,751 943,978 INTEREST CHARGES (net) 381,328 400,077 389,240 PREFERRED STOCK DIVIDEND REQUIREMENTS OF SUBSIDIARIES 41,426 54,771 54,726 NET INCOME $587,430 $529,903 $500,012 AVERAGE NUMBER OF SHARES OUTSTANDING 187,321 185,847 184,666 EARNINGS PER SHARE $3.14 $2.85 $2.71 CASH DIVIDENDS PAID PER SHARE $2.40 $2.40 $2.40 CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (in thousands) Year Ended December 31, 1996 1995 1994 RETAINED EARNINGS JANUARY 1 $1,409,645 $1,325,581 $1,269,283 NET INCOME 587,430 529,903 500,012 DEDUCTIONS: Cash Dividends Declared 449,353 445,831 443,101 Other (24) 8 613 RETAINED EARNINGS DECEMBER 31 $1,547,746 $1,409,645 $1,325,581 See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF CASH FLOWS (in thousands)
Year Ended December 31, 1996 1995 1994 OPERATING ACTIVITIES: Net Income $587,430 $529,903 $500,012 Adjustments for Noncash Items: Depreciation and Amortization 590,657 578,003 561,188 Deferred Federal Income Taxes (21,478) 11,916 (16,033) Deferred Investment Tax Credits (25,808) (25,819) (31,275) Amortization of Operating Expenses and Carrying Charges (net) 55,458 53,479 16,022 Changes in Certain Current Assets and Liabilities: Accounts Receivable (net) (39,049) (71,804) 34,302 Fuel, Materials and Supplies 35,831 457 (1,627) Accrued Utility Revenues 32,953 (40,433) 2,419 Accounts Payable (13,915) (31,044) (7,959) Taxes Accrued (6,019) 37,515 (26,521) Other (net) 41,002 14,437 (52,803) Net Cash Flows From Operating Activities 1,237,062 1,056,610 977,725 INVESTING ACTIVITIES: Construction Expenditures (577,691) (605,974) (643,457) Proceeds from Sale of Property and Other 12,283 20,567 49,802 Net Cash Flows Used For Investing Activities (565,408) (585,407) (593,655) FINANCING ACTIVITIES: Issuance of Common Stock 65,461 48,707 22,256 Issuance of Cumulative Preferred Stock - - 88,787 Issuance of Long-term Debt 407,291 523,476 411,869 Retirement of Cumulative Preferred Stock (70,761) (158,839) (35,949) Retirement of Long-term Debt (601,278) (469,767) (445,636) Change in Short-term Debt (net) (45,430) 48,140 38,009 Dividends Paid on Common Stock (449,353) (445,831) (443,101) Net Cash Flows Used For Financing Activities (694,070) (454,114) (363,765) Net Increase (Decrease) in Cash and Cash Equivalents (22,416) 17,089 20,305 Cash and Cash Equivalents January 1 79,955 62,866 42,561 Cash and Cash Equivalents December 31 $57,539 $79,955 $62,866 See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED BALANCE SHEETS (In Thousands - Except Share Data)
December 31, 1996 1995 ASSETS ELECTRIC UTILITY PLANT: Production $ 9,341,849 $ 9,238,843 Transmission 3,380,258 3,316,664 Distribution 4,402,449 4,184,251 General (including mining assets and nuclear fuel) 1,491,781 1,442,086 Construction Work in Progress 353,832 314,118 Total Electric Utility Plant 18,970,169 18,495,962 Accumulated Depreciation and Amortization 7,549,798 7,111,123 NET ELECTRIC UTILITY PLANT 11,420,371 11,384,839 OTHER PROPERTY AND INVESTMENTS 892,674 825,781 CURRENT ASSETS: Cash and Cash Equivalents 57,539 79,955 Accounts Receivable: Customers (less allowance for uncollectible accounts of $3,692 in 1996 and $5,430 in 1995) 415,413 417,854 Miscellaneous 115,919 74,429 Fuel - at average cost 235,257 271,933 Materials and Supplies - at average cost 251,896 251,051 Accrued Utility Revenues 174,966 207,919 Prepayments and Other 103,891 98,717 TOTAL CURRENT ASSETS 1,354,881 1,401,858 REGULATORY ASSETS 1,889,482 1,979,446 DEFERRED CHARGES 328,139 310,377 TOTAL $15,885,547 $15,902,301 See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED BALANCE SHEETS
December 31, 1996 1995 CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock-Par Value $6.50: 1996 1995 Shares Authorized. .300,000,000 300,000,000 Shares Issued . . ..197,234,992 195,634,992 (8,999,992 shares were held in treasury) $ 1,282,027 $ 1,271,627 Paid-in Capital 1,715,554 1,658,524 Retained Earnings 1,547,746 1,409,645 Total Common Shareholders' Equity 4,545,327 4,339,796 Cumulative Preferred Stocks of Subsidiaries:* Not Subject to Mandatory Redemption 90,323 148,240 Subject to Mandatory Redemption 509,900 515,085 Long-term Debt* 4,796,768 4,920,329 TOTAL CAPITALIZATION 9,942,318 9,923,450 OTHER NONCURRENT LIABILITIES 1,002,208 884,707 CURRENT LIABILITIES: Preferred Stock and Long-term Debt Due Within One Year* 86,942 144,597 Short-term Debt 319,695 365,125 Accounts Payable 206,227 220,142 Taxes Accrued 414,173 420,192 Interest Accrued 75,124 80,848 Obligations Under Capital Leases 89,553 89,692 Other 304,323 304,466 TOTAL CURRENT LIABILITIES 1,496,037 1,625,062 DEFERRED INCOME TAXES 2,643,143 2,656,651 DEFERRED INVESTMENT TAX CREDITS 404,050 430,041 DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2 240,598 249,875 DEFERRED CREDITS 157,193 132,515 CONTINGENCIES (Note 4) TOTAL $15,885,547 $15,902,301 *See Accompanying Schedules on pages 36 - 37.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. Significant Accounting Policies: The American Electric Power System (AEP, AEP System or the Company) is a public utility engaged in the generation, purchase, transmission and distribution of electric power to over 2.9 million retail customers in its seven state service territory which covers portions of Ohio, Michigan, Indiana, Kentucky, West Virginia, Virginia and Tennessee. Electric power is also supplied at wholesale to neighboring utility systems and power marketers. The organization of the AEP System consists of American Electric Power Company, Inc., the parent holding company; seven electric utility operating companies (utility subsidiaries); a generating subsidiary, AEP Generating Company (AEPGEN); a service company, American Electric Power Service Corporation (AEPSC); three active coal-mining companies and a group of subsidiaries that complement utility activities. The following utility subsidiaries pool their generating and transmission facilities and operate them as an integrated system: - - Appalachian Power Company (APCo) - - Columbus Southern Power Company (CSPCo) - - Indiana Michigan Power Company (I&M) - - Kentucky Power Company (KEPCo) - - Ohio Power Company (OPCo) The remaining two utility subsidiaries, Kingsport Power Company and Wheeling Power Company, are distribution companies that purchase power from APCo and OPCo, respectively. AEPSC provides management and professional services to the AEP System. The active coal-mining companies are wholly-owned by OPCo and sell most of their production to OPCo. AEPGEN has a 50% interest in the Rockport Plant which is comprised of two of the AEP System's six 1,300 megawatt (mw) generating units. The group of subsidiaries that complement utility activities are engaged in providing non-regulated energy services and are seeking and considering new business opportunities domestically and internationally that will permit AEP to utilize its expertise and core competencies. Effective January 1, 1996, AEPSC and the seven utility subsidiaries began operating as American Electric Power. There has been no change to the legal names of these companies. The AEP System's operations are divided into major business units which are managed centrally by AEPSC. Rate Regulation - The AEP System is subject to regulation by the Securities and Exchange Commission (SEC) under the Public Utility Holding Company Act of 1935 (1935 Act). The rates charged by the utility subsidiaries are approved by the Federal Energy Regulatory Commission (FERC) or one of the state utility commissions as applicable. The FERC regulates wholesale rates and the state commissions regulate retail rates. Principles of Consolidation - The consolidated financial statements include American Electric Power Company, Inc. (AEPCo., Inc.) and its wholly-owned subsidiaries consolidated with their wholly-owned subsidiaries. Significant intercompany items are eliminated in consolidation. Basis of Accounting - As the owner of cost-based rate-regulated electric public utility companies, AEPCo., Inc.'s consolidated financial statements reflect the actions of regulators that result in the recognition of revenues and expenses in different time periods than enterprises that are not rate regulated. In accordance with Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation," regulatory assets (deferred expenses) and regulatory liabilities (deferred income) are recorded to reflect the economic effects of regulation. Use of Estimates - The preparation of these financial statements in conformity with generally accepted accounting principles requires in certain instances the use of management's estimates. Actual results could differ from those estimates. Utility Plant - Electric utility plant is stated at original cost and is generally subject to first mortgage liens. Additions, major replacements and betterments are added to the plant accounts. Retirements from the plant accounts and associated removal costs, net of salvage, are deducted from accumulated depreciation. The costs of labor, materials and overheads incurred to operate and maintain utility plant are included in operating expenses. Allowance for Funds Used During Construction (AFUDC) - AFUDC is a noncash nonoperating income item that is recovered over the service life of utility plant through depreciation and represents the estimated cost of borrowed and equity funds used to finance construction projects. The average rates used to accrue AFUDC were 6.09%, 6.91%, and 6.59% in 1996, 1995 and 1994, respectively. Depreciation, Depletion and Amortization - Depreciation is provided on a straight-line basis over the estimated useful lives of property other than coal-mining property and is calculated largely through the use of composite rates by functional class as follows: Composite Functional Class Depreciation of Property Annual Rates Production: Steam-Nuclear 3.4% Steam-Fossil-Fired 3.2% to 4.4% Hydroelectric-Conventional and Pumped Storage 2.7% to 3.2% Transmission 1.7% to 2.7% Distribution 3.3% to 4.2% General 2.5% to 3.8% The utility subsidiaries presently recover amounts to be used for demolition of non-nuclear plant through depreciation charges included in rates. Depreciation, depletion and amortization of coal-mining assets is provided over each asset's estimated useful life, ranging up to 30 years, and is calculated using the straight-line method for mining structures and equipment. The units-of-production method is used to amortize coal rights and mine development costs based on estimated recoverable tonnages at a current average rate of $1.49 per ton. These costs are included in the cost of coal charged to fuel expense. Cash and Cash Equivalents - Cash and cash equivalents include temporary cash investments with original maturities of three months or less. Sale of Receivables - Under an agreement that was terminated in January 1997, CSPCo sold $50 million of undivided interests in designated pools of accounts receivable and accrued utility revenues with limited recourse. As collections reduced previously sold pools, interests in new pools were sold. At December 31, 1996, 1995 and 1994, $50 million remained to be collected and remitted to the buyer. Operating Revenues - Revenues include the accrual of electricity consumed but unbilled at month-end as well as billed revenues. Fuel Costs - Fuel costs are matched with revenues in accordance with rate commission orders. Generally in the retail jurisdictions, changes in fuel costs are deferred or revenues accrued until approved by the regulatory commission for billing or refund to customers in later months. Wholesale jurisdictional fuel cost changes are expensed and billed as incurred. Levelization of Nuclear Refueling Outage Costs - Incremental operation and maintenance costs associated with refueling outages at I&M's Donald C. Cook Nuclear Plant (Cook Plant) are deferred and amortized over the period (generally eighteen months) beginning with the commencement of an outage and ending with the beginning of the next outage. Income Taxes - The Company follows the liability method of accounting for income taxes as prescribed by SFAS 109, "Accounting for Income Taxes." Under the liability method, deferred income taxes are provided for all temporary differences between book cost and tax basis of assets and liabilities which will result in a future tax consequence. Where the flow-through method of accounting for temporary differences is reflected in rates, deferred income taxes are recorded with related regulatory assets and liabilities in accordance with SFAS 71. Investment Tax Credits - Investment tax credits have been accounted for under the flow-through method except where regulatory commissions have reflected investment tax credits in the rate-making process on a deferral basis. Deferred investment tax credits are being amortized over the life of the related plant investment. Debt and Preferred Stock - Gains and losses on reacquired debt are deferred and amortized over the remaining term of the reacquired debt in accordance with rate-making treatment. If the debt is refinanced the reacquisition costs are deferred and amortized over the term of the replacement debt commensurate with their recovery in rates. Debt discount or premium and debt issuance expenses are amortized over the term of the related debt, with the amortization included in interest charges. Redemption premiums paid to reacquire preferred stock are included in paid-in capital and amortized to retained earnings in accordance with rate-making treatment. The excess of par value over costs of preferred stock reacquired to meet sinking fund requirements is credited to paid-in capital and amortized to retained earnings. Other Property and Investments - Excluding decommissioning and spent nuclear fuel disposal trust funds, other property and investments are stated at cost. Securities held in trust funds for decommissioning nuclear facilities and for the disposal of spent nuclear fuel are recorded at market value in accordance with SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities." Securities in the trust funds have been classified as available-for-sale due to their long-term purpose. Due to the rate-making process, adjustments for unrealized gains and losses are not reported in equity but result in adjustments to regulatory assets and liabilities. 2. Rate Matters: Recovery of Fuel Costs - Under the terms of a 1992 stipulation agreement the cost of coal burned at the Gavin Plant is subject to a 15-year predetermined price of $1.575 per million Btu's with quarterly escalation adjustments through November 2009. A 1995 Settlement Agreement set the fuel component of the EFC factor at 1.465 cents per kwh for the period June 1, 1995 through November 30, 1998 and reserved certain items including emission allowances for later consideration in determining total fuel recovery. The agreements provide OPCo with the opportunity to recover over the term of the stipulation agreement the Ohio jurisdictional share of OPCo's investment in and the liabilities and future shut-down costs of its affiliated mines as well as any fuel costs incurred above the fixed rate to the extent the actual cost of coal burned at the Gavin Plant is below the predetermined price. After November 2009 the price that OPCo can recover for coal from its affiliated Meigs mine which supplies the Gavin Plant will be limited to the lower of cost or the then-current market price. Pursuant to these agreements the Company has deferred $28.5 million for future recovery at December 31, 1996. Based on the estimated future cost of coal burned at Gavin Plant, management believes that the Ohio jurisdictional portion of the investment in and liabilities and closing costs of the affiliated mining operations including deferred amounts will be recovered under the terms of the predetermined price agreement. Management intends to seek from non-Ohio jurisdictional ratepayers recovery of the non-Ohio jurisdictional portion of the investment in and the liabilities and closing costs of the affiliated Meigs, Muskingum and Windsor mines. The non-Ohio jurisdictional portion of shutdown costs for these mines which includes the investment in the mines, leased asset buy-outs, reclamation costs and employee benefits is estimated to be approximately $180 million after tax at December 31, 1996. The affiliated Muskingum and Windsor mines may have to close by January 2000 in order to comply with the Phase II requirements of the Clean Air Act Amendments of 1990. The Muskingum and/or Windsor mines could close prior to January 2000 depending on the economics of continued operation under the terms of the above Settlement Agreement. Unless future shutdown costs and/or the cost of affiliated coal production of the Meigs, Muskingum and Windsor mines can be recovered, results of operations would be adversely affected. 3. Effects of Regulation and Phase-In Plans: In accordance with SFAS 71 the consolidated financial statements include assets (deferred expenses) and liabilities (deferred income) recorded in accordance with regulatory actions to match expenses and revenues in cost-based rates. Regulatory assets are expected to be recovered in future periods through the rate-making process and the regulatory liabilities are expected to reduce future cost recoveries. The Company has reviewed all the evidence currently available and concluded that it continues to meet the requirements to apply SFAS 71. In the event a portion of the Company's business no longer met these requirements net regulatory assets would have to be written off for that portion of the business. Regulatory assets and liabilities are comprised of the following at: December 31, 1996 1995 (In Thousands) Regulatory Assets: Amounts Due From Customers For Future Income Taxes $1,459,086 $1,446,485 Rate Phase-in Plan Deferrals 27,249 74,402 Unamortized Loss on Reacquired Debt 107,305 109,551 Other 295,842 349,008 Total Regulatory Assets $1,889,482 $1,979,446 Regulatory Liabilities: Deferred Investment Tax Credits $404,050 $430,041 Other Regulatory Liabilities* 86,609 86,347 Total Regulatory Liabilities $490,659 $516,388 * Included in Deferred Credits on Consolidated Balance Sheets The rate phase-in plan deferrals are applicable to the Zimmer Plant and Rockport Plant Unit 1. The Zimmer Plant is a 1,300 mw coal-fired plant which commenced commercial operation in 1991. CSPCo owns 25.4% of the plant with the remainder owned by two unaffiliated companies. In May 1992 the Public Utilities Commission of Ohio (PUCO) issued an order providing for a phased in rate increase of $123 million to be implemented in three steps over a two-year period and disallowed $165 million of Zimmer Plant investment. CSPCo appealed the PUCO ordered Zimmer disallowance and phase-in plan to the Ohio Supreme Court. In November 1993 the Supreme Court issued a decision on CSPCo's appeal affirming the disallowance and finding that the PUCO did not have statutory authority to order phased-in rates. The Court instructed the PUCO to fix rates to provide gross annual revenues in accordance with the law and to provide a mechanism to recover the amounts deferred as regulatory assets under the phase-in order. As a result of the Supreme Court decision, in January 1994 the PUCO approved a 7.11% rate increase effective February 1, 1994. The increase is comprised of a 3.72% base rate increase to complete the rate increase phase-in and a temporary 3.39% surcharge, which will be in effect until the deferrals are recovered, estimated to be 1997. In 1996, 1995 and 1994 $31.5 million, $28.5 million and $18.5 million, respectively, of net phase-in deferrals were collected through the surcharge. The deferrals were $15.4 million at December 31, 1996 and $46.9 million at December 31, 1995. The recovery of amounts deferred under the phase-in plan and the increase in rates to the full rate level did not affect net income. From the in-service date of March 1991 until rates went into effect in May 1992 deferred carrying charges of $43 million were recorded on the Zimmer Plant investment. Recovery of the deferred carrying charges will be sought in the next PUCO base rate proceeding in accordance with the PUCO accounting order that authorized the deferral. The Rockport Plant consists of two 1,300 mw coal-fired units. I&M and AEPGEN each own 50% of one unit (Rockport 1) and lease a 50% interest in the other unit (Rockport 2) from unaffiliated lessors under an operating lease. The gain on the sale and leaseback of Rockport 2 was deferred and is being amortized, with related taxes, over the initial lease term which expires in 2022. Rate phase-in plans in I&M's Indiana and FERC jurisdictions for its share of Rockport 1 provide for the recovery and straight-line amortization through 1997 of prior-year cost deferrals. Unamortized deferred amounts under the phase-in plans were $11.9 million and $27.5 million at December 31, 1996 and 1995, respectively. Amortization was $16 million in 1996, 1995 and 1994. 4. Commitments and Contingencies: Construction and Other Commitments - The AEP System has made substantial construction commitments for utility operations. Such commitments do not presently include any expenditures for new generating capacity. The aggregate construction program expenditures for 1997-1999 are estimated to be $2 billion. Long-term fuel supply contracts contain clauses for periodic adjustments, and most jurisdictions have fuel clause mechanisms that provide for recovery of changes in the cost of fuel with the regulators' review and approval. The contracts are for various terms, the longest of which extend to the year 2014, and contain various clauses that would release the Company from its obligation under certain force majeure conditions. The AEP System has contracted to sell up to 1,350 mw of capacity on a long-term basis to unaffiliated utilities. Certain contracts totaling 705 mw of capacity are unit power agreements requiring the delivery of energy regardless of whether the unit capacity is available. The power sales contracts expire from 1997 to 2010. Tender Offer - On February 24, 1997 AEP and Public Service Company of Colorado with equal interests in a joint venture announced a cash tender offer for Yorkshire Electricity Group plc in the United Kingdom. The joint venture proposes to pay $2.4 billion to acquire all of the stock of Yorkshire Electricity. AEP's equity investment, estimated to be $360 million, will be made through its subsidiary AEP Resources Inc., initially using cash borrowed under a revolving credit agreement. Nuclear Plant - I&M owns and operates the two-unit 2,110 mw Cook Nuclear Plant under licenses granted by the Nuclear Regulatory Commission. The operation of a nuclear facility involves special risks, potential liabilities, and specific regulatory and safety requirements. Should a nuclear incident occur at any nuclear power plant facility in the United States, the resultant liability could be substantial. By agreement I&M is partially liable together with all other electric utility companies that own nuclear generating units for a nuclear power plant incident. In the event nuclear losses or liabilities are underinsured or exceed accumulated funds and recovery in rates is not possible, results of operations and financial condition could be negatively affected. Nuclear Incident Liability - Public liability is limited by law to $8.9 billion should an incident occur at any licensed reactor in the United States. Commercially available insurance provides $200 million of coverage. In the event of a nuclear incident at any nuclear plant in the United States the remainder of the liability would be provided by a deferred premium assessment of $79.3 million on each licensed reactor payable in annual installments of $10 million. As a result, I&M could be assessed $158.6 million per nuclear incident payable in annual installments of $20 million. The number of incidents for which payments could be required is not limited. Nuclear insurance pools and other insurance policies provide $3.6 billion of property damage, decommissioning and decontamination coverage for the Cook Plant. Additional insurance provides coverage for extra costs resulting from a prolonged accidental Cook Plant outage. Some of the policies have deferred premium provisions which could be triggered by losses in excess of the insurer's resources. The losses could result from claims at the Cook Plant or certain other non-affiliated nuclear units. I&M could be assessed up to $35.8 million under these policies. Spent Nuclear Fuel Disposal - Federal law provides for government responsibility for permanent spent nuclear fuel disposal and assesses nuclear plant owners fees for spent fuel disposal. A fee of one mill per kilowatthour for fuel consumed after April 6, 1983 is being collected from customers and remitted to the U.S. Treasury. Fees and related interest of $172 million for fuel consumed prior to April 7, 1983 have been recorded as long-term debt. I&M has not paid the government the pre-April 1983 fees due to continued delays and uncertainties related to the federal disposal program. At December 31, 1996, funds collected from customers towards payment of the pre-April 1983 fee and related earnings thereon approximate the liability. Decommissioning and Low Level Waste Accumulation Disposal - Decommissioning costs are accrued over the service life of the Cook Plant. The licenses to operate the two nuclear units expire in 2014 and 2017. After expiration of the licenses the plant is expected to be decommissioned through dismantlement. The Company's latest estimate for decommissioning and low level radioactive waste accumulation disposal costs range from $634 million to $988 million in 1993 nondiscounted dollars. The wide range is caused by variables in assumptions including the estimated length of time spent nuclear fuel must be stored at the plant subsequent to ceasing operations. This in turn depends on future developments in the federal government's spent nuclear fuel disposal program. Continued delays in the federal fuel disposal program can result in increased decommissioning costs. I&M is recovering estimated decommissioning costs in its three rate-making jurisdictions based on at least the lower end of the range in the most recent decommissioning study at the time of the last rate proceeding. I&M records decommissioning costs in other operation expense and records a noncurrent liability equal to the decommissioning cost recovered in rates; such amount was $27 million in 1996, $30 million in 1995 including $4 million of special deposits and $26 million in 1994. Decommissioning costs recovered from customers are deposited in external trusts. Trust fund earnings increase the fund assets and the recorded liability and decrease the amount needed to be recovered from ratepayers. At December 31, 1996 I&M has recognized a decommissioning liability of $314 million which is included in other noncurrent liabilities. Litigation - The Company is involved in a number of legal proceedings and claims. While management is unable to predict the ultimate outcome of litigation, it is not expected that the resolution of these matters will have a material adverse effect on the results of operations or financial condition. 5. Dividend Restrictions: Mortgage indentures, charter provisions and orders of regulatory authorities place various restrictions on the use of the subsidiaries' retained earnings for the payment of cash dividends on their common stocks. At December 31, 1996, $30 million of retained earnings were restricted. To pay dividends out of paid-in capital the subsidiaries need regulatory approval. 6. Lines of Credit and Commitment Fees: At December 31, 1996 and 1995 unused short-term bank lines of credit were available in the amounts of $409 million and $372 million, respectively. Commitment fees of approximately 1/8 of 1% of the unused short-term lines of credit are required to maintain the lines of credit. In addition several of the subsidiaries engaged in providing non-regulated energy services share a $100 million line of credit under a revolving credit agreement which requires the payment of a commitment fee of approximately 1/8 of 1% of the unused balance. At December 31, 1996 no borrowings were outstanding under the revolving credit agreement. In February 1997 the credit available under this agreement was increased to $500 million. Outstanding short-term debt consisted of: December 31, (Dollars In Thousands) 1996 1995 Balance Outstanding: Notes Payable $ 91,293 $ 128,425 Commercial Paper 228,402 236,700 Total $319,695 $365,125 Year-End Weighted Average Interest Rate: Notes Payable 6.2% 6.1% Commercial Paper 7.2% 6.1% Total 6.9% 6.1% 7. Benefit Plans: AEP System Pension Plan - The AEP pension plan is a trusteed, noncontributory defined benefit plan covering all employees meeting eligibility requirements, except participants in the United Mine Workers of America (UMWA) pension plans. Benefits are based on service years and compensation levels. The funding policy is to make annual contributions to a qualified trust fund equal to the net periodic pension cost up to the maximum amount deductible for federal income taxes, but not less than the minimum required contribution in accordance with the Employee Retirement Income Security Act of 1974. Net AEP pension plan costs were computed as follows: Year Ended December 31, 1996 1995 1994 (In Thousands) Service Cost-Benefits Earned During the Year $ 40,000 $ 30,400 $ 40,000 Interest Cost on Projected Benefit Obligation 119,500 116,700 114,500 Actual Return on Plan Assets (302,400) (416,800) (6,700) Net Amortization (Deferral) 161,800 281,800 (123,300) Net AEP Pension Plan Costs $ 18,900 $ 12,100 $ 24,500 AEP pension plan assets and actuarially computed benefit obligations are: December 31, 1996 1995 (In Thousands) AEP Pension Plan Assets at Fair Value (a) $2,009,500 $1,805,300 Actuarial Present Value of Benefit Obligation: Vested 1,377,000 1,321,600 Nonvested 136,500 147,400 Accumulated Benefit Obligation 1,513,500 1,469,000 Effects of Salary Progression 162,700 181,000 Projected Benefit Obligation 1,676,200 1,650,000 Funded Status - AEP Pension Plan Assets in Excess of Projected Benefit Obligation 333,300 155,300 Unrecognized Prior Service Cost 133,200 147,000 Unrecognized Net Gain (488,200) (295,200) Unrecognized Net Transition Assets (Being Amortized Over 17 Years) (68,900) (78,700) Accrued Net AEP Pension Plan Liability $ (90,600) $ (71,600) (a) AEP pension plan assets primarily consist of common stocks, bonds and cash equivalents and are included in a separate entity trust fund. Assumptions used to determine AEP pension plan's funded status were: December 31, 1996 1995 1994 Discount Rate 7.75% 7.25% 8.5% Average Rate of Increase in Compensation Levels 3.2% 3.2% 3.2% Expected Long-Term Rate of Return on Plan Assets 9.0% 9.0% 8.5% AEP System Savings Plan - An employee savings plan is offered to non-UMWA employees which allows participants to contribute up to 17% of their salaries into various investment alternatives, including AEP common stock. An employer matching contribution, equaling one-half of the employees' contribution to the plan up to a maximum of 3% of the employees' base salary, is invested in AEP common stock. The employer's annual contributions totaled $19 million in 1996, $18.8 million in 1995 and $18.6 million in 1994. UMWA Pension Plans - The coal-mining subsidiaries of OPCo provide UMWA pension benefits for UMWA employees meeting eligibility requirements. Benefits are based on age at retirement and years of service. As of June 30, 1996, the UMWA actuary estimates the OPCo coal-mining subsidiaries' share of the UMWA pension plans' unfunded vested liabilities was approximately $26 million. In the event the OPCo coal-mining subsidiaries cease or significantly reduce mining operations or contributions to the UMWA pension plans, a withdrawal obligation may be triggered for all or a portion of their share of the unfunded vested liability. Contributions are based on the number of hours worked, are expensed when paid and totaled $1.6 million in 1996, $1.4 million in 1995 and $1.6 million in 1994. Postretirement Benefits Other Than Pensions (OPEB) - The AEP System provides certain other benefits for retired employees. Substantially all non-UMWA employees are eligible for postretirement health care and life insurance if they retire from active service after reaching age 55 and have at least 10 service years. Postretirement medical benefits for UMWA employees at affiliated mining operations who have or will retire after January 1, 1976 are the liability of the OPCo coal-mining subsidiaries. They are eligible for postretirement medical benefits if they retire from active service after reaching age 55 and have at least 10 service years. In addition, non-active UMWA employees will become eligible for postretirement benefits at age 55 if they have had 20 service years. The funding policy for AEP's plan is to make contributions to an external Voluntary Employees Beneficiary Association trust fund equal to the incremental OPEB costs (i.e., the amount that the total postretirement benefits cost under SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," exceeds the pay-as-you-go amount). Contributions were $45.8 million in 1996, $53 million in 1995 and $29.5 million in 1994. In several jurisdictions the utility subsidiaries deferred the increased OPEB costs resulting from the SFAS 106 required change from pay-as-you-go to accrual accounting which were not being recovered in rates. No additional deferrals were made in 1996. At December 31, 1996 and 1995, $14.5 million and $24.6 million, respectively, of incremental OPEB costs were deferred. Aggregate OPEB costs were computed as follows: Year Ended December 31, 1996 1995 1994 (In Thousands) Service Cost $ 15,300 $ 13,500 $16,500 Interest Cost on Projected Benefit Obligation 53,500 54,900 47,300 Net Amortization of Transition Obligation 32,300 32,000 31,100 Return on Plan Assets (21,100) (25,400) 900 Net Amortization (Deferral) 9,900 16,800 (6,800) Net OPEB Costs $ 89,900 $ 91,800 $89,000 OPEB assets and actuarially computed benefit obligations are: December 31, 1996 1995 (In Thousands) Fair Market Value of Plan Assets (a) $ 232,500 $ 165,600 Accumulated Postretirement Benefit Obligation: Active Employees Fully Eligible for Benefits 57,800 59,200 Current Retirees 423,000 398,400 Other Active Employees 245,600 282,400 Total Benefit Obligation 726,400 740,000 Unfunded Benefit Obligation (493,900) (574,400) Unrecognized Net Loss (Gain) (3,300) 48,500 Unrecognized Net Transition Obligation Being Amortized Over 20 Years 448,500 485,600 Accrued Net OPEB Liability $ (48,700) $ (40,300) (a) Plan assets consist of cash surrender value of life insurance contracts on certain employees owned by the trust and short-term tax exempt municipal bonds. Assumptions used to determine OPEB's funded status were: December 31, 1996 1995 1994 Discount Rate 7.75% 7.25% 8.5% Expected Long-Term Rate of Return on Plan Assets 8.75% 8.75% 8.25% Initial Medical Cost Trend Rate 7.5% 8.0% 8.0% Ultimate Medical Cost Trend Rate 4.75% 4.5% 5.25% Medical Cost Trend Rate Decreases to Ultimate Rate in Year 2005 2005 2005 Assuming a one percent increase in the medical cost trend rate, the 1996 OPEB cost for all employees, both non-UMWA and UMWA, would increase by $8 million and the accumulated benefit obligations would increase by $82 million. Several UMWA health plans pay the postretirement medical benefits for the Company's UMWA retirees who retired before January 2, 1976 and their survivors plus retirees and others whose last employer is no longer a signatory to the UMWA contract or is no longer in business. The UMWA health plans are funded by payments from current and former UMWA wage agreement signatories, the 1950 UMWA Pension Plan surplus and the Abandoned Mine Land Reclamation Fund Surplus. Required annual payments to the UMWA health funds made by AEP's active and inactive coal-mining subsidiaries were recognized as expense when paid and totaled $0.9 million in 1996, $2.8 million in 1995 and $3.1 million in 1994. By law, excess Black Lung Trust funds may be used to pay certain postretirement medical benefits under one of the UMWA health plans. Excess AEP Black Lung Trust funds used to reimburse the coal companies totaled $7.4 million in 1996, $7.9 million in 1995 and $6.9 million in 1994. The Black Lung Trust had excess funds at December 31, 1996 of approximately $12 million, of which $10.8 million may be used to pay future costs. 8. Fair Value of Financial Instruments: Nuclear Trust Funds Recorded at Market Value - The trust investments, reported in other property and investments, are recorded at market value in accordance with SFAS 115 and consist of long-term tax-exempt municipal bonds and other securities. At December 31, 1996 and 1995 the fair values of the trust investments were $491 million and $434 million, respectively. Accumulated gross unrealized holding gains were $21.9 million and $19.1 million and accumulated gross unrealized holding losses were $1.2 million and $1 million at December 31, 1996 and 1995, respectively. The change in market value in 1996 was a net unrealized holding gain of $2.6 million, in 1995 a net unrealized holding gain of $24.9 million and in 1994 a net unrealized holding loss of $27.1 million. The trust investments' cost basis by security type were: December 31, 1996 1995 (In Thousands) Tax-Exempt Bonds $340,290 $336,073 Equity Securities 54,389 24,101 Treasury Bonds 26,958 12,992 Corporate Bonds 7,977 1,971 Cash, Cash Equivalents and Accrued Interest 40,430 40,356 Total $470,044 $415,493 Proceeds from sales and maturities of securities of $115.3 million during 1996 resulted in $2.6 million of realized gains and $2.1 million of realized losses. Proceeds from sales and maturities of securities of $78.2 million during 1995 resulted in $1.4 million of realized gains and $0.3 million of realized losses. During 1994 proceeds from sales and maturities of securities of $20.1 million resulted in $52,000 of realized gains and $155,000 of realized losses. The cost of securities for determining realized gains and losses is original acquisition cost including amortized premiums and discounts. At December 31, 1996, the year of maturity of trust fund investments other than equity securities, was: (In Thousands) 1997 $ 56,452 1998 - 2001 120,327 2002 - 2006 163,250 After 2006 75,626 Total $415,655 Other Financial Instruments Recorded at Historical Cost - The carrying amounts of cash and cash equivalents, accounts receivable, short-term debt, and accounts payable approximate fair value because of the short-term maturity of these instruments. Fair values for preferred stock subject to mandatory redemption were $517 million and $544 million and for long-term debt were $5.0 billion and $5.3 billion at December 31, 1996 and 1995, respectively. The carrying amounts on the financial statements for preferred stock subject to mandatory redemption were $510 million and $523 million and for long-term debt were $4.9 billion and $5.1 billion at December 31, 1996 and 1995, respectively. Fair values are based on quoted market prices for the same or similar issues and the current dividend or interest rates offered for instruments of the same remaining maturities. The carrying amount of the pre-April 1983 spent nuclear fuel disposal liability approximates the Company's best estimate of its fair value. 9. Federal Income Taxes: The details of federal income taxes as reported are as follows:
Year Ended December 31, 1996 1995 1994 (In Thousands) Charged (Credited) to Operating Expenses (net): Current $375,528 $265,313 $240,655 Deferred (17,008) 22,990 (10,177) Deferred Investment Tax Credits (16,298) (16,276) (17,079) Total 342,222 272,027 213,399 Charged (Credited) to Nonoperating Income (net): Current (5,636) 11,325 (2,907) Deferred (4,470) (11,074) (5,856) Deferred Investment Tax Credits (9,510) (9,543) (14,196) Total (19,616) (9,292) (22,959) Total Federal Income Tax as Reported $322,606 $262,735 $190,440 The following is a reconciliation of the difference between the amount of federal incometaxes computed by multiplying book income before federal income taxes by the statutory tax rate, and the amount of federal income taxes reported. Year Ended December 31, 1996 1995 1994 (In Thousands) Income Before Preferred Stock Dividend Requirements of Subsidiaries $628,856 $584,674 $554,738 Federal Income Taxes 322,606 262,735 190,440 Pre-Tax Book Income $951,462 $847,409 $745,178 Federal Income Tax on Pre-Tax Book Income at Statutory Rate (35%) $333,012 $296,593 $260,812 Increase (Decrease) in Federal Income Tax Resulting from the Following Items: Depreciation 50,537 46,453 31,212 Removal Costs (15,327) (14,640) (13,818) Corporate Owned Life Insurance (12,009) (25,506) (22,970) Investment Tax Credits (net) (25,813) (26,179) (31,273) Federal Income Tax Accrual Adjustments - - (16,100) Other (7,794) (13,986) (17,423) Total Federal Income Taxes as Reported $322,606 $262,735 $190,440 Effective Federal Income Tax Rate 33.9% 31.0% 25.6%
The following tables show the elements of the net deferred tax liability and the significant temporary differences:
December 31, 1996 1995 (In Thousands) Deferred Tax Assets $ 784,349 $ 723,196 Deferred Tax Liabilities (3,427,492) (3,379,847) Net Deferred Tax Liabilities $(2,643,143) $ 2,656,651) Property Related Temporary Differences $(2,162,099) $(2,139,387) Amounts Due From Customers For Future Federal Income Taxes (428,698) (442,311) Deferred State Income Taxes (229,429) (183,981) All Other (net) 177,083 109,028 Total Net Deferred Tax Liabilities $(2,643,143) $(2,656,651)
The Company has settled with the Internal Revenue Service (IRS) all issues from the audits of the consolidated federal income tax returns for the years prior to 1991. Returns for the years 1991 through 1993 are presently being audited by the IRS. During the audit the IRS agents requested a ruling from their National Office that certain interest deductions relating to corporate owned life insurance (COLI) claimed by the Company for 1991 through 1993 should not be allowed. The Company filed a brief with the IRS National Office refuting the agents' position. Although no adjustments have been proposed, a disallowance of the COLI interest deductions through December 31, 1996 would reduce earnings by approximately $247 million (including interest). AEP believes it will ultimately prevail on this issue and will vigorously contest any adjustments that may be assessed. Accordingly, no provision for this amount has been recorded. In the opinion of management, the final settlement of open years will not have a material effect on results of operations. 10. Leases: Leases of property, plant and equipment are for periods up to 35 years and require payments of related property taxes, maintenance and operating costs. The majority of the leases have purchase or renewal options and will be renewed or replaced by other leases. Lease rentals are primarily charged to operating expenses in accordance with rate-making treatment. The components of rentals are as follows:
Year Ended December 31, 1996 1995 1994 (In Thousands) Operating Leases $262,451 $259,877 $233,805 Amortization of Capital Leases 114,050 101,068 79,116 Interest on Capital Leases 28,696 27,542 23,280 Total Rental Payments $405,197 $388,487 $336,201
Properties under capital leases and related obligations on the Consolidated Balance Sheets are as follows:
December 31, 1996 1995 (In Thousands) ELECTRIC UTILITY PLANT: Production $ 44,390 $ 44,849 Transmission 6 7 Distribution 14,699 14,753 General: Nuclear Fuel (net of amortization) 59,681 69,442 Mining Plant and Other 466,797 424,952 Total Electric Utility Plant 585,573 554,003 Accumulated Amortization 200,931 179,952 Net Electric Utility Plant 384,642 374,051 OTHER PROPERTY 33,439 34,536 Accumulated Amortization 3,854 3,994 Net Other Property 29,585 30,542 Net Property under Capital Leases $414,227 $404,593 Obligations under Capital Leases $414,227 $404,593 Less Portion Due Within One Year 89,553 89,692 Noncurrent Capital Lease Liability $324,674 $314,901 Properties under operating leases and related obligations are not included in the Consolidated Balance Sheets. Future minimum lease rentals, consisted of the following at December 31, 1996: Noncancelable Capital Operating Leases Leases (In Thousands) 1997 $ 90,813 $ 240,923 1998 73,817 232,903 1999 63,356 230,994 2000 53,027 229,039 2001 41,634 225,733 Later Years 150,278 3,858,008 Total Future Minimum Lease Rentals 472,925 (a) $5,017,600 Less Estimated Interest Element 118,379 Estimated Present Value of Future Minimum Lease Rentals 354,546 Unamortized Nuclear Fuel 59,681 Total $414,227 (a) Minimum lease rentals do not include nuclear fuel rentals. The rentals are paid in proportion to heat produced and carrying charges on the unamortized nuclear fuel balance. There are no minimum lease payment requirements for leased nuclear fuel.
11. SUPPLEMENTARY INFORMATION:
Year Ended December 31, 1996 1995 1994 (In Thousands) Purchased Power - Ohio Valley Electric Corp. (44.2% owned by AEP) $22,156 $10,546 $5,755 Cash was paid for: Interest (net of capitalized amounts) $373,570 $395,169 $379,361 Income Taxes $404,297 $273,671 $312,233 Noncash Acquisitions under Capital Leases were $136,988 $106,256 $227,055 12. CAPITAL STOCKS AND PAID-IN CAPITAL: Changes in capital stocks and paid-in capital during the period January 1, 1994 through December 31, 1996 were: Cumulative Preferred Stocks Shares of Subsidiaries Cumulative Not Subject Subject to Common Stock- Preferred Stocks Paid-in To Mandatory Mandatory Par Value $6.50(a) of Subsidiaries Common Stock Capital Redemption Redemption(b) (Dollars in Thousands) January 1, 1994 193,534,992 7,687,768 $1,257,977 $1,624,176 $ 268,240 $ 500,537 Issuances 700,000 900,000 4,550 17,706 - 90,000 Retirements and Other - (351,517) - (1,221) (35,000) (152) December 31, 1994 194,234,992 8,236,251 1,262,527 1,640,661 233,240 590,385 Issuances 1,400,000 - 9,100 39,607 - - Retirements and Other - (1,526,500) - (21,744) (85,000) (67,650) December 31, 1995 195,634,992 6,709,751 1,271,627 1,658,524 148,240 522,735 Issuances 1,600,000 - 10,400 55,061 - - Retirements and Other - (707,518) - 1,969 (57,917) (12,835) December 31, 1996 197,234,992 6,002,233 $1,282,027 $1,715,554 $ 90,323 $509,900 (a) Includes 8,999,992 shares of treasury stock. (b) Including portion due within one year.
13. Unaudited Quarterly Financial Information:
Quarterly Periods Ended 1996 March 31 June 30 Sept. 30 Dec. 31 (In Thousands - Except Per Share Amounts) Operating Revenues $1,517,781 $1,400,941 $1,484,422 $1,446,090 Operating Income 292,122 220,625 259,745 235,480 Net Income 180,012 112,666 162,324 132,428 Earnings per Share 0.96 0.60 0.87 0.71 Quarterly Periods Ended 1995 March 31 June 30 Sept. 30 Dec. 31 (In Thousands - Except Per Share Amounts) Operating Revenues $1,416,169 $1,305,342 $1,523,390 $1,425,429 Operating Income 257,556 211,284 262,548 233,159 Net Income 147,850 96,478 154,156 131,419 Earnings per Share 0.80 0.52 0.83 0.70
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES SCHEDULE OF CONSOLIDATED CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES
December 31, 1996 Call Price per Shares Shares Amount (in Share (a) Authorized(b) Outstanding thousands) Not Subject to Mandatory Redemption: 4.08% - 4.56% (c) $102-$110 932,403 903,233 $ 90,323 Subject to Mandatory Redemption (d): 5.90% - 5.92% (c) (e) 1,950,000 1,904,000 $190,400 6.02% - 6-7/8% (c) (f) 1,950,000 1,945,000 194,500 7% - 7-7/8% (c) $107.80-$107.88(g) 1,250,000 1,250,000 125,000 Total Subject to Mandatory Redemption (h) $509,900 ______________________________________________________________________________________________________ December 31, 1995 Call Price per Shares Shares Amount (in Share (a) Authorized Outstanding thousands) Not Subject to Mandatory Redemption: 4.08% - 4.56% $102-$110 932,403 932,403 $ 93,240 7.08% - 7.40% $101.85-$102.11 550,000 550,000 55,000 Total Not Subject to Mandatory Redemption $148,240 Subject to Mandatory Redemption (d): 4.50% $102 19,625 2,348 $ 235 5.90% - 5.92% (e) 1,950,000 1,950,000 195,000 6.02% - 6-7/8% (f) 1,950,000 1,950,000 195,000 7% - 7-7/8% $107.80-$107.88(g) 1,250,000 1,250,000 125,000 9.50% (i) 750,000 75,000 7,500 Total Subject to Mandatory Redemption (h) 522,735 Less Portion Due Within One Year 7,650 Long-term Portion $515,085 NOTES TO SCHEDULE OF CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES (a) At the option of the subsidiary the shares may be redeemed at the call price plus accrued dividends. The involuntary liquidation preference is $100 per share for all outstanding shares. (b) As of December 31, 1996 the subsidiaries had 4,708,320, 22,200,000 and 5,801,850 shares of $100, $25 and no par value preferred stock, respectively, that were authorized but unissued. (c) In January 1997 a tender offer for certain series of preferred stock was announced. In conjunction with the tender offer a special shareholders meeting is scheduled to be held on February 28, 1997 for the purpose of considering amendments to the subsidiaries' articles of incorporation to remove certain capitalization ratio requirements. (d) With sinking fund. Shares outstanding and related amounts are stated net of applicable retirements through sinking funds (generally at par) and reacquisitions of shares in anticipation of future requirements. (e) Not callable prior to 2003; after that the call price is $100 per share. (f) Not callable prior to 2000; after that the call price is $100 per share. (g) Redemption is restricted prior to 1997. (h) The sinking fund provisions of the series subject to mandatory redemption aggregate $5,000,000, $5,000,000, $16,000,000 and $16,000,000 in 1998, 1999, 2000 and 2001, respectively. (i) On February 1, 1996 the outstanding balance of 75,000 shares was redeemed at $100 per share.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES SCHEDULE OF CONSOLIDATED LONG-TERM DEBT OF SUBSIDIARIES
Weighted Average Maturity Interest Rate Interest Rates at December 31, December 31, December 31, 1996 1996 1995 1996 1995 (in thousands) FIRST MORTGAGE BONDS 1996-1999 7.35% 6-1/4%-9.15% 5%-9.15% $ 383,671 $ 496,866 2001-2006 7.10% 6%-8.95% 6%-9.31% 1,511,000 1,530,020 2020-2025 8.07% 7.10%-9.35% 7.10%-9-7/8% 1,276,750 1,473,127 INSTALLMENT PURCHASE CONTRACTS (a) 1998-2002 4.80% 4.10%-7-1/4% 5%-7-1/4% 209,500 209,500 2007-2025 6.45% 5.45%-7-7/8% 5.45%-7-7/8% 756,745 756,745 NOTES PAYABLE (b) 1996-2008 7.31% 5.29%-9.60% 5.29%-10.78% 282,681 221,000 DEBENTURES 1996 - 1999 (c) - - 5-1/8%-7-7/8% - 30,759 2025 - 2026 8.28% 8%-8.72% 8.16%-8.72% 315,000 200,000 OTHER LONG-TERM DEBT (d) 182,943 172,403 Unamortized Discount (net) (34,580) (33,144) Total Long-term Debt Outstanding (e) 4,883,710 5,057,276 Less Portion Due Within One Year 86,942 136,947 Long-term Portion $4,796,768 $4,920,329 NOTES TO SCHEDULE OF CONSOLIDATED LONG-TERM DEBT OF SUBSIDIARIES (a) For certain series of installment purchase contracts interest rates are subject to periodic adjustment. Certain series will be purchased on demand at periodic interest-adjustment dates. Letters of credit from banks and standby bond purchase agreements support certain series. (b) Notes payable represent outstanding promissory notes issued under term loan agreements with a number of banks and other financial institutions. At expiration all notes then issued and outstanding are due and payable. Interest rates are both fixed and variable. Variable rates generally relate to specified short-term interest rates. (c) All sinking fund debentures were reacquired on March 1, 1996. (d) Other long-term debt consists primarily of a liability along with accrued interest for disposal of spent nuclear fuel (see Note 4 of the Notes to Consolidated Financial Statements). (e) Long-term debt outstanding at December 31, 1996 is payable as follows: Principal Amount (in thousands) 1997 $ 86,942 1998 224,274 1999 210,678 2000 183,652 2001 252,575 Later Years 3,960,169 Total $4,918,290
Management's Responsibility The management of American Electric Power Company, Inc. is responsible for the integrity and objectivity of the information and representations in this annual report, including the consolidated financial statements. These statements have been prepared in conformity with generally accepted accounting principles, using informed estimates where appropriate, to reflect the Company's financial condition and results of operations. The information in other sections of the annual report is consistent with these statements. The Company's Board of Directors has oversight responsibilities for determining that management has fulfilled its obligation in the preparation of the financial statements and in the ongoing examination of the Company's established internal control structure over financial reporting. The Audit Committee, which consists solely of outside directors and which reports directly to the Board of Directors, meets regularly with management, Deloitte & Touche LLP - Certified Public Accountants and the Company's internal audit staff to discuss accounting, auditing and reporting matters. To ensure auditor independence, both Deloitte & Touche LLP and the internal audit staff have unrestricted access to the Audit Committee. The financial statements have been audited by Deloitte & Touche LLP, whose report appears on the next page. The auditors provide an objective, independent review as to management's discharge of its responsibilities insofar as they relate to the fairness of the Company's reported financial condition and results of operations. Their audit includes procedures believed by them to provide reasonable assurance that the financial statements are free of material misstatement and includes a review of the Company's internal control structure over financial reporting. Independent Auditors' Report To the Shareholders and Board of Directors of American Electric Power Company, Inc.: We have audited the accompanying consolidated balance sheets of American Electric Power Company, Inc. and its subsidiaries as of December 31, 1996 and 1995, and the related consolidated statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 1996. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of American Electric Power Company, Inc. and its subsidiaries as of December 31, 1996 and 1995, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1996 in conformity with generally accepted accounting principles. /s/ Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 25, 1997 EX-21 10 AEP SUBSIDIARIES OF REGISTRANT 10K EX21 EXHIBIT 21 Subsidiaries of American Electric Power Company, Inc. As of January 1, 1997
Percentage of Voting Securities Location of Owned By Name of Company Incorporation Immediate Parent American Electric Power Service Corporation New York 100.0 AEP Communications, Inc. Ohio 100.0 AEP Energy Services, Inc.* Ohio 100.0 AEP Energy Solutions, Inc.** Ohio 100.0 AEP Generating Company Ohio 100.0 AEP Investments, Inc. Ohio 100.0 AEP Resources, Inc. Ohio 100.0 AEP Resources Australia Pty., Ltd. Australia 100.0 AEP Resources Delaware, Inc. Delaware 100.0 AEP Resources International, Ltd. Cayman Islands 100.0 AEP Pushan Power, LDC Cayman Islands 99.0 (a) Nanyang General Light Electric Company, Ltd.People's Republic of China 70.0 (b) AEP Resources Mauritius Company Mauritius 99.0 (a) AEP Resources Project Management Company, Ltd. Cayman Islands 100.0 AEP Pushan Power, LDC Cayman Islands 1.0 (a) Nanyang General Light Electric Company, Ltd.People's Republic of China 70.0 (b) AEP Resources Mauritius Company Mauritius 1.0 (a) Appalachian Power Company Virginia 97.8 (c) Cedar Coal Co. West Virginia 100.0 Central Appalachian Coal Company West Virginia 100.0 Central Coal Company West Virginia 50.0 (d) Central Operating Company West Virginia 50.0 (d) Southern Appalachian Coal Company West Virginia 100.0 West Virginia Power Company West Virginia 100.0 Columbus Southern Power Company Ohio 100.0 Colomet, Inc. Ohio 100.0 Conesville Coal Preparation Company Ohio 100.0 Simco Inc. Ohio 100.0 Franklin Real Estate Company Pennsylvania 100.0 Indiana Franklin Realty, Inc. Indiana 100.0 Indiana Michigan Power Company Indiana 100.0 Blackhawk Coal Company Utah 100.0 Price River Coal Company Indiana 100.0 Integrated Communications Systems, Inc. Georgia 13.1 (e) Kentucky Power Company Kentucky 100.0 Kingsport Power Company Virginia 100.0 Ohio Power Company Ohio 97.3 (f) Cardinal Operating Company Ohio 50.0 (g) Central Coal Company West Virginia 50.0 (d) Central Ohio Coal Company Ohio 100.0 Central Operating Company West Virginia 50.0 (d) Southern Ohio Coal Company West Virginia 100.0 Windsor Coal Company West Virginia 100.0 Ohio Valley Electric Corporation Ohio 44.2 (h) Indiana-Kentucky Electric Corporation Indiana 100.0 Wheeling Power Company West Virginia 100.0 * Effective March 7, 1997 name changed to AEP Resources Engineering & Services Company. ** Effective March 7, 1997 name changed to AEP Energy Services, Inc. (a) Owned 99% by AEP Resources International, Ltd. and 1% by AEP Resources Project Management Company, Ltd. (b) AEP Pushan Power LDC owns 70% and the remaining 30% is owned by two unaffiliated entities. (c) 13,499,500 shares of Common Stock, all owned by parent, have one vote each and 298,150 shares of Preferred Stock, all owned by public, have one vote each. (d) Owned 50% by Appalachian Power Company and 50% by Ohio Power Company. (e) American Electric Power Company, Inc. owns 13.1% of the stock and the remaining 86.9% is owned by unaffiliated companies. (f) 27,952,473 shares of Common Stock, all owned by parent, have one vote each and 789,316 shares of Preferred Stock, all owned by public, have one vote each. (g) Ohio Power Company owns 50% of the stock; the other 50% is owned by a corporation not affiliated with American Electric Power Company, Inc. (h) American Electric Power Company, Inc. and Columbus Southern Power Company own 39.9% and 4.3% of the stock, respectively, and the remaining 55.8% is owned by unaffiliated companies.
EX-23 11 AEP CONSENT OF DELOITTE & TOUCHE 10K EX23 Exhibit 23 INDEPENDENT AUDITORS' CONSENT We consent to the incorporation by reference in Post-Effective Amendment No. 3 to Registration Statement No. 33-01052 of American Electric Power Company, Inc. on Form S-8 and Post-Effective Amendment No. 1 to Registration Statement No. 33-01734 of American Electric Power Company, Inc. on Form S-3 of our reports dated February 25, 1997, appearing in and incorporated by reference in this Annual Report on Form 10-K of American Electric Power Company, Inc. for the year ended December 31, 1996. Deloitte & Touche LLP Columbus, Ohio March 25, 1997 EX-24 12 AEP POWER OF ATTORNEY 10K EX24 Exhibit 24 POWER OF ATTORNEY AMERICAN ELECTRIC POWER COMPANY, INC. Annual Report on Form lO-K for the Fiscal Year Ended December 31, 1996 The undersigned director of AMERICAN ELECTRIC POWER COMPANY, INC., a New York corporation (the "Company"), does hereby consti- tute and appoint E. LINN DRAPER, JR., G. P. MALONEY and P. J. DeMARIA, and each of them, his attorneys-in-fact and agents, to execute for him, and in his name, and in any and all of his capacities, the Annual Report of the Company on Form lO-K, pursuant to Section 13 of the Securities Exchange Act of 1934, for the fiscal year ended December 31, 1996, and any and all amendments thereto, and to file the same, with all exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform every act and thing required or necessary to be done, as fully to all intents and purposes as the undersigned might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, may lawfully do or cause to be done by virtue hereof. IN WITNESS WHEREOF, the undersigned has signed these presents this 18th day of December, 1996. /s/ Robert W. Fri ------------------------------- Robert W. Fri Exhibit 24 POWER OF ATTORNEY AMERICAN ELECTRIC POWER COMPANY, INC. Annual Report on Form lO-K for the Fiscal Year Ended December 31, 1996 The undersigned directors of AMERICAN ELECTRIC POWER COMPANY, INC., a New York corporation (the "Company"), do hereby constitute and appoint E. LINN DRAPER, JR., G. P. MALONEY and P. J. DeMARIA, and each of them, their attorneys-in-fact and agents, to execute for them, and in their names, and in any and all of their capacities, the Annual Report of the Company on Form lO-K, pursuant to Section 13 of the Securities Exchange Act of 1934, for the fiscal year ended December 31, 1996, and any and all amendments thereto, and to file the same, with all exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform every act and thing required or necessary to be done, as fully to all intents and purposes as the undersigned might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, may lawfully do or cause to be done by virtue hereof. IN WITNESS WHEREOF, the undersigned have signed these presents this 26th day of February, 1997. /s/ P. J. DeMaria /s/ G. P. Maloney - ------------------------------ ------------------------------- P. J. DeMaria G. P. Maloney /s/ E. Linn Draper, Jr. /s/ Angus E. Peyton - ------------------------------ ------------------------------- E. Linn Draper, Jr. Angus E. Peyton /s/ Robert M. Duncan /s/ Donald G. Smith - ------------------------------ ------------------------------- Robert M. Duncan Donald G. Smith /s/ Arthur G. Hansen /s/ Linda Gillespie Stuntz - ------------------------------ ------------------------------- Arthur G. Hansen Linda Gillespie Stuntz /s/ Lester A. Hudson, Jr. /s/ Morris Tanenbaum - ------------------------------ ------------------------------- Lester A. Hudson, Jr. Morris Tanenbaum /s/ Leonard J. Kujawa /s/ Ann Haymond Zwinger - ------------------------------ ------------------------------- Leonard J. Kujawa Ann Haymond Zwinger EX-27 13 AEP FINANCIAL DATA SCHEDULE 10K EX27
UT 0000004904 AMERICAN ELECTRIC POWER COMPANY, INC. 1,000 12-MOS DEC-31-1996 DEC-31-1996 PER-BOOK 11,420,371 892,674 1,354,881 328,139 1,889,482 15,885,547 1,282,027 1,715,554 1,547,746 4,545,327 509,900 90,323 4,796,768 91,293 0 228,402 86,942 0 324,674 89,553 5,122,365 15,885,547 5,849,234 365,305 4,475,957 4,841,262 1,007,972 2,212 1,010,184 381,328 587,430 41,426 587,430 449,353 250,063 1,237,062 $3.14 $3.14 Represents preferred stock dividend requirements of subsidiaries; deducted before computation of net income.
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