-----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, M5R4Rz6s21YGvkkofk5ml4FZ1Tbr4O8r7aQb7bMa2ZNi0trFVY7f19yr9pqCd5ch 6S5FnNgoTwlDwAURNvIpjA== 0000006879-97-000016.txt : 19970328 0000006879-97-000016.hdr.sgml : 19970328 ACCESSION NUMBER: 0000006879-97-000016 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 9 CONFORMED PERIOD OF REPORT: 19961231 FILED AS OF DATE: 19970327 SROS: NYSE SROS: PHLX FILER: COMPANY DATA: COMPANY CONFORMED NAME: APPALACHIAN POWER CO CENTRAL INDEX KEY: 0000006879 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 540124790 STATE OF INCORPORATION: VA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K405 SEC ACT: 1934 Act SEC FILE NUMBER: 001-03457 FILM NUMBER: 97564183 BUSINESS ADDRESS: STREET 1: 40 FRANKLIN RD SW CITY: ROANOKE STATE: VA ZIP: 24011 BUSINESS PHONE: 7039852300 MAIL ADDRESS: STREET 1: 1 RIVERSIDE PLAZA CITY: COLUMBUS STATE: OH ZIP: 43215 10-K405 1 APCO 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.C 2 APCO AMENDED ARTICLES OF INCORP 10K405 EX3C EXHIBIT 3(c) APPALACHIAN POWER COMPANY ARTICLES OF AMENDMENT TO THE RESTATED ARTICLES OF INCORPORATION, AS AMENDED 1. The name of the corporation is APPALACHIAN POWER COMPANY. 2. The Amendment adopted is to remove in its entirety ARTICLE V, Clause 7(B)(b) from the Restated Articles of Incorporation, as amended. 3. On January 30, 1997, notice of the meeting, accompanied by a copy of the Amendment, was given in the manner provided in the Virginia Stock Corporation Act to each of the Corporation's shareholders of record. The foregoing Amendment was adopted by the shareholders of the Corporation on February 28, 1997. 4. On January 29, 1997, the foregoing Amendment was proposed by the Board of Directors of the Corporation, which found adoption of the Amendment to be in the Corporation's best interest and directed that it be submitted to the shareholders of the Corporation for their approval at a special meeting on February 28, 1997. 5. Holders of the shares of the Corporation's common stock and preferred stock were eligible to vote separately as a class in the adoption of the Amendment. The number of shares of common stock and preferred stock voted for the Amendment was sufficient to approve the Amendment. The designation, the number of outstanding shares on the record date, the number of votes entitled to be cast by each voting group entitled to vote separately on the foregoing Amendment and the undisputed number of votes cast for, against and abstaining from the Amendment were as follows: Undisputed Votes Cast Entitled Class Outstanding to Vote For Against Abstain Cumulative Preferred Stock, no par value 2,198,150 2,198,150 Common Stock no par value 13,499,500 13,499,500 APPALACHIAN POWER COMPANY By_/s/ John M. Adams, Jr. John M. Adams, Jr. Assistant Secretary March 3, 1997 EX-3.D 3 APCO COMPOSITE OF RESTATED ARTICLES 10K405 EX3D EXHIBIT 3(d) [COMPOSITE] RESTATED ARTICLES OF INCORPORATION OF APPALACHIAN POWER COMPANY (a Virginia Public Service Corporation) ARTICLE I NAME The name of the Corporation is: APPALACHIAN POWER COMPANY ARTICLE II PURPOSE The purpose of the Corporation is to conduct business as a public service company for the generation, transmission, distribution and sale of electricity within and without the Commonwealth of Virginia, with all the rights, powers and privileges of such companies conferred by the constitution and laws of the Commonwealth of Virginia as they now or may hereafter exist. The Corporation shall have the power to conduct any business in any place, other than the Commonwealth of Virginia, authorized or permitted by the laws thereof. ARTICLE III Directors The number of Directors shall be fixed by the By-Laws. In the absence of a By-Law establishing the number of Directors, the number of Directors shall be ten. ARTICLE IV Common Stock The Corporation shall have authority to issue 30,000,000 shares of Common Stock without par value. No holder of Common Stock shall have any pre-emptive right to acquire unissued shares of the Corporation or to acquire any securities convertible into or exchangeable for such shares or to acquire any options, warrants or rights to purchase such shares. ARTICLE V Cumulative Preferred Stock The Corporation shall have authority to issue 8,000,000 shares of Cumulative Preferred Stock without par value, except that the aggregate involuntary liquidation price for all shares of Cumulative Preferred Stock outstanding may not exceed $300,000,000. Subject to the provisions of the following paragraphs (1) through (11) hereof, the Board of Directors is hereby empowered to cause the Cumulative Preferred Stock to be issued in series with such variations as may be determined by the Board of Directors prior to the issue thereof. (1) The shares of the Cumulative Preferred Stock of different series may vary as to: (a) the distinctive serial designations; (b) the rate of dividends and the dates from which dividends shall be cumulative as provided in paragraph (2); (c) the price or prices at and the terms and conditions on which such shares may be redeemed; (d) the amount or amounts payable upon such shares in event of involuntary liquidation; (e) the amount or amounts payable upon such shares in event of voluntary liquidation; (f) sinking fund provisions (if any) for the redemption or purchase of such shares; and (g) the terms and conditions (if any) on which such shares may be converted. The shares of all series of the Cumulative Preferred Stock shall in all other respects be equal, except for the right to vote as provided herein. No shares of the Cumulative Preferred Stock shall be entitled to any right of participation. (2) The holders of each series of the Cumulative Preferred Stock at the time outstanding shall be entitled to receive, but only when and as declared by the Board of Directors, out of funds legally available for the payment of dividends, cumulative preferential dividends, at the annual dividend rate for the particular series fixed therefor as herein provided, payable quarter-yearly on the first days of February, May, August and November in each year, to stockholders of record on the respective dates, not exceeding fifty (50) days and not less than ten (10) days preceding such dividend payment dates, fixed for the purpose by the Board of Directors. The shares of any series of Cumulative Preferred Stock issued by the Corporation prior to June 1, 1977, for which the annual dividend rate is designated as a specified percentage per annum, shall be entitled to receive such dividends, calculated, per share, at the percentage specified for such series multiplied by $100. No dividends shall be declared on any series of the Cumulative Preferred Stock in respect of any quarter-yearly dividend period unless there shall likewise be declared on all shares of all series of the Cumulative Preferred Stock at the time outstanding, like proportionate dividends, ratably, in proportion to the respective annual dividend rates fixed therefor, in respect of the same quarter-yearly dividend period, to the extent that such shares are entitled to receive dividends for such quarter-yearly dividend period. The dividends on shares of all series of the Cumulative Preferred Stock shall be cumulative. Dividends on shares of any series shall be cumulative from the date or dates fixed by the Board of Directors, or, if not so fixed, from the date of the initial issuance of such shares. All dividends declared payable to the holders of record of the Cumulative Preferred Stock of any series as of a date on which shares of the Cumulative Preferred Stock of such series are owned by the Corporation shall be deemed to have been paid in respect of such shares owned by the Corporation on such date. Unless dividends on all outstanding shares of each series of the Cumulative Preferred Stock, at the annual dividend rate and from the dates for accumulation thereof fixed as herein provided shall have been paid for all past quarter-yearly dividend periods, but without interest on cumulative dividends, no dividends shall be paid or declared and no other distribution shall be made on the Common Stock, and no Common Stock shall be purchased or otherwise acquired for value by the Corporation. The holders of the Cumulative Preferred Stock of any series shall not be entitled to receive any dividends thereon other than the dividends referred to in this paragraph (2). (3) The Corporation, by action of its Board of Directors, may redeem the whole or any part of any series of the Cumulative Preferred Stock, at any time or from time to time, by paying in cash the redemption price of the shares of the particular series fixed therefor as herein provided, together with a sum in the case of each share of each series so to be redeemed, computed at the annual dividend rate for the series of which the particular share is a part from the date from which dividends on such share became cumulative to the date fixed for such redemption, less the aggregate of the dividends theretofore or on such redemption date paid thereon. Notice of every such redemption shall be given by publication at least once in one daily newspaper printed in the English language and of general circulation in Roanoke, Virginia, and in one daily newspaper printed in the English language and of general circulation in the Borough of Manhattan, The City of New York, the first publication in such newspapers to be at least thirty (30) days and not more than ninety (90) days prior to the date fixed for such redemption. At least thirty (30) days' and not more than ninety (90) days' previous notice of every such redemption shall also be mailed to the holders of record of the shares of the Cumulative Preferred Stock so to be redeemed, at their respective addresses as the same shall appear on the books of the Corporation; but no failure to mail such notice nor any defect therein or in the mailing thereof shall affect the validity of the proceedings for the redemption of any shares of the Cumulative Preferred Stock so to be redeemed. In case of the redemption of a part only of any series of the Cumulative Preferred Stock at the time outstanding, the Corporation shall select by lot, or in such other manner as the Board of Directors may determine, the shares so to be redeemed. The Board of Directors shall have full power and authority, subject to the limitations and provisions herein contained, to prescribe the manner in which, and the terms and conditions upon which, the shares of the Cumulative Preferred Stock shall be redeemed from time to time. If such notice of redemption shall have been duly given by publication, and if on or before the redemption date specified in such notice all funds necessary for such redemption shall have been set aside by the Corporation, separate and apart from its other funds, in trust for the account of the holders of the shares to be redeemed, so as to be and continue to be available therefor, then, notwithstanding that any certificate for such shares so called for redemption shall not have been surrendered for cancellation, from and after the date fixed for redemption, the shares represented thereby shall no longer be deemed outstanding, the right to receive dividends thereon shall cease to accrue and all rights with respect to such shares so called for redemption shall forthwith on such redemption date cease and terminate, except only the right of the holders thereof to receive, out of the funds so set aside in trust, the amount payable upon redemption thereof, without interest; provided, however, that the Corporation may, after giving notice by publication of any such redemption as hereinbefore provided or after giving to the bank or trust company hereinafter referred to irrevocable authorization to give such notice by publication, and at any time prior to the redemption date specified in such notice, deposit in trust, for the account of the holders of the shares to be redeemed, funds necessary for such redemption with a bank or trust company in good standing, organized under the laws of the United States of America or of the State of New York, doing business in the Borough of Manhattan, The City of New York, and having capital, surplus and undivided profits aggregating at least $50,000,000, or organized under the laws of the Commonwealth of Virginia, doing business in the City of Richmond, Virginia, and having capital, surplus and undivided profits aggregating at least $10,000,000, designated in such notice of redemption, and, upon such deposit in trust, all shares with respect to which such deposit shall have been made shall no longer be deemed to be outstanding, and all rights with respect to such shares shall forthwith cease and terminate, except only the right of the holders thereof to receive, out of the funds so deposited in trust, from and after the date of such deposit, the amount payable upon the redemption thereof, without interest. Nothing herein contained shall limit any right of the Corporation to purchase or otherwise acquire any shares of the Cumulative Preferred Stock; provided, however, that the Corporation shall not, if and when dividends payable on the Cumulative Preferred Stock shall be in default, purchase or otherwise acquire for value any shares of the Cumulative Preferred Stock (except by redemption of all outstanding shares of each series of the Cumulative Preferred Stock) unless such purchase or acquisition shall have been ordered, approved, or permitted by the Securities and Exchange Commission or any successor commission under the provisions of the Public Utility Holding Company Act of 1935 as at the time in effect. (4) Before any amount shall be paid to, or any assets distributed among, the holders of the Common Stock upon any liquidation, dissolution or winding up of the Corporation, and after paying or providing for the payment of all creditors of the Corporation, the holders of each series of the Cumulative Preferred Stock at the time outstanding shall be entitled to be paid in cash the amount for the particular series fixed therefor as herein provided, together with a sum in the case of each such share of each series, computed at the annual dividend rate for the series of which the particular share is a part, from the date from which dividends on such share became cumulative to the date fixed for the payment of such distributive amount, less the aggregate of the dividends theretofore or on such date paid thereon; but no payments on account of such distributive amounts shall be made to the holders of any series of the Cumulative Preferred Stock unless there shall likewise be paid at the same time to the holders of each other series of the Cumulative Preferred Stock at the time outstanding like proportionate distributive amounts, ratably, in proportion to the full distributive amounts to which they are respectively entitled as herein provided. The holders of the Cumulative Preferred Stock of any series shall not be entitled to receive any amounts with respect thereto upon any liquidation, dissolution or winding up of the Corporation other than the amounts referred to in this paragraph. Neither the consolidation or merger of the Corporation with any other corporation or corporations, nor the sale or transfer by the Corporation of all or any part of its assets, shall be deemed to be a liquidation, dissolution or winding up of the Corporation. (5) Whenever the full dividends on all series of the Cumulative Preferred Stock at the time outstanding for all past quarter-yearly dividend periods shall have been paid or declared and set apart for payment, then, subject to the provisions of subparagraph (7)(B)(c) hereof, such dividends (payable in cash, stock or otherwise) as may be determined by the Board of Directors may be declared and paid on the Common Stock, but only out of funds legally available for the payment of dividends; provided, however, that so long as any shares of the Cumulative Preferred Stock of any series are outstanding, the Corporation shall not declare or pay any dividends on the Common Stock of the Corporation except as follows: (a) If and so long as the Common Stock Equity at the end of the calendar month immediately preceding the date on which a dividend on the Common Stock is declared is, or as a result of such dividend would become, less than 20% of total capitalization, the Corporation shall not declare such dividends in an amount which, together with all other dividends on the Common Stock paid within the year ending with and including the date on which such dividend is payable, exceeds 50% of the net income of the Corporation available for dividends on the Common Stock for the twelve full calendar months immediately preceding the calendar month in which such dividends are declared, except in an amount not exceeding the aggregate of dividends on the Common Stock which could have been, but have not been, declared under this clause (a); and (b) If and so long as the Common Stock Equity at the end of the calendar month immediately preceding the date on which a dividend on the Common Stock is declared is, or as a result of such dividend would become, less than 25% but not less than 20% of total capitalization, the Corporation shall not declare such dividends in an amount which, together with all other dividends on the Common Stock paid within the year ending with and including the date on which such dividend is payable, exceeds 75% of the net income of the Corporation available for dividends on the Common Stock for the twelve full calendar months immediately preceding the calendar month in which such dividends are declared, except in an amount not exceeding the aggregate of dividends on the Common Stock which could have been, but have not been, declared under clause (a) above and this clause (b). (c) At any time when the Common Stock Equity is 25% or more of total capitalization, the Corporation may not declare dividends on shares of the Common Stock which would reduce the Common Stock Equity below 25% of total capitalization, except to the extent provided in clauses (a) and (b) above. For purposes of this paragraph (5): (i) The term "Common Stock" shall mean any stock of the Corporation ranking junior to the Cumulative Preferred Stock as to dividends or assets; the term "dividends" shall mean any dividend or distribution on the Common Stock (other than in shares of Common Stock) or any purchase or acquisition for value of any shares of Common Stock; and the term "Common Stock Equity" shall mean the aggregate of the par value of, or stated capital represented by, the outstanding shares of Common Stock, all earned surplus and capital surplus, and any premiums on the Common Stock then carried on the books of the Corporation, less (I) the excess, if any, of the aggregate amount payable on involuntary liquidation of the Corporation upon all outstanding shares of the Cumulative Preferred Stock of the Corporation of all series (including any stock of the Corporation ranking prior to or on a parity with the Cumulative Preferred Stock) over the sum of the aggregate stated capital attributable to such shares and any premiums thereon; (II) any amounts on the books of the Corporation known, or estimated if not known, to represent the excess, if any, of recorded value over original cost of used or useful utility plant; and (III) any intangible items set forth on the asset side of the balance sheet of the Corporation as the result of accounting convention, such as unamortized debt discount and expense; provided, however, that no deductions shall be required to be made in respect of items referred to in subdivision (II) and (III) of this subparagraph (i) in cases in which such items are being amortized or are provided for, or are being provided for, by reserves. (ii) The term "total capitalization" shall mean the aggregate of (I) the principal amount of all outstanding indebtedness of the Corporation maturing more than twelve months after the date of issue thereof, and (II) the stated capital represented by, and any premiums carried on the books of the Corporation in respect of, the outstanding shares of all classes of the capital stock of the Corporation, earned surplus and capital surplus, less any amounts required to be deducted pursuant to subdivisions (II) and (III) of subparagraph (i) above in the determination of Common Stock Equity. (6) In the event of any liquidation, dissolution or winding up of the Corporation, all assets and funds of the Corporation remaining after paying or providing for the payment of all creditors of the Corporation and after paying or providing for the payment to the holders of shares of all series of the Cumulative Preferred Stock of the full distributive amounts to which they are respectively entitled as herein provided, shall be divided among and paid to the holders of the Common Stock according to their respective rights and interests. (7)(A) So long as any shares of the Cumulative Preferred Stock of any series are outstanding, the Corporation shall not, without the consent (given by vote at a meeting called for that purpose) of the holders of more than two-thirds of the total number of votes which holders of the outstanding shares of the Cumulative Preferred Stock of all series are entitled to cast: (a) Increase the total authorized amount of the Cumulative Preferred Stock; or (b) Create or authorize any series of stock (other than a series of the Cumulative Preferred Stock) ranking prior to or on a parity with Cumulative Preferred Stock as to assets or dividends, or create or authorize any obligation or security convertible into shares of stock of any such series, or issue any shares of any such stock ranking prior to the Cumulative Preferred Stock (other than upon the conversion of any such convertible obligation or security), or issue any such convertible obligation or security, more than twelve months in the case of any such issuance after the date as of which the Corporation was empowered to create or authorize such prior ranking stock or such convertible obligation or security; or (c) Amend, alter, change or repeal any of the express terms of the Cumulative Preferred Stock or of any series of the Cumulative Preferred Stock then outstanding in a manner prejudicial to the holders thereof; provided, however, that if any such amendment, alteration, change or repeal would be prejudicial to the holders of one or more, but not all, of the series of the Cumulative Preferred Stock at the time outstanding, such consent of the holders of two-thirds of the total number of votes which holders of the shares of each series prejudicially affected are entitled to cast shall be required. (B) So long as any shares of the Cumulative Preferred Stock of any series are outstanding, the Corporation shall not, without the consent (given by vote at a meeting called for that purpose) of the holders of a majority of the total number of votes which holders of the outstanding shares of the Cumulative Preferred Stock of all series are entitled to cast, unless the consent of the holders of shares having some greater proportion of the total vote is required: (a) Merge or consolidate with or into any other corporation or corporations, or sell or otherwise dispose of all or substantially all of its assets, unless such merger, consolidation, sale or disposition, or the issuance and assumption of all securities to be issued or assumed in connection with any such transaction, shall have been ordered, approved, or permitted by the Securities and Exchange Commission or any successor commission under the provisions of the Public Utility Holding Company Act of 1935 as at the time in effect; provided that the provisions of this clause (a) shall not apply to a purchase or other acquisition by the Corporation of franchises or assets of another corporation in any manner which does not involve a merger or consolidation; or (b) Issue any additional shares, or reissue any reacquired shares, of Cumulative Preferred Stock or of any other class of stock ranking on a parity with the outstanding shares of the Cumulative Preferred Stock as to dividends or assets for any purpose other than to refinance an amount of outstanding Cumulative Preferred Stock, or stock ranking prior to or on a parity with the Cumulative Preferred Stock as to dividends or assets, having an aggregate involuntary liquidation price equal to the aggregate involuntary liquidation price of such issued or reissued shares, unless (i) the net income of the Corporation, determined in accordance with generally accepted accounting principles to be available for the payment of dividends for a period of twelve consecutive calendar months within the fifteen calendar months immediately preceding the calendar month of such issuance, is equal to at least twice the annual dividend requirements on the Cumulative Preferred Stock (including dividend requirements on any class of stock ranking prior to or on a parity with the shares to be issued as to dividends or assets), which will be outstanding immediately after the issuance of such shares; (ii) the gross income of the Corporation for said period, determined in accordance with generally accepted accounting principles (but in any event after all taxes including taxes based on income), is equal to at least one and one-half times the aggregate of the annual interest charges on indebtedness of the Corporation (excluding interest charges on indebtedness to be retired by the application of the proceeds from the issuance of such shares) and the annual dividend require- ments on the Cumulative Preferred Stock (including dividend requirements on any class of stock ranking prior to or on a parity with the shares to be issued as to dividends or assets), which will be outstanding immediately after the issuance of such shares; and (iii) the aggregate of the Common Stock Equity (the words "Common Stock" and "Common Stock Equity" having, for the purposes of this subpara- graph (7)(B)(b), the respective meanings defined in paragraph (5)(i) hereof) is at least equal to the aggregate amount payable in connection with an involuntary liquidation of the Corporation with respect to all shares of the Cumulative Preferred Stock and all shares of stock, if any, ranking prior thereto or on a parity therewith as to dividends or assets, which will be outstanding immediately after the issuance of such shares of Cumulative Preferred Stock or stock ranking prior to or on a parity therewith. If for the purposes of meeting the require- ments of subdivision (iii) of clause (b), it shall have been necessary to take into consideration any earned surplus of the Corporation, the Corporation shall not thereafter pay any dividends on or make any distributions in respect of, or purchase or otherwise acquire for value, Common Stock which would result in reducing the Common Stock Equity to an amount less than the amount payable on involuntary liquidation of the Corporation with respect to all shares of the Cumulative Preferred Stock and all shares ranking prior to or on a parity with the Cumulative Preferred Stock as to dividends or assets, at the time outstanding. If during the period as of which gross income is to be determined for the purposes set forth in clause (b), the amount, if any, required to be expended by the Corporation for property additions pursuant to a renewal and replacement fund or similar fund established under its mortgage indenture shall exceed the amount deducted in the determination of such gross income on account of depreciation and amortization of electric plant acquisition adjustments, such excess shall also be deducted in determining such gross income. (8) No holder of Cumulative Preferred Stock shall have any pre-emptive right to acquire unissued shares of the Corporation or to acquire any securities convertible into or exchangeable for such shares or to acquire any options, warrants or rights to purchase such shares. (9)(A) Every holder of any series of Cumulative Preferred Stock issued by the Corporation prior to June 1, 1977, shall be entitled to vote together with the holders of the Common Stock (every holder of Common Stock having one vote for each share of stock held) for the election of Directors and upon all other matters, except as otherwise provided in this paragraph (9) or in para- graph (7) hereof or as otherwise required by law. Every holder of any series of Cumulative Preferred Stock issued by the Corporation on or after June 1, 1977, shall be entitled to vote only as provided in paragraph (7), as provided in subparagraphs (B) through (F) of this para- graph (9) or as otherwise required by law. (B) On any matter on which the holders of any series of the Cumulative Preferred Stock shall be entitled to vote, each share shall entitle the holder thereof to a vote equal to the fraction of which the involuntary liquidation price fixed for such share as herein provided is the numerator and $100 is the denominator. (C) If and when dividends payable on the Cumulative Preferred Stock shall be in default in an amount equivalent to four (4) full quarter-yearly dividends on all shares of all series of the Cumulative Preferred Stock at the time outstanding, and until all dividends in default on the Cumulative Preferred Stock shall have been paid, the holders of all shares of the Cumulative Preferred Stock, voting separately as one class, shall be entitled to elect the smallest number of Directors necessary to constitute a majority of the full Board of Directors, and the holders of the Common Stock, voting separately as a class, shall be entitled to elect the remaining Directors of the Corporation. The terms of office of all persons who may be Directors of the Corporation at the time shall terminate upon the election of a majority of the Board of Directors by the holders of the Cumulative Preferred Stock, whether or not the holders of the Common Stock shall then have elected the remaining Directors of the Corporation. (D) If and when all dividends then in default on the Cumulative Preferred Stock at the time outstanding shall be paid (and such dividends shall be declared and paid out of any funds legally available therefor as soon as reasonably practicable), the Cumulative Preferred Stock shall thereupon be divested of any special right with respect to the election of Directors provided in subparagraph (C) hereof, and the voting power of the Cumulative Preferred Stock and the Common Stock shall revert to the status existing before the occurrence of such default; but always subject to the same provisions for vesting such special rights in the Cumulative Preferred Stock in case of further like default or defaults in dividends thereon. Upon the termination of any such special right upon payment of all accumulated and defaulted dividends on such stock, the terms of office of all persons who may have been elected Directors of the Corporation by vote of the holders of the Cumulative Preferred Stock, as a class, pursuant to such special right shall forthwith terminate. (E) In case of any vacancy in the Board of Directors occurring among the Directors elected by the holders of the Cumulative Preferred Stock, as a class, pursuant to subparagraph (C) hereof, the holders of the Cumulative Preferred Stock then outstanding and entitled to vote may elect a successor to hold office for the unexpired term of the Director whose place shall be vacant. In case of a vacancy in the Board of Directors occurring among the Directors elected by the holders of the Common Stock, as a class, pursuant to subparagraph (C) hereof, the holders of the Common Stock then out- standing and entitled to vote may elect a successor to hold office for the unexpired term of the Director whose place shall be vacant. In all other cases, any vacancy occurring among the Directors shall be filled by the vote of a majority of the remaining Directors. (F) Whenever the holders of the Cumulative Preferred Stock, as a class, become entitled to elect Directors of the Corporation pursuant to either sub- paragraph (C) or (E) hereof, or whenever the holders of the Common Stock, as a class, become entitled to elect Directors of the Corporation pursuant to either sub- paragraph (C) or (E) hereof, a meeting of the holders of the Cumulative Preferred Stock or of the Common Stock, as the case may be, shall be held at any time thereafter upon call by the holders of shares of the Cumulative Preferred Stock or of the Common Stock, as the case may be, entitling them to cast at least 1,000 votes for such purpose, or upon call by the Secretary of the Corporation at the request in writing of any stockholder addressed to him at the principal office of the Corporation. At all meetings of stockholders held for the purpose of electing Directors during such times as the holders of shares of the Cumulative Preferred Stock shall have the special right, voting separately as one class, to elect Directors pursuant to either subparagraph (C) or (E) hereof, the presence in person or by proxy of the holders of a majority of the outstanding shares of the Common Stock shall be required to constitute a quorum of such class for the election of Directors, and the presence in person or by proxy of the holders of a majority of the total number of votes which holders of the outstanding shares of all series of the Cumulative Preferred Stock are entitled to cast shall be required to constitute a quorum of such class for the election of Directors; provided, however, that the absence of a quorum of the holders of stock of either such class shall not prevent the election at any such meeting or adjournment thereof of Directors by the other such class if the necessary quorum of the holders of stock of such other class is present in person or by proxy at such meeting; and provided further that in the absence of a quorum of the holders of stock of either such class, the holders of a majority of the votes which holders of the stock of such class who are present in person or by proxy are entitled to cast shall have power to adjourn the election of the Directors to be elected by such class from time to time without notice other than announcement at the meeting until the holders of the requisite number of shares of such class shall be present in person or by proxy. (G) Except when some mandatory provision of law shall be controlling and except as otherwise provided in clause (c) of paragraph (7)(A) hereof and, as regards the special rights of any series of the Cumulative Preferred Stock, as provided in the terms determined for such series, whenever shares of two or more series of the Cumulative Preferred Stock are outstanding, no particular series of the Cumulative Preferred Stock shall be entitled to vote as a separate series on any matter and all shares of the Cumulative Preferred Stock of all series shall be deemed to constitute but one class for any purpose for which a vote of the stockholders of the Corporation by classes may now or hereafter be required. (10) The Corporation may, at any time and from time to time, issue and dispose of any of the authorized and unissued shares of the Cumulative Preferred Stock and Common Stock for such consideration as may be fixed by the Board of Directors, subject to any provisions of law then applicable, and subject to the provisions of any resolutions of the stockholders of the Corporation relating to the issue and disposition of such shares; provided, however, that, in the case of the Cumulative Preferred Stock, such consideration shall have a value not less than the aggregate preferential amount, fixed as herein provided, payable upon such shares in the event of involuntary liquidation. (11) As of June 1, 1977, 1,079,307 shares of the Cumulative Preferred Stock are issued and designated in series; and the Corporation has determined and fixed the designations, descriptions and terms of such series as follows: DIVISION A 4-1/2% Cumulative Preferred Stock 300,000 shares of Cumulative Preferred Stock are designated "4-1/2% Cumulative Preferred Stock". The description and terms of the shares of such series, and the respects in which they shall vary from other shares of Cumulative Preferred Stock, are as follows: (a) The annual dividend rate for such series shall be 4-1/2% per annum; (b) The redemption price for such series shall be $110 per share; (c) The amounts which shall be paid to the holders of shares of such series upon any liquidation, dissolution or winding up of the Corporation shall be $110 per share, upon any voluntary liquidation, dissolution or winding up of the Corporation, except that if such voluntary liquidation, dissolution or winding up of the Corporation shall have been approved by the vote in favor thereof of the holders of a majority of the total number of shares of the 4-1/2% Cumulative Preferred Stock then outstanding, given at a meeting called for that purpose, the amount so payable on such voluntary liquidation, dissolution, or winding up shall be $100 per share; or $100 per share, in the event of any involuntary liquidation, dissolution or winding up of the Corporation; (d) There shall not be any sinking fund provided for the purchase or redemption of shares of the 4-1/2% Cumulative Preferred Stock; and (e) The shares of the 4-1/2% Cumulative Preferred Stock shall not have any rights to convert the same into and/or purchase stock of any other series or class or other securities, or any special rights other than those specified herein. DIVISION B 4.50% Cumulative Preferred Stock 29,307 shares of Cumulative Preferred Stock are designated "4.50% Cumulative Preferred Stock". The description and terms of the shares of such series, and the respects in which they shall vary from other shares of Cumulative Preferred Stock, are as follows: (a) The annual dividend rate for such series shall be 4.50% per annum; (b) The regular redemption price for such series shall be $102 per share; the shares of such series shall be redeemable for the sinking fund provided for such series, or for any other sinking fund applicable to the shares of such series, at $100 per share (hereinafter referred to as the "sinking fund redemption price"); (c) The amounts which shall be paid to the holders of shares of such series upon any liquidation, dissolution or winding up of the Corporation shall be: $104 per share upon any voluntary liquidation, dissolution or winding up of the Corporation, except that if such voluntary liquidation, dissolution or winding up of the Corporation shall have been approved by the vote in favor thereof of the holders of a majority of the total number of shares of such series then outstanding given at a meeting called for that purpose, the amount so payable on such voluntary liquidation, dissolution or winding up shall be $100 per share; or $100 per share upon any involuntary liquidation, dissolution or winding up of the Corporation; (d) There shall be a sinking fund for the benefit of the shares of such series. So long as there shall remain outstanding any shares of such series, the Corporation, after the full dividends on all series of the Cumulative Preferred Stock at the time outstanding for all past quarter-yearly dividend periods shall have been paid or declared and set apart for payment, shall, on or before November 30 in each year, set aside out of funds legally available therefor as the sinking fund requirement for such year an amount in cash sufficient to redeem, at the sinking fund redemption price provided in (b) above, two per cent (2%) of the maximum number of shares of the 4.50% Cumulative Preferred Stock which shall theretofore have been issued and outstanding at any one time (75,000 shares), provided, however, that against the sinking fund requirement for any calendar year the Corporation may credit an amount equal to the sinking fund redemption price in respect of any shares of such series which it may have purchased for retirement or redeemed otherwise than through the sinking fund and not theretofore credited against any sinking fund require- ment. Unless the sinking fund requirement for such series for all past sinking fund periods shall have been set aside, no dividends shall be paid or declared and no other distribution shall be made on the Common Stock, and no Common Stock shall be purchased or otherwise acquired for value by the Corporation. The Corporation may apply any cash set aside for sinking fund purposes to the purchase or redemption and cancellation of shares of such series. Any balance of cash so set aside remaining after 90 days from November 30th of each year shall be applied promptly to the redemption and cancellation of shares of such series. All shares to be redeemed through the sinking fund shall be selected by lot in such manner as the Board of Directors of the Corporation may determine. Notwithstanding the foregoing, the cancellation of shares of such series so purchased or redeemed shall not retire such shares or decrease capital except upon compliance with the provisions of Section 13.1-63 of the Code of Virginia as at the time in effect; and (e) The shares of such series shall not have any rights to convert the same into and/or purchase stock of any other series or class or other securities, or any special rights other than those specified herein. DIVISION C 8.12% Cumulative Preferred Stock 300,000 shares of Cumulative Preferred Stock are designated "8.12% Cumulative Preferred Stock". The description and terms of the shares of such series, and the respects in which they shall vary from other shares of Cumulative Preferred Stock, are as follows: (a) The annual dividend rate for such series shall be 8.12% per annum; (b) The redemption price for such series shall be $107.59 per share prior to September 1, 1981; $105.56 per share on and after September 1, 1981 but prior to September 1, 1986; $103.53 per share on and after September 1, 1986 but prior to September 1, 1991; and $102.31 per share on September 1, 1991 and thereafter; (c) The preferential amounts to which the holders of shares of such series shall be entitled upon any liquidation, dissolution or winding up of the Corporation shall be the redemption price in effect at the date of any voluntary liquidation, dissolution or winding up of the Corporation; or $100 per share, in the event of any involuntary liquidation, dissolution or winding up of the Corporation; (d) There shall not be any sinking fund provided for the purchase or redemption of shares of such series; and (e) The shares of such series shall not have any rights to convert the same into and/or purchase stock of any other series or class or any other securities, or any special rights other than those specified herein. DIVISION D 7.40% Cumulative Preferred Stock 250,000 shares of Cumulated Preferred Stock are designated "7.40% Cumulative Preferred Stock". The description and terms of the shares of such series, and the respects in which they shall vary from other shares of Cumulative Preferred Stock, are as follows: (a) The annual dividend rate for such series shall be 7.40% per annum; (b) The redemption price for such series shall be $106.92 per share prior to February 1, 1982; $105.07 per share on and after February 1, 1982 but prior to February 1, 1987; $103.22 per share on and after February 1, 1987 but prior to February 1, 1992; and $102.11 per share on February 1, 1992 and thereafter; (c) The preferential amounts to which the holders of shares of such series shall be entitled upon any liquidation, dissolution or winding up of the Corporation shall be the redemption price in effect at the date of any voluntary liquidation, dissolution or winding up of the Corporation; or $100 per share, in the event of any involuntary liquidation, dissolution or winding up of the Corporation; (d) There shall not be any sinking fund provided for the purchase or redemption of shares of such series; and (e) The shares of such series shall not have any rights to convert the same into and/or purchase stock of any other series or class or any other securities, or any special rights other than those specified herein. DIVISION E 8.52% Cumulative Preferred Stock 200,000 shares of Cumulative Preferred Stock are designated "8.52% Cumulative Preferred Stock". The description and terms of the shares of such series, and the respects in which they shall vary from other shares of Cumulative Preferred Stock, are as follows: (a) The annual dividend rate for such series shall be 8.52% per annum; (b) The redemption price for such series shall be $109.52 per share prior to March 1, 1979; $107.39 per share on and after March 1, 1979 but prior to March 1, 1984; $105.26 per share on and after March 1, 1984 but prior to March 1, 1989; $103.13 per share on and after March 1, 1989 but prior to March 1, 1994; and $101.86 per share on March 1, 1994 and thereafter, provided, however, that no share of such series shall be redeemed prior to March 1, 1979 if such redemption is for the purpose or in anticipation of refunding such share, directly or indirectly, through the incurring of debt, or through the issuance of capital stock ranking equally with or prior to the shares of said series as to dividends or assets, if such debt has an effective interest cost to the Corporation (computed in accordance with generally accepted financial practice), or such capital stock has an effective dividend cost to the Corporation (so computed) of less than 8.52% per annum; (c) The preferential amounts to which the holders of shares of such series shall be entitled upon any liquidation, dissolution or winding up of the Corporation shall be the redemption price in effect at the date of any voluntary liquidation, dissolution or winding up of the Corporation; or $100 per share, in the event of any voluntary liquidation, dissolution or winding up of the Corporation; (d) There shall not be any sinking fund provided for the purchase or redemption of shares of such series; and (e) The shares of such series shall not have any rights to convert the same into and/or purchase stock of any other series or class or any other securities, or any special rights other than those specified herein. DIVISION F 9% Cumulative Preferred Stock 600,000 shares of Cumulative Preferred Stock are designated "9% Cumulative Preferred Stock". The description and terms of the shares of such series, and the respects in which they shall vary from other shares of Cumulative Preferred Stock, are as follows: (a) The distinctive serial designation of such series shall be "9% Cumulative Preferred Stock"; (b) The annual dividend rate for such series shall be 9% per share per annum, which dividend shall be calculated, per share, at such percentage multiplied by $100, and the date from which dividends on all shares of said series issued prior to the record date for the dividend payable November 1, 1987, shall be cumulative, shall be the date of issuance of the shares of such series; (c) The regular redemption price for such series shall be $109.00 per share on or prior to August 31, 1992 and thereafter shall be as follows: If Redeemed Regular During 12 Months Redemption Period Ending Price August 31 Per Share 1993 $106.75 1994 106.30 1995 105.85 1996 105.40 1997 104.95 1998 104.50 1999 104.05 2000 103.60 2001 103.15 2002 102.70 2003 102.25 2004 101.80 2005 101.35 2006 100.90 2007 100.45 and thereafter the regular redemption price per share of such series shall be $100 per share; provided, however, that no share of such series shall be redeemed prior to September 1, 1992 if such redemption is for the purpose or in anticipation of refunding such share, directly or indirectly, through the incurring of debt, or through the issuance of capital stock ranking equally with or prior to the shares of said series as to dividends or assets, if such debt has an effective interest cost to the Corporation (computed in accordance with generally accepted financial practice), or such capital stock has an effective dividend cost to the Corporation (so computed) of less than 9.10% per annum; (d) The preferential amounts to which the holders of shares of such series shall be entitled upon any liquidation, dissolution or winding up of the Corporation shall be the redemption price in effect at the date of any voluntary liquidation, dissolution or winding up of the Corporation; or $100 per share, in the event of any involuntary liquidation, dissolution or winding up of the Corporation; (e)(1) A sinking fund shall be established for the retirement of the shares of such series. So long as there shall remain outstanding any shares of such series, the Corporation shall, to the extent permitted by law on November 1 in each year commencing with the year 1992, redeem as and for a sinking fund requirement, out of funds legally available therefor, a number of shares equal to 5% of the total number of shares classified as 9% Cumulative Preferred Stock in these Articles of Amendment at a redemption price of $100 per share. The sinking fund requirement shall be cumulative so that if on any such November 1 the sinking fund requirement shall not have been met, then such sinking fund requirement, to the extent not met, shall become an additional sinking fund requirement for the next succeeding November 1 on which such redemption may be effected. (2) The Corporation shall have the non- cumulative option, on any sinking fund date as provided in subparagraph (e)(1) hereof, to redeem at a redemption price of $100 per share, an additional number of shares equal to 5% of the total number of shares classified as 9% Cumulative Preferred Stock in these Articles of Amendment. No redemption made pursuant to this subparagraph (e)(2) shall be deemed to fulfill any sinking fund requirement established pursuant to subparagraph (e)(1). (3) The Corporation shall be entitled, at its election, to credit against the sinking fund requirement due on November 1 of any year pursuant to subparagraph (e)(1) shares of such series theretofore purchased or otherwise acquired by the Corporation and not previously credited against any sinking fund requirement. (f) The shares of such series shall not have any rights to convert the same into and/or purchase stock of any other series or class or any other securities, or any special rights other than those specified herein. DIVISION G 7.80% Cumulative Preferred Stock 500,000 shares of Cumulative Preferred Stock are designated "7.80% Cumulative Preferred Stock". The description and terms of the shares of such series, and the respects in which they shall vary from other shares of Cumulative Preferred Stock, are as follows: (a) The distinctive serial designation of such series shall be "7.80% Cumulative Preferred Stock". (b) The annual dividend rate for such series shall be 7.80% per share per annum, which dividend shall be calculated, per share, at such percentage multiplied by $100, and the date from which dividends on all shares of said series issued prior to the record date for the dividend payable May 1, 1992, shall be cumulative, shall be the date of initial issuance of the shares of such series. (c) The regular redemption price for such series shall be $107.80 per share on or prior to March 31, 1997 and thereafter shall be as follows: Regular Redemption Price Redemption Date (Dates Inclusive) Per Share April 1, 1997 to March 31, 1998 $105.20 April 1, 1998 to March 31, 1999 104.68 April 1, 1999 to March 31, 2000 104.16 April 1, 2000 to March 31, 2001 103.64 April 1, 2001 to March 31, 2002 103.12 April 1, 2002 to March 31, 2003 102.60 April 1, 2003 to March 31, 2004 102.08 April 1, 2004 to March 31, 2005 101.56 April 1, 2005 to March 31, 2006 101.04 April 1, 2006 to March 31, 2007 100.52 and thereafter the regular redemption price per share shall be $100 per share, plus an amount in each case equal to accrued unpaid dividends to the date of redemption; provided, however, that no share of such series shall be redeemed prior to April 1, 1997 if such redemption is for the purpose or in anticipation of refunding such share, directly or indirectly, through the incurring of debt, or through the issuance of shares of capital stock ranking equally with or prior to the shares of said series as to dividends or assets, if such debt has an effective interest cost to the Corporation (computed in accordance with generally accepted financial practice), or such shares of capital stock have an effective dividend cost to the Corporation (so computed), of less than 7.88% per annum. (d) The preferential amounts to which the holders of shares of such series shall be entitled upon any liquidation, dissolution or winding up of the Corporation shall be the regular redemption price in effect at the date of any voluntary liquidation, dissolution or winding up of the Corporation; or $100 per share, in the event of any involuntary liquidation, dissolution or winding up of the Corporation. (e)(1) A sinking fund shall be established for the retirement of the shares of such series. So long as there shall remain outstanding any shares of such series, the Corporation shall, to the extent permitted by law, on May 1 in each year commencing with the year 1998, redeem as and for a sinking fund requirement, out of funds legally available therefor, a number of shares equal to 5% of the total number of shares initially classified as 7.80% Cumulative Preferred Stock in these Articles of Amendment at a sinking fund redemption price of $100 per share plus accrued unpaid dividends to the date of redemption. The sinking fund requirement shall be cumulative so that if on any such May 1 the sinking fund requirement shall not have been met, then such sinking fund requirement, to the extent not met, shall become an additional sinking fund requirement for the next succeeding May 1 on which such redemption may be effected. (2) The Corporation shall have the non-cumulative option, on any sinking fund date as provided in subparagraph (e)(1) hereof, to redeem at a sinking fund redemption price of $100 per share, an additional number of shares equal to not more than 5% of the total number of shares initially classified as 7.80% Cumulative Preferred Stock in these Articles of Amendment. No redemption made pursuant to this subparagraph (e)(2) shall be deemed to fulfill any sinking fund requirement established pursuant to subparagraph (e)(1). (3) The Corporation shall be entitled, at its election, to credit against the sinking fund requirement due on May 1 of any year pursuant to subparagraph (e)(1) shares of such series theretofore purchased or otherwise acquired by the Corporation and not previously credited against any such sinking fund requirement. (f) The shares of such series shall not have any rights to convert the same into and/or purchase stock of any other series or class or any other securities, or any special rights other than those specified herein. DIVISION H 5.92% Cumulative Preferred Stock 600,000 shares of Cumulative Preferred Stock are designated "5.92% Cumulative Preferred Stock". The description and terms of the shares of such series, and the respects in which they shall vary from other shares of Cumulative Preferred Stock, are as follows: (a) The distinctive serial designation of such series shall be "5.92% Cumulative Preferred Stock". (b) The annual dividend rate for such series shall be 5.92% per share per annum, which dividend shall be calculated, per share, at such percentage multiplied by $100, and the date from which dividends on all shares of said series issued prior to the record date for the dividend payable February 1, 1994, shall be cumulative, shall be the date of initial issuance of the shares of such series. (c) Such series shall not be subject to redemption prior to October 1, 2003; the regular redemption price for shares of such series shall be $100 per share on or after October 1, 2003, plus an amount equal to accrued and unpaid dividends to the date of redemption. (d) The preferential amounts to which the holders of shares of such series shall be entitled upon any voluntary or involuntary liquidation, dissolution or winding up of the Corporation shall be $100 per share, plus accrued and unpaid dividends. (e)(1) A sinking fund shall be established for the retirement of the shares of such series. So long as there shall remain outstanding any shares of such series, the Corporation shall, to the extent not prohibited by law, on November 1, 2003, and on each November 1 thereafter to and including November 1, 2007, redeem as and for a sinking fund requirement, a number of shares equal to 5% of the total number of shares initially classified as 5.92% Cumulative Preferred Stock in these Articles of Amendment at a sinking fund redemption price of $100 per share plus accrued unpaid dividends to the date of redemption. The remaining shares of such series outstanding on November 1, 2008 will be redeemed as a final sinking fund requirement, to the extent not prohibited by law, on such date at a sinking fund redemption price of $100 per share plus accrued and unpaid dividends to the date of redemption. The sinking fund requirement shall be cumulative so that if on any such November 1 the sinking fund requirement shall not have been met, then such sinking fund requirement, to the extent not met, shall become an additional sinking fund requirement for the next succeeding November 1 on which such redemption may be effected. (2) The Corporation shall be entitled, at its election, to credit against the sinking fund requirement due on November 1 of any year pursuant to subparagraph (e)(1) shares of such series theretofore purchased or otherwise acquired by the Corporation and not previously credited against any such sinking fund requirement. (f) The shares of such series shall not have any rights to convert the same into and/or purchase stock of any other series or class or any other securities, or any special rights other than those specified herein. DIVISION I 5.90% Cumulative Preferred Stock 500,000 shares of Cumulative Preferred Stock are designated "5.90% Cumulative Preferred Stock". The description and terms of the shares of such series, and the respects in which they shall vary from other shares of Cumulative Preferred Stock, are as follows: (a) The distinctive serial designation of such series shall be "5.90% Cumulative Preferred Stock". (b) The annual dividend rate for such series shall be 5.90% per share per annum, which dividend shall be calculated, per share, at such percentage multiplied by $100, and the date from which dividends on all shares of said series issued prior to the record date for the dividend payable February 1, 1994, shall be cumulative, shall be the date of initial issuance of the shares of such series. (c) Such series shall not be subject to redemption prior to November 1, 2003; the regular redemption price for shares of such series shall be $100 per share on or after November 1, 2003, plus an amount equal to accrued and unpaid dividends to the date of redemption. (d) The preferential amounts to which the holders of shares of such series shall be entitled upon any voluntary or involuntary liquidation, dissolution or winding up of the Corporation shall be $100 per share, plus accrued and unpaid dividends. (e)(1) A sinking fund shall be established for the retirement of the shares of such series. So long as there shall remain outstanding any shares of such series, the Corporation shall, to the extent not prohibited by law, on November 1, 2003, and on each November 1 thereafter to and including November 1, 2007, redeem as and for a sinking fund requirement, a number of shares equal to 5% of the total number of shares initially classified as 5.90% Cumulative Preferred Stock in these Articles of Amendment at a sinking fund redemption price of $100 per share plus accrued unpaid dividends to the date of redemption. The remaining shares of such series outstanding on November 1, 2008 will be redeemed as a final sinking fund requirement, to the extent not prohibited by law, on such date at a sinking fund redemption price of $100 per share plus accrued and unpaid dividends to the date of redemption. The sinking fund requirement shall be cumulative so that if on any such November 1 the sinking fund requirement shall not have been met, then such sinking fund requirement, to the extent not met, shall become an additional sinking fund requirement for the next succeeding November 1 on which such redemption may be effected. (2) The Corporation shall be entitled, at its election, to credit against the sinking fund requirement due on November 1 of any year pursuant to subparagraph (e)(1) shares of such series theretofore purchased or otherwise acquired by the Corporation and not previously credited against any such sinking fund requirement. (f) The shares of such series shall not have any rights to convert the same into and/or purchase stock of any other series or class or any other securities, or any special rights other than those specified herein. DIVISION J 6.85% Cumulative Preferred Stock 300,000 shares of Cumulative Preferred Stock, without par value, are designated "6.85% Cumulative Preferred Stock," consisting of shares of such Cumulative Preferred Stock with designation, description and terms as follows: (a) The distinctive serial designation of such series shall be "6.85% Cumulative Preferred Stock". (b) The annual dividend rate for such series shall be 6.85% per share per annum, which dividend shall be calculated, per share, at such percentage multiplied by $100, and the date from which dividends on all shares of said series issued prior to the record date for the dividend payable August 1, 1994, shall be cumulative, shall be the date of original issuance of the shares of such series. (c) Such series shall not be subject to redemption except as provided in subparagraph (e) below. (d) The preferential amounts to which the holders of shares of such series shall be entitled upon any voluntary or involuntary liquidation, dissolution or winding up of the Corporation shall be $100 per share, plus accrued and unpaid dividends. (e)(1) A sinking fund shall be established for the retirement of the shares of such series. So long as there shall remain outstanding any shares of such series, the Corporation shall, to the extent not prohibited by law, on August 1 of each year commencing with the year 2000, redeem as and for a sinking fund requirement, 60,000 shares of the 6.85% Cumulative Preferred Stock at a sinking fund redemption price of $100 per share plus accrued unpaid dividends to the date of redemption. The sinking fund requirement shall be cumulative so that if on any such August 1 the sinking fund requirement shall not have been met, then such sinking fund requirement, to the extent not met, shall become an additional sinking fund requirement for the next succeeding August 1 on which such redemption may be effected. (2) The Corporation shall have the non-cumulative option, on any sinking fund date as provided in subparagraph (e)(1), to redeem at the sinking fund redemption price of $100 per share plus accrued and unpaid dividends to the date of redemption up to an additional 60,000 shares of such series. No redemption made pursuant to this subparagraph (e)(2) shall be deemed to fulfill any sinking fund redemption established pursuant to subparagraph (e)(1). (3) The Corporation shall be entitled, at its election, to credit against the sinking fund requirement due on August 1 of any year pursuant to subparagraph (e)(1) shares of such series theretofore purchased or otherwise acquired by the Corporation (other than pursuant to the option provided by subparagraph (e)(2)) and not previously credited against any such sinking fund requirement. (f) The shares of such series shall not have any rights to convert the same into and/or purchase stock of any other series or class or any other securities, or have any special rights other than those specified herein. EX-4.B 4 APCO INDENTURE SUPPLEMENTAL 10K405 EX4B EXHIBIT 4(b) Indenture Supplemental TO Mortgage and Deed of Trust (Dated as of December 1, 1940) Executed by APPALACHIAN POWER COMPANY formerly Appalachian Electric Power Company TO BANKERS TRUST COMPANY, As Trustee Dated as of February 1, 1997 $48,000,000 First Mortgage Bonds, Designated Secured Medium Term Notes, 6.35% Series due March 1, 2000 TABLE OF CONTENTS The Table of Contents shall not be deemed to be any part of the Indenture Supplemental to Mortgage and Deed of Trust. PAGE PARTIES . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 RECITALS Execution of Mortgage. . . . . . . . . . . . . . . . . . 1 Execution of supplemental indentures . . . . . . . . . . 1 Termination of Individual Trustee. . . . . . . . . . . . 1 Provision for issuance of bonds in one or more series. . 2 Right to execute supplemental indenture. . . . . . . . . 2 First Mortgage Bonds heretofore issued . . . . . . . . . 2 Issue of new First Mortgage Bonds of the 61st Series . . 3 First 1997 Supplemental Indenture . . . . . . . . . . . . 3 Compliance with legal requirements . . . . . . . . . . . 4 GRANTING CLAUSES. . . . . . . . . . . . . . . . . . . . . . . 4 DESCRIPTION OF PROPERTY . . . . . . . . . . . . . . . . . . . 4 APPURTENANCES, ETC. . . . . . . . . . . . . . . . . . . . . . 4 HABENDUM. . . . . . . . . . . . . . . . . . . . . . . . . . . 5 PRIOR LEASEHOLD ENCUMBRANCES. . . . . . . . . . . . . . . . . 5 GRANT IN TRUST. . . . . . . . . . . . . . . . . . . . . . . . 6 SECTION 1. Amendment to Section 40 of Original Indenture to delete the third paragraph of Part I of said section. . . . . . . . . . . . . .7 SECTION 2. Amendment to Section 27 of Original Indenture to delete the fourth paragraph of said section. . . . . . . . . . . . . . . . . . .7 SECTION 3. Supplement to Original Indenture by adding Section 20HHH. . . . . . . . . . . . . . . . . 7 SECTION 4. Initial Issuance of the Bonds of the 61st Series. 9 SECTION 5. Provision for record date for meetings of Bondholders . . . . . . . . . . . . . . . . 10 SECTION 6. Original Indenture and First 1997 Supplemental Indenture same instrument. . . . . . . . . . . 10 SECTION 7. Limitation of rights . . . . . . . . . . . . . . . 10 SECTION 8. Execution in counterparts . . . . . . . . . . . . 10 TESTIMONIUM . . . . . . . . . . . . . . . . . . . . . . . . . 11 SIGNATURES AND SEALS. . . . . . . . . . . . . . . . . . . . . 11 ACKNOWLEDGMENTS . . . . . . . . . . . . . . . . . . . . . . . 13 SCHEDULE I. . . . . . . . . . . . . . . . . . . . . . . . . . I-1 SUPPLEMENTAL INDENTURE, dated as of the first day of February in the year One Thousand Nine Hundred and Ninety-seven, made and entered into by and between APPALACHIAN POWER COMPANY, a corporation of the Commonwealth of Virginia, the corporate title of which was, prior to April 17, 1958, APPALACHIAN ELECTRIC POWER COMPANY (hereinafter sometimes called the "Company"), a transmitting utility (as such term is defined in Section 46-9- 105(1)(n) of the West Virginia Code), party of the first part, and BANKERS TRUST COMPANY, a corporation of the State of New York (hereinafter sometimes called the "Corporate Trustee" or "Trustee"), as Trustee, party of the second part. WHEREAS, the Company has heretofore executed and delivered its Mortgage and Deed of Trust (hereinafter sometimes referred to as the "Mortgage"), dated as of December 1, 1940, to the Trustee for the security of all bonds of the Company outstanding thereunder, and by said Mortgage conveyed to the Trustee, upon certain trusts, terms and conditions, and with and subject to certain provisos and covenants therein contained, all and singular the property, rights and franchises which the Company then owned or should thereafter acquire, excepting any property expressly excepted by the terms of the Mortgage; and WHEREAS, the Company has heretofore executed and delivered to the Trustee supplements and indentures supplemental to the Mortgage, dated as of December 1, 1943, December 2, 1946, December 1, 1947, March 1, 1950, June 1, 1951, October 1, 1952, December 1, 1953, March 1, 1957, May 1, 1958, October 2, 1961, April 1, 1962, June 1, 1965, September 2, 1968, December 1, 1968, October 1, 1969, June 1, 1970, October 1, 1970, September 1, 1971, February 1, 1972, December 1, 1972, July 1, 1973, March 1, 1974, April 1, 1975, May 1, 1975, December 1, 1975, April 1, 1976, September 1, 1976, November 1, 1977, May 1, 1979, August 1, 1979, February 1, 1980, November 1, 1980, April 1, 1982, October 1, 1983, February 1, 1987, September 1, 1987, November 1, 1989, December 1, 1990, August 1, 1991, February 1, 1992, May 1, 1992, August 1, 1992, November 15, 1992, April 15, 1993, May 15, 1993, October 1, 1993, November 1, 1993, August 15, 1994, October 1, 1994, March 1, 1995, May 1, 1995, June 1, 1995 and March 1, 1996 (hereinafter referred to as the "First 1996 Supplemental Indenture"), respectively, amending and supplementing the Mortgage in certain respects (the Mortgage, as so amended and supplemented, being hereinafter called the "Original Indenture") and conveying to the Trustee, upon certain trusts, terms and conditions, and with and subject to certain provisos and covenants therein contained, certain property rights and property therein described; and WHEREAS, effective October 7, 1988, pursuant to Section 115 of the Original Indenture, the Individual Trustee resigned and all powers of the Individual Trustee then terminated, as did the Individual Trustee's right, title or interest in and to the trust estate, and without appointment of a new trustee as successor to the Individual Trustee, all the right, title and powers of the Trustee thereupon devolved upon the Corporate Trustee and its successors alone; and WHEREAS, the Original Indenture provides that bonds issued thereunder may be issued in one or more series and further provides that, with respect to each series, the rate or rates of interest, the date or dates of maturity, the dates for the payment of interest, the terms and rates of optional redemption, and other terms and conditions not inconsistent with the Original Indenture may be established, prior to the issue of bonds of such series, by an indenture supplemental to the Original Indenture; and WHEREAS, Section 132 of the Original Indenture provides that any power, privilege or right expressly or impliedly reserved to or in any way conferred upon the Company by any provision of the Original Indenture, whether such power, privilege or right is in any way restricted or is unrestricted, may be in whole or in part waived or surrendered or subjected to any restriction if at the time unrestricted or to additional restriction if already restricted, and that the Company may enter into any further covenants, limitations or restrictions for the benefit of any one or more series of bonds issued under the Original Indenture and provide that a breach thereof shall be equivalent to a default under the Original Indenture, or the Company may cure any ambiguity or correct or supplement any defective or inconsistent provisions contained in the Original Indenture or in any indenture supplemental to the Original Indenture, by an instrument in writing, executed and acknowledged, and that the Trustee is authorized to join with the Company in the execution of any such instrument or instruments; and WHEREAS, the Company has heretofore issued, in accordance with the provisions of the Mortgage, as amended and supplemented as of the respective dates thereof, bonds of the series (which are outstanding), entitled and designated as hereinafter set forth, in the respective original aggregate principal amounts indicated: Series Amount First Mortgage Bonds, 7.00% Series due 1999. . . $30,000,000 First Mortgage Bonds, 6-3/8% Series due 2001. . . 100,000,000 First Mortgage Bonds, 7.95% Series due 2002. . . 60,000,000 First Mortgage Bonds, 7.38% Series due 2002. . . 50,000,000 First Mortgage Bonds, 7.40% Series due 2002. . . 30,000,000 First Mortgage Bonds, 6.65% Series due 2003. . . 40,000,000 First Mortgage Bonds, 6.85% Series due 2003. . . 30,000,000 First Mortgage Bonds, 6.00% Series due 2003. . . 30,000,000 First Mortgage Bonds, 7.70% Series due 2004. . . 21,000,000 First Mortgage Bonds, 7.85% Series due 2004. . . 50,000,000 First Mortgage Bonds, 8.00% Series due 2005. . . 50,000,000 First Mortgage Bonds, 6.89% Series due 2005. . . 30,000,000 First Mortgage Bonds, 6.80% Series due 2006. . . 100,000,000 First Mortgage Bonds, 9.35% Series due 2021. . . 50,000,000 First Mortgage Bonds, 8.75% Series due 2022. . . 50,000,000 First Mortgage Bonds, 8.70% Series due 2022. . . 40,000,000 First Mortgage Bonds, 8.43% Series due 2022. . . 50,000,000 First Mortgage Bonds, 8.50% Series due 2022. . . 70,000,000 First Mortgage Bonds, 7.80% Series due 2023. . . 40,000,000 First Mortgage Bonds, 7.90% Series due 2023. . . 30,000,000 First Mortgage Bonds, 7.15% Series due 2023. . . 30,000,000 First Mortgage Bonds, 7.125% Series due 2024. . . 50,000,000 First Mortgage Bonds, 8.00% Series due 2025. . . 50,000,000 and WHEREAS, the Company, by appropriate corporate action in conformity with the terms of the Original Indenture, has duly determined to create a series of bonds under the Original Indenture to be designated as "First Mortgage Bonds, Designated Secured Medium Term Notes, 6.35% Series due March 1, 2000" (hereinafter sometimes referred to as the "bonds of the 61st Series"); and WHEREAS, each of the bonds of the 61st Series is to be substantially in the form set forth in Schedule I to this Supplemental Indenture (hereinafter sometimes referred to as the "First 1997 Supplemental Indenture"); and WHEREAS, the Company, in the exercise of the powers and authorities conferred upon and reserved to it under and by virtue of the provisions of the Original Indenture, and pursuant to resolutions of its Board of Directors, has duly resolved and determined to make, execute and deliver to the Trustee a supplemental indenture, in the form hereof, for the purposes herein provided; and WHEREAS, all conditions and requirements necessary to make this First 1997 Supplemental Indenture a valid, binding and legal instrument in accordance with its terms, have been done, performed and fulfilled, and the execution and delivery thereof have been in all respects duly authorized; NOW, THEREFORE, THIS INDENTURE WITNESSETH: That Appalachian Power Company, in consideration of the premises and of the purchase and acceptance of the bonds by the holders thereof and of the sum of One Dollar ($1.00) and other good and valuable consideration paid to it by the Trustee at or before the ensealing and delivery of these presents, the receipt whereof is hereby acknowledged, and in order to secure the payment of both the principal of and interest and premium, if any, on the bonds from time to time issued under and secured by the Original Indenture and this First 1997 Supplemental Indenture, according to their tenor and effect, and the performance of all the provisions of the Original Indenture and this First 1997 Supplemental Indenture (including any further indenture or indentures supplemental to the Original Indenture and any modification or alteration made as in the Original Indenture provided) and of said bonds, has granted, bargained, sold, released, conveyed, transferred, mortgaged, pledged, set over and confirmed, and by these presents does grant, bargain, sell, release, convey, assign, transfer, mortgage, pledge, set over and confirm unto Bankers Trust Company, as Trustee, and to its respective successor or successors in the trust hereby created, and to its and their assigns, all the following described properties of the Company, that is to say: All property, real, personal and mixed, tangible and intangible, and all franchises owned by the Company on the date of the execution hereof, acquired since the execution of the First 1996 Supplemental Indenture (except any hereinafter expressly excepted from the lien and operation of this First 1997 Supplemental Indenture). TOGETHER WITH all and singular the tenements, hereditaments and appurtenances belonging or in anywise appertaining to the aforesaid property or any part thereof, with the reversion and reversions, remainder and remainders and (subject to the provisions of Section 63 of the Original Indenture) the tolls, rents, revenues, issues, earnings, income, product and profits thereof and all the estate, right, title and interest and claim whatsoever, at law as well as in equity, which the Company now has or may hereafter acquire in and to the aforesaid property and franchises and every part and parcel thereof. Provided that, in addition to the reservations and exceptions herein elsewhere contained, the following are not and are not intended to be now or hereafter granted, bargained, sold, released, conveyed, assigned, transferred, mortgaged, pledged, set over or confirmed hereunder and are hereby expressly excepted from the lien and operation of the Original Indenture and this First 1997 Supplemental Indenture, viz.: (1) cash, shares of stock, and obligations (including bonds, notes and other securities) not hereinafter or in the Original Indenture specifically pledged, deposited or delivered hereunder or thereunder or hereinafter or therein covenanted so to be; (2) any goods, wares, merchandise, equipment, materials or supplies acquired for the purpose of sale or resale in the usual course of business or for consumption in the operation of any properties of the Company and automobiles and trucks; (3) all judgments, accounts, and choses in action, the proceeds of which the Company is not obligated as hereinafter provided or as provided in the Original Indenture to deposit with the Trustee hereunder and thereunder; provided, however, that the property and rights expressly excepted from the lien and operation of the Original Indenture and this First 1997 Supplemental Indenture in the above subdivisions (2) and (3) shall (to the extent permitted by law) cease to be so excepted, in the event that the Trustee or a receiver or trustee shall enter upon and take possession of the mortgaged and pledged property in the manner provided in Article XIV of the Original Indenture by reason of the occurrence of a completed default, as defined in said Article XIV. TO HAVE AND TO HOLD all such properties, real, personal and mixed, granted, bargained, sold, released, conveyed, assigned, transferred, mortgaged, pledged, set over or confirmed by the Company as aforesaid, or intended so to be, unto the Trustee and its successors in the trust; SUBJECT, HOWEVER, to the reservations, exceptions, conditions, limitations and restrictions contained in the several deeds, leases, servitudes, franchises and contracts or other instruments through which the Company acquired and/or claims title to and/or enjoys the use of the aforesaid properties; and subject also to encumbrances of the character defined in Section 6 of the Original Indenture as "excepted encumbrances" in so far as the same may attach to any of the property embraced herein. Inasmuch as the Company holds certain of said lands, rights of way and other property under leases, power agreements and other contracts which provide that the Company's interest therein shall not be mortgaged without the consent of the respective lessors or other parties to said agreements and contracts, and such lessors and parties have either given such consent or have waived the requirement of such consent, it is hereby expressly agreed and made a condition upon which this First 1997 Supplemental Indenture is executed and delivered, that the lien of this First 1997 Supplemental Indenture and the estate, rights and remedies of the Trustee hereunder, and the rights and remedies of the holders of the bonds secured hereby and by the Original Indenture in so far as they may affect such lands, rights of way and other property now held or to be hereafter acquired by the Company under such leases, contracts or agreements, shall be subject and subordinate in all respects to the rights and remedies of the respective lessors or other parties thereto. And it is hereby expressly covenanted and agreed as follows: (a) That the rights of the Trustee hereunder, and of every person or corporation whatsoever claiming by reason of this First 1997 Supplemental Indenture any right, title or interest, legal or equitable, in the property covered by any such lease, power agreement or other contract, are and at all times hereafter shall be subject in the same manner and degree as the rights of the Company might or would at all times be subject, had this First 1997 Supplemental Indenture not been made, to all terms, provisions, conditions, covenants, stipulations, and agreements, and to all exceptions, reservations, limitations, restrictions, and forfeitures contained in any such lease, power agreement or other contract; (b) That any right, claim, condition or forfeiture which might at any time be asserted against the party in possession under the provisions of any such lease, power agreement or other contract, had this First 1997 Supplemental Indenture not been made, may be asserted with the same force and effect against any and all persons or corporations at any time claiming any right, title or interest in any such property under or by reason of this First 1997 Supplemental Indenture or of any bond hereby and by the Original Indenture secured; and (c) That such consent or waiver of the requirement of such consent given by the lessor under any such lease or party to any such power agreement or other contract is intended and shall be construed to be solely for the purpose of permitting the Company to mortgage its property generally without violating the express covenant contained in such lease, power agreement or other contract, and that such consent or waiver of the requirement of such consent confers upon the Trustee hereunder and the holders of bonds secured hereby and by the Original Indenture no rights in addition to such as they would have had, respectively, if such consent or waiver of the requirement of such consent had not been given. IN TRUST NEVERTHELESS, upon the terms and trusts in the Original Indenture and this First 1997 Supplemental Indenture set forth, for the equal and pro rata benefit and security of those who shall hold the bonds and coupons issued and to be issued hereunder and under the Original Indenture, in accordance with the terms of the Original Indenture and of this First 1997 Supplemental Indenture, without preference, priority or distinction as to lien of any of said bonds or coupons over any other thereof by reason of priority in the time of issuance or negotiation thereof, or otherwise howsoever, subject, however, to the conditions, provisions and covenants set forth in the Original Indenture and in this First 1997 Supplemental Indenture. AND THIS INDENTURE FURTHER WITNESSETH: That in further consideration of the premises and for the considerations aforesaid, the Company, for itself and its successors and assigns, hereby covenants and agrees to and with the Trustee, and its successor or successors in such trust, under the Original Indenture, as follows: Section 1. Section 40 of the Original Indenture is hereby amended by deleting the third full paragraph of Part I thereof. Section 2. Section 27 of the Original Indenture is hereby amended by deleting the fourth full paragraph thereof. Section 3. The Original Indenture is hereby supplemented by adding immediately after Section 20GGG a new Section 20HHH as follows: SECTION 20HHH. The Company hereby creates a sixty-first series of bonds to be issued under and secured by this Indenture, to be designated and to be distinguished from the bonds of all other series by the title "First Mortgage Bonds, Designated Secured Medium Term Notes, 6.35% Series due March 1, 2000" (herein sometimes referred to as the "bonds of the 61st Series"). The form of the bonds of the 61st Series shall be substantially as set forth in Schedule I to the First 1997 Supplemental Indenture. Bonds of the 61st Series shall mature on the date specified in their title. Unless otherwise determined by the Company, the bonds of the 61st Series shall be issued in fully registered form without coupons in denominations of $1,000 and in integral multiples thereof; the principal of and premium (if any) and interest on each said bond to be payable at the office or agency of the Company in the Borough of Manhattan, The City of New York, in lawful money of the United States of America, provided that at the option of the Company interest may be mailed to registered owners of the bonds at their respective addresses that appear on the register thereof; and the rate of interest shall be the rate per annum specified in the title thereof, payable semi-annually on the first days of April and October of each year (commencing April 1, 1997) and on their maturity date. The person in whose name any bond of the 61st Series is registered at the close of business on any record date (as hereinbelow defined) with respect to any regular semi-annual interest payment date shall be entitled to receive the interest payable on such interest payment date notwithstanding the cancellation of such bond of the 61st Series upon any registration of transfer or exchange thereof subsequent to the record date and prior to such interest payment date, except, if and to the extent that the Company shall default in the payment of the interest due on such interest payment date, then the registered owners of bonds of the 61st Series on such record date shall have no further right to or claim in respect of such defaulted interest as such registered owners on such record date, and the persons entitled to receive payment of any defaulted interest thereafter payable or paid on any bonds of the 61st Series shall be the registered owners of such bonds of the 61st Series (or any bond or bonds issued, directly or after intermediate transactions upon transfer or exchange or in substitution thereof) on the date of payment of such defaulted interest. Interest payable upon maturity shall be payable to the person to whom the principal is paid. The term "record date" as used in this Section 20HHH, and in the form of the bonds of the 61st Series, with respect to any regular semi-annual interest payment date applicable to the bonds of the 61st Series, shall mean the March 15 next preceding an April 1 interest payment date or the September 15 next preceding an October 1 interest payment date, as the case may be, or, if such March 15 or September 15 is not a Business Day (as defined hereinbelow), the next preceding Business Day. The term "Business Day" with respect to any bond of the 61st Series shall mean any day, other than a Saturday or Sunday, which is not a day on which banking institutions or trust companies in The City of New York, New York or the city in which is located any office or agency maintained for the payment of principal of or premium, if any, or interest on such bond of the 61st Series are authorized or required by law, regulation or executive order to remain closed. Every registered bond of the 61st Series shall be dated the date of authentication ("Issue Date") and shall bear interest computed on the basis of a 360-day year consisting of twelve 30-day months from its Issue Date or from the latest semi-annual interest payment date to which interest has been paid on the bonds of the 61st Series preceding the Issue Date, unless such Issue Date be an interest payment date to which interest is being paid on the bonds of the 61st Series, in which case it shall bear interest from its Issue Date or unless the Issue Date be the record date for the interest payment date first following the date of original issuance of bonds of the 61st Series (the "Original Issue Date"), or a date prior to such record date, then from the Original Issue Date; provided that, so long as there is no existing default in the payment of interest on said bonds, the owner of any bond authenticated by the Corporate Trustee between the record date for any regular semi-annual interest payment date and such interest payment date shall not be entitled to the payment of the interest due on such interest payment date and shall have no claim against the Company with respect thereto; provided further, that, if and to the extent the Company shall default in the payment of the interest due on such interest payment date, then any such bond shall bear interest from the April 1 or October 1, as the case may be, next preceding its Issue Date, to which interest has been paid or, if the Company shall be in default with respect to the interest payment date first following the Original Issue Date, then from the Original Issue Date. If any semi-annual interest payment date or the maturity date is not a Business Day, payment of amounts due on such date may be made on the next succeeding Business Day, and, if such payment is made or duly provided for on such Business Day, no interest shall accrue on such amounts for the period from and after such interest payment date or the maturity date, as the case may be, to such Business Day. Notwithstanding the provisions of Section 14 of this Indenture, the bonds of the 61st Series shall be executed on behalf of the Company by its Chairman of the Board, by its President or by one of its Vice Presidents or by one of its officers designated by the Board of Directors of the Company for such purpose, whose signature may be a facsimile, and its corporate seal shall be thereunto affixed or printed thereon and attested by its Secretary or one of its Assistant Secretaries, and the provisions of the penultimate sentence of said Section 14 shall be applicable to such bonds of the 61st Series. The bonds of the 61st Series are not redeemable prior to their maturity. Notwithstanding the provisions of Section 12 of this Indenture, the Company shall not be required to make transfers or exchanges of bonds of the 61st Series for a period of fifteen days next preceding any interest payment date. Registered bonds of the 61st Series shall be transferable upon presentation and surrender thereof, for cancellation, at the office or agency of the Company in the Borough of Manhattan, The City of New York, and at such other office or agency of the Company as the Company may from time to time designate, by the registered owners thereof, in person or by duly authorized attorney, in the manner and upon payment, if required by the Company, of the charges prescribed in this Indenture. In the manner and upon payment, if required by the Company, of the charges prescribed in this Indenture, registered bonds of the 61st Series may be exchanged for a like aggregate principal amount of registered bonds of the 61st Series of other authorized denominations, upon presentation and surrender thereof, for cancellation, at the office or agency of the Company in the Borough of Manhattan, The City of New York, or at such other office or agency of the Company as the Company may from time to time designate. Section 4. Initial Issuance of the Bonds of the 61st Series: In accordance with and upon compliance with such provisions of the Original Indenture as shall be selected for such purpose by the officers of the Company duly authorized to take such action, bonds of the 61st Series, in an aggregate principal amount not exceeding $48,000,000, shall forthwith be executed by the Company and delivered to the Trustee and shall be authenticated by the Trustee and delivered to or upon the order of the Company (without awaiting the filing and recording of this First 1997 Supplemental Indenture except to the extent required by subdivision (10) of Section 29 of the Original Indenture). Section 5. At any meeting of bondholders held as provided for in Article XX of the Original Indenture at which owners of bonds of the 61st Series are entitled to vote, all owners of bonds of the 61st Series at the time of such meeting shall be entitled to vote thereat; provided, however, that the Trustee may, and upon request of the Company or of a majority of the bondowners of the 61st Series, shall, fix a day not exceeding ninety days preceding the date for which the meeting is called as a record date for the determination of owners of bonds of the 61st Series, entitled to notice of and to vote at such meeting and any adjournment thereof and only such registered owners who shall have been such registered owners on the date so fixed, and who are entitled to vote such bonds of the 61st Series at the meeting, shall be entitled to receive notice of such meeting. Section 6. As supplemented by this First 1997 Supplemental Indenture, the Original Indenture is in all respects ratified and confirmed and the Original Indenture and this First 1997 Supplemental Indenture shall be read, taken and construed as one and the same instrument. The bonds of the 61st Series are the original debt secured by this First 1997 Supplemental Indenture and the Original Indenture, and this First 1997 Supplemental Indenture and the Original Indenture shall be, and shall be deemed to be, the original lien instrument securing the bonds of the 61st Series. Section 7. Nothing contained in this First 1997 Supplemental Indenture shall, or shall be construed to, confer upon any person other than the owners of bonds issued under the Original Indenture and this First 1997 Supplemental Indenture, the Company and the Trustee, any right to avail themselves of any benefit of any provision of the Original Indenture or of this First 1997 Supplemental Indenture. Section 8. This First 1997 Supplemental Indenture may be simultaneously executed in several counterparts and all such counterparts executed and delivered, each as an original, shall constitute one and the same instrument. IN WITNESS WHEREOF, APPALACHIAN POWER COMPANY, party of the first part, has caused this instrument to be signed in its name and behalf by its President, a Vice President, its Treasurer or an Assistant Treasurer, and its corporate seal to be hereunto affixed and attested by its Secretary or an Assistant Secretary, and BANKERS TRUST COMPANY, party of the second part, in token of its acceptance hereof, has caused this instrument to be signed in its name and behalf by a Vice President or an Assistant Vice President and its corporate seal to be hereunto affixed and attested by its Secretary, an Assistant Secretary, Assistant Vice President or Assistant Treasurer. Executed and delivered as of the date and year first above written. APPALACHIAN POWER COMPANY [SEAL] By: /s/ A. A. Pena A. A. Pena Treasurer Attest: /s/ John M. Adams, Jr. John M. Adams, Jr. Assistant Secretary In the presence of: /s/ T. G. Berkemeyer T. G. Berkemeyer /s/ S. T. Haynes S. T. Haynes BANKERS TRUST COMPANY [SEAL] By /s/ James McDonough James McDonough Vice President Attest: /s/ Scott Thiel Scott Thiel Assistant Vice President Executed by BANKERS TRUST COMPANY in the presence of: /s/ Jason Theriault Jason Theriault /s/ Barbara Nastro Barbara Nastro STATE OF OHIO ) ) SS: COUNTY OF FRANKLIN ) On this 7th day of February, 1997, personally appeared before me, a Notary Public within and for said County in the State aforesaid, A. A. PENA and JOHN M. ADAMS, JR., to me known and known to me to be respectively the Treasurer and Assistant Secretary of APPALACHIAN POWER COMPANY, one of the corporations named in and which executed the foregoing instrument, who severally acknowledged that they did sign and seal said instrument as such Treasurer and Assistant Secretary for and on behalf of said corporation and that the same is their free act and deed as such Treasurer and Assistant Secretary, respectively, and the free and corporate act and deed of said corporation. In Witness Whereof, I have hereunto set my hand and notarial seal this 7th day of February, 1997. [Notarial Seal] /s/ Mary M. Soltesz MARY M. SOLTESZ Notary Public, State of Ohio My Commission Expires July 12, 1999 STATE OF NEW YORK ) ) SS: COUNTY OF NEW YORK ) I, PATRICIA M. CARILLO, a Notary Public, duly qualified, commissioned and sworn, and acting in and for the County and State aforesaid, hereby certify that on this 10th day of February, 1997: JAMES MC DONOUGH and SCOTT THIEL, whose names are signed to the writing above, bearing a date as of the 1st day of February, 1997, as Vice President and Assistant Vice President, respectively, of BANKERS TRUST COMPANY, have this day acknowledged the same before me in my County aforesaid. JAMES MC DONOUGH, who signed the writing above and hereto annexed for BANKERS TRUST COMPANY, a corporation, bearing a date as of the 1st day of February, 1997, has this day in my said County before me acknowledged the said writing to be the act and deed of said corporation. Before me appeared JAMES MC DONOUGH and SCOTT THIEL to me personally known, who, being by me duly sworn, did say that they are Vice President and Assistant Vice President, respectively, of BANKERS TRUST COMPANY, and that the seal affixed to said instrument is the corporate seal of said corporation, and that said instrument was signed and sealed in behalf of said corporation, by authority of its Board of Directors and said JAMES MC DONOUGH acknowledged said instrument to be the free act and deed of said corporation. SCOTT THIEL personally came before me this day and acknowledged that he is an Assistant Vice President of BANKERS TRUST COMPANY, a corporation, and that by authority duly given and as the act of the corporation, the foregoing instrument was signed in its name by an Assistant Vice President, sealed with its corporate seal, and attested by himself as an Assistant Vice President. IN WITNESS WHEREOF, I have hereunto set my hand and official notarial seal, in the County and State of New York, this 10th day of February, 1997. /s/ Patricia M. Carillo PATRICIA M. CARILLO [SEAL] Notary Public, State of New York No. 41-4747732 Qualified in Queens County Certificate filed in New York County Commission expires May 31, 1997 The foregoing instrument was prepared by Thomas G. Berkemeyer, 1 Riverside Plaza, Columbus, Ohio 43215. SCHEDULE I APPALACHIAN POWER COMPANY FIRST MORTGAGE BOND, DESIGNATED SECURED MEDIUM TERM NOTE, 6.35% SERIES DUE MARCH 1, 2000 Bond No. Original Issue Date: February 19, 1997 Principal Amount: Semi-annual Interest Payment Dates: April 1 and October 1 Record Dates: March 15 and September 15 CUSIP No: 03774B AX1 APPALACHIAN POWER COMPANY, a corporation of the Commonwealth of Virginia (hereinafter called the "Company"), for value received, hereby promises to pay to ____________, or registered assigns, the Principal Amount set forth above on the maturity date specified in the title of this bond in lawful money of the United States of America, at the office or agency of the Company in the Borough of Manhattan, The City of New York, and to pay to the registered owner hereof interest on said sum from the date of authentication of this bond (herein called the "Issue Date") or latest semi-annual interest payment date to which interest has been paid on the bonds of this series preceding the Issue Date, unless the Issue Date be an interest payment date to which interest is being paid, in which case from the Issue Date or unless the Issue Date be the record date for the interest payment date first following the Original Issue Date set forth above or a date prior to such record date, then from the Original Issue Date (or, if the Issue Date is between the record date for any interest payment date and such interest payment date, then from such interest payment date, provided, however, that if and to the extent that the Company shall default in the payment of the interest due on such interest payment date, then from the next preceding semi-annual interest payment date to which interest has been paid on the bonds of this series, or if such interest payment date is the interest payment date first following the Original Issue Date set forth above, then from the Original Issue Date), until the principal hereof shall have become due and payable, at the rate per annum specified in the title of this bond, payable on April 1 and October 1 of each year (commencing April 1, 1997) and on the maturity date specified in the title of this bond; provided that, at the option of the Company, such interest may be paid by check, mailed to the registered owner of this bond at such owner's address appearing on the register hereof. This bond is one of a duly authorized issue of bonds of the Company, issuable in series, and is one of a series known as its First Mortgage Bonds, of the series designated in its title, all bonds of all series issued and to be issued under and equally secured (except in so far as any sinking fund, established in accordance with the provisions of the Mortgage hereinafter mentioned, may afford additional security for the bonds of any particular series and except as provided in Section 73 of the Mortgage) by a Mortgage and Deed of Trust (herein, together with all indentures supplemental thereto, called the Mortgage), dated as of December 1, 1940, executed by APPALACHIAN ELECTRIC POWER COMPANY (the corporate title of which was changed to APPALACHIAN POWER COMPANY) to BANKERS TRUST COMPANY, as Trustee, to which Mortgage reference is made for a description of the property mortgaged and pledged, the nature and extent of the security, the rights of the holders of the bonds and of the Trustee in respect thereof, the duties and immunities of the Trustee, and the terms and conditions upon which the bonds are secured. With the consent of the Company and to the extent permitted by and as provided in the Mortgage, the rights and obligations of the Company and/or of the holders of the bonds and/or coupons and/or the terms and provisions of the Mortgage and/or of any instruments supplemental thereto may be modified or altered by affirmative vote of the holders of at least seventy-five per centum (75%) in principal amount of the bonds affected by such modification or alteration, then outstanding under the Mortgage (excluding bonds disqualified from voting by reason of the Company's interest therein as provided in the Mortgage); provided that, without the consent of the owner hereof no such modification or alteration shall permit the extension of the maturity of the principal of or interest on this bond or the reduction in the rate of interest hereon or any other modification in the terms of payment of such principal or interest or the creation of a lien on the mortgaged and pledged property ranking prior to or on a parity with the lien of the Mortgage or the deprivation of the owner hereof of a lien upon such property or reduce the above percentage. As provided in said Mortgage, said bonds may be for various principal sums and are issuable in series, which may mature at different times, may bear interest at different rates and may otherwise vary as therein provided, and this bond is one of a series entitled "First Mortgage Bonds, Designated Secured Medium Term Notes, 6.35% Series due March 1, 2000" (herein called "bonds of the 61st Series") created by an Indenture Supplemental to Mortgage and Deed of Trust dated as of February 1, 1997 (the "First 1997 Supplemental Indenture"), as provided for in said Mortgage. The interest payable on any April 1 or October 1 will, subject to certain exceptions provided in said First 1997 Supplemental Indenture, be paid to the person in whose name this bond is registered at the close of business on the record date, which shall be the March 15 or September 15, as the case may be, next preceding such interest payment date, or, if such March 15 or September 15 is not a Business Day (as hereinbelow defined), the next preceding Business Day. Interest payable upon maturity shall be payable to the person to whom the principal is paid. The term "Business Day" means any day, other than a Saturday or Sunday, which is not a day on which banking institutions or trust companies in The City of New York, New York or the city in which is located any office or agency maintained for the payment of principal or premium, if any, or interest on bonds of the 61st Series are authorized or required by law, regulation or executive order to remain closed. If any semi-annual interest payment date or the maturity date is not a Business Day, payment of amounts due on such date may be made on the next succeeding Business Day, and, if such payment is made or duly provided for on such Business Day, no interest shall accrue on such amounts for the period from and after such interest payment date or the maturity date, as the case may be, to such Business Day. The Company and the Trustee may deem and treat the person in whose name this bond is registered as the absolute owner hereof for the purpose of receiving payment of or on account of principal or (subject to the provisions hereof) interest hereon and for all other purposes and the Company and the Trustee shall not be affected by any notice to the contrary. The Company shall not be required to make transfers or exchanges of bonds of the 61st Series for a period of fifteen days next preceding any interest payment date. The Bonds of the 61st Series are not redeemable prior to their maturity. The principal hereof may be declared or may become due prior to the express date of the maturity hereof on the conditions, in the manner and at the time set forth in the Mortgage, upon the occurrence of a completed default as in the Mortgage provided. This bond is transferable as prescribed in the Mortgage by the registered owner hereof in person, or by his duly authorized attorney, at the office or agency of the Company in the Borough of Manhattan, The City of New York, and at such other office or agency of the Company as the Company may designate, upon surrender and cancellation of this bond and upon payment, if the Company shall require it, of the transfer charges prescribed in the Mortgage, and, thereupon, a new registered bond or bonds of authorized denominations of the same series for a like principal amount will be issued to the transferee in exchange herefor as provided in the Mortgage. In the manner and upon payment, if the Company shall require it, of the charges prescribed in the Mortgage, registered bonds of the 61st Series may be exchanged for a like aggregate principal amount of registered bonds of other authorized denominations of the same series, upon presentation and surrender thereof, for cancellation, at the office or agency of the Company in the Borough of Manhattan, The City of New York, or at such other office or agency of the Company as the Company may from time to time designate. No recourse shall be had for the payment of the principal of or interest on this bond against any incorporator or any past, present or future stockholder, officer or director, as such, of the Company or of any successor corporation, either directly or through the Company or any successor corporation, under any rule of law, statute or constitution or by the enforcement of any assessment or otherwise, all such liability of incorporators, stockholders, officers and directors, as such, being waived and released by the holder or owner hereof by the acceptance of this bond and being likewise waived and released by the terms of the Mortgage. This bond shall not become valid or obligatory for any purpose until BANKERS TRUST COMPANY, the Trustee under the Mortgage, or its successor thereunder, shall have signed the form of Authentication Certificate endorsed hereon. In Witness Whereof, Appalachian Power Company has caused this bond to be executed in its name by the signature of its Chairman of the Board, its President, one of its Vice Presidents or its Treasurer and its corporate seal, or a facsimile thereof, to be impressed or imprinted hereon and attested by the signature of its Secretary or one of its Assistant Secretaries. Dated: APPALACHIAN POWER COMPANY By________________________ Treasurer (SEAL) Attest:___________________ Assistant Secretary TRUSTEE'S AUTHENTICATION CERTIFICATE This bond is one of the bonds, of the series herein designated, described in the within-mentioned Mortgage. BANKERS TRUST COMPANY, as Trustee, By______________________________ Authorized Officer FOR VALUE RECEIVED, the undersigned hereby sell(s), assign(s) and transfer(s) unto (PLEASE INSERT SOCIAL SECURITY OR OTHER IDENTIFYING NUMBER OF ASSIGNEE) _______________________________________ ________________________________________________________________ ________________________________________________________________ (PLEASE PRINT OR TYPE NAME AND ADDRESS, INCLUDING ZIP CODE, OF ________________________________________________________________ ASSIGNEE) the within Bond and all rights thereunder, hereby ________________________________________________________________ irrevocably constituting and appointing such person attorney to ________________________________________________________________ transfer such Bond on the books of the Issuer, with full power of ________________________________________________________________ substitution in the premises. Dated: ______________________ ____________________________ NOTICE: The signature to this assignment must correspond with the name as written upon the face of the within Bond in every particular without alteration or enlargement or any change whatsoever. EX-12 5 APCO COMPUTATION OF RATIOS 10K405 EX12 EXHIBIT 12 APPALACHIAN POWER COMPANY Computation of Consolidated Ratio of Earnings to Fixed Charges (in thousands except ratio data)
Year Ended December 31, 1992 1993 1994 1995 1996 Fixed Charges: Interest on First Mortgage Bonds. . . . . . . . . . . $ 84,177 $ 80,472 $ 75,815 $ 80,777 $ 82,082 Interest on Other Long-term Debt. . . . . . . . . . . 17,986 16,846 16,415 16,404 18,025 Interest on Short-term Debt . . . . . . . . . . . . . 1,792 1,615 3,366 5,119 3,639 Miscellaneous Interest Charges. . . . . . . . . . . . 2,617 2,954 3,913 5,323 7,327 Estimated Interest Element in Lease Rentals . . . . . 6,700 7,900 7,700 7,000 6,600 Total Fixed Charges. . . . . . . . . . . . . . . $113,272 $109,787 $107,209 $114,623 $117,673 Earnings: Net Income. . . . . . . . . . . . . . . . . . . . . . $131,419 $125,132 $102,345 $115,900 $133,689 Plus Federal Income Taxes . . . . . . . . . . . . . . 46,017 51,681 39,599 53,355 65,801 Plus State Income Taxes . . . . . . . . . . . . . . . 2,649 8,887 5,910 7,273 10,180 Plus Fixed Charges (as above) . . . . . . . . . . . . 113,272 109,787 107,209 114,623 117,673 Total Earnings . . . . . . . . . . . . . . . . . $293,357 $295,487 $255,063 $291,151 $327,343 Ratio of Earnings to Fixed Charges. . . . . . . . . . . 2.58 2.69 2.37 2.54 2.78
EX-13 6 APCO 1996 ANNUAL REPORT 10K405 EX13 Selected Consolidated Financial Data
Year Ended December 31, 1996 1995 1994 1993 1992 (in thousands) INCOME STATEMENTS DATA: Operating Revenues $1,624,869 $1,545,039 $1,535,500 $1,519,104 $1,410,778 Operating Expenses 1,381,993 1,317,937 1,330,282 1,289,764 1,176,882 Operating Income 242,876 227,102 205,218 229,340 233,896 Nonoperating Income (Loss) 128 (4,699) (4,716) (3,353) 3,036 Income Before Interest Charges 243,004 222,403 200,502 225,987 236,932 Interest Charges 109,315 106,503 98,157 100,855 105,513 Net Income 133,689 115,900 102,345 125,132 131,419 Preferred Stock Dividend Requirements 15,938 16,405 15,660 16,540 16,596 Earnings Applicable to Common Stock $ 117,751 $ 99,495 $ 86,685 $ 108,592 $ 114,823 December 31, 1996 1995 1994 1993 1992 (in thousands) BALANCE SHEETS DATA: Electric Utility Plant $4,717,132 $4,558,436 $4,398,727 $4,193,700 $4,038,735 Accumulated Depreciation and Amortization 1,782,017 1,694,746 1,627,852 1,550,855 1,477,078 Net Electric Utility Plant $2,935,115 $2,863,690 $2,770,875 $2,642,845 $2,561,657 Total Assets $3,811,380 $3,735,378 $3,647,795 $3,491,674 $3,094,091 Common Stock and Paid-in Capital $ 835,838 $ 785,509 $ 764,866 $ 755,292 $ 741,509 Retained Earnings 208,472 199,021 206,361 227,816 229,920 Total Common Shareholder's Equity $1,044,310 $ 984,530 $ 971,227 $ 983,108 $ 971,429 Cumulative Preferred Stock: Not Subject to Mandatory Redemption $ 29,815 $ 55,000 $ 55,000 $ 55,000 $ 105,000 Subject to Mandatory Redemption (a) 190,000 190,235 190,385 160,537 108,509 Total Cumulative Preferred Stock $ 219,815 $ 245,235 $ 245,385 $ 215,537 $ 213,509 Long-term Debt (a) $1,365,842 $1,285,684 $1,228,911 $1,215,168 $1,200,272 Obligations Under Capital Leases (a) $ 51,969 $ 48,937 $ 43,138 $ 29,973 $ 24,269 Total Capitalization and Liabilities $3,811,380 $3,735,378 $3,647,795 $3,491,674 $3,094,091 (a) Including portion due within one year.
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 the American Electric Power (AEP) System, Appalachian Power Company and our changing industry. The industry's adjustment to greater competition in the generation and sale of electricity, customer choice and the ability to fully recover costs will probably be the most significant factors affecting the Company's future profitability. Although the Company, as a member of the AEP System, has the financial strength, geographic reach, location and cost structure to be an able competitor, no assurance can be given that this position can be maintained. 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 of a strong financial position. 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 the AEP transmission grid at 143 interconnections to all parties under the same terms and conditions available to AEP affiliates. This has provided greater opportunities for transmission service sales. 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 changes, if any. We are actively involved in discussions on the state and federal level regarding whether to and how best to transition to competition in order to represent the best interests of our customers, shareholders and employees. We favor an orderly and smooth transition to a more competitive energy market because we believe that AEP will do better in the long term if it is free to compete. If 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 recovery 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, 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 the Company 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," regulatory assets (deferred expenses) and regulatory 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 and assets tested for possible impairment. Whether an impairment exists would depend on how low the market price of energy is in competition relative to the cost of energy. Among other requirements the application of SFAS 71 requires that the rates charged to customers be cost based. Our generation business is still cost-based regulated and should remain so for the foreseeable future. Should enabling state legislation be enacted we believe there should be at least a three to five year transition 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 our firm wholesale sales are still under cost-of-service contracts. We believe that enabling state legislation if enacted should provide for a sufficient transition period to allow for the recovery of any generation-related stranded costs and we are dedicating ourselves to working with regulators, customers and legislators to accomplish both an orderly transition and a reasonable and fair disposition of the stranded cost issue. However, if the Company were to no longer be cost-based regulated and recovery of stranded costs were not possible, results of operations and financial condition 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, are aggressively pursuing deregulation. However, the states the Company operates in are addressing the call for customer choice more cautiously. Restructuring/Functional Unbundling In 1996 we took some major steps to maintain and enhance the Company's competitive strength. We restructured our management and operations to allow us to comply with the new FERC orders which required separation of generation and energy sales operations from our energy transmission and delivery operations. This has achieved and should continue to achieve staffing, managerial and operating efficiencies. The generation and marketing business units are preparing for the possibility of competition in an open market for customers. Our energy delivery business expects to remain regulated and ultimately be subject to some form of incentive or performance-based ratemaking. If competition never replaces regulation we will be a more efficient and productive business as a result of our preparations which should benefit all concerned. Marketing and customer service efforts have been enhanced with programs like the Key Accounts Program which strives to build strong partnerships with key customers in order to build customer loyalty. In 1996 we also launched a series of new television commercials to inform our customers that we will be operating under the name, American Electric Power. The commercials are intended to position AEP as more than just a supplier of electricity. We want to be the energy and energy services provider of choice; AEP: America's Energy Partner. 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, 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. 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 programs, 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 the Company to maintain its position as a low-cost producer. Coal is 50% of the production cost of electricity. Although our average coal costs per unit of electricity (per Kwh) have declined by 45% since 1986, we recognize that we must continue to manage our coal costs to maintain our competitive position. As long-term coal supply contracts expire we are negotiating with non-affiliated suppliers to lower purchased coal costs. We intend to continue to prudently supplement our long-term coal supplies with spot market purchases as long as favorable spot market prices exist. Environmental Matters We take great pride in our efforts to economically produce and deliver electricity while minimizing the impact on the environment. The Company has spent hundreds of millions of dollars to equip its facilities with the latest economical clean air and water technologies and to research possible new technologies. 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 and sludge. 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, the generating plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls (PCBs) and other hazardous and non-hazardous materials. The Company is 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 authorizes the United States Environmental Protection Agency (Federal EPA) to administer the clean-up programs. As of year-end 1996, there are two sites for which the Company has received information requests which could lead to "Potentially Responsible Party" (PRP) designation. The Company's present estimates do not anticipate material cleanup costs for identified sites for which the Company is involved. 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. 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 the Company's power plants. In December 1996 a group of utilities including the Company 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 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 further requirements for reductions of nitrogen oxides and sulfur dioxide emitted from coal fired power plants and could have a significant impact on operations. The proposals being considered are of particular concern because they do not 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 Net income increased by $17.8 million or 15% in 1996 mainly due to increased sales of energy and services. Sales increased predominately due to greater demand for energy by wholesale customers and increased transmission and other services provided to power marketers and utilities. Also contributing to the improvement in net income were the effect of severance pay charges recorded in 1995 in connection with a management and operations realignment and gains recorded in 1996 from emission allowance transactions. In 1995 net income increased by $13.6 million or 13% due to a reduction in AEP System Power Pool (Power Pool) capacity charges. The reduction in Power Pool capacity charges resulted from a decrease in the Company's prior twelve-month peak demand relative to the total peak demand of all Power Pool members. Power Pool members like the Company whose internal demand exceeds their capacity are allocated capacity costs by the Power Pool based on the relative peak demands and generating reserves of all Power Pool members. Operating Revenues and Energy Sales Increase Operating revenues increased 5% in 1996 and 1% in 1995. Increased wholesale energy sales, transmission and coal conversion service revenues were the primary reasons for the increase in 1996 revenues. Increased energy usage by retail customers and growth in the number of retail customers increased revenues in 1995. The following is a price/volume analysis of revenues: Increase (Decrease) From Previous Year (dollars in millions) 1996 1995 Amount % Amount % Retail: Price variance $ 1.4 $ 20.2 Volume variance 14.4 39.3 Fuel and Purchased Power Recoveries (13.6) (23.5) 2.2 0.2 36.0 3.0 Wholesale: Price variance (145.8) (17.4) Volume variance 211.8 (1.8) Fuel Cost Recoveries (2.7) (2.7) 63.3 23.5 (21.9) (7.5) Other Operating Revenues 14.3 (4.6) Total $ 79.8 5.2 $ 9.5 0.6 Wholesale revenues increased 23% in 1996 reflecting a 77% increase in wholesale sales. The Company's share of Power Pool sales increased 38% as a result of increased transactions with power marketers and other utilities. The Company through the Power Pool shared in sales of a new product, coal conversion services which resulted in 2.2 billion kilowatthours of electricity being provided to power marketers and certain other utilities under a new Federal Energy Regulatory Commission approved interruptible tariff. Since these new sales are for the service of converting the customers' coal to electricity and do not include recovery of a fuel cost, the average wholesale price per kilowatthour was significantly less in 1996 than in 1995. Energy sales to the Power Pool increased mainly due to increased demand for electric energy by customers of the other affiliated Power Pool members. An increased level of activity in the wholesale energy markets encouraged by the 1996 issuance of FERC open access transmission rules and the Company's 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 as other operating revenues, increased by approximately $12 million. The modest increase in 1995 operating revenues resulted from a 5% increase in sales to retail customers and the effect of a rate increase in the Virginia jurisdiction partly offset by a reduction in revenues from wholesale customers. Energy sales to residential customers, which is the most weather- sensitive customer class, rose over 6% in 1995 mainly as a result of increased weather related usage in the last half of the year reflecting unseasonably warm summer weather in 1995 and colder weather in the fourth quarter of 1995 compared with the weather in the prior year. Sales to commercial and industrial customers rose 6% and 2%, respectively, in 1995, reflecting the addition of 2,531 new customers, the effects of weather and economic growth in the Company's service area. Revenues from wholesale customers declined 7.5% in 1995 reflecting the effect of increased competition on the price of wholesale energy while sales were relatively flat. Operating Expenses Operating expense increased by approximately 5% in 1996 reflecting increases in all expense categories except for maintenance expense while the decrease of 1% in 1995 was largely due to a decline in fuel and purchased power expenses. Changes in the components of operating expenses were as follows: Increase (Decrease) From Previous Year (dollars in millions) 1996 1995 Amount % Amount % Fuel $ 18.9 5.4 $(42.1) (10.8) Purchased Power 32.9 11.0 (15.7) (5.0) Other Operation 18.5 8.3 25.7 13.1 Maintenance (22.1) (15.8) 5.5 4.1 Depreciation and Amortization 0.1 - 4.8 3.7 Taxes Other Than Federal Income Taxes 3.2 2.7 (2.4) (2.0) Federal Income Taxes 12.6 21.8 11.9 25.9 Total $ 64.1 4.9 $(12.3) (0.9) The 5% increase in fuel expense in 1996 was mainly due to increased generation to meet the increased demand of wholesale customers and increased availability of generating capacity. The substantial decrease in 1995 fuel expense was due to a decrease in coal-fired generation. The decrease in generation generally resulted from the increased availability of an affiliate's low cost nuclear powered units. When the availability of the affiliate's lower cost nuclear units is increased, the Company decreases its generation for delivery to the Power Pool. Also contributing to the decrease in 1995 fuel expense was a lower average cost of fuel. Coal prices declined in 1995 primarily due to the renegotiation of certain long-term coal contracts. Increased purchases of energy from the Power Pool in 1996 to meet the increased demand for energy and an increase in Power Pool capacity charges accounted for the rise in purchased power expense. An increase in the Company's prior twelve-month peak demand relative to the total peak demand of all Power Pool members caused the increase in Power Pool capacity charges. Purchased power expense declined in 1995 due to a reduction in Power Pool capacity charges and reduced purchases from unaffiliated utilities for pass-through sales to other unaffiliated utilities. Capacity charges declined due to a decrease in the Company's prior twelve-month peak demand relative to the total peak demand of all Power Pool members. The increase in other operation expense in 1996 was due to an increase in expenditures for customer service and management information software systems; recognition of deferred software development costs as a result of a final rate order from the Virginia State Corporation Commission (Virginia SCC); an increase in employee benefit costs; and higher costs relating to new coal conversion and transmission services to power marketers and other utilities. These items more than offset the recognition of gains on the sale of emission allowances and the effect of a provision for severance pay recorded in 1995 related mainly to the functional realignment of AEP's operations. The increase in other operation expense in 1995 was due to the provisions for severance pay; costs associated with the development of a new activity based budgeting system; increased employee benefit costs; and the effect of a $4.6 million favorable adjustment in 1994 which capitalized previously expensed software costs in accordance with an order of the Virginia SCC. Maintenance expense declined in 1996 after increasing in 1995. These fluctuations are primarily the result of accounting for incremental storm damage expense in accordance with directions of the Virginia SCC. Federal income taxes attributable to operations increased in 1996 and 1995 primarily due to an increase in pre-tax operating income. Nonoperating Income Nonoperating income increased in 1996 due to the effect of a loss recorded in 1995 that resulted from the sale of coal-mining assets owned by the Company. Interest Charges Interest charges increased in 1995 primarily as a result of an increase in the balance of long-term debt outstanding. Construction Spending Total plant and property additions were $207 million in 1996 and $232 million in 1995. Management estimates construction expenditures for the next three years to be $596 million. Funds for construction of new facilities and improvement of existing facilities come from a combination of internally generated funds, short-term and long-term borrowings and equity investments by the Company's parent, American Electric Power Company, Inc. (AEP Co., Inc.). Approximately 86% of the construction expenditures for the next three years are expected to be financed with internally generated funds. Capital Resources When necessary the Company generally issues short-term debt to provide for interim financing of capital expenditures that exceed internally generated funds. At December 31, 1996, $409 million of unused short-term lines of credit shared with other AEP System companies were available. Short-term debt borrowings are limited by provisions of the Public Utility Holding Company Act of 1935 to $250 million. Periodic reductions of outstanding short-term debt are made through issuances of long-term debt and preferred stock and additional capital contributions by the parent company. The Company's earnings coverage presently exceeds minimum coverage requirements for the issuance of mortgage bonds and preferred stock. The minimum coverage ratios are 2.0 for mortgage bonds and 1.5 for preferred stock. At December 31, 1996, the mortgage bonds and preferred stock coverage ratios were 3.98 and 1.99, respectively. In January 1997 a tender offer was announced for all of the Company's preferred stock in conjunction with a special meeting scheduled to be held on February 28, 1997. The special meeting's purpose is to consider amendments to the Company's articles of incorporation to remove certain capitalization ratio requirements. These restrictions limit the Company's financial flexibility and could place it at a competitive disadvantage in the future. The amount paid to redeem the preferred stock that is tendered could total as much as $219 million. A combination of short-term debt and unsecured long-term debt is expected to be used to pay for the preferred stock tendered. Litigation The Company is involved in a number of legal proceedings and claims. While management is 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. Effects of Inflation Inflation affects the Company s cost of replacing utility plant and the cost of operating and maintaining plant. The rate-making process limits 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 result from the repayment of long-term debt with inflated dollars partly offset the negative impact of inflation. Corporate Owned Life Insurance In connection with the audit of the AEP System s 1991, 1992 and 1993 consolidated federal income tax returns the Internal Revenue Service (IRS) 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 approximately $62 million (including interest). Management 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 Rule 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 Company generally records such liabilities over the life of its plant commensurate with rate recovery. The exposure draft proposes that the present value of certain 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, the Company 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 the Company cannot determine its ultimate impact. Consolidated Statements of Income
Year Ended December 31, 1996 1995 1994 (in thousands) OPERATING REVENUES $1,624,869 $1,545,039 $1,535,500 OPERATING EXPENSES: Fuel 367,651 348,776 390,864 Purchased Power 333,014 300,086 315,818 Other Operation 240,249 221,783 196,097 Maintenance 117,483 139,566 134,092 Depreciation and Amortization 133,074 132,999 128,192 Taxes Other Than Federal Income Taxes 120,307 117,093 119,458 Federal Income Taxes 70,215 57,634 45,761 Total Operating Expenses 1,381,993 1,317,937 1,330,282 OPERATING INCOME 242,876 227,102 205,218 NONOPERATING INCOME (LOSS) 128 (4,699) (4,716) INCOME BEFORE INTEREST CHARGES 243,004 222,403 200,502 INTEREST CHARGES 109,315 106,503 98,157 NET INCOME 133,689 115,900 102,345 PREFERRED STOCK DIVIDEND REQUIREMENTS 15,938 16,405 15,660 EARNINGS APPLICABLE TO COMMON STOCK $ 117,751 $ 99,495 $ 86,685 See Notes to Consolidated Financial Statements.
Consolidated Balance Sheets
December 31, 1996 1995 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production $1,883,271 $1,857,621 Transmission 1,054,207 1,041,415 Distribution 1,495,445 1,409,407 General 188,740 169,602 Construction Work in Progress 95,469 80,391 Total Electric Utility Plant 4,717,132 4,558,436 Accumulated Depreciation and Amortization 1,782,017 1,694,746 NET ELECTRIC UTILITY PLANT 2,935,115 2,863,690 OTHER PROPERTY AND INVESTMENTS 29,621 31,523 CURRENT ASSETS: Cash and Cash Equivalents 7,260 8,664 Accounts Receivable: Customers 122,969 126,613 Affiliated Companies 15,017 7,721 Miscellaneous 22,035 8,077 Allowance for Uncollectible Accounts (687) (2,253) Fuel - at average cost 52,605 69,037 Materials and Supplies - at average cost 56,605 55,756 Accrued Utility Revenues 51,843 65,078 Prepayments 10,797 8,579 TOTAL CURRENT ASSETS 338,444 347,272 REGULATORY ASSETS 451,272 435,352 DEFERRED CHARGES 56,928 57,541 TOTAL $3,811,380 $3,735,378 See Notes to Consolidated Financial Statements.
December 31, 1996 1995 (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock - No Par Value: Authorized - 30,000,000 Shares Outstanding - 13,499,500 Shares $ 260,458 $ 260,458 Paid-in Capital 575,380 525,051 Retained Earnings 208,472 199,021 Total Common Shareholder's Equity 1,044,310 984,530 Cumulative Preferred Stock: Not Subject to Mandatory Redemption 29,815 55,000 Subject to Mandatory Redemption 190,000 190,085 Long-term Debt 1,365,834 1,278,433 TOTAL CAPITALIZATION 2,629,959 2,508,048 OTHER NONCURRENT LIABILITIES 109,203 102,178 CURRENT LIABILITIES: Long-term Debt Due Within One Year 8 7,251 Short-term Debt 60,700 125,525 Accounts Payable - General 34,714 36,424 Accounts Payable - Affiliated Companies 51,178 45,800 Taxes Accrued 40,935 48,666 Customer Deposits 13,750 14,411 Interest Accrued 20,938 19,057 Other 80,352 75,303 TOTAL CURRENT LIABILITIES 302,575 372,437 DEFERRED INCOME TAXES 669,964 656,006 DEFERRED INVESTMENT TAX CREDITS 83,320 89,682 DEFERRED CREDITS 16,359 7,027 COMMITMENTS AND CONTINGENCIES (Note 4) TOTAL $3,811,380 $3,735,378
Consolidated Statements of Cash Flows
Year Ended December 31, 1996 1995 1994 (in thousands) OPERATING ACTIVITIES: Net Income $ 133,689 $ 115,900 $ 102,345 Adjustments for Noncash Items: Depreciation and Amortization 134,381 134,485 130,694 Deferred Federal Income Taxes 592 647 17,355 Deferred Investment Tax Credits (5,602) (5,465) (5,492) Deferred Power Supply Costs (net) 293 (3,721) 9,356 Provision for Rate Refunds (2,626) 15,224 (8,780) Changes in Certain Current Assets and Liabilities: Accounts Receivable (net) (19,176) (16,896) 7,600 Fuel, Materials and Supplies 15,583 (9,761) (24,800) Accrued Utility Revenues 13,235 (13,392) 6,608 Accounts Payable 3,668 (11,488) 25,554 Taxes Accrued (7,731) 14,043 (17,505) Other (net) 9,437 28,324 (24,933) Net Cash Flows From Operating Activities 275,743 247,900 218,002 INVESTING ACTIVITIES: Construction Expenditures (191,815) (216,200) (230,531) Proceeds from Sales of Property 1,933 7,793 948 Net Cash Flows Used For Investing Activities (189,882) (208,407) (229,583) FINANCING ACTIVITIES: Capital Contributions from Parent Company 50,000 30,000 10,000 Issuance of Cumulative Preferred Stock - - 29,574 Issuance of Long-term Debt 273,340 128,785 70,443 Retirement of Cumulative Preferred Stock (25,904) (150) (152) Retirement of Long-term Debt (195,910) (74,950) (58,236) Change in Short-term Debt (net) (64,825) 2,700 83,325 Dividends Paid on Common Stock (108,300) (106,836) (108,140) Dividends Paid on Cumulative Preferred Stock (15,666) (15,675) (14,562) Net Cash Flows From (Used For) Financing Activities (87,265) (36,126) 12,252 Net Increase (Decrease) in Cash and Cash Equivalents (1,404) 3,367 671 Cash and Cash Equivalents January 1 8,664 5,297 4,626 Cash and Cash Equivalents December 31 $ 7,260 $ 8,664 $ 5,297 See Notes to Consolidated Financial Statements.
Consolidated Statements of Retained Earnings
Year Ended December 31, 1996 1995 1994 (in thousands) Retained Earnings January 1 $199,021 $206,361 $227,816 Net Income 133,689 115,900 102,345 332,710 322,261 330,161 Deductions: Cash Dividends Declared: Common Stock 108,300 106,836 108,140 Cumulative Preferred Stock: 4-1/2% Series 1,348 1,350 1,350 4.50% Series 9 16 22 5.90% Series 2,950 2,950 2,950 5.92% Series 3,552 3,552 3,552 6.85% Series 2,055 2,055 1,296 7.40% Series 1,385 1,850 1,850 7.80% Series 3,900 3,900 3,900 Total Cash Dividends Declared 123,499 122,509 123,060 Capital Stock Expense 739 731 740 Total Deductions 124,238 123,240 123,800 Retained Earnings December 31 $208,472 $199,021 $206,361 See Notes to Consolidated Financial Statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. SIGNIFICANT ACCOUNTING POLICIES: Organization Appalachian Power Company (the Company or APCo) is a wholly-owned subsidiary of American Electric Power Company, Inc. (AEP Co., Inc.), a public utility holding company. The Company is engaged in the generation, purchase, transmission and distribution of electric power to 867,000 retail customers in southwestern Virginia and southern West Virginia. Wholesale electric power is supplied to neighboring utility systems, power marketers and the American Electric Power (AEP) System Power Pool (Power Pool). As a member of the Power Pool and a signatory company to the AEP Transmission Equalization Agreement, APCo's facilities are operated in conjunction with the facilities of certain other AEP affiliated utilities as an integrated utility system. The Company has four wholly-owned subsidiaries which are consolidated in these financial statements: Cedar Coal Co., Central Appalachian Coal Company and Southern Appalachian Coal Company (which were formerly engaged in coal mining and now lease their coal reserves to unaffiliated companies) and West Virginia Power Company (which is inactive). Regulation As a subsidiary of AEP Co., Inc., APCo is subject to the regulation of the Securities and Exchange Commission (SEC) under the Public Utility Holding Company Act of 1935 (1935 Act). Retail rates are regulated by the Virginia State Corporation Commission (Virginia SCC) and the Public Service Commission of West Virginia (WVPSC). The Federal Energy Regulatory Commission (FERC) regulates wholesale rates. Principles of Consolidation The consolidated financial statements include APCo and its wholly-owned subsidiaries. Significant intercompany items are eliminated in consolidation. Basis of Accounting As a cost-based rate-regulated entity, APCo's 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 with regulator approval over the service life of utility plant through depreciation and represents the estimated cost of borrowed and equity funds used to finance construction projects. In the Virginia jurisdiction, construction work in progress is included in rate base and earns a return in regulated rates in lieu of recording AFUDC. The amounts of AFUDC in 1996, 1995 and 1994 were not significant. Cash and Cash Equivalents Cash and cash equivalents include temporary cash investments with original maturities of three months or less. Operating Revenues Revenues include the accrual of electricity consumed but unbilled at month-end as well as billed revenues. Depreciation and Amortization Depreciation of electric utility plant is provided on a straight-line basis over the estimated useful lives of utility plant 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 3.4% Hydro 2.8% Transmission 2.2% Distribution 3.3% General 3.1% Amounts to be used for demolition and removal of plant are recovered through depreciation charges included in rates. Power Supply Costs and Fuel Costs The Company practices deferred accounting with respect to the over and under collection of certain fuel and power supply costs pursuant to the Virginia regulatory commission's fuel cost recovery mechanism. In the Virginia jurisdiction, changes in fuel costs and the fuel portion of purchased power costs are reviewed annually by the Virginia SCC. In the West Virginia jurisdiction, deferral accounting for the over and under collection of fuel and Power Pool capacity charges which are described in Note 5 incurred from November 1993 through October 1996 was suspended as a result of a three-year freeze on fuel rates. For the period November 1996 through December 1999 deferral accounting will be practiced for the over and under collection of fuel, Power Pool capacitiy charges and certain transmission revenue. Although a cumulative over and under recovery balance will be maintained, ratepayers will not be responsible for any cumulative underrecovery balance at December 31, 1999. Over-recoveries during the annual periods through December 31, 1999 in excess of $10 million per period would be accumulated and shared equally between the Company and its ratepayers. See Note 3. Wholesale jurisdictional fuel cost changes are expensed and billed as incurred. 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 The Company's policy was to account for investment tax credits under the flow-through method except where regulatory commissions reflected investment tax credits in the rate-making process on a deferral basis. Deferred investment tax credits, which represent a regulatory liability, are being amortized over the life of the related plant investment commensurate with recovery in rates. 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. Commensurate with ratemaking, debt discount or premium and debt issuance expenses are deferred and amortized over the term of the related debt, with the amortization included in interest charges. Redemption premiums paid to reacquire preferred stock are deferred, debited to 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 is credited to paid-in capital and amortized to retained earnings. Other Property and Investments Other property and investments are stated at cost. 2. EFFECTS OF REGULATION: 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. Among other things application of SFAS 71 requires that the Company's rates be cost-based regulated. In the event a portion of the Company's business were to no longer meet those requirements, net regulatory assets would have to be written off for that portion of the business and assets would have to be tested for possible impairment. Regulatory assets and liabilities are comprised of the following: December 31, 1996 1995 (in thousands) Regulatory Assets: Amounts Due From Customers For Future Income Taxes $392,372 $379,104 Unamortized Loss On Reacquired Debt 25,567 26,075 Deferred Storm Damage 10,990 10,308 Other 22,343 19,865 Total Regulatory Assets $451,272 $435,352 Regulatory Liabilities: Deferred Investment Tax Credits $83,320 $89,682 Other* 10,384 2,645 Total Regulatory Liabilities $93,704 $92,327 * Included in Deferred Credits on Consolidated Balance Sheets. 3. RATE MATTERS: On May 24, 1996 the Virginia SCC issued a final order related to a 1994 base rate request for an increase of $15.7 million annually and denied the Company's request. The request included, among other things, recovery over three years of $23.9 million of incremental storm damage expenses deferred in 1994. The Virginia SCC had authorized the Company to collect the rate increase subject to refund beginning in November 1994. The Order concluded that the Company had recovered $11.9 million of the 1994 deferred incremental storm damage expenses through existing rates with the remaining net deferred storm damage expenses to be amortized commensurate with recovery over a five- year period effective July 1, 1996. The revenue refund liability of $26.5 million, including interest of $1.9 million, was completed in September 1996. Under the terms of a 1993 settlement agreement in the West Virginia jurisdiction, the Company agreed to a 3-year base rate freeze and suspension of the WVPSC Expanded Net Energy Cost (ENEC) recovery mechanism until October 31, 1996. Under the terms of a 1996 settlement agreement which was approved by the WVPSC on December 27, 1996, the Company agreed to reduce base rates by $5 million annually, reduce the ENEC rates by $28 million annually and not request a rate increase to become effective prior to January 1, 2000. The approved rate reductions were retroactive to November 1, 1996. During the period rates are fixed, ENEC cost variances would be subject to deferral accounting and a cumulative ENEC recovery balance would be maintained. The parties agreed that regardless of the actual balance in this cumulative recovery balance at December 31, 1999, ratepayers will not be responsible for any cumulative underrecovery. ENEC over-recoveries during the annual periods through December 31, 1999 in excess of $10 million per period would be accumulated and shared equally between the Company and its ratepayers. 4. COMMITMENTS AND CONTINGENCIES: Construction and Other Commitments Substantial construction commitments have been made. Such commitments do not include any expenditures for new generating capacity. The aggregate construction program expenditures for 1997-1999 are estimated to be $596 million. Long-term fuel supply contracts contain clauses that provide for periodic price adjustments. The contracts are for various terms, the longest of which extends to 2006, and contain various clauses that would release the Company from its obligation under certain force majeure conditions. Litigation The Company is involved in a number of legal proceedings and claims. While management is unable to predict the 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. RELATED PARTY TRANSACTIONS: Benefits and costs of the AEP System's generating plants are shared by members of the Power Pool. The Company is a member of the Power Pool. Under terms of the System Interconnection Agreement, capacity charges and credits are designed to allocate the cost of the System's capacity among the Power Pool members based on their relative peak demands and generating reserves. Power Pool members are also compensated for the out-of-pocket costs of energy delivered to the Power Pool and charged for energy received from the Power Pool. Operating revenues include $54.8 million in 1996, $26.3 million in 1995 and $32.3 million in 1994 for energy supplied to the Power Pool. Since the Company's internal peak demand exceeds its generating capacity, charges for Power Pool capacity reservation and energy received were included in purchased power expense as follows: Year Ended December 31, 1996 1995 1994 (in thousands) Capacity Charges $125,456 $116,821 $138,517 Energy Charges 187,754 161,531 147,655 Total $313,210 $278,352 $286,172 Power Pool members share in wholesale sales to unaffiliated entities made by the Power Pool. The Company's share of these wholesale Power Pool sales included in operating revenues were $127 million in 1996, $92 million in 1995 and $103.8 million in 1994. In addition, the Power Pool purchases power from unaffiliated companies for immediate resale to other unaffiliated utilities. The Company's share of these purchases was included in purchased power expense and totaled $14.7 million in 1996, $18.8 million in 1995 and $27.5 million in 1994. Revenues from these transactions including a transmission fee are included in the above Power Pool wholesale operating revenues. Energy sold directly to Kingsport Power Company, an affiliated distribution utility that is not a member of the Power Pool, was included in operating revenues in the amounts of $59.5 million in 1996, $58.7 million in 1995 and $61.1 million in 1994. Purchased power expense includes $5.1 million in 1996, $2.9 million in 1995 and $2.1 million in 1994 of energy bought from the Ohio Valley Electric Corporation, an affiliated company that is not a member of the Power Pool. AEP System companies participate in a transmission equalization agreement. This agreement combines certain AEP System companies' investments in transmission facilities and shares the costs of ownership in proportion to the System companies' respective peak demands. Pursuant to the terms of the agreement, other operation expense includes equalization charges of $6.5 million, $5.4 million and $10.2 million in 1996, 1995 and 1994, respectively. The Company and an affiliate, Ohio Power Company, jointly own two power plants. The costs of operating these facilities are apportioned between the owners based on ownership interests. The Company's share of these costs is included in the appropriate expense accounts on the Consolidated Statements of Income. The Company's investment in these plants is included in electric utility plant on the Consolidated Balance Sheets. American Electric Power Service Corporation (AEPSC) provides certain managerial and professional services to AEP System companies. The costs of the services are billed by AEPSC on a direct-charge basis, to the extent practicable, and on reasonable bases of proration for indirect costs. The charges for services are made at cost and include no compensation for the use of equity capital, which is furnished to AEPSC by AEP Co., Inc. Billings from AEPSC are capitalized or expensed depending on the nature of the services rendered. AEPSC and its billings are subject to the regulation of the SEC under the 1935 Act. 6. BENEFIT PLANS: The Company and its subsidiaries participate in the AEP System pension plan, a trusteed, noncontributory defined benefit plan covering all employees meeting eligibility requirements. Benefits are based on service years and compensation levels. Pension costs are allocated by first charging each System company with its service cost and then allocating the remaining pension cost in proportion to its share of the projected benefit obligation. The funding policy is to make annual trust fund contributions 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 pension costs for the years ended December 31, 1996, 1995 and 1994 were $4.2 million, $2.7 million and $5.3 million, respectively. An employee savings plan is offered which allows participants to contribute up to 17% of their salaries into various investment alternatives, including AEP Co., Inc. 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 Co., Inc. common stock. The Company's annual contributions totaled $4.1 million in 1996, $4.3 million in 1995, and $4.2 million in 1994. Postretirement benefits other than pensions (OPEB) are provided for retired employees under an AEP System plan. Substantially all 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. OPEB costs are determined by the application of AEP System actuarial assumptions to each operating company's employee complement. The annual accrued costs were $19 million in 1996, $19.5 million in 1995 and $19.4 million in 1994. The funding policy for AEP's OPEB 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 $8.4 million in 1996, $9.5 million in 1995 and $11.6 million in 1994. 7. LEASES: Leases of property, plant and equipment are for periods of up to 30 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 for both operating and capital leases are generally charged to operating expenses in accordance with rate-making treatment. The components of rental costs are as follows: Year Ended December 31, 1996 1995 1994 (in thousands) Operating Leases $ 9,567 $ 8,600 $ 9,490 Amortization of Capital Leases 12,175 11,003 8,878 Interest on Capital Leases 3,416 4,120 4,585 Total Rental Costs $25,158 $23,723 $22,953 Properties under capital leases and related obligations recorded on the Consolidated Balance Sheets are as follows: December 31, 1996 1995 (in thousands) Electric Utility Plant: Production $ 9,366 $ 8,455 General 73,420 66,281 Total Electric Utility Plant 82,786 74,736 Accumulated Amortization 30,817 25,799 Net Properties under Capital Leases $51,969 $48,937 Capital Lease Obligations: Noncurrent Liability $36,857 $36,739 Liability Due Within One Year 15,112 12,198 Total Capital Lease Obligations $51,969 $48,937 Capital lease obligations are included in other noncurrent and other current liabilities on the Consolidated Balance Sheets. Properties under operating leases and related obligations are not included in the Consolidated Balance Sheets. Future minimum lease payments consisted of the following at December 31, 1996: Non- Cancelable Capital Operating Leases Leases (in thousands) 1997 $18,029 $ 6,335 1998 13,654 4,920 1999 12,822 4,354 2000 11,037 3,616 2001 9,762 1,803 Later Years 22,629 8,786 Total Future Minimum Lease Rentals 87,933 $29,814 Less Estimated Interest Element 35,964 Estimated Present Value of Future Minimum Lease Payments $51,969 8. CUMULATIVE PREFERRED STOCK: The authorized shares of no par value cumulative preferred stock is 8,000,000 shares. The aggregate involuntary liquidation price for all shares of cumulative preferred stock may not exceed $300 million. The unissued shares of the cumulative preferred stock may or may not possess mandatory redemption characteristics upon issuance. The cumulative preferred stock is callable at the price indicated plus accrued dividends. The involuntary liquidation preference is $100 per share. In January 1997 a tender offer for all outstanding 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 Company's articles of incorporation to remove certain capitalization ratio requirements. Cumulative Preferred Stock Not Subject to Mandatory Redemption:
Call Price Shares Amount December 31, Number of Shares Redeemed Outstanding December 31, Series 1996 Year Ended December 31, December 31, 1996 1996 1995 1996 1995 1994 (in thousands) 4-1/2% $110.00 1,850 - - 298,150 $29,815 $30,000 7.40% - 250,000 - - - - 25,000 $29,815 $55,000 Cumulative Preferred Stock Subject to Mandatory Redemption: Call Price Shares Amount December 31, Number of Shares Redeemed Outstanding December 31, Series(a) 1996 Year Ended December 31, December 31, 1996 1996 1995 1996 1995 1994 (in thousands) 4.50% 2,348 1,500 1,517 - $ - $ 235 7.80% (b) $107.80 - - - 500,000 50,000 50,000 5.90% (c) (f) - - - 500,000 50,000 50,000 5.92% (d) (f) - - - 600,000 60,000 60,000 6.85% (e) (g) - - N/A 300,000 30,000 30,000 $190,000 $190,235 N/A - Not applicable, shares were issued in a subsequent year. (a) The sinking fund provisions of series subject to mandatory redemption aggregate $2,500,000 in 1998, $2,500,000 in 1999, $8,500,000 in 2000 and $8,500,000 in 2001. (b) Commencing in 1998, a sinking fund for the 7.80% cumulative preferred stock will require the redemption of 25,000 shares at $100 a share on or before May 1 in each year. The Company has the non-cumulative option to redeem up to 25,000 additional shares on any sinking fund date at a redemption price of $100 per share. (c) Commencing in 2003 and continuing through the year 2007, a sinking fund for the 5.90% cumulative preferred stock will require the redemption of 25,000 shares each year and the redemption of the remaining outstanding shares on November 1, 2008, in each case at $100 per share. (d) Commencing in 2003 and continuing through the year 2007, a sinking fund for the 5.92% cumulative preferred stock will require the redemption of 30,000 shares each year and the redemption of the remaining shares outstanding on November 1, 2008, in each case at $100 per share. (e) Shares issued June 1994. Commencing in 2000 and continuing through date of redemption, a sinking fund for the 6.85% cumulative preferred stock will require the redemption of 60,000 shares each year, in each case at $100 per share. The Company has the non-cumulative option to redeem up to 60,000 additional shares on any sinking fund date at a redemption price of $100 per share. (f) Not callable until after 2002. (g) Not callable until after 1999.
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 $71,648 $58,676 $28,779 Deferred 1,283 1,715 19,763 Deferred Investment Tax Credits (2,716) (2,757) (2,781) Total 70,215 57,634 45,761 Charged (Credited) to Nonoperating Income (net): Current (837) (503) (1,043) Deferred (691) (1,068) (2,408) Deferred Investment Tax Credits (2,886) (2,708) (2,711) Total (4,414) (4,279) (6,162) Total Federal Income Taxes as Reported $65,801 $53,355 $39,599
The following is a reconciliation of the difference between the amount of federal income taxes 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) Net Income $133,689 $115,900 $102,345 Federal Income Taxes 65,801 53,355 39,599 Pre-tax Book Income $199,490 $169,255 $141,944 Federal Income Taxes on Pre-tax Book Income at Statutory Rate (35%) $69,822 $ 59,239 $ 49,680 Increase (Decrease) in Federal Income Taxes Resulting From the Following Items: Depreciation 11,932 14,184 11,103 Corporate Owned Life Insurance (2,298) (5,304) (5,050) Removal Costs (5,460) (5,040) (4,200) Percentage Repair Allowance (1,797) (2,945) (2,813) Federal Income Tax Accrual Adjustments - - (3,100) Investment Tax Credits (net) (5,602) (5,465) (5,492) Other (796) (1,314) (529) Total Federal Income Taxes as Reported $65,801 $ 53,355 $ 39,599 Effective Federal Income Tax Rate 33.0% 31.5% 27.9% The following tables show the elements of the net deferred tax liability and the significant temporary differences giving rise to such deferrals: December 31, 1996 1995 (in thousands) Deferred Tax Assets $ 137,932 $ 127,710 Deferred Tax Liabilities (807,896) (783,716) Net Deferred Tax Liabilities $(669,964) $(656,006) Property Related Temporary Differences $(487,316) $(482,003) Amounts Due From Customers For Future Federal Income Taxes (109,259) (110,529) Deferred State Income Taxes (80,201) (63,307) All Other (net) 6,812 (167) Total Net Deferred Tax Liabilities $(669,964) $(656,006) The Company and its subsidiaries join in the filing of a consolidated federal income tax return with their affiliated companies in the AEP System. The allocation of the AEP System's current consolidated federal income tax to the System companies is in accordance with SEC rules under the 1935 Act. These rules permit the allocation of the benefit of current tax losses to the System companies giving rise to them in determining their current tax expense. The tax loss of the System parent company, AEP Co., Inc., is allocated to its subsidiaries with taxable income. With the exception of the loss of the parent company, the method of allocation approximates a separate return result for each company in the consolidated group. The AEP System 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 COLI program was established in 1990 as part of the Company's 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 approximately $62 million (including interest). Management 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. COMMON SHAREHOLDER'S EQUITY: The Company received from AEP Co., Inc. cash capital contributions of $50 million, $30 million and $10 million in 1996, 1995 and 1994, respectively, which were credited to paid-in capital. In 1996, 1995 and 1994 net changes in paid-in capital of $(416,000), $9,357,000 and $426,000, respectively, represented gains and expenses of cumulative preferred stock transactions. There were no other material transactions affecting common stock and paid-in capital accounts in 1996, 1995 and 1994. At December 31, 1996 there were no dividend restrictions on retained earnings. To pay dividends out of paid-in capital, the Company needs regulatory approval. 11. SUPPLEMENTARY INFORMATION: Year Ended December 31, 1996 1995 1994 (in thousands) Cash was paid for: Interest (net of capitalized amounts) $104,156 $102,145 $96,667 Income Taxes 82,194 59,412 48,872 Noncash Acquisitions Under Capital Leases were 15,308 16,209 22,883 12. LONG-TERM DEBT AND LINES OF CREDIT: Long-term debt by major category was outstanding as follows: December 31, 1996 1995 (in thousands) First Mortgage Bonds $1,056,495 $1,044,555 Installment Purchase Contracts 234,047 233,877 Debentures 72,733 7,252 Other Long-term Debt 2,567 - 1,365,842 1,285,684 Less Portion Due Within One Year 8 7,251 Total $1,365,834 $1,278,433 First mortgage bonds outstanding were as follows: December 31, 1996 1995 (in thousands) % Rate Due 7-1/2 1998 - December 1 $ - $ 45,000 7.00 1999 - December 1 30,000 30,000 6-3/8 2001 March 1 100,000 - 7-5/8 2002 - February 1 - 43,350 7.95 2002 - March 1 60,000 60,000 7.38 2002 - August 15 50,000 50,000 7-1/2 2002 - December 1 - 59,760 7.40 2002 - December 1 30,000 30,000 6.65 2003 - May 1 40,000 40,000 6.85 2003 - June 1 30,000 30,000 6.00 2003 - November 1 30,000 30,000 7.70 2004 - September 1 21,000 21,000 7.85 2004 - November 1 50,000 50,000 8.00 2005 - May 1 50,000 50,000 6.89 2005 - June 22 30,000 30,000 6.80 2006 - March 1 100,000 - 9-7/8 2020 - December 1 - 20,584 9.35 2021 - August 1 43,250 50,000 8.75 2022 - February 1 43,000 50,000 8.70 2022 - May 22 35,000 40,000 8.43 2022 - June 1 50,000 50,000 8.50 2022 - December 1 70,000 70,000 7.80 2023 - May 1 40,000 40,000 7.90 2023 - June 1 30,000 30,000 7.15 2023 - November 1 30,000 30,000 7.125 2024 - May 1 50,000 50,000 8.00 2025 - June 1 50,000 50,000 Unamortized Discount (net) (5,755) (5,139) Total $1,056,495 $1,044,555 Certain indentures relating to the first mortgage bonds contain improvement, maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. Installment purchase contracts have been entered into, in connection with the issuance of pollution control revenue bonds by governmental authorities as follows: % Rate Due December 31, 1996 1995 (in thousands) Industrial Development Authority of Russell County, Virginia: 7-1/4% 1998 - November 1 $ 19,500 $ 19,500 7.70% 2007 - November 1 17,500 17,500 Putnam County, West Virginia: 5.45% 2019 - June 1 40,000 40,000 6.60% 2019 - July 1 30,000 30,000 Mason County, West Virginia: 7-7/8% 2013 - November 1 10,000 10,000 7.40% 2014 - January 1 30,000 30,000 6.85% 2022 - June 1 40,000 40,000 6.60% 2022 - October 1 50,000 50,000 Unamortized Discount (2,953) (3,123) Total $234,047 $233,877 Under the terms of the installment purchase contracts, the Company is required to pay amounts sufficient to enable the payment of interest on and the principal (at stated maturities and upon mandatory redemptions) of related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants. Debentures outstanding were as follows: December 31, 1996 1995 (in thousands) 8-1/4% Series A Deferrable Interest due 2026 - September 30 $75,000 $ - 6% due 1996 - March 1 - 7,251 Unamortized Premium (Discount) net (2,267) 1 Total $72,733 $7,252 At December 31, 1996, future annual long-term debt payments, excluding premium or discount, are as follows: Principal Amount (in thousands) 1997 $ 8 1998 19,509 1999 80,004 2000 5 2001 100,006 Later Years 1,177,285 Total $1,376,817 Short-term debt borrowings are limited by provisions of the 1935 Act to $250 million. Lines of credit are shared with other AEP System companies and at December 31, 1996 and 1995 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 line of credit are required to maintain the lines of credit. Outstanding short-term debt consisted of: Year-end Balance Weighted Outstanding Average (in thousands) Interest Rate December 31, 1996: Commercial Paper $60,700 7.3% December 31, 1995: Commercial Paper $125,525 6.1% 13. FAIR VALUE OF FINANCIAL INSTRUMENTS 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. At December 31, 1996 and 1995 fair values for preferred stock subject to mandatory redemption were $192 million and $198 million and for long-term debt were $1,400 million and $1,350 million, respectively. The carrying amounts for preferred stock subject to mandatory redemption were $190 million at December 31, 1996 and 1995 and for long-term debt were $1,366 million and $1,286 million 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. 14. UNAUDITED QUARTERLY FINANCIAL INFORMATION: Quarterly Periods Operating Operating Net Ended Revenues Income Income 1996 March 31 $440,972 $83,637 $55,624 June 30 379,887 43,219 16,106 September 30 393,797 61,259 34,639 December 31 410,213 54,761 27,320 1995 March 31 407,516 69,144 41,937 June 30 339,957 38,839 8,486 September 30 403,786 55,361 28,378 December 31 393,780 63,758 37,099 INDEPENDENT AUDITORS' REPORT To the Shareholders and Board of Directors of Appalachian Power Company: We have audited the accompanying consolidated balance sheets of Appalachian Power Company 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 Appalachian Power Company 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-23 7 APCO CONSENT OF DELOITTE & TOUCHE 10K405 EX23 Exhibit 23 INDEPENDENT AUDITORS' CONSENT We consent to the incorporation by reference in Registration Statement No. 333-20305 of Appalachian Power Company 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 Appalachian Power Company for the year ended December 31, 1996. Deloitte & Touche LLP Columbus, Ohio March 25, 1997 EX-24 8 APCO POWER OF ATTORNEY 10K405 EX24 Exhibit 24 POWER OF ATTORNEY APPALACHIAN POWER COMPANY Annual Report on Form lO-K for the Fiscal Year Ended December 31, 1996 The undersigned directors of APPALACHIAN POWER COMPANY, a Virginia 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 re- quired 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/ James J. Markowsky - ------------------------------ ------------------------------- E. Linn Draper, Jr. James J. Markowsky /s/ Henry W. Fayne /s/ J. H. Vipperman - ------------------------------ ------------------------------- Henry W. Fayne J. H. Vipperman /s/ Wm. J. Lhota - ------------------------------ Wm. J. Lhota EX-27 9 APCO FINANCIAL DATA SCHEDULES 10K405 EX27
UT 0000006879 APPALACHIAN POWER COMPANY 1,000 12-MOS DEC-31-1996 DEC-31-1996 PER-BOOK 2,935,115 29,621 338,444 56,928 451,272 3,811,380 260,458 575,380 208,472 1,044,310 190,000 29,815 1,365,834 0 0 60,700 8 0 36,857 15,112 1,068,744 3,811,380 1,624,869 80,396 1,301,597 1,381,993 242,876 128 243,004 109,315 133,689 15,938 117,751 108,300 82,082 275,743 0 0 All common stock owned by parent company; no EPS required.
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