-----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, V698MwEr0V/2jezs9HrGA9k6DnzAVZ42AbWWpMLf8mGxX3eosP5V+hyRLkUoycUl RV/KE9cZVUiud5bjCy/mGw== 0000006879-98-000012.txt : 19980330 0000006879-98-000012.hdr.sgml : 19980330 ACCESSION NUMBER: 0000006879-98-000012 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 8 CONFORMED PERIOD OF REPORT: 19971231 FILED AS OF DATE: 19980327 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: SEC FILE NUMBER: 001-03457 FILM NUMBER: 98575352 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 AEP FORM 10K FOR 1997 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, 1997 [ ] 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 (check mark) 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 7.20% Senior Notes, Series A, Due 2038 New York Stock Exchange Columbus Southern 8-3/8% Junior Subordinated Deferrable Power Company 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 8% Junior Subordinated Deferrable Power Company 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 chap- ter) 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. (check mark) 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 4-1/8% Cumulative Preferred Stock, Non-Voting, $100 par value Kentucky Power Company None Ohio Power Company 4-1/2% Cumulative Preferred Stock, Voting, $100 par value Aggregate market value of voting and non-voting Number of shares common equity held of common stock by non-affiliates of outstanding of the registrants at the registrants at February 13, 1998 February 13, 1998 AEP Generating Company None 1,000 ($1,000 par value) American Electric Power Company, Inc. $9,333,250,000 189,989,989 ($6.50 par value) Appalachian Power Company None 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 None 27,952,473 (no par value) NOTE ON MARKET VALUE OF COMMON EQUITY 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). 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, 1997: 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. for 1998 Annual Meeting of Shareholders, to be filed within 120 days after December 31, 1997 Part III Portions of Information Statements of the following companies for 1998 Annual Meeting of Shareholders, to be filed within 120 days after December 31, 1997: 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 . . . . . . . . . . . . . . 34 Item 6. Selected Financial Data . . . . . . . . . . . . . . . . 34 Item 7. Management's Discussion and Analysis of Results of Operations and Financial Condition . . . . . . . . . 35 Item 7A. Quantitative and Qualitative Disclosures About Market Risk 35 Item 8. Financial Statements and Supplementary Data . . . . . . 35 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure . . . . . . . . 36 PART III Item 10. Directors and Executive Officers of the Registrants . . . 36 Item 11. Executive Compensation . . . . . . . . . . . . . . . . . 38 Item 12. Security Ownership of Certain Beneficial Owners and Management . . . . . . . . . . . . . . . . . 41 Item 13. Certain Relationships and Related Transactions . . . . . 42 PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K . . . . . . . . . . . . . . . . . . 42 Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44 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. CSW Central and South West Corporation. 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. PCBs 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. 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 domestic electric utility subsidiaries and varying percentages of 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 subsidiar- ies 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, 1997, the subsidiaries of AEP had a total of 17,844 employees. AEP, as such, has no employees. The operating subsidiaries of AEP are: APCo (organized in Virginia in 1926) is engaged in the generation, sale, purchase, transmission and distribution of electric power to approximately 877,000 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, 1997, APCo and its wholly owned subsidiaries had 3,877 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 Energy Corporation 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, sale, purchase, transmission and distribution of electric power to approximately 621,000 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, 1997, CSPCo had 1,802 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, sale, purchase, transmission and distribution of electric power to approximately 549,000 customers in northern and eastern Indiana and southwestern Michigan, and in supplying electric power at wholesale to other electric utility companies, rural electric cooperatives and municipalities. At December 31, 1997, I&M had 3,306 employees. Among the principal industries served 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, sale, purchase, transmission and distribution of electric power to approximately 168,000 customers in an area in eastern Kentucky, and in supplying electric power at wholesale to other utilities and municipalities in Kentucky. At December 31, 1997, KEPCo had 731 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, 1997, Kingsport Power Company had 85 employees. OPCo (organized in Ohio in 1907 and reincorporated in 1924) is engaged in the generation, sale, purchase, transmission and distribution of electric power to approximately 679,000 customers in the northwestern, east central, eastern and southern sections of Ohio, and in supplying electric power at wholesale to other electric utility companies and municipalities. At December 31, 1997, OPCo and its wholly owned subsidiaries had 4,376 employees. Among the principal industries served by OPCo are primary metals, rubber and plastic products, stone, clay, glass and concrete products, 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 43,000 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, 1997, Wheeling Power Company had 94 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 affili- ate transactions. This authority would be transferred to the FERC. Legislation was introduced in Congress in 1997 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 cur- rent 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, 1997 are as follows:
AEP AEGCo APCo CSPCo I&M KEPCo OPCo System (a) (in thousands) Retail Residential Without Electric Heating . . . . $ 0 $ 227,457 $ 317,341 $ 237,475 $ 40,395 $ 274,680 $1,117,740 With Electric Heating . . . . . 0 336,395 110,385 110,547 65,522 147,503 806,095 Total Residential . . . . . . . 0 563,852 427,726 348,022 105,917 422,183 1,923,835 Commercial . . . . . . . . . . . 0 281,939 381,368 264,031 56,680 263,212 1,286,452 Industrial . . . . . . . . . . . 0 382,056 147,367 332,218 94,645 618,548 1,637,058 Miscellaneous . . . . . . . . . 0 32,271 16,170 6,465 863 8,109 67,387 Total Retail . . . . . . . . . 0 1,260,118 972,631 950,736 260,105 1,312,052 4,914,732 Wholesale (sales for resale) . . 227,803 410,813 141,769 415,077 89,337 597,133 1,080,190 Total from KWH Sales . . . . . 227,803 1,670,931 1,114,400 1,365,813 349,442 1,909,185 5,994,922 Provision for Revenue Refunds . . 0 (250) 0 0 0 0 (250) Total Net of Provision for Revenue Refunds . . . . . . . . . 227,803 1,670,681 1,114,400 1,365,813 349,442 1,909,185 5,994,672 65 49,329 25,204 26,104 10,101 56,633 166,696 $227,868 $1,720,010 $1,139,604 $1,391,917 $359,543 $1,965,818 $6,161,368
__________ (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 and Regulation. 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, 1995, 1996 and 1997:
1995 1996 1997(a) (in thousands) APCo . . . . . . $(252,000) $(258,000) $(237,000) CSPCo . . . . . . (143,000) (145,000) (138,000) I&M . . . . . . . 118,000 121,000 67,000 KEPCo . . . . . . 23,000 2,000 20,000 OPCo . . . . . . 254,000 280,000 288,000
__________ (a) Includes credits and charges from allowance transfers related to the transactions. 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, 1995, 1996 and 1997:
1995(a) 1996(a) 1997(a) (in thousands) AEGCo(b) . . . . $ 29,200 $ 26,300 $ 26,200 APCo(c) . . . . . 24,100 36,800 37,500 CSPCo(c) . . . . 12,000 18,100 18,300 I&M(c)(d) . . . . 34,700 43,000 42,400 KEPCo(c) . . . . 5,000 7,600 7,700 OPCo(c) . . . . . 20,200 30,200 30,200 Total System . $125,200 $162,000 $162,300
__________ (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 1995, 1996 and 1997 were made on a short-term basis, except that $22,500,000, $33,300,000 and $25,900,000 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 1995, 1996 and 1997 amounts for I&M include $21,000,000, $20,900,000 and $21,100,000 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) 205 megawatts of electric power through August 2010; and (2) 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 1997 was 611, 109, 451, 18 and 140 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. Several wholesale customers, some of whom had previously given notice of termination, have entered into long-term contracts, ranging from five to seven years, with the AEP System. The expected demand under these contracts aggregates approximately 450 megawatts. 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, where it remains pending. 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 and Regulations. 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, 1995, 1996 and 1997:
1995 1996 1997 (in thousands) APCo . . . . . . $( 5,400) $( 6,500) $( 8,400) CSPCo . . . . . . ( 31,100) ( 30,600) ( 29,900) I&M . . . . . . . 46,700 46,300 46,100 KEPCo . . . . . . 3,500 3,300 2,700 OPCo . . . . . . ( 13,700) ( 12,500) ( 10,500)
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 revenues net of federal income tax expenses of the various companies from such services during the years ended December 31, 1995, 1996 and 1997:
1995 1996 1997 (in thousands) APCo . . . . . . $ 6,000 $ 13,800 $ 18,000 CSPCo . . . . . . 4,200 8,000 10,200 I&M . . . . . . . 4,800 7,700 10,500 KEPCo . . . . . . 1,200 2,800 3,900 OPCo . . . . . . 17,800 17,800 27,200 $ 34,000 $ 50,100 $ 69,800
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 24, 1996, the FERC issued orders 888 and 889. These orders 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 trans- mission 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 transmis- sion 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. During 1996 and 1997 AEP 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. On January 15, 1998, nine utilities or utility systems filed with the FERC a proposal to form the Midwest Independent Transmission System Operator, Inc. ("Midwest ISO"). AEP was not a participant in that filing, but supports the formation of voluntary ISOs, and is currently examining its options, which include, among others, participation in the Midwest ISO. 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 945,000 kilowatts. On March 1, 1998, it is scheduled to increase to approximately 1,900,000 kilowatts. The proceeds from the sale of power by OVEC 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 1997. 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 306 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 16, 1997, was recorded at 1,178,460 kilowatts. Certain Industrial Customers Century Aluminum of West Virginia, Inc. (formerly 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 357,000 kilowatts for Century and 537,000 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 pro- portionate 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 asso- ciated 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 Agree- ment 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 to December 31, 2004. 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 1997 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) pro- vide 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 or have adopted "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 require- ment 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 1998, S.B. 431 was introduced in the Indiana Senate. The bill contained provisions allowing all customers the unrestricted right to choose their generator of electricity by July 1, 2004. Under the bill, customers could have chosen their power supplier after October 1, 1999, by paying an access charge, while transmission and distribution services would have continued to be regulated at the federal and state levels, respectively. Prior to the full vote on the bill, S.B. 431 was amended on the Senate floor to remove these restructuring provisions. Michigan: In June 1995, the MPSC issued an order approving an experimental five-year retail wheeling program and ordered Consumers Energy Company (Consumers) and Detroit Edison Company (Detroit Edison), 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, which commences when each utility needs new capacity, seeks to determine whether a retail wheeling program best serves the public interest. 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 Supreme Court. 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. In December 1996, the MPSC staff issued a report on electric industry restructuring which recommended a phase-in program from 1997 through 2004 of direct access to electricity suppliers applicable to all customers. On June 5, 1997, the MPSC entered an order requiring electric utilities (including I&M) to phase in retail open access for customers, with full customer choice by 2002 (MPSC Order). Under the MPSC Order, customer choice is phased in from 1997 through 2001, at the rate of 2.5% of each utility's customer load per year, with all customers becoming eligible to choose their electric supplier effective January 1, 2002. The MPSC Order essentially adopted the December 1996 MPSC staff report that recommended full recovery of stranded costs of utilities, including nuclear generating investment, through the use of a transition charge applicable to customers exercising choice. While concluding that securitization of stranded costs would be feasible, the MPSC Order stated that legislative guidance is required prior to the implementation of any securitization program. As required by the MPSC Order, in July 1997, I&M filed a proposed open access distribution tariff phasing-in customer choice for all customer classes. The MPSC has not yet acted on I&M's filing. The MPSC has approved, by orders dated January 14, 1998 and February 11, 1998, after contested proceedings and with modifications, filings made by Consumers and Detroit Edison. Detroit Edison, the Michigan Attorney General and other parties have appealed the MPSC's orders to the Michigan Court of Appeals. 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. Pursuant to a PUCO order, all Ohio electric utilities made conjunctive electric service filings on March 31, 1997. Six unaffiliated utilities have appealed these guidelines to the Ohio Supreme Court. 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 co- chairs of the Joint Committee issued their report on January 6, 1998, which described plans for introducing electric retail competition to Ohio consumers. On February 18, 1998, the General Assembly's Joint Committee forwarded its report to the House Speaker and Senate President. The report contains the co-chairs report and the comments of other Committee members. The co-chairs report proposes the establishment of a fully competitive marketplace by the year 2000 and utility tax reform intended to place Ohio's utilities on a level playing field with out-of-state suppliers. One of the co-chairs has indicated her intention to introduce legislation based on the co-chairs report's recommendations. However, there are a number of other bills pending which could be used to enact deregulation. Virginia: Pursuant to a resolution of the Virginia legislature, in November 1997 the staff of the Virginia SCC provided its draft of a working model of a restructured electric utility industry for Virginia to the joint subcommittee of the legislature studying restructuring of the electric utility industry. Two major bills providing for the restructuring of the electric utility industry were acted on by the Virginia General Assembly. One bill, introduced by the chairman of the joint subcommittee, was "carried over" to serve as a framework for study and debate over the balance of 1998, with oversight provided by the joint subcommittee. The second bill, passed by the Virginia General Assembly in March 1998, provides a general timetable for the transition to retail competition by January 1, 2004, but leaves the details to be decided in subsequent legislation. 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 Task Force established by the West Virginia PSC to study electric industry restructuring issued its Initial Report in October 1997 and Supplemental Report on Recommended Legislation in January 1998. On March 14, 1998, the West Virginia Legislature passed restructuring legislation. If signed into law, the bill would authorize the West Virginia PSC to proceed with the development of a plan for electric industry restructuring in West Virginia, if restructuring is determined by the West Virginia PSC to be in the public interest. Any plan developed and proposed by the West Virginia PSC must be approved by the West Virginia Legislature before such plan can be made effective. 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 Service Company (formerly AEP Energy Services, Inc.) (AEPRESC) and AEP Energy Services, Inc. (formerly AEP Energy Solutions, Inc.) (AEPES). Resources' primary business is development of, and investment in, exempt wholesale generators, foreign utility companies, qualifying cogeneration facilities and other energy-related domestic and international investment opportunities and 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 valued Yorkshire Electricity at U.S. $2.4 billion. The Tender Offer was 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, which is a wholly-owned subsidiary of New Century Energies, Inc. Resources and NCII each contributed 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 Power Group gained effective control of Yorkshire Electricity on April 1, 1997. Yorkshire Electricity is an English independent regional electricity company. It is principally engaged in the distribution of elec- tricity to 2.1 million customers in its authorized service territory which is comprised of 3,860 square miles and located centrally in the east coast of England. Resources' indirect 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 City Hengsheng Energy Development Company Limited (formerly 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. Resources' share of the total cost of the project of $190 million is estimated to be approximately $110 million. On October 2, 1997, Resources, DuPont and Conoco, the energy subsidiary of DuPont, signed a letter of intent to form two jointly held venture companies to provide energy management and capital to industrial and large commercial customers. AEP Conoco Energy Capital will acquire and lease back energy assets at industrial and large commercial facilities and provide future capital for energy projects. AEP Conoco Energy Management Services will provide energy management services. The ventures will initially acquire and manage industrial energy assets valued at approximately $1 billion for DuPont energy facilities at 33 U.S. industrial plants. Resources and DuPont will each invest approximately $125 million in equity in the joint ventures with the remainder to be financed through non-recourse debt. AEPRESC offers engineering, construction, project management and other consulting services for projects involving transmission, distribution or generation of electric power both domestically and internationally. AEP Communications, LLC (Communications) was formed in 1997 to pursue opportunities in the telecommunications field. Communications is currently constructing a fiber optic line that stretches between Kentucky, Ohio, Virginia and West Virginia. This fiber optic line will be capable of providing high speed telecommunications capacity to other telecommunications companies. In addition to establishing and providing fiber optic services, Communications also made investments in two companies engaged in providing digital personal communications services, the West Virginia PCS Alliance, LC and the Virginia PCS Alliance, LC. AEP has received approval from the SEC under PUHCA to issue and sell securities in an amount up to 50%, and is seeking approval to finance up to 100%, of its consolidated retained earnings (approximately $1,600,000,000 at December 31, 1997), 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. The SEC 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. AEPES, an energy-related company under Rule 58, is authorized to engage in energy-related activities, including marketing electricity, gas and other energy commodities. In July 1996, AEP Power Marketing, Inc. (AEPPM), a wholly-owned subsidiary of AEP, requested authority from FERC to market electric power at wholesale at market-based rates. In September 1996, the FERC accepted the filing, conditioned upon, among other things, the utility subsidiaries of AEP refraining from (1) selling nonpower goods or services to any affiliate at a price below its cost or market price, whichever is higher, and (2) purchasing nonpower goods or services from any affiliate at a price above market price. AEPPM has requested FERC to clarify that the applicability of this condition relates only to transactions between AEP utility subsidiaries and AEPPM. AEPPM 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. Proposed AEP-CSW Merger AEP and CSW entered into an Agreement and Plan of Merger, dated as of December 21, 1997, pursuant to which CSW would, on the closing date, merge with and into a wholly owned merger subsidiary of AEP with CSW being the surviving corporation. As a result of the merger, each outstanding share of common stock, par value $3.50 per share, of CSW (other than shares owned by AEP or CSW) shall be converted into the right to receive 0.6 of a share of common stock, par value $6.50 per share, of AEP. Based on the price of AEP's common stock on December 19, 1997, the transaction would be valued at $6.6 billion. The combined company will be named American Electric Power Company, Inc. and will be based in Columbus, Ohio. Consummation of the merger is subject to certain conditions, including receipt of approval of the merger and the transactions contemplated thereby by the shareholders of AEP and CSW and the receipt of the required regulatory approvals. Assuming the receipt of all required approvals, completion of the merger is anticipated to occur in the first half of 1999. CSW is a global, diversified public utility holding company based in Dallas, Texas. CSW owns four domestic electric utility subsidiaries serving 1.7 million customers in portions of the states of Texas, Oklahoma, Louisiana and Arkansas and a regional electricity company in the United Kingdom. CSW owns other international energy operations and non-utility subsidiaries involved in energy-related investments, telecommunications, energy efficiency services and financial transactions. Construction Program 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 2001 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 expiration 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 resources until beyond the year 2002. When the time for commitment to additional generation resources approaches, all means for adding such resources, 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 fore- seeable future is highly uncertain. Proposed Transmission Facilities APCo: On September 30, 1997, APCo refiled applications in Virginia and West Virginia for certificates to build the Wyoming-Cloverdale 765,000-volt line. The preferred route for this line is approximately 132 miles in length, connecting APCo's Wyoming Station in southern West Virginia to APCo's Cloverdale Station near Roanoke, Virginia. APCo's estimated cost is $263,300,000. APCo announced this project in 1990. Since then it has been in the process of trying to obtain federal permits and state certificates. At the federal level, the U.S. Forest Service (Forest Service) is directing the preparation of an Environmental Impact Statement (EIS), which is required prior to granting permits for crossing lands under federal jurisdiction. Permits are needed from the (i) Forest Service to cross federal forests, (ii) Army Corps of Engineers to cross the New River and a watershed near the Wyoming Station, and (iii) National Park Service or Forest Service to cross the Appalachian National Scenic Trail. In June 1996, the Forest Service released a Draft EIS and preliminarily identified a "No Action Alternative" as its preferred alternative. If this alternative were incorporated into the Final EIS, APCo would not be authorized to cross federal forests administered by the Forest Service. The Forest Service stated that it would not prepare the Final EIS until after Virginia and West Virginia determined need and routing issues. In an interim order issued in 1995, the Virginia SCC found, based on the record before it, that there is a compelling need for additional electric capacity to serve APCo's Central and Eastern regions and that the proposed transmission line may be the best possible solution. In December 1996, APCo filed a report with the Virginia SCC reviewing the need for the project. Based on that review and after considering all other feasible alternatives, APCo concluded that the need for reinforcement of the transmission system serving its Central and Eastern areas remains compelling and the proposed project is the best alternative for addressing the need. Procedural schedules have been issued in each state. In Virginia, five public hearings will be held in March and April and an evidentiary hearing will be held in July. In West Virginia, three public meetings will be held in early May, followed by an evidentiary hearing. By statute, the West Virginia PSC has 400 days from the filing date, or November 4, 1998, to issue the certificate. If it fails to act, APCo receives the certificate automatically. Virginia does not have such a time constraint. If Virginia and West Virginia issue the required certificates, APCo will cooperate with the Forest Service to complete the EIS process and obtain the federal permits. Management estimates that the project cannot be completed before the winter of 2002-2003. However, given the findings in the Draft EIS, 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 $5,800,000 and $81,600,000, 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 1995, 1996 and 1997 and their current estimate of 1998 construction expenditures, in each case including AFUDC but excluding nuclear fuel and other assets acquired under leases. The construction expenditures for the years 1995-1997 were, and it is anticipated that the estimated construction expenditures for 1998 will be, approximately:
1995 1996 1997 1998 Actual Actual Actual Estimate (in thousands) AEGCo . . . . . . . . . . . $ 4,000 $ 2,200 $ 3,900 $ 4,200 APCo . . . . . . . . . . . 217,600 192,900 218,100 205,600 CSPCo . . . . . . . . . . . 99,500 93,600 108,900 117,900 I&M . . . . . . . . . . . . 113,000 90,500 123,400 169,100 KEPCo . . . . . . . . . . . 39,300 75,800 66,700 53,800 OPCo . . . . . . . . . . . 116,900 113,800 172,700 187,700 AEP System (a) . . . . . $601,200 $578,000 $762,000 $847,000
__________ (a) 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, en- vironmental 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 1995, 1996 and 1997 and the current estimate for 1998 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.
1995 1996 1997 1998 Actual Actual Actual Estimate (in thousands) AEGCo . . . . . . . . . . . $ 0 $ 0 $ 0 $ 0 APCo . . . . . . . . . . . 7,800 10,500 9,100 11,500 CSPCo . . . . . . . . . . . 10,000 1,800 1,300 4,500 I&M . . . . . . . . . . . . 0 0 0 3,200 KEPCo . . . . . . . . . . . 600 0 0 4,000 OPCo . . . . . . . . . . . 3,100 1,600 1,800 32,800 AEP System . . . . . . . $ 21,500 $ 13,900 $ 12,200 $ 56,000
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 pur- pose of retiring the short-term debt previously incurred. In 1997, AEP issued approximately 1,755,000 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 1995-1997, external funds from financings and capital contributions by AEP amounted, with respect to APCo and KEPCo, to approximate- ly 28% and 70%, 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, 1998, 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 CSPCo I&M KEPCo OPCo System(a) (in millions) Amount authorized . . . . . . . . . . . $150 $ 80 $250 $175 $175 $150 $250 $1,230 Amount outstanding: Notes payable . . . . . . . . . . . . $ 24 $ 12 $ 34 $ 4 $ 57 -- $ 11 $ 199 Commercial paper . . . . . . . . . . 29 -- 96 63 63 37 68 356 $ 53 $ 12 $130 $ 67 $120 $ 37 $ 79 $ 555
__________ (a) Includes short-term debt of other subsidiaries not shown. 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, with respect to the preferred stock coverages, that 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, 1995 1996 1997 APCo Mortgage coverage . . . . . . . 3.47 3.98 3.72 Preferred stock coverage . . . 1.78 1.99 1.92 CSPCo Mortgage coverage . . . . . . . 3.90 4.44 4.95 I&M Mortgage coverage . . . . . . . 6.25 6.66 7.57 Preferred stock coverage . . . 2.63 3.07 2.88 KEPCo Mortgage coverage . . . . . . . 2.86 3.22 4.23 OPCo Mortgage coverage . . . . . . . 6.17 8.27 9.74 Preferred stock coverage . . . 3.04 3.63 3.67
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 curtailment of construction and other outlays or the use of alternative financing arrangements, if available, which may be more costly. 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. Rates and Regulation 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 postretirement benefits other than pensions under SFAS 106. FERC action on APCo's applications is pending. Virginia: In June 1997, APCo filed an application with the Virginia SCC for approval of an alternative regulatory plan (Plan) and proposed, among other things, an increase of $30,500,000 in base rates on an annual basis to be effective July 13, 1997. APCo's Plan would institute a moratorium period during which no changes from the rate levels (including APCo's current 1.482 cents/kwh fuel factor) proposed by APCo would be made prior to January 1, 2001. In addition, the Plan includes a sharing of earnings above certain levels between APCo and its customers, and acceleration of the recovery of generation-related regulatory assets. On July 10, 1997, the Virginia SCC issued an order suspending implementation of the proposed rates until November 11, 1997 when these rates were placed into effect subject to refund. A hearing has been scheduled for July 6, 1998 to consider APCo's proposal. West Virginia: 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 Expanded Net Energy Cost (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 overre- coveries 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%). 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. I&M On September 9, 1997, I&M filed a petition with the IURC requesting approval of accounting authority to increase nuclear decommissioning expense in an amount equal to the expiring Rockport phase-in plan amortization expense. The petition would increase I&M's Indiana jurisdictional nuclear decommissioning provision by $10,900,000 annually, effective September 1, 1997. A hearing on I&M's petition was held on February 3, 1998, and an order is awaited from the IURC. I&M has recorded the requested increased nuclear decommissioning expense provision, but has not deposited the increased provision into its nuclear decommissioning trust funds pending IURC approval. 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. After the first to occur of either full recovery of these costs or 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 pre- determined 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 $53,000,000 for Meigs, $37,000,000 for Muskingum and $12,000,000 for Windsor, after tax at December 31, 1997. 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 - Acid Rain). 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. Management anticipates closing the Muskingum mine in 1999, Windsor mine in 2000 and Meigs mine in 2001. Management, however, in making such a determination, will consider certain factors, including the competitiveness of the price of the coal extracted from the mine and the value of SO2 Allowances after the accelerated amortization of mine closure and the recovery of other costs. 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:
1993 1994 1995 1996 1997 Coal . . . . . . . . . . . 86% 91% 88% 87% 92% Nuclear . . . . . . . . . . 13% 8% 11% 12% 7% Hydroelectric and other . . 1% 1% 1% 1% 1%
Variations in the generation of nuclear power are primarily related to refueling outages and, in 1997, the shutdown of the Cook Plant to respond to issues raised by the NRC. See Cook Plant Shutdown. 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 - Acid Rain 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 3,460 coal hopper cars to be used in unit train movements, as well as 13 towboats, 307 jumbo barges and 183 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:
1993 1994 1995 1996 1997 Total coal delivered to AEP operated plants (thousands of tons) . . . . . 40,561 49,024 46,867 51,030 54,292 Sources (percentage): Subsidiaries . . . . . . . . . . . . . . . . . . . 20% 15% 14% 13% 14% Long-term contracts . . . . . . . . . . . . . . . 66% 65% 75% 71% 66% Spot or short-term purchases . . . . . . . . . . . 14% 20% 11% 16% 20% Average price per ton of spot-purchased coal . . . $23.55 $23.00 $25.15 $23.85 $24.38
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:
1993 1994 1995 1996 1997 Dollars per ton AEP System Companies . . . . . 33.57 33.95 32.52 31.70 31.77 AEGCo . . . . . . . . . . . . . 17.74 18.59 18.80 18.22 19.30 APCo . . . . . . . . . . . . . 42.65 39.89 38.86 37.60 36.09 CSPCo . . . . . . . . . . . . . 33.87 32.80 33.23 31.70 31.69 I&M . . . . . . . . . . . . . . 23.80 22.85 23.25 22.99 23.68 KEPCo . . . . . . . . . . . . . 27.08 26.83 26.91 27.25 26.76 OPCo . . . . . . . . . . . . . 38.12 41.10 37.58 35.96 36.00 Cost per Million Btu's AEP System Companies . . . . . 150.89 152.41 145.26 140.48 140.23 AEGCo . . . . . . . . . . . . . 107.71 112.06 112.87 109.25 115.21 APCo . . . . . . . . . . . . . 173.32 161.37 156.96 152.54 146.54 CSPCo . . . . . . . . . . . . . 143.66 140.45 140.79 134.60 134.44 I&M . . . . . . . . . . . . . . 129.39 123.62 125.50 121.16 123.36 KEPCo . . . . . . . . . . . . . 113.90 113.40 114.77 114.42 110.37 OPCo . . . . . . . . . . . . . 161.25 173.51 157.62 151.55 151.66
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, 1997, the System's coal inventory was approximately 43 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 1997 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 1997 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 of Delivered Coal Estimated Require- Total Consumption ments for Remainder During 1997 of Useful Lives Pounds of SO2 (In Thousands of Tons) (In Millions of Tons) By Weight Per Million Btu's AEGCo(a) . . . . 5,043 251 0.3% 0.7 APCo . . . . . . 11,682 446 0.8% 1.3 CSPCo . . . . . . 6,082(b) 236(b) 2.8% 4.7 I&M(c) . . . . . 7,304 294 0.7% 1.4 KEPCo . . . . . . 2,909 91 1.3% 2.1 OPCo . . . . . . 20,493 642 2.1% 3.5
(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 of the 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 1997, 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 3,400,000 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 52,010,543 tons expires on December 31, 2014 and another contract with remaining deliv- eries of 43,395,000 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 2,300,000 tons of coal in 1998. 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 200,000,000 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 103,000,000 tons of clean recoverable coal ranging in sulfur content between 1.4% and 4.0% sulfur by weight (weighted average, 2.2%) of which approximately 26,000,000 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 cur- rently 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 $71,964,000, exclusive of interest of $108,873,000 at December 31, 1997. 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 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 dis- posal 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. On November 12, 1997, the Court of Appeals issued a decision granting in part and denying in part the utilities' request for relief. The court ordered DOE to proceed with contractual remedies and to refrain from concluding that DOE's delay is unavoidable due to the lack of a repository or the lack of interim storage authority. The court, however, declined to order DOE to begin disposing of fuel. On January 31, 1998, the deadline for DOE's performance, the DOE failed to begin disposing of the utilities' spent nuclear fuel. In February 1998, the states and the utilities filed with the Court of Appeals for additional relief in connection with DOE's failure to meet the January 31, 1998 deadline. Studies completed in 1997 estimate decommissioning and low-level radioactive waste disposal costs for the Cook Plant to range from $700,000,000 to $1.152 billion in 1997 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 $28,000,000 in 1997, $27,000,000 in 1996 and $30,000,000 in 1995 (including $4,000,000 in special deposits). At December 31, 1997, I&M had recognized a decommissioning liability of $381,000,000. 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, (e) the technology available at the time of decommissioning differing significantly from that assumed in these studies and (f) the availability of nuclear waste disposal facilities. Accordingly, management is unable to provide assurance that the ultimate cost of decommissioning the Cook Plant will not be significantly greater than current projections. 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. Development of required legislation and prog- ress 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. 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 $39,325,000, subject to inflation adjustments, and is payable in annual assessments over the next nine years. I&M recorded a regulatory asset concurrent with the recording of the liability. The payments are being recorded and recovered as fuel expense. These assessments were held to be unlawful in a June 1995 decision of the U.S. Court of Federal Claims in a case involving an unaffiliated utility. Based upon that decision I&M filed a complaint in the same court seeking refunds of the assessments levied with respect to its enrichment services contracts. In May 1997 the U.S. Court of Appeals for the Federal Circuit reversed the lower court's 1995 decision. The utility has petitioned the U.S. Supreme Court for review of the decision. I&M's complaint has been stayed pending a final decision in this case. 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 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 For the AEP System, compliance with the Clean Air Act (CAA) is requiring substantial expenditures that generally are being recovered through increases in the rates of AEP's operating subsidiaries. However, there can be no assurance that all such costs will be recovered. See Construction Program - Construction Expenditures. Acid Rain: The Acid Rain Program (Title IV) of the Clean Air Act Amendments of 1990 (CAAA) created an emission allowance program pursuant to which utilities are authorized to emit a designated quantity of sulfur dioxide (SO2), 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 levels substantially below historical emission levels for most utility units. There are two phases of SO2 control under the Acid Rain Program. Phase I, effective January 1, 1995, requires SO2 emission reductions from certain units that emitted SO2 above a rate of 2.5 pounds per million Btu heat input in 1985. Phase I unit allowance allocations were calculated based on 1985 utilization rates and an emission rate of 2.5 pounds of SO2 per million Btu heat input. Phase I permits have been issued for all Phase I affected units in the AEP System. Phase II, which affects all fossil fuel-fired steam generating units with capacity greater than 25 megawatts imposes more stringent SO2 emission control requirements beginning January 1, 2000. If a unit emitted SO2 in 1985 at a rate in excess of 1.2 pounds per million Btu heat input, the Phase II allowance allocation is premised upon an emission rate of 1.2 pounds at 1985 utilization levels. If actual SO2 emissions for a Phase II affected unit in 1985 were less than 1.2 pounds per million Btu, the allowance allocation is, in most instances, based on the actual 1985 emission rate. In addition to regulating SO2 emissions, Title IV of the CAAA contains provisions regulating emissions of nitrogen oxides (NOx). 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 for wet bottom wall-fired boilers, cyclone boilers, units applying cell burner technology and all other types of boilers. The regulations also revised downward the NOx limitations applicable to tangentially fired and wall-fired boilers in Phase II. These emission limitations are to be achieved by January 1, 2000. On February 13, 1998, the U.S. Court of Appeals for the District of Columbia Circuit, in an appeal in which the AEP System operating companies participated, upheld the emission limitations. Title I National Ambient Air Quality Standards Attainment: The CAA contains additional provisions, other than the Acid Rain Program, which could require reductions in emissions of NOx and other pollutants from fossil fuel- fired power plants. Title I, dealing generally with attainment of federally set National Ambient Air Quality Standards (NAAQS), establishes a tiered system for classifying degrees of nonattainment with the one-hour NAAQS for ozone. Depending upon the severity of non-attainment within a given non- attainment area, reductions in NOx emissions from fossil fuel-fired power plants may be required as part of a state's plan for achieving attainment with the one-hour ozone NAAQS. While one-hour ozone NAAQS non-attainment is largely restricted to urban areas, AEP System generating units could be determined to be affecting downwind urban ozone concentrations and may therefore, eventually be required to reduce NOx emissions pursuant to Title I. In July 1997, Federal EPA revised the ozone and particulate matter NAAQS, creating a new eight-hour ozone standard and establishing a new standard for particulate matter less than 2.5 microns in diameter (PM2.5). Both of these new standards have the potential to affect adversely the operation of AEP System generating units. Substantial reductions in NOx emissions from fossil fuel-fired power plants may be required as part of a state's plan to attain the eight-hour ozone standard. The actual implementation of the new PM2.5 NAAQS has been delayed for five years. Substantial reductions in SO2 and/or other emissions from fossil fuel-fired power plants may be required as part of a state's plan to attain the PM2.5 NAAQS. The AEP System operating companies joined with other utilities to appeal the revised NAAQS by filing petitions for review in August and September 1997 in the U.S. Court of Appeals for the District of Columbia Circuit. On July 9, 1997, Federal EPA proposed revisions to the New Source Performance Standards applicable to new and modified fossil fuel-fired power plants. Federal EPA characterized its proposal as "fuel neutral" since it would impose the same stringent NOx emission limit (1.35lb./megawatt-hour net energy output) for coal-fired boilers as for gas-fired boilers. If finalized, the proposal would effectively require costly selective catalytic reduction or comparable technology to control NOx emissions from new or modified coal-fired boilers. NOx SIP Calls and the Ozone Transport Assessment Group: In 1995, the Environmental Council of States formed the Ozone Transport Assessment Group (OTAG) to study the role of transport of ozone and ozone precursor emissions (primarily NOx) in contributing to ozone nonattainment in the Northeast, Chicago, and Atlanta nonattainment areas. OTAG was comprised of the environmental commissioners of 37 eastern states, members of Federal EPA and representatives from environmental and industry groups. OTAG studied the ozone problem for two years, conducting extensive modeling and analysis of ozone levels and the effects of ozone transport. OTAG submitted its final recommendations to Federal EPA in July 1997. After receipt of the OTAG recommendations, Federal EPA in October 1997 issued a notice (NOx transport SIP call) concluding that certain State Implementation Plans are deficient because they allow NOx emissions that contribute excessively to ozone nonattainment in downwind states. Federal EPA's proposed NOx transport SIP call would establish state-by-state NOx emission budgets for the five-month ozone season to be met by the year 2002. The proposed NOx budgets apply to 22 eastern states and are premised mainly on the assumption of controlling power plant NOx emissions to 0.15 lb./MBtu (approximately 85% below 1990 levels). The NOx transport SIP call purports to implement both the new eight-hour ozone standard and the one-hour ozone standard. The NOx reductions called for by Federal EPA are clearly targeted at coal-fired electric utilities and may adversely impact the ability of electric utilities to obtain new and modified source permits. The cost of meeting NOx emissions reduction requirements that might be imposed as a result of the NOx transport SIP call cannot be precisely predicted at this time, but could be significant. Section 126 Petitions: On or about August 14, 1997, eight northeastern states (New York, New Hampshire, Maine, Massachusetts, Rhode Island, Pennsylvania, Connecticut, and Vermont) filed petitions with Federal EPA under Section 126 of the Clean Air Act, claiming that NOx emissions from power plants in midwestern states, including all the coal-fired plants of AEP's operating subsidiaries, prevent the Northeast from attaining the ozone NAAQS. Among other things, the petitioners generally seek NOx emission reductions 85% below 1990 levels from the utility sources in midwestern states. Federal EPA on or about December 19, 1997 entered into a Memorandum of Agreement (MOA) with the petitioning states that establishes a schedule for taking final action on the Section 126 petitions on approximately the same time frame as Federal EPA's final action on the NOx transport SIP call. The MOA calls for a proposed rulemaking on the Section 126 petitions by September 30, 1998 and final action by April 30, 1999 (subject to certain limited exceptions). On January 9, 1998, a number of utilities, including the operating companies of the AEP System, filed a petition in the U.S. Court of Appeals for the District of Columbia Circuit seeking a review of the MOA. On February 25, 1998, the eight northeastern states filed an action in the U.S. District Court for the Southern District of New York seeking an order directing Federal EPA to rule on the Section 126 petitions within 60 days of receipt. SO2 NAAQS: On January 30, 1998, the U.S. Court of Appeals for the District of Columbia Circuit remanded the final rule promulgated in May 1996 by Federal EPA reaffirming the existing primary NAAQS for SO2. The court directed Federal EPA to provide additional justification for the rule but did not specify a schedule for completion. Hazardous Air Pollutants: Hazardous air pollutant emissions from utility boilers are potentially subject to control requirements under Title III of the CAAA. The CAAA specifically directed Federal EPA to study potential public health impacts of hazardous air pollutants emitted from electric utility steam generating units. Federal EPA was required to report the results of this study to Congress by November 1993 and to regulate emissions of these hazardous pollutants if necessary. On February 25, 1998, Federal EPA issued a final report to Congress citing as potential health and environmental threats, mercury and three other hazardous air pollutants present in power plant emissions. Noting uncertainty regarding health effects and the absence of control technology for mercury, no immediate regulatory action was proposed regarding emission reductions. In addition, Federal EPA is required to study the deposition of hazardous pollutants in 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 this assessment of water body deposition may result in additional regulation of electric utility steam generating units. Federal EPA was also required to study mercury emissions and report its findings to Congress by 1994. Federal EPA presented that report to Congress in December 1997. The report identifies electric utilities as being the third leading emitter of mercury. Presently, mercury emissions from electric utilities are not regulated under the CAA. However, Federal EPA intends to engage in further studies of mercury emissions, which may lead to additional regulation in the future. Permitting and Enforcement: The CAAA expanded the enforcement authority of the federal government by increasing the range of civil and criminal penalties for violations of the CAA and enhancing administrative civil provisions, adding a citizen suit provision and imposing a national operating permit system, emission fee program and enhanced monitoring, recordkeeping and reporting requirements for existing and new sources. On February 13, 1997, Federal EPA issued the Credible Evidence rule, which allows Federal EPA to use any credible evidence or information in lieu of, or in addition to, the test methods prescribed by the regulation for determining compliance with emission limits. This rule has the potential to expand significantly Federal EPA's ability to bring enforcement actions and to increase the stringency of the emission limits to which AEP System plants are subject. On March 10, 1997, a number of industries, including AEP System operating companies, filed petitions for review of the Credible Evidence Rule with the U.S. Court of Appeals for the District of Columbia Circuit. Oral argument in that case is scheduled to be heard on April 21, 1998. Global Climate Change: In December 1997, delegates from 167 nations, including the United States, agreed to a treaty, known as the "Kyoto Protocol," establishing legally-binding emission reductions for gases suspected of causing climate change. If the U.S. becomes a party to the treaty it will be bound to reduce emissions of carbon dioxide (CO2), methane and nitrous oxides by 7% below 1990 levels and emissions of hydrofluorcarbons, perfluorocarbons and sulphur hexafluoride 7% below 1995 levels in the years 2008-2012. The Protocol will be available for signature from March 1998 to March 1999 and requires ratification by at least 55 nations that account for at least 55% of developed countries' 1990 emissions of CO2 to enter into force. The agreement is not expected to be sent to the U.S. Senate for ratification before 1999. Since the AEP System is a significant emitter of carbon dioxide, its financial condition could be adversely affected by the imposition of limitations on CO2 emissions if compliance costs cannot be fully recovered from customers. In addition, any such severe program to reduce CO2 emissions could impose substantial costs on industry and society and erode the economic base that AEP's operations serve. West Virginia SO2 Limits: West Virginia promulgated SO2 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 obligated to reanalyze SO2 emission limits for the Mitchell Plant with respect to secondary ambient air quality (welfare-related) standards. Because the CAA 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 SO2 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 SO2 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 SO2 per million Btu actual heat input on a three-hour basis and 5.8 pounds of SO2 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 SO2 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. Short Term SO2 Limits: On January 2, 1997, Federal EPA proposed a new intervention level program under the authority of Section 303 of the CAA to address five minute peak SO2 concentrations believed to pose a health risk to certain segments of the population. The proposal establishes a "concern" level and an "endangerment" level. States must investigate exceedances of the concern level and decide whether to take corrective action. If the endangerment level is exceeded, the state must take action to reduce SO2 levels. The effects of this proposed intervention program on AEP operations cannot be predicted at this time. Regional Haze: On July 31, 1997, Federal EPA proposed new rules to regulate regional haze attributable to anthropogenic emissions. The primary goal of the new regional haze program is to address visibility impairment in and around "Class I" protected areas, such as national parks and wilderness areas. Because regional haze precursor emissions are believed by Federal EPA to travel long distances, Federal EPA proposes to regulate such precursor emissions in every state. Under the proposal, each state must develop a regional haze control program that imposes controls necessary to steadily reduce visibility impairment in Class I areas on the worst days and that ensures that visibility remains good on the best days. This is accomplished using a unit of measurement known as a "deciview." The plan's goal is to reduce visibility impairment by one deciview or more over each 10-15 year period. The final time period will be set as part of the final rulemaking. The AEP System is a significant emitter of fine particulate matter and its precursors that could be linked to the creation of regional haze. The finalization of Federal EPA's proposed rule to control regional haze may have an adverse financial impact on AEP as it may trigger the requirement to install costly new pollution control devices to control emissions of fine particulate matter and its precursors (including SO2 and NOx). The actual impact of the regional haze regulations cannot be determined at this time. 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 CAA. 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. The court recently requested that the parties submit proposed briefing schedules. 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 applica- tions are being prepared or have been filed for renewal of NPDES permits which expire in 1998. 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 curtail- ment 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, anti-degradation 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. Solid and Hazardous Waste 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, Compensa- tion, 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 PCBs 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 environ- mental 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. AEP System companies are identified as Potentially Responsible Parties (PRPs) for seven additional federal sites, including CSPCo, KEPCo and Wheeling Power Company at one site each, I&M at three 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 1999. 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, 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 con- clusion of the committee is that the current body of evidence does not show that exposure to these fields presents a human health hazard..." The epidemi- ological 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. On July 3, 1997, the results of a five-year study by the National Cancer Institute (NCI) were released. The NCI researchers found no evidence that EMF in the home increases the risk of childhood cancer. The Energy Policy Act of 1992 established a coordinated Federal EMF research program which will end in 1998. The program funding is $65,000,000, half of which was provided by private parties including utilities. AEP has contributed over $400,000 to this program. 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 1997. 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 and no trial date has been set. 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. Applicants are required to address possible health effects and discuss the consideration of design alternatives with respect to estimates of EMF levels. 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. AEP System operating companies are members of the Electric Power Research Institute (EPRI), an 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 $15,300,000 for 1997, $9,900,000 for 1996 and $9,600,000 for 1995. Total research and development expenditures by AEP and its subsidiaries, including EPRI dues, were approximately $23,600,000 for the year ended December 31, 1997, $16,400,000 for the year ended December 31, 1996 and $13,600,000 for the year ended December 31, 1995. This includes expenditures of $4,600,000 for 1997, $3,300,000 for 1996 and $1,100,000 for 1995 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, 1997, 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 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 overhead 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 Overhead Circuit Miles of Transmission and Circuit Miles of Distribution Lines 765,000-volt Lines AEP System(a) . . . . . 127,864(b) 2,022 APCo . . . . . . . . . 49,534 641 CSPCo(a) . . . . . . . 14,820 -- I&M . . . . . . . . . . 20,855 614 KEPCo . . . . . . . . . 10,136 258 OPCo . . . . . . . . . 29,448 509
__________ (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 26 neighboring electric utility systems. The all-time and 1997 one-hour peak System demands were 25,940,000 and 24,485,000 kilo- watts, respectively (which included 7,314,000 and 4,400,000 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 January 17, 1997, respectively. The net dependable capacity to serve the System load on such date, including power available under contractual obligations, was 23,457,000 and 23,669,000 kilo- watts, respectively. The all-time and 1997 one-hour internal peak demands were 19,557,000 and 19,381,000 kilowatts, respectively, and occurred on February 5, 1996 and January 17, 1997, respectively. The net dependable capacity to serve the System load on such date, including power dedicated under contractual arrangements, was 23,765,000 and 23,669,000 kilowatts, respectively. The all-time one-hour integrated and internal net system peak demands and 1997 peak demands for AEP's generating subsidiaries are shown in the following tabulation:
All-time one-hour integrated 1997 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 8,303 January 17, 1997 CSPCo 4,172 June 17, 1994 3,910 July 2, 1997 I&M 5,027 June 17, 1994 4,681 July 2, 1997 KEPCo 1,711 January 17, 1997 1,711 January 17, 1997 OPCo 7,291 June 17, 1994 6,450 January 17, 1997
All-time one-hour integrated 1997 one-hour integrated net internal peak demand net internal peak demand (in thousands) Number of Number of Kilowatts Date Kilowatts Date APCo 6,903 February 5, 1996 6,857 January 17, 1997 CSPCo 3,378 August 14, 1995 3,354 June 25, 1997 I&M 3,926 July 14, 1997 3,926 July 14, 1997 KEPCo 1,418 February 5, 1996 1,417 January 17, 1997 OPCo 5,641 August 14, 1995 5,519 July 14, 1997
Hydroelectric Plants AEP has 17 facilities, of which 16 are licensed through FERC. 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. The application will be filed in 1998. The license for Mottville expires in 2003. A notice of intent to relicense will be filed in 1998. 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 52.6% during 1997 and 97.6% during 1996. 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 65.1% during 1997 and 87.0% during 1996. The Cook Plant was shut down in September 1997 to respond to issues raised by the NRC. See Cook Plant Shutdown. 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, availability of nuclear waste disposal facilities 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. Cook Plant Shutdown On September 9 and 10, 1997, during a NRC architect engineer design inspection, questions regarding the operability of certain safety systems caused AEP operations personnel to shut down Units 1 and 2 of the Cook Plant. On September 19, 1997, the NRC issued a Confirmatory Action Letter requiring AEP to address the issues identified in the letter. AEP is working with the NRC to resolve these issues and other issues related to restart of the units. Certain issues identified in the letter have been addressed. At this time management is unable to determine when the units will be returned to service. If the units are not returned to service in a reasonable period of time, it could have a materially adverse impact on results of operations and possibly financial condition. 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 $3.0 billion. Coverage is provided by Energy Insurance Bermuda (EIB), Nuclear Mutual Limited (NML) and Nuclear Electric Insurance Limited (NEIL). 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 $20,900,000. 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 decommissioning costs in excess of funds already collected for decommissioning and for property damage up to $3.0 billion less any amounts used for stabilization and decontamination. See Fuel Supply - Nuclear Waste. The NML and NEIL extra-expense programs provide 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 17 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 $7,125,000. 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 opera- tors 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 Com- mission'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. A trial date in late 1998 is anticipated. 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 1, 1998. Name Age Office (a) E. Linn Draper, Jr. 56 Chairman of the Board, President and Chief Executive Officer of AEP and of the Service Corporation Peter J. DeMaria 63 Controller of AEP; Vice Chairman of the Board of the Service Corporation Gerald P. Maloney 64 Vice President and Secretary of AEP; Vice Chairman of the Board of the Service Corporation Paul D. Addis 44 Executive Vice President of the Service Corporation Donald M. Clements, Jr. 48 Executive Vice President-Corporate Development of the Service Corporation Henry Fayne 51 Executive Vice President-Financial Services of the Service Corporation William J. Lhota 58 Executive Vice President of the Service Corporation James J. Markowsky 53 Executive Vice President-Power Generation of the Service Corporation J. H. Vipperman 57 Executive Vice President-Corporate Services 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 for Messrs. Addis and Clements. Prior to joining the Service Corporation in February 1997 in his present position, Mr. Addis was Executive Vice President (1992-1993) and President (1993-January 1997) of Louis Dreyfus Electric Power Inc. and President of Duke/Louis Dreyfus LLC (1995- January 1997). Prior to joining the Service Corporation in 1994 as Senior Vice President-Corporate Development, Mr. Clements was Senior Vice President of External Affairs of Gulf States Utilities Company (1993-1994). 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 1, 1998, 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. 56 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 Peter J. DeMaria 63 Director 1988-Present Vice President 1991-Present Controller 1995-Present Treasurer 1978-1995 Controller of AEP 1995-Present Treasurer of AEP 1978-1995 Vice Chairman of the Board of the Service Corporation 1998-Present Executive Vice President- Administration and Chief Accounting Officer of the Service Corporation 1984-1997 William J. Lhota 58 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 Vice Chairman of the Board of the Service Corporation 1998-Present Executive Vice President- Chief Financial Officer of the Service Corporation 1991-1997 James J. Markowsky 53 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 1, 1998, 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. 56 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 Peter J. DeMaria 63 Director 1978-Present Vice President 1991-Present Controller 1995-Present Treasurer 1978-1995 Controller of AEP 1995-Present Treasurer of AEP 1978-1995 Vice Chairman of the Board of the Service Corporation 1998-Present Executive Vice President- Administration and Chief Accounting Officer of the Service Corporation 1984-1997 William J. Lhota 58 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 Vice Chairman of the Board of the Service Corporation 1998-Present Executive Vice President- Chief Financial Officer of the Service Corporation 1991-1997 James J. Markowsky 53 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 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 March 1997 . . . . . 43-3/16 40 .60 June 1997 . . . . . . 42-1/2 39-1/8 .60 September 1997 . . . 46-5/8 41-1/2 .60 December 1997 . . . . 52 45-1/4 .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, 1997, AEP had approximately 145,000 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 1997 Annual Report (for the fiscal year ended December 31, 1997). APCo. The information required by this item is incorporated herein by reference to the material under Selected Consolidated Financial Data in the APCo 1997 Annual Report (for the fiscal year ended December 31, 1997). 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 1997 Annual Report (for the fiscal year ended December 31, 1997). 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 1997 Annual Report (for the fiscal year ended December 31, 1997). 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 1997 Annual Report (for the fiscal year ended December 31, 1997). 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 1997 Annual Report (for the fiscal year ended December 31, 1997). 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 1997 Annual Report (for the fiscal year ended December 31, 1997). 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 1997 Annual Report (for the fiscal year ended December 31, 1997). 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 1997 Annual Report (for the fiscal year ended December 31, 1997). 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 1997 Annual Report (for the fiscal year ended December 31, 1997). 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 1997 Annual Report (for the fiscal year ended December 31, 1997). Item 7A. Quantitative and Qualitative Disclosures About Market Risk 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 1997 Annual Report (for the fiscal year ended December 31, 1997). AEGCo, APCo, CSPCo, I&M, KEPCo and OPCo. Not applicable. 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 for the 1998 annual meeting of shareholders, to be filed within 120 days after December 31, 1997. 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 1998 annual meeting of stockholders, to be filed within 120 days after December 31, 1997. 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 1, 1998, 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. 56 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 Peter J. DeMaria 63 Director 1992-Present Vice President 1991-Present Controller 1995-Present Treasurer 1978-1995 Controller of AEP 1995-Present Treasurer of AEP 1978-1995 Vice Chairman of the Board of the Service Corporation 1998-Present Executive Vice President- Administration and Chief Accounting Officer of the Service Corporation 1984-1997 William J. Lhota 58 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 1978-Present Vice President 1970-Present Vice President of AEP 1974-Present Secretary of AEP 1994-Present Vice Chairman of the Board of the Service Corporation 1998-Present Executive Vice President- Chief Financial Officer of the Service Corporation 1991-1997 James J. Markowsky 53 Director 1995-Present Vice President 1993-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 J. H. Vipperman 57 Director and Vice President 1996-Present Executive Vice President- Corporate Services of the Service Corporation 1998-Present Executive Vice President- Energy Delivery of the Service Corporation 1996-1998 K. G. Boyd 46 Director 1997-Present Indiana Region Manager 1997-Present Fort Wayne District Manager 1994-1997 C. R. Boyle, III 49 Director and Vice President 1996-Present President and Chief Operating Officer of KEPCo 1990-1995 J. A. Kobyra 45 Director 1998-Present Cook Plant Steam Generator Project Manager 1998-Present D. B. Synowiec 54 Director 1995-Present Plant Manager 1990-Present W. E. Walters 50 Director 1991-Present Michiana Region Manager 1994-Present Executive Assistant to President 1987-1994 E. H. Wittkamper 59 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 CellNet Data Systems, Inc. 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, 1997. 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 Directors Compensation and Stock Ownership Guidelines, Executive Compensation and the performance graph of the definitive proxy statement of AEP for the 1998 annual meeting of shareholders to be filed within 120 days after December 31, 1997. 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 1998 annual meeting of stockholders, to be filed within 120 days after December 31, 1997. 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 1998 annual meeting of shareholders, to be filed within 120 days after December 31, 1997. 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 1997, 1996 and 1995 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, 1997.
Summary Compensation Table Long-Term Annual Compensation Compensation Payouts All Other Salary Bonus Compensation Name and Principal Position Year ($) ($)(1) LTIP Payouts($)(1) ($)(2) E. Linn Draper, Jr. - 1997 720,000 327,744 951,132 31,620 Chairman of the board and 1996 720,000 281,664 675,903 31,990 chief executive officer of 1995 685,000 236,325 334,851 30,790 the Company; chairman of the board, president and chief executive officer of AEP and the Service Corporation; chairman of the board and chief executive officer of other AEP System companies Peter J. DeMaria - Vice 1997 385,000 153,345 391,793 21,570 president, controller and 1996 360,000 140,832 290,825 21,190 director of the Company; 1995 330,000 113,850 143,829 20,050 controller and director of AEP; vice chairman and director of the Service Corporation; vice president, controller and director of other AEP System companies G. P. Maloney - Vice 1997 385,000 153,345 391,793 21,570 president and director of the 1996 360,000 140,832 286,288 21,190 Company; vice president, 1995 330,000 113,850 141,582 20,060 secretary and director of AEP; vice chairman and director of the Service Corporation; vice president and director of other AEP System companies William J. Lhota - President, 1997 355,000 141,396 364,436 20,570 chief operating officer and 1996 320,000 125,184 263,114 19,690 director of the Company; 1995 300,000 103,500 132,592 19,140 executive vice president and director of the Service Corporation; president, chief operating officer and director of other AEP System companies James J. Markowsky - Vice 1997 325,000 129,447 338,382 18,020 president and director of the 1996 303,000 118,534 254,535 19,480 Company; executive vice 1995 285,000 98,325 126,599 17,515 president-power generation and director of the Service Corporation; vice president and director of other AEP System companies
___________ (1) Amounts in the "Bonus" column reflect payments under the Senior Officer Annual Incentive Compensation Plan (and predecessor Management Incentive Compensation Plan) for performance measured for each of the years ended December 31, 1995, 1996 and 1997. Payments are made in March of the subsequent year. Amounts for 1997 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 two-, three- and three-year performance periods ending December 31, 1995, 1996 and 1997, respectively. The two-year performance period was a transition performance period. See below under "Long-Term Incentive Plans - Awards in 1997" and page 10 for additional information. (2) For 1997, includes (i) employer matching contributions under the AEP System Employees Savings Plan: Dr. Draper, $3,400; Mr. DeMaria, $3,306; Mr. Maloney, $4,800; Mr. Lhota, $4,800; and Dr. Markowsky, $3,250; (ii) employer matching contributions under the AEP System Supplemental Savings Plan, a non-qualified plan designed to supplement the AEP Savings Plan: Dr. Draper, $18,200; Mr. DeMaria, $8,244; Mr. Maloney, $6,750; Mr. Lhota, $5,850; and Dr. Markowsky, $6,500; and (iii) subsidiary companies director fees: Dr. Draper and Messrs. DeMaria and Maloney, $10,020; Mr. Lhota, $9,920; and Dr. Markowsky, $8,270. Long-Term Incentive Plans - Awards In 1997 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 Non-Stock Price-Based Plan Performance Number of Period Until Performance Maturation Threshold Target Maximum Name Share Units or Payout (#) (#) (#) E. L. Draper, Jr. 7,111 1997-1999 1,778 7,111 14,222 P. J. DeMaria 3,327 1997-1999 832 3,327 6,654 G. P. Maloney 3,327 1997-1999 832 3,327 6,654 W. J. Lhota 3,068 1997-1999 767 3,068 6,136 J. J. Markowsky 2,809 1997-1999 702 2,809 5,618
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 $ 400,000 $ 93,660 $124,880 $156,100 $187,320 $218,540 $245,140 $271,740 500,000 117,660 156,880 196,100 235,320 274,540 307,790 341,040 600,000 141,660 188,880 236,110 283,320 330,540 370,440 410,340 700,000 165,660 220,880 276,100 331,320 386,540 433,090 479,640 900,000 213,660 284,880 356,100 427,320 498,540 588,390 618,240 1,100,000 261,660 348,880 436,100 523,320 610,540 683,390 756,840 1,300,000 309,660 412,880 516,100 619,320 722,540 808,990 895,440
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, 1997, the number of full years of service applicable for retirement benefit calculation purposes for such officers were as follows: Dr. Draper, five years; Mr. DeMaria, 38 years; Mr. Maloney, 42 years; Mr. Lhota, 33 years; and Dr. Markowsky, 26 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 1998 of the executive officers named in the Summary Compensation Table, only Messrs. DeMaria and Maloney would be affected and their annual supplemental benefit would be $491 and $3,847, respectively. 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 par- ticipant 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 payments commencing at age 65, annual supplemental retirement payments under the 1982 and 1986 programs.
1982 Program 1986 Program Annual Amount Annual Amount of of Annual Supplemental Annual Supplemental Amount Retirement Amount Retirement Deferred Payment Deferred Payment (4-Year (15-Year (4-Year (15-Year Name Period) Period) Period) 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 for the 1998 annual meeting of shareholders to be filed within 120 days after December 31, 1997. 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 1998 annual meeting of stockholders, to be filed within 120 days after December 31, 1997. 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, 1998, 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 Karl G. Boyd . . . . . . 1,534(b) 81 1,615 Coulter R. Boyle, III . . 3,702(b) 745 4,447 Gregory A. Clark . . . . 1,066(b) 106 1,172 P. J. DeMaria . . . . . . 7,754(b)(c)(d)(e) 15,932 23,686 E. L. Draper, Jr. . . . . 7,373(b)(d) 62,857 70,230 James A. Kobyra . . . . . 3,188(b)(d) 520 3,708 W. J. Lhota . . . . . . . 15,056(b)(c)(d) 14,827 29,883 G. P. Maloney . . . . . . 5,803(b)(c)(d) 12,715 18,518 J. J. Markowsky . . . . . 5,126(b)(e) 12,417 17,543 David B. Synowiec . . . . 993(b) 124 1,117 J. H. Vipperman . . . . . 5,837(b)(d) 7,676 13,513 William E. Walters . . . 5,655(b) 317 5,972 Earl H. Wittkamper . . . 2,983(b) 315 3,298 All directors and executive officers . . . 151,301(d)(f) 128,632 279,933
(a) This column includes amounts deferred in stock units and held under the Management Incentive Compensation Plan, Senior Officer Annual Incentive Compensation Plan and Performance Share Incentive Plan. (b) Includes share equivalents held in the AEP Employees Savings Plan in the amounts listed below: AEP Employees Savings Plan (Share Equivalents) Mr. Boyd 1,524 Mr. Boyle 3,702 Mr. Clark 1,066 Mr. DeMaria 3,187 Dr. Draper 2,716 Mr. Kobyra 2,380 Mr. Lhota 12,876 Mr. Maloney 3,436 Dr. Markowsky 5,074 Mr. Synowiec 993 Mr. Vipperman 5,142 Mr. Walters 5,655 Mr. Wittkamper 1,653 All Directors and Executive Officers 49,404 With respect to the share equivalents held in the AEP Employees Savings Plan, such persons have sole voting power, but the investment/disposition power is subject to the terms of the Plan. (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, 462; Dr. Draper, 2,200; Mr. Kobyra, 808; Mr. Lhota, 2,180; Mr. Maloney, 2,367; and Mr. Vipperman, 64. (e) Includes the following numbers of shares held by family members over which beneficial ownership is disclaimed: Mr. DeMaria, 3,192; and Dr. Markowsky, 19. (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 1998 annual meeting of shareholders, to be filed within 120 days after December 31, 1997. 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, 1997, 1996 and 1995; Statements of Retained Earnings for the years ended December 31, 1997, 1996 and 1995; Statements of Cash Flows for the years ended December 31, 1997, 1996 and 1995; Balance Sheets as of December 31, 1997 and 1996; Notes to Financial Statements. AEP and its subsidiaries consolidated: Consolidated Statements of Income for the years ended December 31, 1997, 1996 and 1995; Consolidated Statements of Retained Earnings for the years ended December 31, 1997, 1996 and 1995; Consolidated Balance Sheets as of December 31, 1997 and 1996; Consolidated Statements of Cash Flows for the years ended December 31, 1997, 1996 and 1995; Notes to Consolidated Financial Statements; Schedule of Consolidated Cumulative Preferred Stocks of Subsidiaries at December 31, 1997 and 1996; Schedule of Consolidated Long-term Debt of Subsidiaries at December 31, 1997 and 1996; Independent Auditors' Report. APCo: Consolidated Statements of Income for the years ended December 31, 1997, 1996 and 1995; Consolidated Balance Sheets as of December 31, 1997 and 1996; Consolidated Statements of Cash Flows for the years ended December 31, 1997, 1996 and 1995; Consolidated Statements of Retained Earnings for the years ended December 31, 1997, 1996 and 1995; Notes to Consolidated Financial Statements; Independent Auditors' Report. CSPCo: Independent Auditors' Report; Consolidated Statements of Income for the years ended December 31, 1997, 1996 and 1995; Consolidated Balance Sheets as of December 31, 1997 and 1996; Consolidated Statements of Cash Flows for the years ended December 31, 1997, 1996 and 1995; Consolidated Statements of Retained Earnings for the years ended December 31, 1997, 1996 and 1995; Notes to Consolidated Financial Statements. I&M: Independent Auditors' Report; Consolidated Statements of Income for the years ended December 31, 1997, 1996 and 1995; Consolidated Statements of Cash Flows for the years ended December 31, 1997, 1996 and 1995; Consolidated Balance Sheets as of December 31, 1997 and 1996; Consolidated Statements of Retained Earnings for the years ended December 31, 1997, 1996 and 1995; Notes to Consolidated Financial Statements. KEPCo: Independent Auditors' Report; Statements of Income for the years ended December 31, 1997, 1996 and 1995; Statements of Retained Earnings for the years ended December 31, 1997, 1996 and 1995; Balance Sheets as of December 31, 1997 and 1996; Statements of Cash Flows for the years ended December 31, 1997, 1996 and 1995; Notes to Financial Statements. OPCo: Independent Auditors' Report; Consolidated Statements of Income for the years ended December 31, 1997, 1996 and 1995; Consolidated Statements of Cash Flows for the years ended December 31, 1997, 1996 and 1995; Consolidated Balance Sheets as of December 31, 1997 and 1996; Consolidated Statements of Retained Earnings for the years ended December 31, 1997, 1996 and 1995; 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) Reports on Form 8-K: Company Reporting Date of Report Items Reported AEGCo, AEP, APCo, CSPCo, I&M, KEPCo and OPCo December 21, 1997 Item 5. Other Events Item 7. Financial Statements and Exhibits 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 16, 1998 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: *E. Linn Draper, Jr. President, Chief Executive Officer and Director (ii) Principal Financial Officer: __/s/ G. P. Maloney__ Vice President March 16, 1998 (G. P. Maloney) and Director (iii) Principal Accounting Officer: __/s/ P. J. DeMaria__ Vice President, Controller March 16, 1998 (P. J. DeMaria) and Director (iv) A Majority of the Directors: *Henry Fayne *John R. Jones, III *Wm. J. Lhota *James J. Markowsky *By:__/s/ G. P. Maloney__ March 16, 1998 (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. AMERICAN ELECTRIC POWER COMPANY, INC. By:__/s/ G. P. Maloney__ (G. P. Maloney, Vice President) Date: March 16, 1998 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: *E. Linn Draper, Jr. Chairman of the Board, President, Chief Executive Officer and Director (ii) Principal Financial Officer: __/s/ G. P. Maloney__ Vice President, Secretary March 16, 1998 (G. P. Maloney) and Director (iii) Principal Accounting Officer: __/s/ P. J. DeMaria__ Controller and Director March 16, 1998 (P. J. DeMaria) (iv) A Majority of the Directors: *John P. DesBarres *Robert M. Duncan *Robert W. Fri *Lester A. Hudson, Jr. *Leonard J. Kujawa *Angus E. Peyton *Donald G. Smith *Linda Gillespie Stuntz *Kathryn D. Sullivan *Morris Tanenbaum *By:__/s/ G. P. Maloney__ March 16, 1998 (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 16, 1998 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: *E. Linn Draper, Jr. Chairman of the Board, Chief Executive Officer and Director (ii) Principal Financial Officer: __/s/ G. P. Maloney__ Vice President March 16, 1998 (G. P. Maloney) and Director (iii) Principal Accounting Officer: __/s/ P. J. DeMaria__ Vice President, Controller March 16, 1998 (P. J. DeMaria) and Director (iv) A Majority of the Directors: *Henry Fayne *Wm. J. Lhota *James J. Markowsky *J. H. Vipperman *By:__/s/ G. P. Maloney__ March 16, 1998 (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 16, 1998 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: *E. Linn Draper, Jr. Chairman of the Board, Chief Executive Officer and Director (ii) Principal Financial Officer: __/s/ G. P. Maloney__ Vice President March 16, 1998 (G. P. Maloney) and Director (iii) Principal Accounting Officer: __/s/ P. J. DeMaria__ Vice President, Controller March 16, 1998 (P. J. DeMaria) and Director (iv) A Majority of the Directors: *Henry Fayne *Wm. J. Lhota *James J. Markowsky *J. H. Vipperman *By:__/s/ G. P. Maloney__ March 16, 1998 (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 16, 1998 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: *E. Linn Draper, Jr. Chairman of the Board, Chief Executive Officer and Director (ii) Principal Financial Officer: __/s/ G. P. Maloney__ Vice President March 16, 1998 (G. P. Maloney) and Director (iii) Principal Accounting Officer: __/s/ P. J. DeMaria__ Vice President, Controller March 16, 1998 (P. J. DeMaria) and Director (iv) A Majority of the Directors: *K. G. Boyd *C. R. Boyle, III *G. A. Clark *James A. Kobyra *Wm. J. Lhota *James J. Markowsky *D. B. Synowiec *J. H. Vipperman *W. E. Walters *E. H. Wittkamper *By:__/s/ G. P. Maloney__ March 16, 1998 (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 16, 1998 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: *E. Linn Draper, Jr. Chairman of the Board, Chief Executive Officer and Director (ii) Principal Financial Officer: __/s/ G. P. Maloney__ Vice President March 16, 1998 (G. P. Maloney) and Director (iii) Principal Accounting Officer: __/s/ P. J. DeMaria__ Vice President, Controller March 16, 1998 (P. J. DeMaria) and Director (iv) A Majority of the Directors: *Henry Fayne *Wm. J. Lhota *James J. Markowsky *J. H. Vipperman *By:__/s/ G. P. Maloney__ March 16, 1998 (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 16, 1998 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: *E. Linn Draper, Jr. Chairman of the Board, Chief Executive Officer and Director (ii) Principal Financial Officer: __/s/ G. P. Maloney__ Vice President March 16, 1998 (G. P. Maloney) and Director (iii) Principal Accounting Officer: __/s/ P. J. DeMaria__ Vice President, Controller March 16, 1998 (P. J. DeMaria) and Director (iv) A Majority of the Directors: *Henry Fayne *Wm. J. Lhota *James J. Markowsky *J. H. Vipperman *By:__/s/ G. P. Maloney__ March 16, 1998 (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, 1997, 1996 and 1995 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, 1997 and 1996, and for each of the three years in the period ended December 31, 1997, and have issued our reports thereon dated February 24, 1998; such financial statements and reports are included in your respective 1997 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 24, 1998 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 at Charged to Charged to Balance at Beginning Costs 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, 1997 . . $3,692 $20,650 $ 8,953(a) $26,535(b) $6,760 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
(a) Recoveries on accounts previously written off. (b) Uncollectible accounts written off. APPALACHIAN POWER COMPANY AND SUBSIDIARY COMPANIES SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
Column A COLUMN B COLUMN C COLUMN D COLUMN E Additions Balance at Charged to Charged to Balance at Beginning Costs 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, 1997 . . $ 687 $ 3,621 $ 666(a) $ 3,641(b) $1,333 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
(a) Recoveries on accounts previously written off. (b) Uncollectible accounts written off. COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
Column A COLUMN B COLUMN C COLUMN D COLUMN E Additions Balance at Charged to Charged to Balance at Beginning Costs 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, 1997 . . $1,032 $ 6,815 $ 6,380(a) $13,169(b) $1,058 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
(a) Recoveries on accounts previously written off. (b) Uncollectible accounts written off. INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARY COMPANIES SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
Column A COLUMN B COLUMN C COLUMN D COLUMN E Additions Balance at Charged to Charged to Balance at Beginning Costs 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, 1997 . . $ 156 $ 4,411 $ 798(a) $ 4,177(b) $1,188 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
(a) Recoveries on accounts previously written off. (b) Uncollectible accounts written off. KENTUCKY POWER COMPANY AND SUBSIDIARY COMPANIES SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
Column A COLUMN B COLUMN C COLUMN D COLUMN E Additions Balance at Charged to Charged to Balance at Beginning Costs 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, 1997 . . $ 272 $ 1,482 $ 347(a) $ 1,576(b) $ 525 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
(a) Recoveries on accounts previously written off. (b) Uncollectible accounts written off. OHIO POWER COMPANY AND SUBSIDIARY COMPANIES SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
Column A COLUMN B COLUMN C COLUMN D COLUMN E Additions Balance at Charged to Charged to Balance at Beginning Costs 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, 1997 . . $1,433 $ 4,008 $ 675(a) $ 3,615(b) $2,501 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
(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. Sections 229.10(d) and 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 1997 Annual Report (for the fiscal year ended December 31, 1997) 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 October 29, 1997 [Quarterly Report on Form 10-Q of AEP for the quarter ended September 30, 1997, Exhibit 3(a)]. * 3(b) Copy of By-Laws of AEP, as amended through January 28, 1998. 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) 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(d) 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(e) 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(f) Agreement and Plan of Merger, dated as of December 21, 1997, By and Among American Electric Power Company, Inc., Augusta Acquisition Corporation and Central and South West Corporation. !10(g)(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(g)(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(h) 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(i)(1) AEP Deferred Compensation and Stock Plan for Non-Employee Directors [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(f)(1)]. !10(i)(2) AEP Stock Unit Accumulation Plan for Non-Employee Directors [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(f)(2)]. !10(j)(1)(A) AEP Excess Benefit Plan, as amended through August 25, 1997 [Quarterly Report on Form 10-Q of AEP for the quarter ended September 30, 1997, File No. 1-3525, Exhibit 10]. !10(j)(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(j)(2) AEP System Supplemental Savings Plan, as amended through November 15, 1995 (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(j)(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(k) 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(l)(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(l)(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)]. * 13 Copy of those portions of the AEP 1997 Annual Report (for the fiscal year ended December 31, 1997) 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 [Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1996, File No. 1-3457, Exhibit 3(c)]. 3(d) Composite copy of the Restated Articles of Incorporation of APCo (amended as of March 7, 1997) [Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1996, File No. 1-3457, Exhibit 3(d)]. 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); Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1996, File No. 1-3457, Exhibit 4(b)]. * 4(b) Copy of Indenture Supplemental, dated as of May 1, 1997, to Mortgage and Deed of Trust. 4(c) Indenture (for unsecured debt securities), dated as of January 1, 1998, between APCo and The Bank of New York, As Trustee [Registration Statement No. 333-45927, Exhibits 4(a) and 4(b)]. * 4(d) Company Order and Officers' Certificate, dated March 3, 1998, establishing certain terms of the 7.20% Senior Notes, Series A, due 2038. 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) Agreement and Plan of Merger, dated as of December 21, 1997, By and Among American Electric Power Company, Inc., Augusta Acquisition Corporation and Central and South West Corporation [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1997, File No. 1-3525, 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 [Quarterly Report on Form 10-Q of AEP for the quarter ended September 30, 1997, File No. 1-3525, Exhibit 10]. !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) 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 1997 Annual Report (for the fiscal year ended December 31, 1997) 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, 1997, 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)]. * 4(b) Copy of Indenture (for unsecured debt securities), dated as of September 1, 1997, between CSPCo and Bankers Trust Company, as Trustee. * 4(c) Copy of Company Order and Officers' Certificate, dated September 29, 1997, establishing certain terms of the Unsecured Medium Term Notes, Series A. * 4(d) Copy of Instructions, dated September 30, 1997, from CSPCo to Bankers Trust Company, establishing certain terms of the 6.85% Unsecured Medium Term Notes, Series A, due 2005. * 4(e) Copy of Instructions, dated February 5, 1998, from CSPCo to Bankers Trust Company, establishing certain terms of the 6.51% Unsecured Medium Term Notes, Series A, due 2008. 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)]. 10(e) Agreement and Plan of Merger, dated as of December 21, 1997, By and Among American Electric Power Company, Inc., Augusta Acquisition Corporation and Central and South West Corporation [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1997, File No. 1-3525, Exhibit 10(f)]. * 12 Statement re: Computation of Ratios. * 13 Copy of those portions of the CSPCo 1997 Annual Report (for the fiscal year ended December 31, 1997) 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 [Annual Report on Form 10-K of I&M for fiscal year ended December 31, 1996, File No. 1-3570, Exhibit 3(b)]. 3(c) Composite Copy of the Amended Articles of Acceptance of I&M (amended as of March 7, 1997) [Annual Report on Form 10-K of I&M for fiscal year ended December 31, 1996, File No. 1- 3570, Exhibit 3(c)]. 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); Annual Report on Form 10-K of I&M for fiscal year ended December 31, 1996, File No. 1-3570, 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); 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(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)]. 10(g) Agreement and Plan of Merger, dated as of December 21, 1997, By and Among American Electric Power Company, Inc., Augusta Acquisition Corporation and Central and South West Corporation [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1997, File No. 1-3525, Exhibit 10(f)]. * 12 Statement re: Computation of Ratios * 13 Copy of those portions of the I&M 1997 Annual Report (for the fiscal year ended December 31, 1997) 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, 1997, 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)]. * 4(b) Copy of Indenture (for unsecured debt securities), dated as of September 1, 1997, between KEPCo and Bankers Trust Company, as Trustee. * 4(c) Copy of Company Order and Officers' Certificate, dated September 24, 1997, establishing certain terms of the Unsecured Medium Term Notes, Series A. * 4(d) Copy of Instructions, dated September 26, 1997, from KEPCo to Bankers Trust Company, establishing certain terms of the 6.91% Unsecured Medium Term Notes, Series A, due 2007. 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)]. 10(d) Agreement and Plan of Merger, dated as of December 21, 1997, By and Among American Electric Power Company, Inc., Augusta Acquisition Corporation and Central and South West Corporation [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1997, File No. 1-3525, Exhibit 10(f)]. * 12 Statement re: Computation of Ratios. * 13 Copy those portions of the KEPCo 1997 Annual Report (for the fiscal year ended December 31, 1997) 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 [Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1996, File No. 1-6543, Exhibit 3(c)]. 3(d) Composite copy of the Amended Articles of Incorporation of OPCo (amended as of March 7, 1997) [Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1996, File No. 1-6543, Exhibit 3(d)]. 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)]. * 4(b) Copy of Indenture (for unsecured debt securities), dated as of September 1, 1997, between OPCo and Bankers Trust Company, as Trustee. * 4(c) Copy of Company Order and Officers' Certificate, dated September 24, 1997, establishing certain terms of the Unsecured Medium Term Notes, Series A. * 4(d) Copy of Instructions, dated September 25, 1997, from OPCo to Bankers Trust Company, establishing certain terms of the 6.73% Unsecured Medium Term Notes, Series A, due 2004. 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) 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(g) Agreement and Plan of Merger, dated as of December 21, 1997, By and Among American Electric Power Company, Inc., Augusta Acquisition Corporation and Central and South West Corporation [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1997, File No. 1-3525, Exhibit 10(f)]. !10(h)(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(h)(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(i)(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(i)(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(j)(1) Excess Benefits Plan [Quarterly Report on Form 10-Q of AEP for the quarter ended September 30, 1997, File No. 1-3525, Exhibit 10]. !10(j)(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(j)(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(k) 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 OPCo 1997 Annual Report (for the fiscal year ended December 31, 1997) 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, 1997, 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-4 2 EX-4B APCO INDENTURE SUPPLEMENTAL 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 May 1, 1997 $48,000,000 First Mortgage Bonds, Designated Secured Medium Term Notes, 6.71% Series due June 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 62nd Series . . 3 Second 1997 Supplemental Indenture. . . . . . . . . . . . 3 Compliance with legal requirements . . . . . . . . . . . 3 GRANTING CLAUSES. . . . . . . . . . . . . . . . . . . . . . . 3 DESCRIPTION OF PROPERTY . . . . . . . . . . . . . . . . . . . 4 APPURTENANCES, ETC. . . . . . . . . . . . . . . . . . . . . . 4 HABENDUM. . . . . . . . . . . . . . . . . . . . . . . . . . . 5 PRIOR LEASEHOLD ENCUMBRANCES. . . . . . . . . . . . . . . . . 5 GRANT IN TRUST. . . . . . . . . . . . . . . . . . . . . . . . 6 SECTION 1. Supplement to Original Indenture by adding Section 20III. . . . . . . . . . . . . . . . . 7 SECTION 2. Initial Issuance of the Bonds of the 62nd Series. 10 SECTION 3. Provision for record date for meetings of Bondholders . . . . . . . . . . . . . . . . 10 SECTION 4. Original Indenture and Second 1997 Supplemental Indenture same instrument. . . . . . . . . . . 10 SECTION 5. Limitation of rights. . . . . . . . . . . . . . . 10 SECTION 6. 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 May 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, March 1, 1996 and February 1, 1997 (hereinafter referred to as the "First 1997 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, 6.35% Series due 2000. . . 48,000,000 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, 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, 6.71% Series due June 1, 2000" (hereinafter sometimes referred to as the "bonds of the 62nd Series"); and WHEREAS, each of the bonds of the 62nd Series is to be substantially in the form set forth in Schedule I to this Supplemental Indenture (hereinafter sometimes referred to as the "Second 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 Second 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 Second 1997 Supplemental Indenture, according to their tenor and effect, and the performance of all the provisions of the Original Indenture and this Second 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 1997 Supplemental Indenture (except any hereinafter expressly excepted from the lien and operation of this Second 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 Second 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 Second 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 Second 1997 Supplemental Indenture is executed and delivered, that the lien of this Second 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 Second 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 Second 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 Second 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 Second 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 Second 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 Second 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 Second 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. The Original Indenture is hereby supplemented by adding immediately after Section 20HHH, a new Section 20III, as follows: SECTION 20III. The Company hereby creates a sixty- second 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, 6.71% Series due June 1, 2000" (herein sometimes referred to as the "bonds of the 62nd Series"). The form of the bonds of the 62nd Series shall be substantially as set forth in Schedule I to the Second 1997 Supplemental Indenture. Bonds of the 62nd Series shall mature on the date specified in their title. Unless otherwise determined by the Company, the bonds of the 62nd 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 October 1, 1997) and on their maturity date. The person in whose name any bond of the 62nd 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 62nd 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 62nd 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 62nd Series shall be the registered owners of such bonds of the 62nd 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 20III, and in the form of the bonds of the 62nd Series, with respect to any regular semi-annual interest payment date applicable to the bonds of the 62nd 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 62nd 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 62nd Series are authorized or required by law, regulation or executive order to remain closed. Every registered bond of the 62nd 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 62nd 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 62nd 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 62nd 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 62nd 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 62nd Series. The bonds of the 62nd 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 62nd Series for a period of fifteen days next preceding any interest payment date. Registered bonds of the 62nd 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 62nd Series may be exchanged for a like aggregate principal amount of registered bonds of the 62nd 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 2. Initial Issuance of the Bonds of the 62nd 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 62nd 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 Second 1997 Supplemental Indenture except to the extent required by subdivision (10) of Section 29 of the Original Indenture). Section 3. At any meeting of bondholders held as provided for in Article XX of the Original Indenture at which owners of bonds of the 62nd Series are entitled to vote, all owners of bonds of the 62nd 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 62nd 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 62nd 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 62nd Series at the meeting, shall be entitled to receive notice of such meeting. Section 4. As supplemented by this Second 1997 Supplemental Indenture, the Original Indenture is in all respects ratified and confirmed and the Original Indenture and this Second 1997 Supplemental Indenture shall be read, taken and construed as one and the same instrument. The bonds of the 62nd Series are the original debt secured by this Second 1997 Supplemental Indenture and the Original Indenture, and this Second 1997 Supplemental Indenture and the Original Indenture shall be, and shall be deemed to be, the original lien instrument securing the bonds of the 62nd Series. Section 5. Nothing contained in this Second 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 Second 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 Second 1997 Supplemental Indenture. Section 6. This Second 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/ B. M. Barber B. M. Barber Assistant Treasurer Attest: /s/ John M. Adams, Jr. John M. Adams, Jr. Assistant Secretary In the presence of: /s/ David C. House David C. House /s/ Ann B. Graf Ann B. Graf 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 14th day of May, 1997, personally appeared before me, a Notary Public within and for said County in the State aforesaid, B. M. BARBER and JOHN M. ADAMS, JR., to me known and known to me to be respectively an Assistant 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 Assistant Treasurer and Assistant Secretary for and on behalf of said corporation and that the same is their free act and deed as such Assistant 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 14th day of May, 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 15th day of May, 1997: JAMES MC DONOUGH and SCOTT THIEL, whose names are signed to the writing above, bearing a date as of the 1st day of May, 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 May, 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 15th day of May, 1997. /s/ Patricia M. Carillo PATRICIA M. CARILLO Notary Public, State of New York No. 41-4747732 Qualified in Queens County Certificate filed in New York County Commission expires May 31, 1997 [SEAL] The foregoing instrument was prepared by David C. House, 1 Riverside Plaza, Columbus, Ohio 43215. SCHEDULE I APPALACHIAN POWER COMPANY FIRST MORTGAGE BOND, DESIGNATED SECURED MEDIUM TERM NOTE, 6.71% SERIES DUE JUNE 1, 2000 Bond No. Original Issue Date: May 27, 1997 Principal Amount: Semi-annual Interest Payment Dates: April 1 and October 1 Record Dates: March 15 and September 15 CUSIP No: 03774B AY9 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 October 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, 6.71% Series due June 1, 2000 (herein called "bonds of the 62nd Series") created by an Indenture Supplemental to Mortgage and Deed of Trust dated as of May 1, 1997 (the "Second 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 Second 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 62nd 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 62nd Series for a period of fifteen days next preceding any interest payment date. The Bonds of the 62nd 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 62nd 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-4 3 EX-4D APCO ORDER & CERTIFICATE 3/13/98 Exhibit 4(d) March 3, 1998 Company Order and Officers' Certificate Senior Notes, Series A The Bank of New York, as Trustee 101 Barclay Street New York, New York 10286 Attn: Corporate Trust Division Ladies and Gentlemen: Pursuant to Article Two of the Indenture, dated as of January 1, 1998 (as it may be amended or supplemented, the "Indenture"), from Appalachian Power Company (the "Company") to The Bank of New York, as trustee (the "Trustee"), and the Board Resolutions dated December 17, 1997, a copy of which certified by the Secretary or an Assistant Secretary of the Company is being delivered herewith under Section 2.01 of the Indenture, and unless otherwise provided in a subsequent Company Order pursuant to Section 2.04 of the Indenture, 1. The Company's Senior Notes, Series A, Due 2038 (the "Notes") are hereby established. The Notes shall be in substantially the form attached hereto as Exhibit 1. 2. The terms and characteristics of the Notes shall be as follows (the numbered clauses set forth below corresponding to the numbered subsections of Section 2.01 of the Indenture, with terms used and not defined herein having the meanings specified in the Indenture): (i) the aggregate principal amount of Notes which may be authenticated and delivered under the Indenture shall be limited to $100,000,000, except as contemplated in Section 2.01(i) of the Indenture; (ii) the date on which the principal of the Notes shall be payable shall be March 31, 2038; (iii) interest shall accrue from the date of authentication of the Notes; the Interest Payment Dates on which such interest will be payable shall be March 31, June 30, September 30 and December 31, and the Regular Record Date for the determination of holders to whom interest is payable on any such Interest Payment Date shall be the March 15, June 15, September 15 or December 15, as the case may be, next preceding such Interest Payment Date; provided however that if the Original Issue Date of a Note shall be after a Regular Record Date and before the corresponding Interest Payment Date, payment of interest shall commence on the second Interest Payment Date succeeding such Original Issue Date and shall be paid to the Person in whose name this Note was registered on the Regular Record Date for such second Interest Payment Date; and provided further, that interest payable on the Stated Maturity Date or any Redemption Date shall be paid to the Person to whom principal shall be paid; (iv) the interest rate at which the Notes shall bear interest shall be 7.20% per annum; (v) the Notes shall be redeemable at the option of the Company, in whole or in part, at any time on or after March 3, 2003, upon not less than 30 nor more than 60 days' notice, at 100% of the principal amount redeemed together with accrued and unpaid interest to the redemption date; (vi) (a) the Notes shall be issued in the form of a Global Note; (b) the Depositary for such Global Note shall be The Depository Trust Company; and (c) the procedures with respect to transfer and exchange of Global Notes shall be as set forth in the form of Note attached hereto; (vii) the title of the Notes shall be "Senior Notes, Series A, Due 2038"; (viii) the form of the Notes shall be as set forth in Paragraph 1 above; (ix) not applicable; (x) the Notes shall not be subject to a Periodic Offering; (xi) not applicable; (xii) not applicable; (xiii) not applicable; (xiv) the Notes shall be issuable in denominations of $25 and any integral multiple thereof; (xv) not applicable; (xvi) the Notes shall not be issued as Discount Securities; (xvii) not applicable; (xviii) not applicable; and (xix) not applicable. 3. You are hereby requested to authenticate $100,000,000 aggregate principal amount of 7.20% Senior Notes, Series A, Due 2038 in such name as requested by The Depository Trust Company ("DTC") in the Letter of Representations dated March 3, 1998, from the Company and the Trustee to DTC in the manner provided by the Indenture. 4. You are hereby requested to hold the Notes as custodian for DTC in accordance with the Letter of Representations. 5. Concurrently with this Company Order, an Opinion of Counsel under Sections 2.04 and 13.06 of the Indenture is being delivered to you. 6. The undersigned Armando A. Pena and John F. Di Lorenzo, Jr., the Treasurer and Secretary, respectively, of the Company do hereby certify that: (i) we have read the relevant portions of the Indenture, including without limitation the conditions precedent provided for therein relating to the action proposed to be taken by the Trustee as requested in this Company Order and Officers' Certificate, and the definitions in the Indenture relating thereto; (ii) we have read the Board Resolutions of the Company and the Opinion of Counsel referred to above; (iii) we have conferred with other officers of the Company, have examined such records of the Company and have made such other investigation as we deemed relevant for purposes of this certificate; (iv) in our opinion, we have made such examination or investigation as is necessary to enable us to express an informed opinion as to whether or not such conditions have been complied with; and (v) on the basis of the foregoing, we are of the opinion that all conditions precedent provided for in the Indenture relating to the action proposed to be taken by the Trustee as requested herein have been complied with. Kindly acknowledge receipt of this Company Order and Officers' Certificate, including the documents listed herein, and confirm the arrangements set forth herein by signing and returning the copy of this document attached hereto. Very truly yours, APPALACHIAN POWER COMPANY By:/s/ A. A. Pena______________ Treasurer And:/s/ John F. Di Lorenzo, Jr. Secretary Acknowledged by Trustee: By:/s/ Michael Culhane_________ Vice President Exhibit 1 Unless this certificate is presented by an authorized representa- tive of The Depository Trust Company (55 Water Street, New York, New York) to the issuer or its agent for registration of transfer, exchange or payment, and any certificate to be issued is registered in the name of Cede & Co. or in such other name as is requested by an authorized representative of The Depository Trust Company and any payment is made to Cede & Co., ANY TRANSFER, PLEDGE OR OTHER USE HEREOF FOR VALUE OR OTHERWISE BY OR TO ANY PERSON IS WRONGFUL inasmuch as the registered owner hereof, Cede & Co., has an interest herein. Except as otherwise provided in Section 2.11 of the Indenture, this Security may be transferred, in whole but not in part, only to another nominee of the Depository or to a successor Depository or to a nominee of such successor Depository. No. R-1 4,000,000 Senior Notes, $25 principal amount each APPALACHIAN POWER COMPANY 7.20% Senior Notes, Series A, Due 2038 CUSIP: 037735 79 2 Original Issue Date: March 3, 1998 Stated Maturity Date: March 31, 2038 Interest Rate: 7.20% Principal Amount: $100,000,000 Redeemable: Yes X No ____ In Whole: Yes X No ____ In Part: Yes X No ____ Initial Redemption Date: March 3, 2003 Redemption Limitation Date: N/A Initial Redemption Price: 100% Reduction Percentage: N/A APPALACHIAN POWER COMPANY, a corporation duly organized and existing under the laws of the Commonwealth of Virginia (herein referred to as the "Company", which term includes any successor corporation under the Indenture hereinafter referred to), for value received, hereby promises to pay to CEDE & CO. or registered assigns, the Principal Amount specified above on the Stated Maturity Date specified above, and to pay interest on said Prin- cipal Amount from the Original Issue Date specified above or from the most recent interest payment date (each such date, an "Interest Payment Date") to which interest has been paid or duly provided for, quarterly in arrears on March 31, June 30, September 30 and December 31 in each year, commencing (except as provided below) with the Interest Payment Date next succeeding the Original Issue Date specified above, at the Interest Rate per annum specified above, until the Principal Amount shall have been paid or duly provided for. Interest shall be computed on the basis of a 360-day year of twelve 30-day months. The interest so payable, and punctually paid or duly provided for, on any Interest Payment Date, as provided in the Indenture, as hereinafter defined, shall be paid to the Person in whose name this Note (or one or more Predecessor Securities) shall have been registered at the close of business on the Regular Record Date with respect to such Interest Payment Date, which shall be the March 15, June 15, September 15 or December 15 (whether or not a Business Day), as the case may be, next preceding such Interest Payment Date; provided however that if the Original Issue Date of this Note shall be after a Regular Record Date and before the corresponding Interest Payment Date, payment of interest shall commence on the second Interest Payment Date succeeding such Original Issue Date and shall be paid to the Person in whose name this Note was registered on the Regular Record Date for such second Interest Payment Date; and provided further, that interest payable on the Stated Maturity Date or any Redemption Date shall be paid to the Person to whom principal shall be paid. Any such interest not so punctually paid or duly provided for shall forthwith cease to be payable to the Holder on such Regular Record Date and shall be paid as provided in said Indenture. If any Interest Payment Date, any Redemption Date or the Stated Maturity Date is not a Business Day, then payment of the amounts due on this Note on such date will be made on the next succeeding Business Day, and no interest shall accrue on such amounts for the period from and after such Interest Payment Date, Redemption Date or Stated Maturity Date, as the case may be, except that, if such Business Day is in the next succeeding calendar year, such payment shall be made on the immediately preceding Business Day, with the same force and effect as if made on such date. The principal of (and premium, if any) and the interest on this Note shall be payable at the office or agency of the Company maintained for that purpose in the Borough of Manhattan, the City of New York, New York, in any coin or currency of the United States of America which at the time of payment is legal tender for payment of public and private debts; provided, however, that payment of interest (other than interest payable on the Stated Maturity Date or any Redemption Date) may be made at the option of the Company by check mailed to the registered holder at such address as shall appear in the Note Register. This Note is one of a duly authorized series of Notes of the Company (herein sometimes referred to as the "Notes"), specified in the Indenture, all issued or to be issued in one or more series under and pursuant to an Indenture dated as of January 1, 1998 duly executed and delivered between the Company and The Bank of New York, a New York banking corporation organized and existing under the laws of the State of New York, as Trustee (herein referred to as the "Trustee") (such Indenture, as originally executed and delivered and as thereafter supplemented and amended being herein- after referred to as the "Indenture"), to which Indenture and all indentures supplemental thereto or Company Orders reference is hereby made for a description of the rights, limitations of rights, obligations, duties and immunities thereunder of the Trustee, the Company and the holders of the Notes. By the terms of the Indenture, the Notes are issuable in series which may vary as to amount, date of maturity, rate of interest and in other respects as in the Indenture provided. This Note is one of the series of Notes designated on the face hereof. If so specified on the face hereof and subject to the terms of Article Three of the Indenture, this Note is subject to redemption at any time on or after the Initial Redemption Date specified on the face hereof, as a whole or, if specified, in part, at the election of the Company, at the applicable redemption price (as described below) plus any accrued but unpaid interest to the date of such redemption. Unless otherwise specified on the face hereof, such redemption price shall be the Initial Redemption Price specified on the face hereof for the twelve-month period commencing on the Initial Redemption Date and shall decline for the twelve- month period commencing on each anniversary of the Initial Redemption Date by a percentage of principal amount equal to the Reduction Percentage specified on the face hereof until such redemption price is 100% of the principal amount of this Note to be redeemed. Notwithstanding the foregoing, the Company may not, prior to the Redemption Limitation Date, if any, specified on the face hereof, redeem any Note of this series as contemplated above as a part of, or in anticipation of, any refunding operation by the application, directly or indirectly, of moneys borrowed having an effective interest cost to the Company (calculated in accordance with generally accepted financial practice) of less than the effective interest cost to the Company (similarly calculated) of this Note. This Note shall be redeemable to the extent set forth herein and in the Indenture upon not less than thirty, but not more than sixty, days previous notice by mail to the registered owner. The Company shall not be required to (i) issue, exchange or register the transfer of any Notes during a period beginning at the opening of business 15 days before the day of the mailing of a notice of redemption of less than all the outstanding Notes of the same series and ending at the close of business on the day of such mailing, nor (ii) register the transfer of or exchange of any Notes of any series or portions thereof called for redemption. This Global Note is exchangeable for Notes in definitive registered form only under certain limited circumstances set forth in the Indenture. In the event of redemption of this Note in part only, a new Note or Notes of this series, of like tenor, for the unredeemed portion hereof will be issued in the name of the Holder hereof upon the surrender of this Note. In case an Event of Default, as defined in the Indenture, shall have occurred and be continuing, the principal of all of the Notes may be declared, and upon such declaration shall become, due and payable, in the manner, with the effect and subject to the conditions provided in the Indenture. The Indenture contains provisions for defeasance at any time of the entire indebtedness of this Note upon compliance by the Company with certain conditions set forth therein. The Indenture contains provisions permitting the Company and the Trustee, with the consent of the Holders of not less than a majority in aggregate principal amount of the Notes of each series affected at the time outstanding, as defined in the Indenture, to execute supplemental indentures for the purpose of adding any provisions to or changing in any manner or eliminating any of the provisions of the Indenture or of any supplemental indenture or of modifying in any manner the rights of the Holders of the Notes; provided, however, that no such supplemental indenture shall (i) extend the fixed maturity of any Notes of any series, or reduce the principal amount thereof, or reduce the rate or extend the time of payment of interest thereon, or reduce any premium payable upon the redemption thereof, or reduce the amount of the principal of a Discount Security that would be due and payable upon a declaration of acceleration of the maturity thereof pursuant to the Indenture, without the consent of the holder of each Note then outstanding and affected; (ii) reduce the aforesaid percentage of Notes, the holders of which are required to consent to any such supplemental indenture, or reduce the percentage of Notes, the holders of which are required to waive any default and its consequences, without the consent of the holder of each Note then outstanding and affected thereby; or (iii) modify any provision of Section 6.01(c) of the Indenture (except to increase the percentage of principal amount of securities required to rescind and annul any declaration of amounts due and payable under the Notes), without the consent of the holder of each Note then outstanding and affected thereby. The Indenture also contains provisions permitting the Holders of a majority in aggregate principal amount of the Notes of all series at the time outstanding affected thereby, on behalf of the Holders of the Notes of such series, to waive any past default in the performance of any of the covenants contained in the Indenture, or established pursuant to the Indenture with respect to such series, and its consequences, except a default in the payment of the principal of or premium, if any, or interest on any of the Notes of such series. Any such consent or waiver by the registered Holder of this Note (unless revoked as provided in the Indenture) shall be conclusive and binding upon such Holder and upon all future Holders and owners of this Note and of any Note issued in exchange herefor or in place hereof (whether by registration of transfer or otherwise), irrespective of whether or not any notation of such consent or waiver is made upon this Note. No reference herein to the Indenture and no provision of this Note or of the Indenture shall alter or impair the obligation of the Company, which is absolute and unconditional, to pay the principal of and premium, if any, and interest on this Note at the time and place and at the rate and in the money herein prescribed. As provided in the Indenture and subject to certain limitations therein set forth, this Note is transferable by the registered holder hereof on the Note Register of the Company, upon surrender of this Note for registration of transfer at the office or agency of the Company as may be designated by the Company accompanied by a written instrument or instruments of transfer in form satisfactory to the Company or the Trustee duly executed by the registered Holder hereof or his or her attorney duly authorized in writing, and thereupon one or more new Notes of authorized denominations and for the same aggregate principal amount and series will be issued to the designated transferee or transferees. No service charge will be made for any such transfer, but the Company may require payment of a sum sufficient to cover any tax or other governmental charge payable in relation thereto. Prior to due presentment for registration of transfer of this Note, the Company, the Trustee, any paying agent and any Note Registrar may deem and treat the registered Holder hereof as the absolute owner hereof (whether or not this Note shall be overdue and notwithstanding any notice of ownership or writing hereon made by anyone other than the Note Registrar) for the purpose of receiving payment of or on account of the principal hereof and premium, if any, and interest due hereon and for all other purposes, and neither the Company nor the Trustee nor any paying agent nor any Note Registrar shall be affected by any notice to the contrary. No recourse shall be had for the payment of the principal of or the interest on this Note, or for any claim based hereon, or otherwise in respect hereof, or based on or in respect of the Indenture, against any incorporator, stockholder, officer or director, past, present or future, as such, of the Company or of any predecessor or successor corporation, whether by virtue of any constitution, statute or rule of law, or by the enforcement of any assessment or penalty or otherwise, all such liability being, by the acceptance hereof and as part of the consideration for the issuance hereof, expressly waived and released. The Notes of this series are issuable only in registered form without coupons in denominations of $25 and any integral multiple thereof. As provided in the Indenture and subject to certain limitations, Notes of this series are exchangeable for a like aggregate principal amount of Notes of this series of a different authorized denomination, as requested by the Holder surrendering the same. All terms used in this Note which are defined in the Indenture shall have the meanings assigned to them in the Indenture. This Note shall not be entitled to any benefit under the Indenture hereinafter referred to, be valid or become obligatory for any purpose until the Certificate of Authentication hereon shall have been signed by or on behalf of the Trustee. IN WITNESS WHEREOF, the Company has caused this Instrument to be executed. APPALACHIAN POWER COMPANY By:___________________________ Attest: By:___________________________ CERTIFICATE OF AUTHENTICATION This is one of the Notes of the series of Notes designated in accordance with, and referred to in, the within-mentioned Indenture. Dated: March 3, 1998 THE BANK OF NEW YORK, as Trustee By:___________________________ Authorized Signatory 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 Note and all rights thereunder, hereby ________________________________________________________________ irrevocably constituting and appointing such person attorney to ________________________________________________________________ transfer such Note 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 Note in every particular, without alteration or enlargement or any change whatever and NOTICE: Signature(s) must be guaranteed by a financial institution that is a member of the Securities Transfer Agents Medallion Program ("STAMP"), the Stock Exchange Medallion Program ("SEMP") or the New York Stock Exchange, Inc. Medallion Signature Program ("MSP"). EX-12 4 APCO COMPUTATION OF RATIOS EXHIBIT 12 APPALACHIAN POWER COMPANY Computation of Consolidated Ratio of Earnings to Fixed Charges (in thousands except ratio data)
Year Ended December 31, 1993 1994 1995 1996 1997 Fixed Charges: Interest on First Mortgage Bonds. . . . . . . . . . . $ 80,472 $ 75,815 $ 80,777 $ 82,082 $ 81,009 Interest on Other Long-term Debt. . . . . . . . . . . 16,846 16,415 16,404 18,025 28,163 Interest on Short-term Debt . . . . . . . . . . . . . 1,615 3,366 5,119 3,639 4,569 Miscellaneous Interest Charges. . . . . . . . . . . . 2,954 3,913 5,323 7,327 6,857 Estimated Interest Element in Lease Rentals . . . . . 7,900 7,700 7,000 6,600 6,000 Total Fixed Charges. . . . . . . . . . . . . . . $109,787 $107,209 $114,623 $117,673 $126,598 Earnings: Net Income. . . . . . . . . . . . . . . . . . . . . . $125,132 $102,345 $115,900 $133,689 $120,514 Plus Federal Income Taxes . . . . . . . . . . . . . . 51,681 39,599 53,355 65,801 54,835 Plus State Income Taxes . . . . . . . . . . . . . . . 8,887 5,910 7,273 10,180 8,109 Plus Fixed Charges (as above) . . . . . . . . . . . . 109,787 107,209 114,623 117,673 126,598 Total Earnings . . . . . . . . . . . . . . . . . $295,487 $255,063 $291,151 $327,343 $310,056 Ratio of Earnings to Fixed Charges. . . . . . . . . . . 2.69 2.37 2.54 2.78 2.44
EX-13 5 APCO 1997 ANNUAL REPORT
APPALACHIAN POWER COMPANY AND SUBSIDIARIES Selected Consolidated Financial Data Year Ended December 31, 1997 1996 1995 1994 1993 (in thousands) INCOME STATEMENTS DATA: Operating Revenues $1,720,010 $1,624,869 $1,545,039 $1,535,500 $1,519,104 Operating Expenses 1,480,016 1,381,993 1,317,937 1,330,282 1,289,764 Operating Income 239,994 242,876 227,102 205,218 229,340 Nonoperating Income (Loss) (222) 128 (4,699) (4,716) (3,353) Income Before Interest Charges 239,772 243,004 222,403 200,502 225,987 Interest Charges 119,258 109,315 106,503 98,157 100,855 Net Income 120,514 133,689 115,900 102,345 125,132 Preferred Stock Dividend Requirements 7,006 15,938 16,405 15,660 16,540 Earnings Applicable to Common Stock $ 113,508 $ 117,751 $ 99,495 $ 86,685 $ 108,592 Year Ended December 31, 1997 1996 1995 1994 1993 (in thousands) BALANCE SHEETS DATA: Electric Utility Plant $4,901,046 $4,717,132 $4,558,436 $4,398,727 $4,193,700 Accumulated Depreciation and Amortization 1,869,057 1,782,017 1,694,746 1,627,852 1,550,855 Net Electric Utility Plant $3,031,989 $2,935,115 $2,863,690 $2,770,875 $2,642,845 Total Assets $3,883,430 $3,800,737 $3,723,975 $3,635,632 $3,478,751 Common Stock and Paid-in Capital $ 873,506 $ 835,838 $ 785,509 $ 764,866 $ 755,292 Retained Earnings 207,544 208,472 199,021 206,361 227,816 Total Common Shareholder's Equity $1,081,050 $1,044,310 $ 984,530 $ 971,227 $ 983,108 Cumulative Preferred Stock: Not Subject to Mandatory Redemption $ 19,747 $ 29,815 $ 55,000 $ 55,000 $ 55,000 Subject to Mandatory Redemption (a) 22,310 190,000 190,235 190,385 160,537 Total Cumulative Preferred Stock $ 42,057 $ 219,815 $ 245,235 $ 245,385 $ 215,537 Long-term Debt (a) $1,494,535 $1,365,842 $1,285,684 $1,228,911 $1,215,168 Obligations Under Capital Leases (a) $ 60,110 $ 51,969 $ 48,937 $ 43,138 $ 29,973 Total Capitalization and Liabilities $3,883,430 $3,800,737 $3,723,975 $3,635,632 $3,478,751
(a) Including portion due within one year. APPALACHIAN POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION This discussion includes forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. These forward-looking statements reflect assumptions, and involve a number of risks and uncertainties. Among the factors that could cause actual results to differ materially are: electric load and customer growth; abnormal weather conditions; available sources and costs of fuels and availability of generating capacity; the speed and degree to which competition is introduced to our power generation business, the terms of the transition to competition, and its impact on rate structures; the ability to recover stranded costs, new legislation and government regulations, the ability of the Company to successfully reduce its costs; the economic climate and growth in our service territory; inflationary trends, interest rates and other risks. Business Outlook The Company's ability to recover its costs as the industry transitions to competition and as customer choice is more broadly available is the most significant factor affecting the Company's future. Competition in the wholesale generation market continues to intensify since the adoption of federal legislation in 1992 which gave wholesale customers the right to choose their energy supplier. The introduction of competition and customer choice for retail customers has been slow although activity has been increasing. Federal legislation has been proposed to mandate competition and customer choice at the retail level, and several states have introduced or are considering similar legislation. Both West Virginia and Virginia are currently considering legislative initiatives to move to customer choice, although the timing is uncertain. The Company supports customer choice and is proactively involved in discussions at both the state and federal levels regarding how best to structure and transition to a competitive marketplace. As the electric energy market evolves from cost-of-service ratemaking to market-based pricing, many complex issues must be resolved, including the recovery of stranded costs. While Federal Energy Regulation Commission (FERC) orders No. 888 and 889 provide, under certain conditions, for recovery of stranded cost at the wholesale level, the issue of stranded cost recovery is unresolved at the larger retail level. The amount of any stranded costs the Company may experience depends on the timing and extent to which direct competition is introduced to our business and the then-existing market price of electricity. Under the provisions of Statement of Financial Acccounting 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 balance sheets of cost-based regulated utilities in accordance with regulatory actions to match expenses and revenues with cost-based rates. In order to maintain net regulatory assets (net expense deferrals) on the balance sheet, SFAS No. 71 requires that rates charged to customers be cost-based and the recovery of regulatory assets must be probable. In the event a portion of the Company's business no longer meets the requirements of SFAS No. 71, net regulatory assets would have to be written off for that portion of the business. The provisions of SFAS No. 71 and SFAS No. 101 "Accounting for the Discontinuance of Application of Statement No. 71" never anticipated that deregulation would include an extended transition period or that it would provide for recovery after the transition period of stranded costs. In July 1997 the Emerging Issues Task Force (EITF) of the Financial Accounting Standards Board (FASB) reached a consensus that the application of SFAS No. 71 to a segment of a regulated electric utility which is subject to a legislative plan to transition to competition in that segment should cease when the legislation is passed, or an enabling rate order is issued containing sufficient detail for the utility to reasonably determine what the plan would entail. The EITF indicated that the cessation of application of SFAS No. 71 would require that existing regulatory assets and impaired plant be written off unless they are recoverable. Although FERC Orders No. 888 and 889 provide for competition in the firm wholesale market, that market is a relatively small part of our business and most of our firm wholesale sales are still under cost-of-service contracts. As a result the Company's generation business is still cost-based regulated and should remain so for the near future pending the passage of enabling state legislation to deregulate the generation business. We believe that enabling state legislation should provide for the recovery of any generation-related net regulatory assets and other reasonable stranded costs from impaired generation assets. We are working with regulators, customers and legislators to provide for recovery of these stranded costs during a transition period in which rates are fixed or frozen and electric utilities would take steps to achieve cost savings which would be used to reduce or eliminate their stranded costs. However, if in the future the Company's generation business were to no longer be cost-based regulated and if it were not possible to demonstrate probability of recovery of resultant stranded costs including regulatory assets, results of operations, cash flows and financial condition of the Company would be adversely affected. Cost Containment and Process Improvement Efforts continue to reduce the costs of products and services in order to maintain our competitiveness. Prior to 1997, reviews of our major processes led to decisions to consolidate in the AEPSC senior management and certain functions and operations. Among the functions consolidated in this restructuring were generation plant maintenance, system operations, accounting and load research. While staff reductions and cost savings are presently being achieved in these and other areas, expenses for new marketing and customer services and modern efficient management information systems are increasing to prepare the Company for competition. In February 1998, the Company began installing a new unified customer service system which is designed to support the request for service, billing, accounts receivable, credit and collection functions. The new unified customer service system replaces a 30-year-old customer system and a nine-year-old transmission and distribution work management system. Process improvement efforts and expenditures to develop and implement the new customer service system and similar efforts and expenditures to acquire, install and enhance new client server based accounting and budgeting/financial planning software should produce further improvements and efficiencies, enabling the Company to continue to offer its customers excellent service at competitive prices. Fuel Costs We recognize that we must continue to manage our coal costs to maintain our competitive position. Approximately 98% of the Company's generation was coal fired and is supplied under long-term contracts and purchases in the spot market. As long-term contracts expire we are negotiating with unaffiliated suppliers to lower 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 Concerns 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 our 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. By-products from the generation of electricity include materials such as ash, slag and sludge. Coal combustion by-products are typically disposed of or treated in captive disposal facilities or are beneficially utilized. In addition, our generating plants and transmission and distribution facilities have used asbestos, PCBs and other hazardous and nonhazardous materials. The Company is currently incurring costs to safely dispose of such substances. Additional costs could be incurred to comply with new laws and regulations if enacted. Comprehensive Environmental Response, Compensation and Liability Act (CERCLA or Superfund) addresses clean-up of hazardous substances at disposal sites and authorized the United States Environmental Protection Agency (Federal EPA) to administer the clean-up programs. As of year-end 1997, there are two sites for which the Company has received information requests which could lead to "Potentially Responsible Parties" (PRP) designation. The Company's liability has been resolved for a number of sites with no significant effect on results of operations and present estimates do not anticipate material cleanup costs for identified sites in which the Company is involved. However, if for reasons not currently identified significant costs are incurred for cleanup, future results of operations, cash flows and possibly financial condition would be adversely affected unless the costs can be recovered. 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 (NOx) that must be met after January 1, 2000 (Phase II of the CAAA). The final rules will require substantial reductions in NOx emissions from certain types of power plant boilers including those in AEP's power plants. On February 13, 1998, the United States Court of Appeals for the District of Columbia Circuit, in an appeal in which the AEP System operating companies participated, upheld the emission limitations. In addition in November 1997 the Federal EPA published a proposed rulemaking requiring the revision of state implementation plans in 22 eastern states, including West Virginia and Virginia, states in which the Company has coal-fired generating plants. The proposed rule will require reductions in NOx emissions from utility sources of approximately 85% below 1990 levels and entail very substantial capital and operating expenditures by AEP System operating companies. Since the Company shares energy and wholesales sales as a member of the AEP System power pool it is affected by expenditures at the generating units of other affiliated members of the AEP Pool. Pollution controls to meet the proposed revised NOx emission limits would have to be in place by 2002. Also, the Federal EPA has been petitioned for a new rulemaking by eight northeast states for the development of controls for upwind sources. The costs to comply with the emission reductions required by these Federal EPA actions is expected to be substantial and would have a material adverse impact on future results of operations, cash flows and possibly financial condition if the resultant costs are not recovered from customers. In 1997 the Federal EPA published a revised ambient air quality standard for ozone and established a new ambient air quality standard for fine particulate matter. These standards are expected to result in redesignation of a number of areas of the country currently in compliance with the existing standard to nonattainment which could ultimately dictate more stringent emission restrictions for AEP generating units including those of the Company's. Under the new rules the states must first determine the attainment status of their areas. The states then have three years to submit a compliance plan and up to ten years after designation to come into compliance with the new standards. The compliance deadline could be as late as 2010 for the ozone standard and 2012-2015 for the fine particulate standard. Although we are reviewing the impact of the new rules, we are unable to estimate compliance costs without knowledge of the reductions that Virginia and West Virginia will find necessary to meet the new standards. If such reductions are significant and the Company and its affiliates must bear a significant portion of the cost of compliance in a region or county that is in violation of the revised standards, it would have a material adverse effect on results of operations, cash flows and possibly financial condition unless such costs are recovered from customers. At the global climate conference in Kyoto, Japan in December 1997 more than 160 countries negotiated a treaty limiting emissions of greenhouse gases, chiefly carbon dioxide, which may eventually contribute to global warming. Although there is no clear scientific evidence that carbon dioxide contributes to global warming and damages the environment, the treaty, which requires Congressional approval, calls for a seven percent reduction below emission levels of greenhouse gases in 1990. We intend to work with the Congress to ensure that science and reason are introduced into the debate. If approved by Congress, the cost to comply with the emission reductions required by the Kyoto treaty is expected to be substantial and would have a material adverse impact on results of operations, cash flows and possibly financial condition if not recovered from customers. Results of Operations Although operating revenues increased significantly in 1997 due to increased wholesale sales, net income decreased $13.2 million or 10% primarily due to increased operating expenses and interest charges reflecting additional amounts of long-term debt outstanding. The increase in operating expenses was mainly due to increased fuel and purchased power expense which virtually offset the revenue increase from retail and wholesale customers. In July of 1997 AEP started a new power marketing business of buying and selling power outside the AEP System which accounted for the increases in purchased power and wholesale revenues. The significant increase in revenues was substantially offset by an increase in the related purchased power expense. In 1996 net income increased by $17.8 million or 15% mainly due to increased sales of energy and services. The 1996 sales increase was 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 in 1996 were the effects of severance pay charges recorded in 1995 in connection with a management and operations restructuring and gains recorded in 1996 from emission allowance transactions. Operating Revenues and Energy Sales Increase Operating revenues increased 6% in 1997 and 5% in 1996 primarily due to increased wholesale energy sales. The change in operating revenues can be analyzed as follows: Increase (Decrease) From Previous Year (dollars in millions) 1997 1996 Amount % Amount % Retail: Price variance $(21.7) $ 1.4 Volume variance 7.5 14.4 Fuel and Purchased Power Recoveries 16.8 (13.6) 2.6 0.2 2.2 0.2 Wholesale: Price variance 7.5 (143.5) Volume variance 70.5 206.8 78.0 23.4 63.3 23.5 Other Operating Revenues 14.5 14.3 Total $ 95.1 5.9 $ 79.8 5.2 The increases in revenues was mainly due to increased lower profit wholesale sales in both 1997 and 1996. Wholesale revenues and sales increased in 1997 primarily due to new power marketing transactions which began in July 1997 and increased coal conversion services. The new power marketing transactions involve the purchase and sale of electricity outside the AEP transmission system. In 1996 the increase in wholesale sales was due to a 38% increase in the Company's share of Power Pool allocated sales and a rise in sales to the Power Pool. Sales of coal conversion services which are made through the Power Pool resulted in 2.2 billion kilowatthours of electricity being provided to power marketers and certain other utilities. Coal conversion services which began in 1996 are provided to power marketers and certain non-affiliated utilities under a FERC approved interruptible tariff for the conversion of customers' coal to electricity and do not include any fuel cost. Since these sales are for the service of converting the customers' coal to electricity and do not include any fuel cost, the average wholesale price per kilowatthour was significantly less in 1996 than in 1995. Energy sales to the Power Pool increased in 1996 mainly due to increased demand for electric energy by customers of the other affiliated Power Pool members. Energy sales to the Power Pool are priced to compensate the supplying Power Pool member for its out-of-pocket costs. 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 increases in transmission service revenues in 1997 and 1996. As a result transmission revenues from the wheeling of non-affiliated power, which are recorded as other operating revenues, increased by approximately $6.5 million and $12 million in 1997 and 1996, respectively. Also contributing to the increase in other operating revenues in 1997 was the favorable effect due to a provision recorded in 1996 for the completion of rate refunds under a settlement in the Virginia jurisdiction. Operating Expenses Increase Operating expenses increased by 7% in 1997 and 5% in 1996. The increase in 1997 is mainly due to increased power purchases by AEP's new power marketing business. In 1996 all operating expenses except maintenance increased. Changes in the components of operating expenses were as follows: Increase (Decrease) From Previous Year (dollars in millions) 1997 1996 Amount % Amount % Fuel $ 36.1 9.8 $ 18.9 5.4 Purchased Power 70.0 21.0 32.9 11.0 Other Operation 6.5 2.7 18.5 8.3 Maintenance (4.6) (3.9) (22.1) (15.8) Depreciation and Amortization 4.6 3.5 0.1 - Taxes Other Than Federal Income Taxes (3.7) (3.1) 3.2 2.7 Federal Income Taxes (10.9) (15.5) 12.6 21.8 Total $ 98.0 7.1 $ 64.1 4.9 Fuel expense increased 10% in 1997 primarily due to increased generation and the operation of the West Virginia power supply cost recovery mechanism which requires that overcollections of fuel costs be deferred for future refund to customers through a charge to fuel expense in accordance with a rate order. The level of generation increased primarily in the fourth quarter of 1997 when both units of an affiliate's nuclear plant were unavailable. 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 significant increase in purchased power expense in 1997 was mainly due to purchases of electricity for the new power marketing transactions partially offset by decreased purchases from the Power Pool due to the unavailability of the affiliate's nuclear units. The rise in purchased power in 1996 was attributable to increased purchases of energy from the Power Pool to meet the increased demand for energy and an increase in Power Pool capacity charges. 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 which are included in purchased power. 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 State Corporation Commission of Virginia (Virginia SCC); an increase in employee benefit costs; and higher costs related 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 restructuring of AEP's management and operations. Maintenance expense declined in 1996 primarily as a result of accounting for incremental storm damage expense in accordance with directions of the Virginia SCC. The decrease in federal income taxes attributable to operations in 1997 was primarily due to a decline in pre-tax operating income. An increase in pre-tax operating income in 1996 accounted for the increase in federal income taxes attributable to operations. 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 and Preferred Stock Dividends Interest charges increased in 1997 primarily as a result of an increase in the balance of long-term debt outstanding to replace preferred stock. Preferred stock dividend requirements decreased significantly due to a decrease in the number of shares outstanding as 1.3 million shares were reacquired in the first quarter of 1997 as part of a tender offer and the remaining 477,500 outstanding shares of the 7.80% series were redeemed in April 1997. Financial Condition In 1997 the Company maintained its strong financial condition. We redeemed 1,777,585 shares of cumulative preferred stock with rates ranging from 4.50% to 7.8% at a total cost of $184 million. Part of the reacquired shares were reacquired under terms of a tender offer in conjunction with a special shareholders' meeting at which the articles of incorporation were revised to remove certain capitalization ratio requirements that constrained the Company's issuance of unsecured and short-term debt. The restrictions limited our financial flexibility and could have placed us at a competitive disadvantage in the future. We used short-term debt and junior subordinated deferrable interest debentures to pay for the preferred stock tendered and to benefit from the tax deductibility of interest. The Company issued $186 million principal amount of long-term obligations in 1997 at interest rates ranging from 6.35% to 8.0%. We continued to reduce financing costs by retiring higher-cost bonds and restructuring the long-term debt from senior secured/first mortgage bonds to senior unsecured debt/junior debentures. The principal amount of long-term debt retirements, including maturities, totaled $56 million with interest rates ranging from 8.75% to 9.35%. Our senior secured debt/first mortgage bond ratings which were reaffirmed and improved in 1997, are: Moody's, A3; Standard and Poor's (S&P), A; Fitch, A; and Duff & Phelps, LLC (D & P), A. The Company's good bond ratings meet and often exceed the required rating of bond investors. With higher bond ratings, the Company attracts a wider investor base, a bigger share of capital in the bond market and lower interest rates. Gross plant and property additions were $233 million in 1997 and $207 million in 1996. Management estimates construction expenditures for the next three years to be $660 million which includes the cost of transmission and distribution projects for the improvement of and addition to electric energy delivery facilities. The funds for construction of new facilities and improvement of existing facilities can come from a combination of internally generated funds, short-term and long-term borrowings, preferred stock issuances and investments in common equity by the Company's parent, AEP Co., Inc. However, all of the construction expenditures for the next three years are expected to be financed with internally generated funds. Inflation affects the Company's cost of replacing utility plant and the cost of operating and maintaining plant. The rate-making process generally limits our recovery to the historical cost of assets resulting in economic losses when the effects of inflation are not recovered from customers on a timely basis. However, economic gains that result from the repayment of long-term debt with inflated dollars partly offset such losses. 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, 1997, $442 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 1935 Act to $250 million. Generally periodic reductions of outstanding short-term debt are made through issuances of long-term debt and through additional capital contributions by the parent company. The Company's earnings coverage presently exceeds all 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, 1997, the mortgage bonds and preferred stock coverage ratios were 3.72 and 1.92, respectively. Other Matters Corporate Owned Life Insurance In connection with the audit of AEP's consolidated federal income tax returns for the United States Internal Revenue Service (IRS) agents sought a ruling from the IRS National Office that certain interest deductions relating to a COLI program should not be allowed. The Company established the COLI program in 1990 as 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. No adjustments have been proposed by the IRS. However should, a disallowance of the COLI interest deductions be proposed it would, if sustained, reduce earnings by approximately $72 million (including interest). Management believes it has meritorious defenses and will vigorously contest any proposed adjustments. No provisions for this amount have been recorded. In the event the Company is unsuccessful it could have a material adverse impact on results of operations and cash flows. Computer Software - Year 2000 Compliance Many existing computer hardware and software programs will not properly recognize calendar dates beginning in the year 2000. Unless corrected, this "Year 2000" problem may cause computer malfunctions, such as system shutdowns or incorrect calculations and system output. The Company is addressing the problem internally by modifying or replacing its computer hardware and software programs. The problem is also being addressed externally with entities that interact electronically with the Company, including but not limited to, suppliers, service providers, government agencies, customers, creditors and financial service organizations. However, due to the complexity of the problem and the interdependent nature of computer systems, if the Company's corrective actions, and/or the actions of other interdependent entities, fail for critical applications, the Company may be adversely impacted in the year 2000. Although significant, the cost of correcting the "Year 2000" problem is not expected to have a material impact on results of operations, cash flows or financial condition. New Accounting Standards In June 1997 the FASB issued SFAS No. 130 "Reporting Comprehensive Income" and SFAS No. 131 "Disclosures About Segments of an Enterprise and Related Information." SFAS No. 130 establishes the standards for reporting and displaying components of "comprehensive income," which is the total of net income and all other changes in equity except those resulting from investments by shareholders and dispositions to shareholders. SFAS No. 131 initiates standards for reporting information about operating segments in annual and interim financial statements as well as related disclosures about products and services, geographic areas and major customers. APCo's adoption of these new reporting standards in 1998 is not expected to have a material effect on the results of operations, cash flows and/or financial condition. Litigation The Company is involved in a number of legal proceedings and claims. While we are unable to predict the outcome of such litigation, it is not expected that the ultimate resolution of these matters will have a material adverse effect on the results of operations, cash flows and/or financial condition.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Income Year Ended December 31, 1997 1996 1995 (in thousands) OPERATING REVENUES $1,720,010 $1,624,869 $1,545,039 OPERATING EXPENSES: Fuel 403,777 367,651 348,776 Purchased Power 403,009 333,014 300,086 Other Operation 246,785 240,249 221,783 Maintenance 112,873 117,483 139,566 Depreciation and Amortization 137,670 133,074 132,999 Taxes Other Than Federal Income Taxes 116,590 120,307 117,093 Federal Income Taxes 59,312 70,215 57,634 Total Operating Expenses 1,480,016 1,381,993 1,317,937 OPERATING INCOME 239,994 242,876 227,102 NONOPERATING INCOME (LOSS) (222) 128 (4,699) INCOME BEFORE INTEREST CHARGES 239,772 243,004 222,403 INTEREST CHARGES 119,258 109,315 106,503 NET INCOME 120,514 133,689 115,900 PREFERRED STOCK DIVIDEND REQUIREMENTS 7,006 15,938 16,405 EARNINGS APPLICABLE TO COMMON STOCK $ 113,508 $ 117,751 $ 99,495
See Notes to Consolidated Financial Statements.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES Consolidated Balance Sheets December 31, 1997 1996 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production $1,942,325 $1,883,271 Transmission 1,079,919 1,054,207 Distribution 1,583,161 1,495,445 General 207,380 188,740 Construction Work in Progress 88,261 95,469 Total Electric Utility Plant 4,901,046 4,717,132 Accumulated Depreciation and Amortization 1,869,057 1,782,017 NET ELECTRIC UTILITY PLANT 3,031,989 2,935,115 OTHER PROPERTY AND INVESTMENTS 35,467 29,621 CURRENT ASSETS: Cash and Cash Equivalents 6,947 7,260 Accounts Receivable: Customers 129,924 122,969 Affiliated Companies 24,502 15,017 Miscellaneous 10,231 22,035 Allowance for Uncollectible Accounts (1,333) (687) Fuel - at average cost 47,901 52,605 Materials and Supplies - at average cost 57,359 56,605 Accrued Utility Revenues 51,208 51,843 Prepayments 6,037 10,797 TOTAL CURRENT ASSETS 332,776 338,444 REGULATORY ASSETS 441,223 451,272 DEFERRED CHARGES 41,975 46,285 TOTAL $3,883,430 $3,800,737
See Notes to Consolidated Financial Statements.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES December 31, 1997 1996 (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 613,048 575,380 Retained Earnings 207,544 208,472 Total Common Shareholder's Equity 1,081,050 1,044,310 Cumulative Preferred Stock: Not Subject to Mandatory Redemption 19,747 29,815 Subject to Mandatory Redemption 22,310 190,000 Long-term Debt 1,415,026 1,365,834 TOTAL CAPITALIZATION 2,538,133 2,629,959 OTHER NONCURRENT LIABILITIES 137,371 109,203 CURRENT LIABILITIES: Long-term Debt Due Within One Year 79,509 8 Short-term Debt 130,300 60,700 Accounts Payable - General 52,683 34,714 Accounts Payable - Affiliated Companies 44,133 51,178 Taxes Accrued 41,549 40,935 Customer Deposits 13,713 13,750 Interest Accrued 20,949 20,938 Other 71,394 80,352 TOTAL CURRENT LIABILITIES 454,230 302,575 DEFERRED INCOME TAXES 658,655 669,964 DEFERRED INVESTMENT TAX CREDITS 67,496 72,677 DEFERRED CREDITS 27,545 16,359 COMMITMENTS AND CONTINGENCIES (Note 4) TOTAL $3,883,430 $3,800,737 See Notes to Consolidated Financial Statements. /TABLE
APPALACHIAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Cash Flows Year Ended December 31, 1997 1996 1995 (in thousands) OPERATING ACTIVITIES: Net Income $ 120,514 $ 133,689 $ 115,900 Adjustments for Noncash Items: Depreciation and Amortization 138,975 134,381 134,485 Deferred Federal Income Taxes (5,117) 592 647 Deferred Investment Tax Credits (5,181) (5,602) (5,465) Deferred Power Supply Costs (net) 12,310 293 (3,721) Provision for Rate Refunds 7,601 (2,626) 15,224 Changes in Certain Current Assets and Liabilities: Accounts Receivable (net) (3,990) (19,176) (16,896) Fuel, Materials and Supplies 3,950 15,583 (9,761) Accrued Utility Revenues 635 13,235 (13,392) Accounts Payable 10,924 3,668 (11,488) Taxes Accrued 614 (7,731) 14,043 Other (net) (722) 9,437 28,324 Net Cash Flows From Operating Activities 280,513 275,743 247,900 INVESTING ACTIVITIES: Construction Expenditures (218,074) (191,815) (216,200) Proceeds from Sales of Property 4,971 1,933 7,793 Net Cash Flows Used For Investing Activities (213,103) (189,882) (208,407) FINANCING ACTIVITIES: Capital Contributions from Parent Company 40,000 50,000 30,000 Issuance of Long-term Debt 183,257 273,340 128,785 Retirement of Cumulative Preferred Stock (183,875) (25,904) (150) Retirement of Long-term Debt (56,379) (195,910) (74,950) Change in Short-term Debt (net) 69,600 (64,825) 2,700 Dividends Paid on Common Stock (114,436) (108,300) (106,836) Dividends Paid on Cumulative Preferred Stock (5,890) (15,666) (15,675) Net Cash Flows Used For Financing Activities (67,723) (87,265) (36,126) Net Increase (Decrease) in Cash and Cash Equivalents (313) (1,404) 3,367 Cash and Cash Equivalents January 1 7,260 8,664 5,297 Cash and Cash Equivalents December 31 $ 6,947 $ 7,260 $ 8,664
See Notes to Consolidated Financial Statements.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Retained Earnings Year Ended December 31, 1997 1996 1995 (in thousands) Retained Earnings January 1 $208,472 $199,021 $206,361 Net Income 120,514 133,689 115,900 328,986 332,710 322,261 Deductions: Cash Dividends Declared: Common Stock 114,436 108,300 106,836 Cumulative Preferred Stock: 4-1/2% Series 892 1,348 1,350 4.50% Series - 9 16 5.90% Series 455 2,950 2,950 5.92% Series 364 3,552 3,552 6.85% Series 579 2,055 2,055 7.40% Series - 1,385 1,850 7.80% Series 931 3,900 3,900 Total Cash Dividends Declared 117,657 123,499 122,509 Capital Stock Expense 3,785 739 731 Total Deductions 121,442 124,238 123,240 Retained Earnings December 31 $207,544 $208,472 $199,021
See Notes to Consolidated Financial Statements. APPALACHIAN POWER COMPANY AND SUBSIDIARIES 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, sale, purchase, transmission and distribution of electric power to 877,000 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 American Electric Power System (AEP System) Power Pool and a signatory company to the AEP System 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 State Corporation Commission of Virginia (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 and to match expenses with regulated revenues. Use of Estimates The preparation of these financial statements in conformity with generally accepted accounting principles requires in certain instances the use of 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 of plant are deducted from the electric utility plant in service account and deducted from accumulated depreciation together with associated removal costs, net of salvage. 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 capitalized and recovered through depreciation over the service life of utility plant. It 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 1997, 1996 and 1995 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: Annual Composite Functional Class Depreciation of Property Rates Production: Steam 3.4% Hydro 2.9% 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 over or 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 deferred and reviewed for recovery annually by the Virginia SCC. In the West Virginia jurisdiction, under the terms of a 1996 settlement agreement, deferral accounting will be practiced for the over and under collection of fuel, Power Pool capacity charges and certain transmission revenue for the period November 1996 through December 1999. 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. Overrecoveries 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. Overrecoveries under $10 million are included in operating income annually. Wholesale jurisdictional fuel cost changes are expensed and billed as incurred through a FERC fuel clause. Income Taxes The Company follows the liability method of accounting for income taxes as prescribed by SFAS 109, "Accounting for Income Taxes." Under the liability method, deferred income taxes are provided for all temporary differences between book cost and tax basis of assets and liabilities which will result in a future tax consequence. Where the flow-through method of accounting for temporary differences is reflected in rates, deferred income taxes are recorded with related regulatory assets and liabilities in accordance with SFAS 71. Investment Tax Credits Investment tax credits have been accounted for under the flow-through method except where regulatory commissions have reflected investment tax credits in the rate-making process on a deferral basis. Deferred investment tax credits are being amortized over the life of the related plant investment. Debt and Preferred Stock Gains and losses on reacquisiton of debt are deferred and amortized over the remaining term of the reacquired debt in accordance with rate-making treatment. If the debt is refinanced, the reacquisition costs are deferred and amortized over the term of the replacement debt commensurate with their recovery in rates. Debt discount or premium and expenses of debt issuances are amortized over the term of the related debt, with the amortization included in interest charges. Redemption premiums paid to reacquire preferred stock are included in paid-in capital and amortized to retained earnings commensurate with their recovery in rates. The excess of par value over the cost 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. Reclassification Certain prior period amounts have been reclassified to agree with current period presentation. 2. EFFECTS OF REGULATION: In accordance with SFAS No. 71 the consolidated financial statements include regulatory assets (deferred expenses) and regulatory liabilities (deferred income) recorded in accordance with regulatory actions in order to match expenses and revenues from cost-based rates. Regulatory assets are expected to be recovered in future periods through the rate-making process and 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 No. 71. Among other things application of SFAS No. 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 attributable to that portion of the business would have to be tested for possible impairment and if required an impairment loss recorded unless the net regulatory assets and impairment losses are recoverable as a stranded investment. Recognized regulatory assets and liabilities are comprised of the following: December 31, 1997 1996 (in thousands) Regulatory Assets: Amounts Due From Customers For Future Income Taxes $386,127 $392,372 Unamortized Loss On Reacquired Debt 23,561 25,567 Deferred Storm Damage 8,542 10,990 Other 22,993 22,343 Total Regulatory Assets $441,223 $451,272 Regulatory Liabilities: Deferred Investment Tax Credits $67,496 $72,677 Other* 21,121 10,384 Total Regulatory Liabilities $88,617 $83,061 * Included in Deferred Credits on Consolidated Balance Sheets. 3. RATE MATTERS: On June 13, 1997, the Company filed an application with the Virginia SCC for approval of an alternative regulatory plan (Plan) which proposed, among other things, an increase of $30.5 million in base rates on an annual basis to be effective July 13, 1997. The Company's Plan would institute a moratorium period during which no changes from the proposed rates would be made prior to January 1, 2001, (including the Company's current 1.482 cents/kwh fuel factor). In addition, it includes a sharing of earnings above certain levels between the Company and its customers, and acceleration of the recovery of certain regulatory assets. On July 10, 1997, the Virginia SCC issued an order suspending implementation of the proposed rates until November 11, 1997 when rates were placed into effect subject to refund. A hearing has been scheduled for July 6, 1998 to consider the Company's proposal. In 1992 the FERC authorized the Company to implement, subject to refund, an $8.7 million annual rate increase. The revenues collected subject to refund in the FERC jurisdiction total $46.7 million through December 31, 1997. A refund liability, including interest, of $28.1 million at December 31, 1997 has been accrued. 4. COMMITMENTS AND CONTINGENCIES: Construction and Other Commitments Substantial construction commitments have been made to support utility operations. Such commitments do not include any expenditures for new generating capacity. Aggregate construction expenditures for 1998-2000 are estimated to be $660 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. Revised Air Quality Standards On July 18, 1997, the United States Environmental Protection Agency (Federal EPA) published a revised National Ambient Air Quality Standard (NAAQS) for ozone and a new NAAQS for fine particulate matter (less than 2.5 microns in size). The new ozone standard is expected to result in redesignation of a number of areas of the country that are currently in compliance with the existing standard to nonattainment status which could ultimately dictate more stringent emission restrictions for AEP System generating units. New stringent emission restrictions on AEP System generating units to achieve attainment of the fine particulate matter standard could also be imposed. The AEP System operating companies joined with other utilities to appeal the revised NAAQS and filed petitions for review in August and September 1997 in the U.S. Court of Appeals for the District of Columbia Circuit. Management is unable to estimate compliance costs without knowledge of the reductions that may be necessary to meet the new standards. If such costs are significant, they could have a material adverse effect on results of operations, cash flows and possibly financial condition unless recovered. 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, cash flows 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 $40.1 million in 1997, $54.8 million in 1996 and $26.3 million in 1995 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, 1997 1996 1995 (in thousands) Capacity Charges $128,680 $125,456 $116,821 Energy Charges 149,113 187,754 161,531 Total $277,793 $313,210 $278,352 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 $220 million in 1997, $127 million in 1996 and $92 million in 1995. 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 $118.8 million (including new power marketing transactions) in 1997, $14.7 million in 1996 and $18.8 million in 1995. 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 (KGPCo), an affiliated distribution utility that is not a member of the Power Pool, was included in operating revenues in the amounts of $57.9 million in 1997, $59.5 million in 1996 and $58.7 million in 1995. Purchased power expense includes $6.4 million in 1997, $5.1 million in 1996 and $2.9 million in 1995 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 since the Company's relative investment in transmission facilities is greater than its relative peak demands, other operation expense includes equalization charges of $8.4 million, $6.5 million and $5.4 million in 1997, 1996 and 1995, respectively. The Company and an affiliate, Ohio Power Company (OPCo), 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, 1997, 1996 and 1995 were $1.9 million, $4.2 million and $2.7 million, respectively. 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 $17.3 million in 1997, $19 million in 1996 and $19.5 million in 1995. 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 $6.4 million in 1997, $8.4 million in 1996 and $9.5 million in 1995. 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 million in 1997, $4.1 million in 1996, and $4.3 million in 1995. 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, 1997 1996 1995 (in thousands) Operating Leases $ 8,016 $ 9,567 $ 8,600 Amortization of Capital Leases 11,771 12,175 11,003 Interest on Capital Leases 3,290 3,416 4,120 Total Rental Costs $23,077 $25,158 $23,723 Properties under capital leases and related obligations recorded on the Consolidated Balance Sheets are as follows: December 31, 1997 1996 (in thousands) Electric Utility Plant: Production $10,553 $ 9,366 General 77,980 73,420 Total Electric Utility Plant 88,533 82,786 Accumulated Amortization 28,423 30,817 Net Properties under Capital Leases $60,110 $51,969 Capital Lease Obligations: Noncurrent Liability $48,552 $36,857 Liability Due Within One Year 11,558 15,112 Total Capital Lease Obligations $60,110 $51,969 Capital lease obligations are included in other non-current 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, 1997: Non- Cancelable Capital Operating Leases Leases (in thousands) 1998 $15,599 $ 8,693 1999 13,751 2,244 2000 11,315 2,007 2001 9,347 936 2002 8,227 415 Later Years 17,214 4,125 Total Future Minimum Lease Rentals 75,453 $18,420 Less Estimated Interest Element 15,343 Estimated Present Value of Future Minimum Lease Payments $60,110 8. CUMULATIVE PREFERRED STOCK: The authorized number shares of no par value cumulative preferred stock is 8,000,000. 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. The Company redeemed and canceled 2,348 and 1,500 shares of the 4.50% series subject to mandatory redemption in 1996 and 1995, respectively. The Company redeemed and canceled 250,000 shares of the 7.40% series not subject to mandatory redemption in 1996. Cumulative Preferred Stock Not Subject to Mandatory Redemption:
Call Price Shares Amount December 31, Number of Shares Redeemed Outstanding December 31, Series 1997 Year Ended December 31, December 31, 1997 1997 1996 1997 1996 1995 (in thousands) 4-1/2% $110.00 100,685 1,850 - 197,465 $19,747 $29,815 Cumulative Preferred Stock Subject to Mandatory Redemption: Call Price December 31, Number of Shares Redeemed Outstanding December 31, Series(a) 1997 Year Ended December 31, December 31, 1997 1997 1996 1997 1996 1995 (in thousands) 7.80% $ - 500,000 - - - $ - $ 50,000 5.90% (b) (d) 422,900 - - 77,100 7,710 50,000 5.92% (b) (d) 538,500 - - 61,500 6,150 60,000 6.85% (c) (e) 215,500 - - 84,500 8,450 30,000 $22,310 $190,000 (a) The sinking fund provisions of each series have been met by purchase of shares in advance of the due date. (b) Commencing in 2003 and continuing through 2007 the Company may redeem at $100 per share 25,000 shares of the 5.90% series and 30,000 shares of the 5.92% series outstanding under sinking fund provisions at its option and all outstanding shares must be reacquired in 2008. Shares redeemed in 1997 may be applied to meet the sinking fund requirement. (c) 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. Shares redeemed in 1997 may be applied to meet the sinking fund requirement. (d) Not callable until after 2002. (e) Not callable until after 1999.
9. FEDERAL INCOME TAXES: The details of federal income taxes as reported are as follows:
Year Ended December 31, 1997 1996 1995 (in thousands) Charged (Credited) to Operating Expenses (net): Current $66,810 $71,648 $58,676 Deferred (4,801) 1,283 1,715 Deferred Investment Tax Credits (2,697) (2,716) (2,757) Total 59,312 70,215 57,634 Charged (Credited) to Nonoperating Income (net): Current (1,677) (837) (503) Deferred (316) (691) (1,068) Deferred Investment Tax Credits (2,484) (2,886) (2,708) Total (4,477) (4,414) (4,279) Total Federal Income Taxes as Reported $54,835 $65,801 $53,355 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, 1997 1996 1995 (in thousands) Net Income $120,514 $133,689 $115,900 Federal Income Taxes 54,835 65,801 53,355 Pre-tax Book Income $175,349 $199,490 $169,255 Federal Income Taxes on Pre-tax Book Income at Statutory Rate (35%) $61,372 $69,822 $ 59,239 Increase (Decrease) in Federal Income Taxes Resulting From the Following Items: Depreciation 10,945 11,932 14,184 Corporate Owned Life Insurance (3,974) (2,298) (5,304) Removal Costs (4,200) (5,460) (5,040) Investment Tax Credits (net) (5,181) (5,602) (5,465) Other (4,127) (2,593) (4,259) Total Federal Income Taxes as Reported $54,835 $65,801 $ 53,355 Effective Federal Income Tax Rate 31.3% 33.0% 31.5%
The following tables show the elements of the net deferred tax liability and the significant temporary differences giving rise to such deferrals: December 31, 1997 1996 (in thousands) Deferred Tax Assets $ 144,869 $ 137,932 Deferred Tax Liabilities (803,524) (807,896) Net Deferred Tax Liabilities $(658,655) $(669,964) Property Related Temporary Differences $(491,904) $(487,316) Amounts Due From Customers For Future Federal Income Taxes (108,727) (109,259) Deferred State Income Taxes (75,476) (80,201) All Other (net) 17,452 6,812 Total Net Deferred Tax Liabilities $(658,655) $(669,964) 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 United States 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 1996 are presently open and under audit 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 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, 1997 would reduce earnings by approximately $72 million (including interest). Management believes it has meritorious defenses and will vigorously contest any proposed adjustments. No provisions for this amount have been recorded. In the event the Company is unsuccessful it could have a material adverse impact on results of operations and cash flows. 10. COMMON SHAREHOLDER'S EQUITY: The Company received from AEP Co., Inc. cash capital contributions of $40 million, $50 million and $30 million in 1997, 1996 and 1995, respectively, which were credited to paid-in capital. In 1997, 1996 and 1995 net changes in paid-in capital of $(2,332,000), $329,000 and $(9,357,000), respectively, resulted from gains and expenses associated with cumulative preferred stock transactions. There were no other material transactions affecting common stock and paid-in capital accounts in 1997, 1996 and 1995. At December 31, 1997 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, 1997 1996 1995 (in thousands) Cash was paid for: Interest (net of capitalized amounts) $115,508 $104,156 $102,145 Income Taxes $71,749 $82,194 $59,412 Noncash Acquisitions Under Capital Leases $15,266 $15,308 $16,209 12. LONG-TERM DEBT AND LINES OF CREDIT: Long-term debt by major category was outstanding as follows: December 31, 1997 1996 (in thousands) First Mortgage Bonds $1,096,811 $1,056,495 Installment Purchase Contracts 234,217 234,047 Junior Debentures 160,948 72,733 Other Long-term Debt 2,559 2,567 1,494,535 1,365,842 Less Portion Due Within One Year 79,509 8 Total $1,415,026 $1,365,834 First mortgage bonds outstanding were as follows: December 31, 1997 1996 (in thousands) % Rate Due 7.00 1999 - December 1 $ 30,000 $ 30,000 6.35 2000 - March 1 48,000 - 6.71 2000 - June 1 48,000 - 6-3/8 2001 March 1 100,000 100,000 7.95 2002 - March 1 (a) 60,000 60,000 7.38 2002 - August 15 50,000 50,000 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 (b) 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 1 100,000 100,000 9.35 2021 - August 1 - 43,250 8.75 2022 - February 1 29,919 43,000 8.70 2022 - May 22 35,000 35,000 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 (5,108) (5,755) 1,096,811 1,056,495 Less Portion Due Within One Year 60,000 - Total $1,036,811 $1,056,495 (a) Called for early redemption on March 1, 1998. (b) A one time put feature allows this series of bonds to be put back to the Company on November 1, 1999. Consequently the bonds are classified as due in 1999. 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, 1997 1996 (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 (2,783) (2,953) 234,217 234,047 Less Portion Due Within One Year 19,500 - Total $214,717 $234,047 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. Junior debentures outstanding were as follows: December 31, 1997 1996 (in thousands) 8-1/4% Series A due 2026 - September 30 $ 75,000 $75,000 8% Series B due 2027 - March 31 90,000 - Unamortized Discount (4,052) (2,267) Total $160,948 $72,733 Interest may be deferred and payment of principal and interest on the junior debentures is subordinated and subject in right to the prior payment in full of all senior indebtedness of the Company. At December 31, 1997, future annual long-term debt payments are as follows: Amount (in thousands) 1998 $ 79,509 1999 80,004 2000 96,005 2001 100,006 2002 80,006 Later Years 1,070,948 Total Principal Amount 1,506,478 Unamortized Discount 11,943 Total $1,494,535 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, 1997 and 1996 were available in the amounts of $442 million and $409 million, respectively. Facility fees of approximately 1/10 of 1% of the 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, 1997: Notes Payable $ 33,700 6.5% Commercial Paper 96,600 6.8% Total $130,300 6.7% December 31, 1996: Commercial Paper $60,700 7.3% 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, 1997 and 1996 fair values for preferred stock subject to mandatory redemption were $23 million and $192 million and for long-term debt were $1.57 billion and $1.4 billion, respectively. The carrying amounts for preferred stock subject to mandatory redemption were $22 million and $190 million and for long-term debt were $1,495 million and $1,366 million at December 31, 1997 and 1996, 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 (in thousands) 1997 March 31 $416,450 $64,334 $36,484 June 30 373,084 45,397 15,378 September 30 438,510 64,780 34,753 December 31 491,966 65,483 33,899 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 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, 1997 and 1996, and the related consolidated statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 1997. 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, 1997 and 1996, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1997 in conformity with generally accepted accounting principles. /s/ Deloitte & Touche LLP DELOITTE & TOUCHE LLP Columbus, Ohio February 24, 1998 EX-23 6 APCO CONSENT OF DELOITTE & TOUCHE Exhibit 23 INDEPENDENT AUDITORS' CONSENT We consent to the incorporation by reference in Registration Statement Nos. 333-20305 and 333-42593 of Appalachian Power Company on Form S-3 of our reports dated February 24, 1998, appearing in and incorporated by reference in this Annual Report on Form 10-K of Appalachian Power Company for the year ended December 31, 1997. Deloitte & Touche LLP Columbus, Ohio March 25, 1998 EX-24 7 APCO POWER OF ATTORNEY Exhibit 24 POWER OF ATTORNEY APPALACHIAN POWER COMPANY Annual Report on Form lO-K for the Fiscal Year Ended December 31, 1997 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 Sec- tion 13 of the Securities Exchange Act of 1934, for the fiscal year ended December 31, 1997, and any and all amendments thereto, and to file the same, with all exhibits thereto and other docu- ments in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform every act and thing required or necessary to be done, as fully to all intents and purposes as the undersigned might or could do in per- son, 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 28th day of January, 1998. /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 8 ARTICLE UT FIN. DATA SCH. FOR 10-K
UT 0000006879 APPALACHIAN POWER COMPANY 1,000 12-MOS DEC-31-1997 DEC-31-1997 PER-BOOK 3,031,989 35,467 332,776 41,975 441,223 3,883,430 260,458 613,048 207,544 1,081,050 22,310 19,747 1,415,026 33,700 0 96,600 79,509 0 48,552 11,558 1,075,378 3,883,430 1,720,010 67,421 1,412,595 1,480,016 239,994 (222) 239,772 119,258 120,514 7,006 113,508 114,436 81,009 280,513 0 0 All common stock owned by parent company; no EPS required.
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