-----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, AynJdTaPktJblCN2qEnP29v/eJosOc8vOsVhEMJvI+9iH77DuMIE5Uucen5GHAKA tyMOWZBUHXOioDnI/cXiNA== 0000004904-99-000027.txt : 19990330 0000004904-99-000027.hdr.sgml : 19990330 ACCESSION NUMBER: 0000004904-99-000027 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 10 CONFORMED PERIOD OF REPORT: 19981231 FILED AS OF DATE: 19990329 FILER: COMPANY DATA: COMPANY CONFORMED NAME: AMERICAN ELECTRIC POWER COMPANY INC CENTRAL INDEX KEY: 0000004904 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 134922640 STATE OF INCORPORATION: NY FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: SEC FILE NUMBER: 001-03525 FILM NUMBER: 99575955 BUSINESS ADDRESS: STREET 1: 1 RIVERSIDE PLZ CITY: COLUMBUS STATE: OH ZIP: 43215 BUSINESS PHONE: 6142231000 FORMER COMPANY: FORMER CONFORMED NAME: KINGSPORT UTILITIES INC DATE OF NAME CHANGE: 19660906 10-K 1 AEP 10-K FOR 1998 1 ================================================================================ 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, 1998 [ ] 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) 1 Riverside Plaza Columbus, Ohio 43215 Telephone (614) 223-1000 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 [X}. No. 2 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 7.30% Senior Notes, Series B, 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 7.60% Junior Subordinated Deferrable Interest Debentures, Series B, Due 2038...........................................New.York.Stock.Exchange Kentucky Power 8.72% Junior Subordinated Deferrable Company 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 7 3/8% Senior Notes, Series A, Due 2038......................................... 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 (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 (229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in the definitive information statements of Appalachian Power Company or Ohio Power Company incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X] 3 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 1, 1999 FEBRUARY 1, 1999 ------------------------ ------------------ AEP Generating Company None 1,000 ($1,000 par value) American Electric Power Company, Inc $8,177,004,087 191,835,873 ($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). 4
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 Part II ended December 31, 1998: 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 Part III 1999 Annual Meeting of Shareholders, to be filed within 120 days after December 31, 1998 Portions of Information Statements of the following companies for 1999 Part III Annual Meeting of Shareholders, to be filed within 120 days after December 31, 1998 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. ================================================================================ 5
TABLE OF CONTENTS PAGE NUMBER ------ Glossary of Terms........................................................................ i Forward-Looking Information.............................................................. 1 PART I Item 1. Business............................................................. 2 Item 2. Properties........................................................... 36 Item 3. Legal Proceedings.................................................... 42 Item 4. Submission of Matters to a Vote of Security Holders.................. 43 Executive Officers of the Registrants.............................................. 43 PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters............................................. 45 Item 6. Selected Financial Data.............................................. 46 Item 7. Management's Discussion and Analysis of Results of Operations and Financial Condition............................... 46 Item 7A. Quantitative and Qualitative Disclosures About Market Risk .......... 47 Item 8. Financial Statements and Supplementary Data.......................... 47 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure........................... 47 PART III Item 10. Directors and Executive Officers of the Registrants.................. 48 Item 11. Executive Compensation............................................... 50 Item 12. Security Ownership of Certain Beneficial Owners and Management.................................................. 54 Item 13. Certain Relationships and Related Transactions....................... 55 PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K..................................................... 55 Signatures............................................................................... 57 Index to Financial Statement Schedules................................................... S-1 Independent Auditors' Report............................................................. S-2 Exhibit Index............................................................................ E-1
6 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. 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.
i 7 [THIS PAGE INTENTIONALLY LEFT BLANK] 8 FORWARD-LOOKING INFORMATION - -------------------------------------------------------------------------------- This report made by AEP and certain of its subsidiaries 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 from forward-looking statements are: o Electric load and customer growth. o Abnormal weather conditions. o Available sources and costs of fuels. o Availability of generating capacity. o The impact of the proposed merger with CSW including any regulatory conditions imposed on the merger or the inability to consummate the merger with CSW. o The speed and degree to which competition is introduced to our power generation business. o The structure and timing of a competitive market and its impact on energy prices or fixed rates. o The ability to recover stranded costs in connection with possible deregulation of generation. o New legislation and government regulations. o The ability of AEP to successfully control its costs. o The success of new business ventures. o International developments affecting AEP's foreign investments. o The economic climate and growth in AEP's service territory. o Unforeseen events affecting AEP's nuclear plant which is on an extended safety related shutdown. o Problems or failures related to Year 2000 readiness of computer software and hardware. o Inflationary trends. o Electricity and gas market prices. o Interest rates o Other risks and unforeseen events. 1 9 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 worldwide as discussed in New Business Development. The service area of AEP's electric utility subsidiaries covers portions of the states of Indiana, Kentucky, Michigan, Ohio, Tennessee, Virginia and West Virginia. The generating and transmission facilities of AEP's subsidiaries are physically interconnected, and their operations are coordinated, as a single integrated electric utility system. Transmission networks are interconnected with extensive distribution facilities in the territories served. The electric utility subsidiaries of AEP have traditionally provided electric service, consisting of generation, transmission and distribution, on an integrated basis to their retail customers. As a result of the changing nature of the electric business (see Competition and Business Change), effective January 1, 1996, AEP's subsidiaries realigned into four functional business units: Power Generation; Nuclear Generation; Energy Delivery; and Corporate Development. In addition, the electric utility subsidiaries began to do business as "American Electric Power." The legal and financial structure of AEP and its subsidiaries, however, did not change. At December 31, 1998, the subsidiaries of AEP had a total of 17,943 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 888,000 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, 1998, APCo and its wholly owned subsidiaries had 3,577 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 640,000 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, 1998, CSPCo had 1,528 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 554,000 customers in northern and eastern Indiana and southwestern Michigan, and in supplying electric power at wholesale to other electric utility 2 10 companies, rural electric cooperatives and municipalities. At December 31, 1998, I&M had 3,074 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 170,000 customers in an area in eastern Kentucky, and in supplying electric power at wholesale to other utilities and municipalities in Kentucky. At December 31, 1998, KEPCo had 541 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 44,000 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, 1998, Kingsport Power Company had 65 employees. OPCo (organized in Ohio in 1907 and re-incorporated in 1924) is engaged in the generation, sale, purchase, transmission and distribution of electric power to approximately 685,000 customers in the northwestern, east central, eastern and southern sections of Ohio, and in supplying electric power at wholesale to other electric utility companies and municipalities. At December 31, 1998, OPCo and its wholly owned subsidiaries had 4,170 employees. Among the principal industries served by OPCo are primary metals, rubber and plastic products, stone, clay, glass and concrete products, petroleum refining and chemicals. 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 42,000 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, 1998, Wheeling Power Company had 80 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 3 11 the FERC under the Federal Power Act in respect of rates for interstate sale at wholesale and transmission of electric power, accounting and other matters and construction and operation of hydroelectric projects. I&M is subject to regulation by the NRC under the Atomic Energy Act of 1954, as amended, with respect to the operation of the Cook Plant. Possible Change to PUHCA The provisions of PUHCA, administered by the SEC, regulate all aspects of a registered holding company system, such as the AEP System. PUHCA requires that the operations of a registered holding company system be limited to a single integrated public utility system and such other businesses as are incidental or necessary to the operations of the system. In addition, PUHCA governs, among other things, financings, sales or acquisitions of assets and intra-system transactions. On June 20, 1995, the SEC released a report from its Division of Investment Management recommending a conditional repeal of PUHCA, including its limits on financing and on geographic and business diversification. Specific federal authority, however, would be preserved over access to the books and records of registered holding company systems, audit authority over registered holding companies and their subsidiaries and oversight over affiliate transactions. This authority would be transferred to the FERC. 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. Such legislation has been reintroduced in 1999. It is expected that a number of bills contemplating the restructuring of the electric utility industry will be introduced in the current Congress. See Competition and Business Change. If PUHCA is repealed, registered holding company systems, including the AEP System, will be able to compete in the changing industry without the constraints of PUHCA. Management of AEP believes that removal of these constraints would be beneficial to the AEP System. PUHCA and the rules and orders of the SEC currently require that transactions between associated companies in a registered holding company system be performed at cost with limited exceptions. Over the years, the AEP System has developed numerous affiliated service, sales and construction relationships and, in some cases, invested significant capital and developed significant operations in reliance upon the ability to recover its full costs under these provisions. Legislation has been introduced in Congress to repeal PUHCA or modify its provisions governing intra-system transactions. The effect of repeal or amendment of PUHCA on AEP's intra-system transactions depends on whether the assurance of full cost recovery is eliminated immediately or phased-in and whether it is eliminated for all intra-system transactions or only some. If the cost recovery assurance is eliminated immediately for all intra-system transactions, it could have a material adverse effect on results of operations and financial condition of AEP and OPCo. Conflict of Regulation Public utility subsidiaries of AEP can be subject to regulation of the same subject matter by two or more jurisdictions. In such situations, it is possible that the decisions of such regulatory bodies may conflict or that the decision of one such body may affect the cost of providing service and so the rates in another jurisdiction. In a case involving OPCo, the U.S. Court of Appeals for the District of Columbia held that the determination of costs to be charged to associated companies by the SEC under PUHCA precluded the FERC from determining that such costs were unreasonable for ratemaking purposes. The U.S. Supreme Court also has held that a state commission may not conclude that a FERC approved wholesale power agreement is unreasonable for state ratemaking purposes. Certain actions that would overturn these decisions or otherwise affect the jurisdiction of the SEC and FERC are under consideration by the U.S. Congress and these regulatory bodies. Such conflicts of jurisdiction often result in litigation and, if resolved adversely to a public utility subsidiary of AEP, could have a material adverse effect on the results of operations or financial condition of such subsidiary or AEP. 4 12 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, 1998 are as follows:
AEP AEGCO APCO CSPCO I&M KEPCO OPCO SYSTEM (a) -------- ---------- ---------- ---------- -------- ---------- ---------- (IN THOUSANDS) Retail Residential Without Electric Heating......... $ 0 $ 230,160 $ 335,270 $ 265,442 $ 40,190 $ 287,219 $ 1,179,792 With Electric Heating............ 0 328,623 104,905 108,950 64,516 139,052 781,659 -------- ---------- ---------- ---------- -------- ---------- ---------- Total Residential............ 0 558,783 440,175 374,392 104,706 426,271 1,961,451 Commercial.......................... 0 284,206 394,363 290,149 60,115 276,135 1,343,426 Industrial.......................... 0 381,733 148,463 370,329 94,186 670,757 1,727,109 Miscellaneous....................... 0 34,505 17,115 6,849 877 8,230 71,240 -------- ---------- ---------- ---------- -------- ---------- ---------- Total Retail.................. 0 1,259,227 1,000,116 1,041,719 259,884 1,381,393 5,103,226 Wholesale (sales for resale)........... 223,821 350,014 145,376 321,771 87,401 644,058 1,005,481 -------- ---------- ---------- ---------- -------- ---------- ---------- Total from KWH Sales.......... 223,821 1,609,241 1,145,492 1,363,490 347,285 2,025,451 6,108,707 Provision for Revenue Refunds.......... 0 (7,796) 0 0 0 0 (10,044) -------- ---------- ---------- ---------- -------- ---------- ---------- Total Net of Provision for Revenue Refunds........... 223,821 1,601,445 1,145,492 1,363,490 347,285 2,025,451 6,098,663 Other Operating Revenues............... 325 70,799 42,253 42,304 15,714 80,096 247,239 -------- ---------- ---------- ---------- -------- ---------- ---------- Total Electric Operating Revenues............................... $224,146 $1,672,244 $1,187,745 $1,405,794 $362,999 $2,105,547 $6,345,902 ======== ========== ========== ========== ======== ========== ==========
- ---------------------------- (a) Includes revenues of other subsidiaries not shown and 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. Power marketing and trading transactions (trading activities) are conducted by the AEP Power Pool and shared among the parties under the Interconnection Agreement. Trading activities involve the purchase and sale of electricity under physical forward contracts at fixed and variable prices and the trading of electricity contracts including exchange traded futures and options and over-the-counter options and swaps. The majority of these transactions represent physical forward contracts in the AEP System's traditional marketing area and are typically settled by entering into offsetting contracts. The regulated physical forward contracts are recorded on a net basis in the month when the contract settles. In addition, the AEP Power Pool enters into transactions for the purchase and sale of electricity options, futures and swaps, and for the forward purchase and sale of electricity outside of the AEP System's traditional marketing area. These non-regulated trading activities are accounted for on a mark-to-market basis. 5 13 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, 1996, 1997 and 1998: 1996 1997 1998(a) ---- ---- ------- (IN THOUSANDS) APCo.............. $(258,000) $(237,000) $(142,500) CSPCo............. (145,000) (138,000) (146,800) I&M............... 121,000 67,000 ( 86,100) KEPCo............. 2,000 20,000 34,000 OPCo.............. 280,000 288,000 341,400 - ------------------------- (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 Power Pool 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, 1996, 1997 and 1998: 1996(a) 1997(a) 1998(a) ------- ------- ------- (IN THOUSANDS) AEGCo(b)............ $ 26,300 $ 26,200 $ 23,500 APCo(c)............. 36,800 37,500 40,700 CSPCo(c)............ 18,100 18,300 23,000 I&M(c)(d)........... 43,000 42,400 47,800 KEPCo(c)............ 7,600 7,700 8,700 OPCo(c)............. 30,200 30,200 36,900 -------- ------- -------- Total System........ $162,000 $162,300 $180,600 ======== ======== ======== - ----------------------- (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 1996, 1997 and 1998 were made on a short-term basis, except that $33,300,000, $25,900,000 and $38,300,000 respectively, of the contribution to operating income for the total System were from long-term System sales. (d) In addition to its allocation of System sales, the 1996, 1997 and 1998 amounts for I&M include $20,900,000, $21,100,000 and $21,800,000 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 1998 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 1996, customers have given notices of termination, effective in 1999 and 2000, 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 245 megawatts. In June 1993, certain municipal customers of APCo 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 were full-requirements contracts which precluded the customers from purchasing power from third parties until 1998. 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 6 14 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. The customers terminated their contracts with APCo in 1998. 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 Regulation. As discussed below, 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, 1996, 1997 and 1998: 1996 1997 1998 ---- ---- ---- (IN THOUSANDS) APCo.......... $( 6,500) $ ( 8,400) $ 2,400 CSPCo......... (30,600) (29,900) (35,600) I&M........... 46,300 46,100 44,100 KEPCo......... 3,300 2,700 6,000 OPCo.......... (12,500) (10,500) (16,900) 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, 1996, 1997 and 1998: 1996 1997 1998 ---- ---- ---- (IN THOUSANDS) APCo.................... $ 13,800 $ 18,000 $30,600 CSPCo................... 8,000 10,200 18,100 I&M..................... 7,700 10,500 19,200 KEPCo................... 2,800 3,900 6,400 OPCo.................... 17,800 27,200 42,100 -------- -------- -------- Total System............ $ 50,100 $ 69,800 $116,400 ======== ======== ======== 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 transmission system. The orders also require utilities to functionally unbundle their services, by requiring them to use their own tariffs in making off-system and third-party sales. As part of the orders, the FERC issued a pro-forma tariff which reflects the Commission's views on the minimum non-price terms and conditions for non-discriminatory transmission service. In addition, the orders require all transmitting utilities to establish an Open Access Same-time Information System ("OASIS") which electronically posts transmission information such as available capacity and prices, and require utilities to comply with Standards of Conduct which prohibit utilities' system operators from providing non-public transmission information to the utility's merchant employees. The orders also allow a utility to seek recovery of certain prudently-incurred stranded costs that result from unbundled transmission service. On July 9, 1996, the AEP System companies filed a tariff conforming with the FERC's pro-forma transmission tariff, subject to the resolution of certain pricing issues, which are still pending before FERC. 7 15 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. In January 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 and elected not to join the Midwest ISO as a transmission owner member. AEP has since joined the Midwest ISO as a non-owner member. AEP is currently engaged in discussions with Consumers Energy Company, FirstEnergy Corp. and VEPCo regarding the development of a Regional Transmission Organization ("RTO") which may take the form of an independent system operator ("ISO") or an independent transmission company ("Transco"), depending upon the occurrence of certain conditions. The parties envision that the Transco, if formed, would operate transmission assets that it would own, and also would operate other owners' transmission assets on a contractual basis. The discussions are also open to interested stakeholders. The discussions are expected to culminate in a FERC filing during the first part of 1999. See Competition and Business Change -- AEP Position on Competition. OVEC AEP, CSPCo and several unaffiliated utility companies jointly own OVEC, which supplies the power requirements of a uranium enrichment plant near Portsmouth, Ohio owned by the DOE. The aggregate equity participation of AEP and CSPCo in OVEC is 44.2%. The DOE demand under OVEC's power agreement, which is subject to change from time to time, is 1,402,000 kilowatts. On April 1, 1999, 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 1998. 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 26 of the rural electric cooperatives which operate in the State of Ohio at 318 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. OPCo is providing electric service to Century pursuant to a contract approved by the PUCO for the period July 1, 1996 through July 31, 2003. 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. 8 16 AEGCO Since its formation in 1982, AEGCo's business has consisted of the ownership and financing of its 50% interest in the Rockport Plant and, since 1989, leasing of its 50% interest in Unit 2 of the Rockport Plant. The operating revenues of AEGCo are derived from the sale of capacity and energy associated with its interest in the Rockport Plant to I&M, KEPCo and VEPCo, pursuant to unit power agreements. Pursuant to these unit power agreements, AEGCo is entitled to recover its full cost of service from the purchasers and will be entitled to recover future increases in such costs, including increases in fuel and capital costs. See Unit Power Agreements. Pursuant to a capital funds agreement, AEP has agreed to provide cash capital contributions, or in certain circumstances subordinated loans, to AEGCo, to the extent necessary to enable AEGCo, among other things, to provide its proportionate share of funds required to permit continuation of the commercial operation of the Rockport Plant and to perform all of its obligations, covenants and agreements under, among other things, all loan agreements, leases and related documents to which AEGCo is or becomes a party. See Capital Funds Agreement. Unit Power Agreements A unit power agreement between AEGCo and I&M (the I&M Power Agreement) provides for the sale by AEGCo to I&M of all the power (and the energy associated therewith) available to AEGCo at the Rockport Plant. I&M is obligated, whether or not power is available from AEGCo, to pay as a demand charge for the right to receive such power (and as an energy charge for any associated energy taken by I&M) such amounts, as when added to amounts received by AEGCo from any other sources, will be at least sufficient to enable AEGCo to pay all its operating and other expenses, including a rate of return on the common equity of AEGCo as approved by FERC, currently 12.16%. The I&M Power Agreement will continue in effect until the date that the last of the lease terms of Unit 2 of the Rockport Plant has expired unless extended in specified circumstances. Pursuant to an assignment between I&M and KEPCo, and a unit power agreement between KEPCo and AEGCo, AEGCo sells KEPCo 30% of the power (and the energy associated therewith) available to AEGCo from both units of the Rockport Plant. KEPCo has agreed to pay to AEGCo in consideration for the right to receive such power the same amounts which I&M would have paid AEGCo under the terms of the I&M Power Agreement for such entitlement. The KEPCo unit power agreement expires on December 31, 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 1998 was derived from its sales to VEPCo. Capital Funds Agreement AEGCo and AEP have entered into a capital funds agreement pursuant to which, among other things, AEP has unconditionally agreed to make cash capital contributions, or in certain circumstances subordinated loans, to AEGCo to the extent necessary to enable AEGCo to (i) maintain such an equity component of capitalization as required by governmental regulatory authorities, (ii) provide its proportionate share of the funds required to permit commercial operation of the Rockport Plant, (iii) enable AEGCo to perform all of its obligations, covenants and agreements under, among other things, all loan agreements, leases and related documents to which AEGCo is or becomes a party (AEGCo Agreements), and (iv) pay all indebtedness, obligations and liabilities of AEGCo (AEGCo Obligations) under the AEGCo Agreements, other than indebtedness, obligations or liabilities owing to AEP. The Capital Funds Agreement will terminate after all AEGCo Obligations have been paid in full. 9 17 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 and transmission lines 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; availability of capacity; 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. 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 any stranded investment losses. 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 10 18 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. 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 benefited 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 11 19 service territory. A requirement to transmit directly to retail customers would have the result of permitting retail customers to purchase electric power, at the election of such customers, not only from the electric utility in whose service area they are located but from another electric utility, an independent power producer or an intermediary, such as a power marketer. Although AEP's power generation would have competitors under some of these proposals, its transmission and distribution would not. If competition develops in retail power generation, the public utility subsidiaries of AEP believe that they should 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 1999, Senate Bill 648 was introduced in the Indiana Senate on behalf of a group of industrial customers. The bill would allow retail electric customers to choose their electricity supply companies after December 31, 2000. The bill would provide that the IURC would determine each utility's net stranded costs, which would be recovered by a transition charge in effect until no later than December 31, 2005. The bill was not reported out of committee and attempts by the sponsors to amend the bill were unsuccessful. AEP continues to work with other utilities in Indiana to develop a consensus on customer-choice legislation that can be enacted into law in Indiana. The outcome of this effort is uncertain. Kentucky: During the 1998 Regular Session of the Kentucky legislature, the Electric Utility Restructuring Task Force was established by resolution. The 20-member Task Force includes ten members of the General Assembly and ten officials from the Governor's office. The Task Force began monthly meetings in August 1998. At the January 1999 meeting, AEP, the other Kentucky investor-owned public utilities and the Kentucky electric cooperatives were requested to file with the Task Force a description of their non-traditional, unregulated businesses. The final report of the Task Force is due in November 1999, prior to the next regularly scheduled legislative session in 2000. A second Task Force was also established to study the effects of utility restructuring on taxes. This Task Force also has been meeting monthly and will report its findings in November 1999. Several advisory committees have been formed to assist this Task Force in gathering and studying information. The Kentucky investor-owned utilities, including AEP, are represented on each of those committees. At the January meeting, the Task Force voted to retain a consulting firm with extensive experience in utility tax issues to facilitate the proceedings. The KPSC Chairwoman leads 23 state public utility commissions in a coalition entitled Low Cost States Initiative. The coalition's stated purpose is to ensure that the U.S. Congress gives equal consideration to the issues facing low-cost states. The coalition is focusing on the following five issues: o A National Voice. o Low Rates. o Rural Electricity Rates. o Stranded Costs and Benefits. o Economic Development. 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 12 20 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 authorization 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. However, the MPSC has closed the relevant docket and taken no action with regard to AEP's filing. The MPSC has approved, by orders dated January 14, 1998, February 11, 1998 and March 8, 1999, 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: In March 1998, twin proposals on electric industry restructuring were introduced in the Ohio House and Senate. Among other provisions, the bills proposed a fully competitive marketplace in the year 2000, with no phase-in period. The bills were the subject of hearings in the Senate Ways and Means Committee and the House Public Utilities Committee in April-May 1998. However, no additional action was taken with respect to the bills by the end of the legislative session on December 31, 1998. In August 1998, four of Ohio's investor-owned electric utilities - AEP, Cinergy Corp., FirstEnergy and DP&L - announced that they had reached a consensus on a basic alternative framework to deregulate Ohio's electric industry. The proposal called for: o The introduction of customer choice on January 1, 2001. o A freeze on rates during a five-year transition period. o Changes in utility taxes to achieve, among other things, equalized treatment of in-state and out-of-state electricity suppliers. o An opportunity to recover stranded costs during a five-year transition period. In September 1998, the leaders of the House and Senate called for a series of "working study group" meetings involving the various stakeholder groups. The study group's members were encouraged to reconcile their differences and develop a consensus position on industry restructuring. The working study group continues to hold periodic meetings. On January 20, 1999, two new "placeholder" bills were introduced in the Ohio House and Senate declaring the legislature's public policy with respect to electric industry restructuring. On March 8, 1999, a legislative working group released a Summary of Proposed Major Provisions of Electric Restructuring Legislation. It is expected that these provisions will be incorporated into more extensive legislative proposals expected to supplant the placeholder bills. Legislative leaders have publicly indicated their desire to pass restructuring legislation during the current legislative session. Virginia: On February 25, 1999, the legislature passed an electric utility industry restructuring bill and tax reform bill. The restructuring bill requires Virginia utilities to join or establish a regional transmission entity by January 2001, to which such utilities shall transfer the management and control of their transmission systems. The bill provides for a transition to retail customer choice from January 1, 2002 through January 1, 2004. The Virginia SCC can delay or accelerate the implementation of choice based on considerations of reliability, safety, communications or market power, but in no event shall any delay extend the implementation of customer choice beyond January 1, 2005. With limited exceptions, the generation of electricity will no longer be subject to regulation. The bill provides for capped rates, effective January 1, 2001, for a period of time ending as late as July 1, 2007. The capped rates may be terminated 13 21 after January 1, 2004, upon petition of the Virginia SCC by the utility and a finding by the Virginia SCC that an effective competitive market exists. If capped rates continue beyond January 1, 2004, the bill provides for a one-time change in the non-generation components of such rates upon approval by the Virginia SCC. The Virginia SCC also may adjust the capped rates in connection with the utility's recovery of fuel costs, changes in taxation by Virginia, and any financial distress of the utility beyond the utility's control. The restructuring bill provides for recovery of just and reasonable net stranded costs to the extent that such costs exceed zero in total value for any incumbent electric utility through either capped rates or the imposition of a wires charge upon customers who may depart the incumbent in favor of an alternative supplier prior to the termination of the rate cap. A ten-member legislative task force, to serve from July 1, 1999 through July 1, 2005, will monitor the work of the Virginia SCC, determine the discontinuance of capped rates and review related matters. The task force will report annually to the Governor and legislature. The tax bill provides for replacement of gross receipts and certain other taxes by (i) a consumption tax levied upon customers on the basis of kilowatt-hour usage and (ii) a state corporate net income tax. The intention of the tax bill is to achieve approximate revenue neutrality for Virginia. 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 authorizing the West Virginia PSC to proceed with the development of a plan for electric industry restructuring, 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. Following the passage of the restructuring legislation, the West Virginia PSC closed the 1996 general investigation and commenced a new proceeding to carry out its obligations under the legislation. On April 20, 1998, the West Virginia PSC initiated a general investigation to determine whether West Virginia should adopt a restructuring plan. Workshops were held throughout the summer of 1998 and on November 24, 1998, the West Virginia PSC held a hearing at which the West Virginia PSC was advised that the participants involved in the general investigation had been unable to reach a consensus on a restructuring plan. The West Virginia PSC then issued a procedural order on December 23, 1998, establishing dates beginning in June 1999 for pre-filed testimony, responsive testimony, hearing dates and briefs regarding the issues of codes of conduct, universal service, class subsidies and generation plant valuation. 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 has expanded its business to non-regulated energy activities through several subsidiaries, including AEP Energy Services, Inc. (AEPES), AEP Resources, Inc. (Resources), AEP Resources Service Company (RESCo) and AEP Communications, LLC (AEP Communications). 14 22 AEPES AEPES markets and trades natural gas and provides gas storage and transportation services. Resources 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. Resources has business development offices in London, Beijing, Singapore, Sydney, Toronto, Washington and Houston. Resources has a 50% interest in Yorkshire Electric Group plc (Yorkshire Electricity) with an indirect wholly-owned subsidiary of New Century Energies, Inc. Yorkshire Electricity is a United Kingdom independent regional electricity company. It is principally engaged in the distribution of electricity to 2.2 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. Unit 1 went into service in February 1999 and Unit 2 is expected to go into service in the third quarter of 1999. Resources' share of the total cost of the project of $190,000,000 is estimated to be approximately $110,000,000. In March 1998, Resources, through AEP Resources Australia Pty., Ltd., a special purpose subsidiary of Resources, acquired a 20% interest in Pacific Hydro Limited for $10,000,000. Pacific Hydro is principally engaged in the development and operation of, and ownership of interests in, hydroelectric facilities in the Asia Pacific region. Currently, Pacific Hydro has interests in six hydroelectric units that operate or are under construction in Australia and the Philippines. The hydroelectric facilities in which Pacific Hydro had interests as of December 31, 1998 (including those under construction) had total design capacity of approximately 178 megawatts. In December 1998, Resources, through wholly-owned subsidiaries, acquired CitiPower Pty., an electric distribution and retail sales company in Victoria, Australia, for $1,100,000,000. CitiPower serves approximately 240,000 customers in the city of Melbourne. With about 3,100 miles of distribution lines in a service area that covers approximately 100 square miles, CitiPower distributes about 4,800 gigawatt-hours annually. In December 1998, Resources acquired from Equitable Resources, Inc. midstream gas operations for approximately $340,000,000 including working capital funds. The gas trading and marketing group included in this purchase was acquired by AEPES. Assets acquired include: o A 2,000-mile intrastate pipeline system in Louisiana. o Four natural gas processing plants that straddle the pipeline. o Jefferson Island storage facility, including an existing salt dome storage cavern and a second cavern under construction, both directly connected to the Henry Hub, the most active gas trading area in North America. The pipeline and storage facility are interconnected to 15 interstate and 23 intrastate pipelines. RESCo RESCo offers engineering, construction, project management and other consulting services for projects involving transmission, distribution or generation of electric power both domestically and internationally. 15 23 AEP Communications AEP Communications markets energy information, wireless tower infrastructure and fiber optic services. In 1998, AEP Communications launched DatapultSM, a portfolio of energy information data and analysis tools designed to help customers identify energy- and cost-saving opportunities. AEP Communications also is expanding its fiber optic network and marketing dedicated telecommunications bandwidth to other carriers. AEP Power Marketing 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 requested FERC to clarify that the applicability of this condition relates only to transactions between AEP utility subsidiaries and AEPPM. In 1998, FERC granted the requested clarification. AEPPM has not entered into any transactions to date. However, the AEP System is engaged in regulated power marketing and trading within its traditional marketing area through its Power Pool and in non-regulated financial derivative power trading activities conducted by the Power Pool but recorded in non-operating income by the AEP Power Pool member companies. SEC Limitations AEP has received approval from the SEC under PUHCA to issue and sell securities in an amount up to 100% of its average quarterly consolidated retained earnings balance (such average balance was approximately $1,674,000,000 for the twelve months ended December 31, 1998) for investment in exempt wholesale generators and foreign utility companies. Resources expects to continue its pursuit of new and existing energy generation and delivery projects worldwide. SEC Rule 58 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. Risk These continuing efforts to invest in and develop new business opportunities offer the potential of earning returns which may exceed those of traditional AEP rate-regulated operations. However, they also involve a higher degree of risk which must be carefully considered and assessed. AEP may make additional substantial investments in these and other new businesses. Reference is made to Market Risks under Item 7A herein for a discussion of certain market risks inherent in AEP business activities. 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 the receipt of required regulatory approvals. Assuming the receipt of all required approvals, completion of the merger is anticipated to occur by the end 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 16 24 states of Texas, Oklahoma, Louisiana and Arkansas and a regional electricity company in the United Kingdom. CSW also owns other international energy operations and non-regulated subsidiaries involved in energy-related investments, energy efficiency services and financial transactions. CONSTRUCTION PROGRAM New Generation The AEP System is continuously involved in assessing the adequacy of its generation, transmission, distribution and other facilities to plan and 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, 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's generation resources include: o Rerating of the Smith Mountain pumped storage hydroelectric plant (36-megawatt increase). o Purchase from an independent power producer's hydro project with an expected capacity value of 28 megawatts. o Expiration of the Rockport Unit 1 sale of 455 megawatts to VEPCo on December 31, 1999 (see AEGCo). Apart from these changes and temporary power purchases that can be arranged, 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 2003. 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 extent of the need of AEP's operating companies for any additional generation resources in the foreseeable future is highly uncertain. Proposed Transmission Facilities 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. West Virginia: On May 27, 1998, the West Virginia PSC issued an order granting APCo's application for a certificate with respect to the preferred route for the Wyoming-Cloverdale 765,000-volt line. Virginia: By Hearing Examiner's Ruling of June 9, 1998, the procedural schedule for the certificate in Virginia was suspended for 90 days to allow APCo to conduct additional studies. On August 21, 1998, APCo filed a report stating that a two-phased alternative project could provide electrical transmission reinforcement comparable to the Wyoming-Cloverdale line. By Hearing Examiner's Ruling of September 22, 1998, the proceeding was continued and APCo was directed to study the first phase of the alternative 17 25 project, involving a line running from Wyoming Station in West Virginia to APCo's existing Jacksons Ferry Station in Virginia or any point on the Jacksons Ferry-Cloverdale 765kV transmission line. APCo estimates that the Wyoming-Jacksons Ferry line would be between 82-100 miles in length, including 32 miles in West Virginia previously certified. APCo must file its study by June 1, 1999. The Hearing Examiner also ordered APCo and the Virginia SCC Staff to provide at the evidentiary hearing information on generation alternatives, specifically natural gas generation, to APCo's proposed transmission line. If the Virginia SCC grants a certificate for the Wyoming-Jacksons Ferry line, APCo will have to amend its certificate from West Virginia. Proposed Completion Schedule: If the Virginia SCC and West Virginia PSC issue the required certificates, APCo will cooperate with the Forest Service to complete the EIS process and obtain the federal permits. Management estimates that neither project can be completed before the winter of 2003-2004. However, given the findings in the Draft EIS, APCo cannot presently predict the schedule for completion of the state and federal permitting process. 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 1996, 1997 and 1998 and their current estimate of 1999 construction expenditures, in each case including AFUDC but excluding nuclear fuel and other assets acquired under leases. The construction expenditures for the years 1996-1998 were, and it is anticipated that the estimated construction expenditures for 1999 will be, approximately: 1996 1997 1998 1999 ACTUAL ACTUAL ACTUAL ESTIMATE ------ ------ ------ -------- (IN THOUSANDS) AEP System (a).. $578,000 $762,000 $792,100 $820,100 AEGCo........ 2,200 3,900 6,600 6,300 APCo......... 192,900 218,100 204,900 254,600 CSPCo........ 93,600 108,900 115,300 94,500 I&M.......... 90,500 123,400 148,900 151,800 KEPCo........ 75,800 66,700 43,800 42,500 OPCo......... 113,800 172,700 185,200 201,000 - ----------------------- (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, environmental requirements and other factors. Changes in construction schedules and costs, and in estimates and projections of needs for additional facilities, as well as variations from currently anticipated levels of net earnings, Federal income and other taxes, and other factors affecting cash requirements, may increase or decrease the estimated capital requirements for the System's construction program. From time to time, as the System companies have encountered the industry problems described above, such companies also have encountered limitations on their ability to secure the capital necessary to finance construction expenditures. Environmental Expenditures: Expenditures related to compliance with air and water quality standards, included in the gross additions to plant of the System, during 1996, 1997 and 1998 and the current estimate for 1999 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. 1996 1997 1998 1999 ACTUAL ACTUAL ACTUAL ESTIMATE ------ ------ ------ -------- (IN THOUSANDS) AEGCo............. $ 0 $ 0 $ 800 $ 0 APCo.............. 10,500 9,100 25,000 36,100 CSPCo............. 1,800 1,300 5,300 3,600 I&M............... 0 100 13,000 6,700 KEPCo............. 100 1,300 4,600 400 OPCo.............. 1,600 11,800 27,100 32,100 AEP System..... $14,000 $23,600 $75,800 $78,900 ======= ======= ======= ======= 18 26 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 cash capital contributions by AEP. It has been the practice of AEP, in turn, to finance cash capital contributions to the common stock equities of its subsidiaries by issuing unsecured short-term debt, principally commercial paper, and then to sell additional shares of Common Stock of AEP for the purpose of retiring the short-term debt previously incurred. In 1998, AEP issued approximately 1,193,000 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 1996-1998, net external funds from financings and capital contributions by AEP amounted, with respect to APCo and KEPCo, to approximately 23% and 75%, 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 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, 1999, 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........................... $500 $80 $325 $300 $300 $150 $400 $2,115 ==== === ==== ==== ==== ==== ==== ====== Amount outstanding: Notes payable......................... $ -- $24 $ 34 $ -- $ -- $ 5 $ -- $ 197 Commercial paper...................... 78 -- 42 52 109 15 123 419 ---- --- ---- ---- ---- ---- ---- ------ $ 78 $24 $ 76 $ 52 $109 $ 20 $123 $ 616 ==== === ==== ==== ==== ==== ==== ======
- ------------------ (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, it is necessary for APCo, CSPCo, I&M, KEPCo and OPCo to comply with earnings coverage requirements contained in their respective mortgages. The most restrictive of these provisions generally requires, 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 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 at certain times restricted the ability of one or more of the above subsidiaries of AEP to issue senior securities. 19 27 The respective mortgage coverages of APCo, CSPCo, I&M, KEPCo and OPCo under their respective mortgage provisions, calculated on the foregoing basis and in accordance with the respective amounts then recorded in the accounts of the companies, were at least those stated in the following table: DECEMBER 31, ------------ 1996 1997 1998 ---- ---- ---- APCo Mortgage coverage............. 3.98 3.72 3.88 CSPCo Mortgage coverage............. 4.44 4.95 6.36 I&M Mortgage coverage............. 6.66 7.57 6.39 KEPCo Mortgage coverage............. 3.22 4.23 4.40 OPCo Mortgage coverage............. 8.27 9.74 9.40 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 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. New projects undertaken by AEP Resources and its subsidiaries are generally financed through equity funds provided by AEP, non-recourse debt incurred on a project-specific basis, debt issued by AEP Resources or through a combination thereof. See New Business Development and Item 7 for additional information concerning AEP Resources and its subsidiaries. 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. However, the rates of AEP's operating subsidiaries in those states continue to be cost-based. 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 20 28 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. In addition, current rate regulation may be subject to significant revision. See Competition and Business Change. Investigations of June 1998 Pricing Abnormalities During the week of June 22-26, 1998, wholesale electric power markets in the Midwest exhibited unprecedented price volatility due to several market factors, including an extended period of unseasonably hot weather, scheduled and unplanned generating unit outages, transmission constraints, and defaults by certain power marketers on their supply obligations. The simultaneous culmination of these events resulted in temporary but extreme price spikes in the hourly and daily markets. As a result of this situation, the FERC, IURC and PUCO initiated separate investigations into the price increase. After completing their reviews, these commissions concluded that the pricing abnormalities were due to the unusual conditions that occurred during that time. The FERC Staff report issued in September 1998 did not find evidence that firm service to consumers was compromised anywhere in the Midwest during the period of the pricing abnormalities. The FERC reserved the right to conduct further investigations on a company-specific basis. AEP is unable to predict what, if any, further action may be taken by the FERC in respect of this matter. No assurance can be given that the FERC will not take enforcement action in this connection. 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 (ALJ) issued an initial decision affirming the terms of APCo's filing except for APCo's requested return on common equity of 12.75% which the ALJ found should be 10.1%. On June 29, 1998, the FERC issued its order affirming the ALJ's decision except the return on common equity, which the FERC approved at 9.95%. On July 29, 1998, APCo filed with the FERC a request for rehearing of the FERC's order. At December 31, 1998, APCo had accrued a refund liability, including interest, of $42,800,000. 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. 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. On February 18, 1999, the Virginia SCC approved a stipulation and settlement agreement among APCo, the Virginia SCC Staff and consumer and major industrial customer representatives that provides for the following: o Elimination of the $30,500,000 annual increase in base rates that has been collected subject to refund since mid-November 1997. o During the period January 1, 1998 through December 31, 2000: o Reduction in base rates of $6,000,000 from the level in effect prior to the November 1997 increase, with the expectation that rates would remain at the agreed-upon levels. 21 29 o APCo's commitment to invest at least $90,000,000 in Virginia distribution facilities to maintain the overall quality and reliability of electric service. o Benchmark rate of return on equity of 10.85% with one-third of earnings above that level to be retained by APCo and the remaining two-thirds to be refunded to ratepayers. o Refund with interest of all amounts collected above the approved rates. At December 31, 1998, APCo had accrued a refund liability, including interest, of $51,600,000. 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 overrecoveries will be treated in a manner to be determined by the West Virginia PSC, except that ENEC overrecoveries during each calendar year through December 31, 1999, in excess of $10,000,000 per period, will be accumulated and shared equally between APCo and its ratepayers. CSPCo Zimmer Plant: The Zimmer Plant was placed in commercial operation as a 1,300-megawatt coal-fired plant on March 30, 1991. CSPCo owns 25.4% of the Zimmer Plant with the remainder owned by two unaffiliated companies, CG&E (46.5%) and DP&L (28.1%). 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 Reference is made to Cook Nuclear Plant --Cook Plant Shutdown under Item 2 herein for a discussion of recovery of fuel costs. 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 fixed the electric fuel component 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 predetermined price agreement following shutdown. Management intends to seek from non-Ohio jurisdictional ratepayers recovery of the non-Ohio jurisdictional portion of any remaining investment in, and the liabilities and closing costs of, OPCo's Muskingum, Windsor and Meigs 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 $17,000,000 for Muskingum, $14,000,000 for Windsor and $68,000,000 for Meigs, after tax at December 31, 1998. 22 30 Management anticipates closing the Muskingum mine in October 1999, Windsor mine in December 2000 and Meigs mine in December 2001. The Muskingum mine supplies coal to Muskingum River Plant and the Windsor mine supplies coal to Cardinal Plant Unit 1. These mines are closing, in part, as a result of compliance with the Phase II requirements of the Clean Air Act Amendments of 1990 (see Environmental and Other Matters -- Air Pollution Control -- Acid Rain). The mines could close earlier 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 Muskingum, Windsor and Meigs mines, including amounts deferred, can be recovered, AEP's and OPCo's results of operations would be adversely affected. FUEL SUPPLY The following table shows the sources of power generated by the AEP System: 1994 1995 1996 1997 1998 ---- ---- ---- ---- ---- Coal..................... 91% 88% 87% 92% 99% Nuclear.................. 8% 11% 12% 7% 0% Hydroelectric and other.. 1% 1% 1% 1% 1% Variations in the generation of nuclear power are primarily related to refueling outages and, in 1997 and 1998, the shutdown of the Cook Plant to respond to issues raised by the NRC. See Cook Nuclear Plant -- 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. 23 31 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 an affiliated terminal on the Ohio River for transloading to barges for delivery to generating stations on the river. Subsidiaries of AEP lease approximately 3,593 coal hopper cars to be used in unit train movements, as well as 14 towboats, 352 jumbo barges and 145 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:
1994 1995 1996 1997 1998 ---- ---- ---- ---- ---- Total coal delivered to AEP operated plants (thousands of tons)....................... 49,024 46,867 51,030 54,292 54,004 Sources (percentage): Subsidiaries.................................................. 15% 14% 13% 14% 14% Long-term contracts........................................... 65% 75% 71% 66% 66% Spot or short-term purchases.................................. 20% 11% 16% 20% 20% Average price per ton of spot-purchased coal..................... $23.00 $25.15 $23.85 $24.38 $25.05
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:
1994 1995 1996 1997 1998 ---- ---- ---- ---- ---- DOLLARS PER TON --------------- AEP System Companies........................................... $ 33.95 $ 32.52 $ 31.70 $ 31.77 $ 32.60 AEGCo....................................................... 18.59 18.80 18.22 19.30 19.37 APCo........................................................ 39.89 38.86 37.60 36.09 34.81 CSPCo....................................................... 32.80 33.23 31.70 31.69 31.63 I&M......................................................... 22.85 23.25 22.99 23.68 22.61 KEPCo....................................................... 26.83 26.91 27.25 26.76 27.42 OPCo........................................................ 41.10 37.58 35.96 36.00 38.94 CENTS PER MILLION BTU'S ----------------------- AEP System Companies........................................... 152.41 145.26 140.48 140.23 143.51 AEGCo....................................................... 112.06 112.87 109.25 115.21 112.63 APCo........................................................ 161.37 156.96 152.54 146.54 141.76 CSPCo....................................................... 140.45 140.79 134.60 134.44 134.15 I&M......................................................... 123.62 125.50 121.16 123.36 118.02 KEPCo....................................................... 113.40 114.77 114.42 110.37 112.15
24 32 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, 1998, the System's coal inventory was approximately 38 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 1998 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 1998 to these units. Reference is made to Environmental and Other Matters for information concerning current emissions limitations in the AEP System's various jurisdictions and the effects of the Clean Air Act Amendments.
AVERAGE SULFUR CONTENT ESTIMATED REQUIRE- OF DELIVERED COAL TOTAL CONSUMPTION MENTS FOR REMAINDER ----------------------------- DURING 1998 OF USEFUL LIVES POUNDS OF SO2 (IN THOUSANDS OF TONS) (IN MILLIONS OF TONS) BY WEIGHT PER MILLION BTU'S ---------------------- --------------------- --------- ----------------- AEGCo (a).............. 4,966 253 0.3% 0.7 APCo................... 11,813 454 0.8% 1.3 CSPCo.................. 6,359(b) 249(b) 2.8% 4.7 I&M (c)................ 6,956 293 0.8% 1.5 KEPCo.................. 3,044 94 1.2% 1.9 OPCo................... 20,648 654 2.3% 3.9
- ------------------------ (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 1998, 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 2,400,000 tons per year through 1999. 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 48,685,543 tons expires on December 31, 2014 and another contract with remaining deliveries of 37,785,000 tons expires on December 31, 2004. 25 33 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 1999. 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 containing approximately 190,000,000 tons of clean recoverable coal and ranging in sulfur content between 3.4% and 4.5% sulfur by weight (weighted average, 3.8%), which reserves are presently being mined. 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 2.7%). 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 101,000,000 tons of clean recoverable coal ranging in sulfur content between 1.4% and 4.0% sulfur by weight (weighted average, 2.1%) of which approximately 24,000,000 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: o Mining and milling of uranium ore to uranium concentrates. o Conversion of uranium concentrates to uranium hexafluoride. o Enrichment of uranium hexafluoride. o Fabrication of fuel assemblies. o Utilization of nuclear fuel in the reactor. o Reprocessing or other disposition of spent fuel. Steps currently are being taken, based upon the planned fuel cycles for the Cook Plant, to review and evaluate I&M's requirements for the supply of nuclear fuel. I&M has made and will make purchases of uranium in various forms in the spot, short-term, and mid-term markets until it decides that deliveries under long-term supply contracts are warranted. For purposes of the storage of high-level radioactive waste in the form of spent nuclear fuel, I&M has completed modifications to its spent nuclear fuel storage pool. AEP anticipates that the Cook Plant has storage capacity to permit normal operations through 2012. 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 $72,000,000, exclusive of interest of $118,000,000 at December 31, 1998. The aggregate amount has been recorded as 26 34 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, 1998, 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 disposal would be deposited into I&M's nuclear decommissioning trust funds. On May 30, 1995, I&M and a group of unaffiliated utilities owning and operating nuclear plants filed a petition for review in the U.S. Court of Appeals for the District of Columbia Circuit requesting that the court issue a declaration that the Nuclear Waste Policy Act of 1982 (NWPA) imposes on DOE an unconditional obligation to begin acceptance of spent nuclear fuel and high level radioactive waste by January 31, 1998. On July 23, 1996, the court ruled that the NWPA creates an obligation for 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. On June 8, 1998, I&M filed a complaint in the U.S. Court of Federal Claims seeking damages in excess of $150,000,000 due to the U.S. Department of Energy's partial material breach of its unconditional contractual deadline to begin disposing of spent nuclear fuel and high level nuclear waste generated by the Cook Nuclear Plant. Similar lawsuits have been filed by other utilities. 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 $29,000,000 in 1998, $28,000,000 in 1997, and $27,000,000 in 1995. At December 31, 1998, I&M had recognized a decommissioning liability of $446,000,000. 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. 27 35 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 the: o Type of decommissioning plan selected. o Escalation of various cost elements (including, but not limited to, general inflation). o Further development of regulatory requirements governing decommissioning. o Limited availability to date of significant experience in decommissioning such facilities. o Technology available at the time of decommissioning differing significantly from that assumed in these studies. o 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. As a result, 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 progress with the site selection process has been inhibited by many factors, and management is unable to predict when a new disposal site for Michigan low-level waste will be available. On July 1, 1995, the disposal site in South Carolina reopened to accept waste from most areas of the U.S., including Michigan. This was the first opportunity for the Cook Plant to dispose of low-level waste since 1990. To the extent practicable, the waste formerly placed in storage and the waste presently generated are now being sent to the disposal site. Energy Policy Act -- Nuclear Fees The Energy Policy Act of 1992 (Energy Act), contains a provision to fund the decontamination and decommissioning of uranium enrichment facilities formerly owned by DOE. Funding is to be provided from a combination of sources including assessments against electric utilities which purchased enrichment services from DOE facilities. I&M's remaining estimated liability is $35,521,000, subject to inflation adjustments, and is payable in annual assessments over the next eight years. I&M recorded a regulatory asset concurrent with the recording of the liability. The payments are being recorded and recovered as fuel expense over a 15-year period ending in 2007. I&M joined with 22 other utility plaintiffs in filing a complaint in the U.S. District Court for the Southern District of New York seeking a declaratory judgment that the annual decontamination and decommissioning assessments are unconstitutional. I&M's claims for refund of previously paid assessments remain pending in the U.S. Court of Federal Claims. I&M is seeking to stay the Court of Federal Claims action pending the outcome of the District Court action. 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. In addition to imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. 28 36 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. 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. See NOx SIP Call below. In July 1997, Federal EPA revised the ozone and particulate matter National Ambient Air Quality Standards (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. In August and September 1997 the AEP System operating companies joined with certain other utilities to appeal the revised NAAQS by filing petitions for review in the U.S. Court of Appeals for the District of Columbia Circuit. Oral argument was held in December 1998. 29 37 In September 1998, Federal EPA issued 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. per megawatt-hour net energy output) for coal-fired boilers as for gas-fired boilers. The emission limit is set at a level which cannot currently be achieved by combustion controls and will require the use of post combustion control equipment. The final rule effectively requires selective catalytic reduction or comparable technology to control NOx emissions from new or modified coal-fired boilers. Imposition of this standard to existing sources which might become subject to the rule based on an administrative finding that an existing source had been modified or reconstructed could result in substantial capital and operating expenditures. On October 30, 1998, the AEP System operating companies joined with certain other utilities to appeal the revised regulations by filing petitions for review in the U.S. Court of Appeals for the District of Columbia Circuit. NOx SIP Call: On October 27, 1998, Federal EPA published in the Federal Register a final rule (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 NOx transport SIP call establishes state-by-state NOx emission budgets for the five-month ozone season to be met by the year 2003. The NOx budgets apply to 22 eastern states and are premised mainly on the assumption of controlling power plant NOx emissions to 0.15 lb. per million Btu (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 SIP call was accompanied by a proposed Federal Implementation Plan which could be implemented in any state which fails to submit an approvable SIP by September 1999. The NOx reductions called for by Federal EPA are targeted at coal-fired electric utilities and may adversely impact the ability of electric utilities to obtain new and modified source permits or to operate affected facilities without making significant capital expenditures. In October 1998, the AEP System operating companies joined with certain other utilities to appeal the final NOx SIP Call rule by filing a petition for review in the U.S. Court of Appeals for the District of Columbia Circuit. Preliminary estimates indicate that compliance costs could result in required capital expenditures as follows: (IN MILLIONS) ------------- AEP System.......................... $1,200 APCo............................. 325 CSPCo............................ 140 I&M.............................. 169 KEPCo............................ 105 OPCo............................. 452 Compliance costs cannot be estimated with certainty and the actual costs incurred to comply could be significantly different from this preliminary estimate depending upon the compliance alternatives selected to achieve reductions in NOx emissions. Unless such costs are recovered from customers, they would have a material adverse effect on results of operations, cash flows and possibly financial condition. Section 126 Petitions: In August 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 certain named sources in midwestern states, including all the coal-fired plants of AEP's operating subsidiaries, prevent those states 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, as in the NOx SIP call. On October 21, 1998, Federal EPA published in the Federal Register proposed conditional remedial action requiring NOx emission reductions from named utility sources. Federal EPA is seeking comment on the effect on the Section 126 petitions of a proposed determination by Federal EPA that the one-hour ozone standard no longer applies to non-attainment areas in Maine, New Hampshire, Rhode Island and a portion of Massachusetts. In a separate Notice of Proposed Rulemaking, Federal EPA is seeking comment with respect to its proposed determination 30 38 that eight-hour ozone non-attainment in New Hampshire and Maine is being significantly affected by sources of NOx emissions in the northeastern U.S. as well as certain sources in the midwestern and southern U.S. In December 1997 Federal EPA 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 called for a proposed rulemaking on the Section 126 petitions by September 30, 1998 and a technical determination by April 30, 1999. Final action would be deferred pending satisfaction of the NOx SIP call requirements. In October 1998, the U.S. District Court for the Southern District of New York entered an order directing Federal EPA to conform to the schedule set forth in the MOA. 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. In March 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. In August 1998, the court held that the appeal was not ripe for review. A petition for writ of certiori was filed with the U.S. Supreme Court. 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 sulfur hexafluoride 7% below 1995 levels in the years 2008-2012. The Protocol was available for signature from March 16, 1998 to March 15, 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. 31 39 Although the United States has agreed to the treaty and signed it on November 12, 1998, President Clinton has indicated that he will not submit the treaty to the Senate for ratification until it contains requirements for "meaningful participation by key developing countries" and the rules, procedures, methodology and guidelines of the treaty's market-based policy instruments, joint implementation programs and compliance enforcement provisions have been negotiated. At the Fourth Conference of the Parties, held in Buenos Aires, Argentina, in November 1998, the parties agreed to a work plan to complete negotiations on outstanding issues with a view toward approving them at the Sixth Conference of the Parties to be held in December 2000. Since the AEP System is a significant emitter of carbon dioxide, its results of operations, cash flows and 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 October 1, 1999. 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. 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. 32 40 New Source Review: 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. In July 1998, Federal EPA requested comment on proposed revisions to the New Source Review rules which would change New Source Review applicability criteria by eliminating exemptions contained in the current regulation. On February 4, 1999, Federal EPA (Regions III and V) issued a request under Section 114 of the Clean Air Act seeking documents and information regarding capital and maintenance expenditures at AEP's Muskingum River, Gavin, Cardinal, Sporn and Mitchell plants. Federal EPA conducted a review of the accounting records of AEGCo, APCo, CSPCo, I&M, KEPCo and OPCo in the summer of 1998 and made site visits to Sporn, Muskingum River and Mitchell plants in the summer and fall of 1998. These activities are focused on assessing compliance with the New Source Review and New Source Performance Standard provisions of the Clean Air Act. Water Pollution Control The Clean Water Act prohibits the discharge of pollutants to waters of the United States from point sources except pursuant to an NPDES permit issued by Federal EPA or a state under a federally authorized state program. Under the Clean Water Act, effluent limitations requiring application of the best available technology economically achievable are to be applied, and those limitations require that no pollutants be discharged if Federal EPA finds elimination of such discharges is technologically and economically achievable. The Clean Water Act provides citizens with a cause of action to enforce compliance with its pollution control requirements. Since 1982, many such actions against NPDES permit holders have been filed. To date, no AEP System plants have been named in such actions. All System Plants are operating with NPDES permits. Under EPA's regulations, operation under an expired NPDES permit is authorized provided an application is filed at least 180 days prior to expiration. Renewal applications are being prepared or have been filed for renewal of NPDES permits which expire in 1999. The NPDES permits generally require that certain thermal impact study programs be undertaken. These studies have been completed for all System plants. Thermal variances are in effect for all plants with once-through cooling water. The thermal variances for Conesville and Muskingum River plants impose thermal management conditions that could result in load curtailment under certain conditions, but the cost impacts are not expected to be significant. Based on favorable results of in-stream biological studies, the thermal temperature limits for both Conesville and Muskingum River plants were raised in the renewed permits issued in 1996. Consequently, the potential for load curtailment and adverse cost impacts is further reduced. Certain mining operations conducted by System companies as discussed under Fuel Supply are also subject to Federal and state water pollution control requirements, which may entail substantial expenditures for control facilities, not included at present in the System's construction cost estimates set forth herein. The Federal Water Quality Act of 1987 requires states to adopt stringent water quality standards for a large category of toxic pollutants and to identify specialized control measures for dischargers to waters where it is shown through the use of total maximum daily loads (TMDLs) that water quality standards are not being met. Implementation of these provisions could result in significant costs to the AEP System if biological monitoring requirements and water quality-based effluent limits are placed in NPDES permits. 33 41 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. Based on Federal EPA's current policy on intake credits and site specific variables and Michigan's implementation strategy, management does not presently expect the GLWQI will have a significant adverse impact on Cook Plant operations. If Indiana and Ohio eventually adopt the GLWQI criteria for statewide application, AEP System plants located in those states could be adversely affected, although the significance depends on the implementation strategy of those states. The Oil Pollution Act of 1990 (OPA) defines certain facilities that, due to oil storage volume and location, could reasonably be expected to cause significant and substantial harm to the environment by discharging oil. Such facilities must operate under approved spill response plans and implement spill response training and drill programs. OPA imposes substantial penalties for failure to comply. AEP companies with oil handling and storage facilities meeting the OPA criteria have in place required response plans, training and drill programs. 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, Compensation, and Liability Act (CERCLA) expanded the reporting requirements to cover the release of hazardous substances generally into the environment, including water, land and air. AEP's subsidiaries store and use some of these hazardous substances, including PCBs contained in certain capacitors and transformers, but the occurrence and ramifications of a spill or release of such substances cannot be predicted. CERCLA, RCRA 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, joint and several, and can be applied retroactively, AEP System companies which previously disposed of PCB-containing electrical equipment and other hazardous substances may be required to participate in remedial activities at such disposal sites should environmental problems result. AEP System companies are presently defendants in three cases involving cost-recovery lawsuits at Federal EPA-identified CERCLA sites. OPCo is involved at two of these sites and I&M at the other site. AEP System companies are identified as Potentially Responsible Parties (PRPs) for three additional federal sites, including CSPCo at one site and I&M at two sites. 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 34 42 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. In 1996, the National Academy of Sciences (NAS) released a report, based on a review of over 500 studies spanning 17 years of research, which contained the following summary statement: "... the conclusion of the committee is that the current body of evidence does not show that exposure to these fields presents a human health hazard..." In 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 ended in 1998. The program funding was $65,000,000, half of which was provided by private parties including utilities. The National Institute of Environmental Health Sciences will provide a report to Congress this year, summarizing the results of this program. AEP 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 1998. See Research and Development. AEP's participation in these programs is a continuation of its efforts to monitor and support further research and to communicate with its customers and employees about this issue. Residential customers of AEP are provided 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 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. These rules were reissued in 1998 with no change to EMF language. 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. 35 43 RESEARCH AND DEVELOPMENT AEP and its subsidiaries are involved in over 100 research projects which are directed toward: o Developing more efficient methods of burning coal. o Reducing the emissions resulting from the combustion of coal. o Utilizing combustion by-products of coal. o Exploring new methods of generating electricity. o Exploring the application of new electrotechnologies. o 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 founded in 1973 that manages research and development initiatives, primarily on behalf of the U.S. electric utility industry. These initiatives include technical programs to improve power production, delivery and use. EPRI's more than 700 members represent over 90% of the kilowatt sales in the U.S., but also include competitive power producers, international organizations and others. Total AEP dues to EPRI were $15,400,000 for 1998, $15,300,000 for 1997 and $9,900,000 for 1996. Total research and development expenditures by AEP and its subsidiaries, including EPRI dues, were approximately $24,100,000 for the year ended December 31, 1998, $23,600,000 for the year ended December 31, 1997 and $16,400,000 for the year ended December 31, 1996. This includes expenditures of $3,300,000 for 1998, $4,600,000 for 1997 and $3,300,000 for 1996 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, 1998, 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
36 44
NET KILOWATT OWNER, PLANT TYPE AND NAME LOCATION (NEAR) CAPABILITY -------------------------- --------------- ---------- APPALACHIAN POWER COMPANY, CONT.: 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 ----------
37 45
NET KILOWATT OWNER, PLANT TYPE AND NAME LOCATION (NEAR) CAPABILITY -------------------------- --------------- ---------- OHIO POWER COMPANY: Steam -- Coal-Fired: John E. Amos, Unit 3 (OPCo share) St. Albans, West Virginia 867,000(b) Cardinal, Unit 1 Brilliant, Ohio 600,000 General James M. Gavin Cheshire, Ohio 2,600,000(e) Kammer Captina, West Virginia 630,000 Mitchell Captina, West Virginia 1,600,000 Muskingum River Beverly, Ohio 1,425,000 Philip Sporn, Units 2, 4 & 5 New Haven, West Virginia 742,000 Hydroelectric -- Conventional: Racine Racine, Ohio 48,000 ---------- 8,512,000 ---------- Total Generating Capability.......... 23,759,000 ========== SUMMARY: Total Steam -- Coal-Fired....................................................................................... 20,795,000 Nuclear.......................................................................................... 2,110,000 Total Hydroelectric -- Conventional..................................................................................... 271,000 Pumped Storage................................................................................... 565,000 Other............................................................................................ 18,000 ---------- Total Generating Capability............................. 23,759,000 ==========
- -------------------- (a) Unit 1 of the Rockport Plant is owned one-half by AEGCo and one-half by I&M. Unit 2 of the Rockport Plant is leased one-half by AEGCo and one-half by I&M. The leases terminate in 2022 unless extended. (b) Unit 3 of the John E. Amos Plant is owned one-third by APCo and two-thirds by OPCo. (c) Represents CSPCo's ownership interest in generating units owned in common with CG&E and DP&L. (d) Leased from the City of Fort Wayne, Indiana. Since 1975, I&M has leased and operated the assets of the municipal system of the City of Fort Wayne, Indiana under a 35-year lease with a provision for an additional 15-year extension at the election of I&M. (e) The scrubber facilities at the Gavin Plant are leased. The lease terminates in 2010 unless extended. See Item 1 under Fuel Supply, for information concerning coal reserves owned or controlled by subsidiaries of AEP. The following table sets forth the total 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 CIRCUIT MILES AND OF DISTRIBUTION 765,000-VOLT LINES LINES ----- ----- AEP System (a).............. 128,983(b) 2,022 APCo..................... 49,793 641 CSPCo (a)................ 15,578 -- I&M...................... 20,899 614 KEPCo.................... 10,223 258 OPCo .................... 29,406 509 - ---------------------- (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. 38 46 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 121 high-voltage transmission interconnections with 25 neighboring electric utility systems. The all-time and 1998 one-hour peak System demands were 25,940,000 and 23,192,000 kilowatts, respectively (which included 7,314,000 and 3,732,000 kilowatts, respectively, of scheduled deliveries to unaffiliated systems which the System might, on appropriate notice, have elected not to schedule for delivery) and occurred on June 17, 1994 and June 22, 1998, respectively. The net dependable capacity to serve the System load on such date, including power available under contractual obligations, was 23,457,000 and 23,761,000 kilowatts, respectively. The all-time and 1998 one-hour internal peak demands were 19,557,000 and 19,414,000 kilowatts, respectively, and occurred on February 5, 1996 and July 21, 1998, respectively. The net dependable capacity to serve the System load on such date, including power dedicated under contractual arrangements, was 23,765,000 and 23,749,000 kilowatts, respectively. The all-time one-hour integrated and internal net system peak demands and 1998 peak demands for AEP's generating subsidiaries are shown in the following tabulation: ALL-TIME ONE-HOUR INTEGRATED 1998 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 6,739 March 12, 1998 CSPCo...... 4,172 June 17, 1994 4,027 July 21, 1998 I&M........ 5,027 June 17, 1994 4,778 July 14, 1998 KEPCo...... 1,711 January 17, 1997 1,444 August 25, 1998 OPCo....... 7,291 June 17, 1994 6,642 August 28, 1998 ALL-TIME ONE-HOUR INTEGRATED 1998 ONE-HOUR INTEGRATED NET INTERNAL PEAK DEMAND NET INTERNAL PEAK DEMAND - ------------------------------ -------------------------- (IN THOUSANDS) NUMBER OF NUMBER OF KILOWATTS DATE KILOWATTS DATE ----------- ------ ----------- ------- APCo ...... 6,908 February 5, 1996 6,135 March 13, 1998 CSPCo...... 3,551 July 21, 1998 3,551 July 21, 1998 I&M........ 3,926 July 14, 1997 3,870 July 21, 1998 KEPCo..... 1,418 February 5, 1996 1,299 March 13, 1998 OPCo....... 5,641 August 14, 1995 5,588 June 25, 1998 HYDROELECTRIC PLANTS AEP has 17 facilities, of which 16 are licensed through FERC. 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 was filed in 1998. The license for the Mottville hydroelectric plant in Michigan expires in 2003. A notice of intent to relicense was 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 -0-% during 1998 and 52.6% during 1997. 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 -0-% during 1998 and 65.1% during 1997. The Cook Plant was shut down in September 1997 to respond to issues raised regarding the operability of certain safety systems. 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 of greater significance and less predictable than costs associated with other sources of generation, in large part due to changing 39 47 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. 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, any unamortized investment at the end of the Cook Plant's useful life (whether scheduled or premature), the carrying costs of that investment 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 the remaining open issue in the letter. In April 1998 the NRC notified I&M that it had convened a Restart Panel for Cook Plant. In July 1998 the NRC provided a list of the required restart activities and in October the NRC expanded the list. In order to identify and resolve the issues necessary to restart the Cook units, AEP is meeting with the Panel on a regular basis until the units are returned to service. In January 1999 AEP announced that it will conduct additional engineering reviews at the Cook Plant that will delay restart of the units. Previously, the units were scheduled to return to service at the end of the first and second quarters of 1999. The decision to delay restart resulted from internal assessments that indicated a need to conduct expanded system readiness reviews. A new restart schedule will be developed based on the results of the expanded reviews and should be available in June 1999. When maintenance and other activities required for restart are complete, AEP will seek concurrence from the NRC to return the Cook Plant to service. Until these additional reviews are completed, management is unable to determine when the units will be returned to service. Unless the costs of the extended outage and restart efforts are recovered from customers, there would be a material adverse effect on results of operations, cash flows and possibly financial condition. In July 1998 AEP received an "adverse trend letter" from the NRC indicating that NRC senior managers determined that there had been a slow decline in performance at the Cook Plant during the 18-month period preceding the letter. The letter indicated that the NRC will closely monitor efforts to address issues at Cook Plant through additional inspection activities. In October 1998 the NRC issued AEP a Notice of Violation and proposed a $500,000 civil penalty for alleged violations at the Cook Plant discovered during five inspections conducted between August 1997 and April 1998. AEP paid the penalty. The cost of electricity supplied to certain retail customers rose due to the outage of the Cook Plant because higher cost coal-fired generation and coal-based purchased power were substituted for lower cost nuclear generation. AEP's Indiana and Michigan retail jurisdictional fuel cost recovery mechanisms permit the recovery, subject to regulatory commission review and approval, of changes in fuel costs. This includes the fuel component of purchased power in the Indiana jurisdiction and changes in replacement power in the Michigan jurisdiction. Under these fuel cost recovery mechanisms, retail rates contain a fuel cost adjustment factor that reflects estimated fuel costs for the period during which the factor will be in effect subject to reconciliation to actual fuel costs in a future proceeding. When actual fuel costs exceed the estimated costs reflected in the billing factor a regulatory asset is recorded and revenues are accrued. Consequently, AEP has recorded a regulatory asset and accrued revenues in anticipation of the future reconciliation and billing, under the fuel cost recovery mechanisms, of the higher fuel costs to replace Cook energy during the extended outage. At December 31, 1998, the regulatory asset was $65,000,000. The IURC approved, subject to future reconciliation or refund, agreements authorizing AEP, during the billing months of July 1998 through March 1999, to include in rates a fuel cost adjustment factor less than that requested by AEP. 40 48 On March 16, 1999, a settlement agreement was filed with the IURC resolving all matters related to the recovery of replacement energy costs due to the extended Cook Plant outage. The settlement agreement, which is subject to IURC approval, provides for, among other things: o A credit of $55,000,000 to Indiana retail customers to be refunded through customer bills during the months of July, August and September 1999. The credit returns to customers Cook replacement fuel costs previously recovered. o Authorization to defer any unrecovered fuel revenues accrued between September 9, 1997 and December 31, 1999, including the $55,000,000 credited to customers. o Authorization to defer up to $150,000,000 in incremental operation and maintenance restart costs for the Cook Plant above the base rate level incurred during 1999. o Amortization of the fuel recoveries and restart cost deferrals over a five-year period ending December 31, 2003. o Subject to certain force majeure provisions, a freeze in base rates through December 31, 2003 and a cap on fuel recovery charges through March 1, 2004. o Incremental nuclear decommissioning trust fund deposits of $2,500,000 annually over a five-year period ending December 31, 2003. If the IURC does not approve this settlement, the recovery of Cook Plant replacement energy costs would then become subject to regulatory hearings. Nuclear Incident Liability The Price-Anderson Act limits public liability for a nuclear incident at any licensed reactor in the United States to $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 $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 $176,000,000 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) and Nuclear Electric Insurance Limited (NEIL). If EIB's and NEIL's losses exceed their available resources, I&M would be subject to a total retrospective premium assessment of up to $16,792,035. 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 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 $6,405,535. 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 41 49 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 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. In January 1997 OPCo and the Service Corporation filed an answer and counterclaims in the District Court and in February 1998 they filed a motion for summary judgment. On March 1, 1999, the District Court issued an opinion and order granting OPCo and the Service Corporation's motion for summary judgment and dismissing the case. ---------------------- The Internal Revenue Service (IRS) agents auditing the AEP System's consolidated federal income tax returns requested a ruling from their National Office that certain interest deductions claimed by AEP relating to its corporate owned life insurance (COLI) program should not be allowed. As a result of a suit filed in U.S. District Court (discussed below) this request for ruling was withdrawn by the IRS agents. Adjustments have been or will be proposed by the IRS disallowing COLI interest deductions for taxable years 1991-96. A disallowance of the COLI interest deductions through December 31, 1998 would reduce earnings (including interest) as follows: (in millions) ------------- AEP System..................................... $316 APCo........................................ 79 CSPCo....................................... 43 I&M......................................... 66 KEPCo....................................... 8 OPCo........................................ 117 AEP System companies have made no provision for any possible adverse earnings impact from this matter. In 1998 AEP made payments of taxes and interest attributable to COLI interest deductions for taxable years 1991-97 to avoid the potential assessment by the IRS of any additional above- market rate interest on the contested amount. The payments to the IRS are included on the balance sheet in other property and investments pending the resolution of this matter. AEP will seek refund, either administratively or through litigation, of all amounts paid plus interest. In order to resolve this issue without further delay, on March 24, 1998, AEP filed suit against the U.S. in the U.S. District Court for the Southern District of Ohio. Management believes that it has a meritorious position and will vigorously pursue this lawsuit. In the event the resolution of this matter is unfavorable, it will have a material adverse impact on results of operations and cash flows. ---------------------- See Item 1 for a discussion of certain environmental and rate matters. 42 50 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, 1999.
NAME AGE OFFICE (a) - ---- --- ---------- E. Linn Draper, Jr............ 57 Chairman of the Board, President and Chief Executive Officer of AEP and of the Service Corporation Donald M. Clements, Jr........ 49 Executive Vice President-Corporate Development of the Service Corporation Henry W. Fayne................ 52 Executive Vice President-Financial Services of the Service Corporation William J. Lhota.............. 59 Executive Vice President of the Service Corporation James J. Markowsky............ 54 Executive Vice President-Power Generation of the Service Corporation J. H. Vipperman............... 58 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 Mr. Clements. 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, 1999, 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............ 57 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 Henry W. Fayne................ 52 Director 1995-Present Vice President 1998-Present Vice President and Chief Financial Officer of AEP 1998-Present Executive Vice President-Financial Services of the Service Corporation 1998-Present Senior Vice President-Corporate Planning & Budgeting of the Service Corporation 1995-1998 Senior Vice President-Controller of the Service Corporation 1993-1995
43 51
NAME AGE POSITION (a) PERIOD - ---- --- ------------ ------ William J. Lhota.............. 59 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 James J. Markowsky............ 54 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 J. H. Vipperman............... 58 Director 1985-Present Vice President 1996-Present President and Chief Operating Officer 1990-1995 Executive Vice President-Corporate Services of the Service Corporation 1998-Present Executive Vice President-Energy Delivery of the Service Corporation 1996-1997
- ---------------------- (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, 1999, 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.......... 57 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 Henry W. Fayne.............. 52 Director 1993-Present Vice President 1998-Present Vice President and Chief Financial Officer of AEP 1998-Present Executive Vice President-Financial Services of the Service Corporation 1998-Present Senior Vice President-Corporate Planning & Budgeting of the Service Corporation 1995-1998 Senior Vice President-Controller of the Service Corporation 1993-1995
44 52
NAME AGE POSITION (a) PERIOD - ---- --- ------------ ------ William J. Lhota............ 59 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 James J. Markowsky............ 54 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 J. H. Vipperman............. 58 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 1996-1997 President and Chief Operating Officer of APCo 1990-1995
- -------------------- (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 - ------------- ---- --- -------- 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 March 1998........................... 51-11/16 47-13/16 .60 June 1998............................ 50-3/4 44-11/16 .60 September 1998....................... 48 13/16 42 1/16 .60 December 1998........................ 53 5/16 45 5/16 .60 At December 31, 1998, AEP had approximately 134,000 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. 45 53 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 1998 Annual Report (for the fiscal year ended December 31, 1998). APCO. The information required by this item is incorporated herein by reference to the material under Selected Consolidated Financial Data in the APCo 1998 Annual Report (for the fiscal year ended December 31, 1998). 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 1998 Annual Report (for the fiscal year ended December 31, 1998). 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 1998 Annual Report (for the fiscal year ended December 31, 1998). 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 1998 Annual Report (for the fiscal year ended December 31, 1998). 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 1998 Annual Report (for the fiscal year ended December 31, 1998). 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 1998 Annual Report (for the fiscal year ended December 31, 1998). 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 1998 Annual Report (for the fiscal year ended December 31, 1998). 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 1998 Annual Report (for the fiscal year ended December 31, 1998). 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 1998 Annual Report (for the fiscal year ended December 31, 1998). 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 1998 Annual Report (for the fiscal year ended December 31, 1998). 46 54 Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK - -------------------------------------------------------------------------------- AEGCO. The information required by this item is incorporated herein by reference to the material under Management's Narrative Analysis of Results of Operations in the AEGCo 1998 Annual Report (for the fiscal year ended December 31, 1998). 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 1998 Annual Report (for the fiscal year ended December 31, 1998). 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 1998 Annual Report (for the fiscal year ended December 31, 1998). CSPCO. The information required by this item is incorporated herein by reference to the material under Management's Narrative Analysis of Results of Operations in the CSPCo 1998 Annual Report (for the fiscal year ended December 31, 1998). 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 1998 Annual Report (for the fiscal year ended December 31, 1998). KEPCO. The information required by this item is incorporated herein by reference to the material under Management's Narrative Analysis of Results of Operations in the KEPCo 1998 Annual Report (for the fiscal year ended December 31, 1998). 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 1998 Annual Report (for the fiscal year ended December 31, 1998). Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA - -------------------------------------------------------------------------------- AEGCO, AEP, APCO, CSPCO, I&M, KEPCO, AND 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. 47 55 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 1999 annual meeting of shareholders, to be filed within 120 days after December 31, 1998. 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 1999 annual meeting of stockholders, to be filed within 120 days after December 31, 1998. 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, 1999, 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............ 57 Director 1992-Present Chairman of the Board and Chief Executive Officer 1993-Present Vice President 1992-1993 Chairman of the Board, President and Chief Executive Officer of AEP and of the Service Corporation 1993-Present President of AEP 1992-1993 President and Chief Operating Officer of the Service Corporation 1992-1993 Henry W. Fayne................ 52 Director and Vice President 1998-Present Vice President and Chief Financial Officer of AEP 1998-Present Executive Vice President-Financial Services of the Service Corporation 1998-Present Senior Vice President-Corporate Planning & Budgeting of the Service Corporation 1995-1998 Senior Vice President-Controller of the Service Corporation 1993-1995 William J. Lhota.............. 59 Director 1989-Present President and Chief Operating Officer 1996-Present Vice President 1989-1995 Executive Vice President of the Service Corporation 1993-Present
48 56
NAME AGE POSITION (a)(b)(c) PERIOD - ---- --- ------------------ ------ James J. Markowsky............ 54 Director 1995-Present Vice President 1993-Present Executive Vice President-Power Generation of the Service Corporation 1996-Present Executive Vice President-Engineering & Construction of the Service Corporation 1993-1996 Senior Vice President and Chief Engineer of the Service Corporation 1988-1993 Armando A. Pena............... 54 Director, Vice President and Chief Financial Officer 1998-Present Treasurer 1995-Present Chief Financial Officer of the Service Corporation 1998-Present Senior Vice President-Finance of the Service Corporation 1996-Present Treasurer of AEP and the Service Corporation 1995-Present J. H. Vipperman............... 58 Director and Vice President 1996-Present Executive Vice President-Corporate Services of the Service Corporation 1998-Present Executive Vice President-Energy Delivery of the 1996-1997 Service Corporation President and Chief Operating Officer of APCo 1990-1995 K. G. Boyd.................... 47 Director 1997-Present Indiana Region Manager 1997-Present Fort Wayne District Manager 1994-1997 C. R. Boyle, III.............. 50 Director 1996-Present Vice President 1996-1999 Vice President-Regulatory Services of the Service Corporation 1999-Present President and Chief Operating Officer of KEPCo 1990-1995 G. A. Clark.................. 47 Director 1995-Present Governmental Affairs Manager 1996-Present General Counsel 1994-1995 General Attorney 1991-1993 J. A. Kobyra.................. 46 Director 1998-Present Cook Plant Steam Generator Project Manager 1998-Present Cook Plant Chief Nuclear Engineer 1994-1998 D. B. Synowiec................ 55 Director 1995-Present Plant Manager 1990-Present W. E. Walters................. 51 Director 1991-Present Michiana Region Manager 1994-Present Executive Assistant to President 1987-1994 E. H. Wittkamper.............. 60 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. Fayne, Lhota and Pena are directors of AEGCo, APCo, CSPCo, KEPCo and OPCo. Dr. Draper is also a director of AEP. Mr. Vipperman is a director of APCo, CSPCo, KEPCo and OPCo. 49 57 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 1999 annual meeting of shareholders, to be filed within 120 days after December 31, 1998. 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 1999 annual meeting of shareholders to be filed within 120 days after December 31, 1998. 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 1999 annual meeting of stockholders, to be filed within 120 days after December 31, 1998. 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 1999 annual meeting of shareholders, to be filed within 120 days after December 31, 1998. 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 1998, 1997 and 1996 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, 1998. Summary Compensation Table
LONG TERM ANNUAL COMPENSATION COMPENSATION --------------------- ------------------- PAYOUTS ALL OTHERN SALARY BONUS --------------------- COMPENSATION NAME AND PRINCIPAL POSITION YEAR ($) ($)(1) LTIP PAYOUTS ($)(1) ($)(2) ---------------------------------- ------- ------ --------- --------------------- ------------ E. LINN DRAPER, JR. - Chairman of the board, 1998 780,000 194,376 345,906 104,941 president and chief executive officer of the 1997 720,000 327,744 951,132 31,620 Company and the Service Corporation; chairman 1996 720,000 281,664 675,903 31,990 and chief executive officer of other subsidiaries WILLIAM J. LHOTA - Executive vice president and 1998 380,000 82,859 134,266 56,493 director of the Service Corporation; 1997 355,000 141,396 364,436 20,570 president, chief operating officer and 1996 320,000 125,184 263,114 19,690 director of other subsidiaries JAMES J. MARKOWSKY - Executive vice president - 1998 350,000 76,317 127,115 51,859 power generation and director of the Service 1997 325,000 129,447 338,382 18,020 Corporation; vice president and director of 1996 303,000 118,534 254,535 19,480 other subsidiaries
50 58
LONG TERM ANNUAL COMPENSATION COMPENSATION --------------------- ------------------- PAYOUTS ALL OTHERN SALARY BONUS --------------------- COMPENSATION NAME AND PRINCIPAL POSITION YEAR ($) ($)(1) LTIP PAYOUTS ($)(1) ($)(2) ---------------------------------- ------- ------ --------- --------------------- ------------ JOSEPH H.VIPPERMAN - Executive vice president 1998 310,000 67,595 82,859 58,435 -corporate services and director of the Service Corporation; vice president and director of other subsidiaries (3) HENRY W. FAYNE - Executive vice president - 1998 290,000 63,234 61,555 34,124 financial services and director of the Service Corporation; vice president and director of other subsidiaries (3)
- ------------------------ (1) Amounts in the Bonus column reflect awards under the Senior Officer Annual Incentive Compensation Plan (and predecessor Management Incentive Compensation Plan). Payments were made in March of the succeeding fiscal year for performance in the year indicated. Amounts for 1998 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 for three-year performance periods. See below under Long Term Incentive Plans - Awards in 1998 for additional information. (2) Amounts in the All Other Compensation column include (i) AEP's matching contributions under the AEP Employees Savings Plan and the AEP Supplemental Savings Plan, a non-qualified plan designed to supplement the AEP Savings Plan, and (ii) subsidiary companies director fees. For 1998, the amounts also include split-dollar insurance. Split-dollar insurance represents the present value of the interest projected to accrue for the employee's benefit on the current year's insurance premium paid by AEP. Cumulative net life insurance premiums paid are recovered by AEP at the later of retirement or 15 years. Detail of the 1998 amounts in the All Other Compensation column is shown below.
Item Dr. Draper Mr. Lhota Dr. Markowsky Mr. Vipperman Mr. Fayne ---- ---------- --------- ------------- ------------- --------- Savings Plan Matching Contributions $ 3,200 $ 4,800 $ 4,800 $ 4,800 $ 4,800 Supplemental Savings Plan Matching Contributions 20,200 6,600 5,700 4,500 3,900 Split-Dollar Insurance 71,621 35,173 31,439 43,135 17,399 Subsidiaries Directors Fees 9,920 9,920 9,920 6,000 8,025 -------- ------- ------- ------- ------- Total All Other Compensation $104,941 $56,493 $51,859 $58,435 $34,124 ======== ======= ======= ======= =======
(3) No 1996 or 1997 compensation information is reported for Messrs. Vipperman and Fayne because they were not executive officers in these years. Long-Term Incentive Plans -- Awards In 1998 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 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. 51 59
ESTIMATED FUTURE PAYOUTS OF PERFORMANCE SHARE UNITS UNDER PERFORMANCE NON-STOCK PRICE-BASED PLAN NUMBER OF PERIOD UNTIL ----------------------------- PERFORMANCE MATURATION THRESHOLD TARGET MAXIMUM NAME SHARE UNITS OR PAYOUT (#) (#) (#) ---- ----------- --------- --- --- --- E. L. Draper, Jr................... 7,730 1998-2000 1,932 7,730 15,460 W. J. Lhota........................ 2,636 1998-2000 659 2,636 5,272 J. J. Markowsky.................... 2,428 1998-2000 607 2,428 4,856 J. H. Vipperman.................... 2,150 1998-2000 537 2,150 4,300 H. W. Fayne........................ 2,012 1998-2000 503 2,012 4,024
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 --------------- --------- ------- ------- ------- ------- ------- $ 300,000 $ 69,525 $ 92,700 $115,875 $139,050 $162,225 $182,175 400,000 93,525 124,700 155,875 187,050 218,225 244,825 500,000 117,525 156,700 195,875 235,050 274,225 307,475 700,000 165,525 220,700 275,875 331,050 386,225 432,775 900,000 213,525 284,700 355,875 427,050 498,225 558,075 1,200,000 285,525 380,700 475,875 571,050 666,225 746,025
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 55 and 62. 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 Senior Officer Annual Incentive Compensation Plan (and predecessor 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, 1998, the number of full years of service applicable for retirement benefit calculation purposes for such officers were as follows: Dr. Draper, six years; Mr. Lhota, 34 years; Dr. Markowsky, 27 years; Mr. Vipperman, 35 years; and Mr. Fayne, 23 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. 52 60 Ten AEP System employees (including Messrs. Fayne, Lhota and Vipperman 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 1999 of the executive officers named in the Summary Compensation Table, none of them would receive any supplemental benefits. AEP made available a voluntary deferred-compensation program in 1982 and 1986, which permitted certain members of AEP System management to defer receipt of a portion of their salaries. Under this program, a participant was able to defer up to 10% or 15% annually (depending on the terms of the program offered), over a four-year period, of his or her salary, and receive supplemental retirement or survivor benefit payments over a 15-year period. The amount of supplemental retirement payments received is dependent upon the amount deferred, age at the time the deferral election was made, and number of years until the participant retires. The following table sets forth, for the executive officers named in the Summary Compensation Table, the amounts of annual deferrals and, assuming retirement at age 65, annual supplemental retirement payments under the 1982 and 1986 programs.
1982 PROGRAM 1986 PROGRAM ------------------------------------------- ------------------------------------------- ANNUAL AMOUNT OF ANNUAL AMOUNT OF ANNUAL SUPPLEMENTAL ANNUAL SUPPLEMENTAL AMOUNT RETIREMENT AMOUNT DEFERRED RETIREMENT DEFERRED PAYMENT (4-YEAR PERIOD) PAYMENT NAME (4-YEAR PERIOD) (15-YEAR PERIOD) (15-YEAR PERIOD) -------- ------------------- -------------------- ------------------- -------------------- J. H. Vipperman............... $11,000 $90,750 $10,000 $67,500 H. W. Fayne................... $ 0 $ 0 $ 9,000 $95,400
Severance Plan In connection with the proposed merger with Central and South West Corporation, AEP's Board of Directors adopted a severance plan on February 24, 1999, effective March 1, 1999, that includes Dr. Markowsky and Messrs. Lhota, Vipperman and Fayne. The severance plan provides for payments and other benefits if, within two years after the merger is completed, the officer's employment is terminated by AEP without "cause" or by the officer because of a detrimental change in responsibilities or a reduction in salary or benefits. Under the severance plan, the officer will receive: o A lump sum payment equal to three times the officer's annual base salary plus target annual incentive under the Senior Officer Annual Incentive Compensation Plan. o Maintenance for a period of three additional years of all medical and dental insurance benefits substantially similar to those benefits to which the officer was entitled immediately prior to termination, reduced to the extent comparable benefits are otherwise received. o Outplacement services not to exceed a cost of $30,000 or use of an office and secretarial services for up to one year. AEP's obligation for the payments and benefits under the severance plan is subject to the waiver by the officer of any other severance benefits that may be provided by AEP. In addition, the officer agrees to refrain from the disclosure of confidential information relating to AEP. ----------------------------- 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. 53 61 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 1999 annual meeting of shareholders to be filed within 120 days after December 31, 1998. 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 1999 annual meeting of stockholders, to be filed within 120 days after December 31, 1998. 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, 1999, 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(a) UNITS(b) TOTAL - ---- --------- -------- ----- Karl G. Boyd ......................... 1,679 158 1,837 Coulter R. Boyle, III ................ 4,000 662 4,662 Gregory A. Clark ..................... 16 -- 16 E. Linn Draper, Jr ................... 7,934(c) 77,612 85,546 Henry W. Fayne ....................... 4,649 10,135 14,784 James A. Kobyra ...................... 3,454(c) 415 3,869 William J. Lhota ..................... 16,042(c)(d) 14,902 30,944 James J. Markowsky ................... 3,942(e) 13,062 17,004 Armando A. Pena ...................... 4,886 5,213 10,099 David B. Synowiec .................... 74 366 440 Joseph H. Vipperman .................. 10,734(c)(d) 4,718 15,452 William E. Walters ................... 6,118 316 6,434 Earl H. Wittkamper ................... 3,231(c) 307 3,538 All Directors and Executive Officers.. 151,990(d)(f) 127,866 279,856 (a) Includes share equivalents held in the AEP Employees Savings Plan in the amounts listed below:
AEP EMPLOYEES SAVINGS AEP EMPLOYEES SAVINGS NAME PLAN (SHARE EQUIVALENTS) NAME PLAN (SHARE EQUIVALENTS) ---- ------------------------ ---- ------------------------ Mr. Boyd............................. 1,675 Dr. Markowsky.............................. 3,888 Mr. Boyle............................ 4,000 Mr. Pena................................... 3,464 Mr. Clark............................ 16 Mr. Synowiec............................... 74 Dr. Draper........................... 3,033 Mr. Vipperman.............................. 10,002 Mr. Fayne............................ 4,144 Mr. Walters................................ 6,118 Mr. Kobyra........................... 2,604 Mr. Wittkamper............................. 1,809 Mr. Lhota............................ 13,862 All Directors and Executive Officers............ 54,689
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. (b) This column includes amounts deferred in stock units and held under AEP's officer benefit plans. (c) Includes the following numbers of shares held in joint tenancy with a family member: Dr. Draper, 4,901; Mr. Kobyra, 850; Mr. Lhota, 2,180; Mr. Vipperman, 67; and Mr. Wittkamper, 1,422. (d) Does not include, for Messrs. Lhota and Vipperman, 85,231 shares in the American Electric Power System Educational Trust Fund over which Messrs. Lhota and Vipperman 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. (e) Includes 20 shares held by family members of Dr. Markowsky over which beneficial ownership is disclaimed. (f) Represents less than 1% of the total number of shares outstanding 54 62 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 1999 annual meeting of shareholders, to be filed within 120 days after December 31, 1998. 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: The following financial statements have been incorporated herein by reference pursuant to Item 8.
PAGE ---- AEGCo: Independent Auditors' Report; Statements of Income for the years ended December 31, 1998, 1997 and 1996; Statements of Retained Earnings for the years ended December 31, 1998, 1997 and 1996; Statements of Cash Flows for the years ended December 31, 1998, 1997 and 1996; Balance Sheets as of December 31, 1998 and 1997; Notes to Financial Statements AEP and its subsidiaries consolidated: Consolidated Statements of Income for the years ended December 31, 1998, 1997 and 1996; Consolidated Statements of Retained Earnings for the years ended December 31, 1998, 1997 and 1996; Consolidated Balance Sheets as of December 31, 1998 and 1997; Consolidated Statements of Cash Flows for the years ended December 31, 1998, 1997 and 1996; Notes to Consolidated Financial Statements; Schedule of Consolidated Cumulative Preferred Stocks of Subsidiaries at December 31, 1998 and 1997; Schedule of Consolidated Long-term Debt of Subsidiaries at December 31, 1998 and 1997; Independent Auditors' Report. APCo: Consolidated Statements of Income for the years ended December 31, 1998, 1997 and 1996; Consolidated Balance Sheets as of December 31, 1998 and 1997; Consolidated Statements of Cash Flows for the years ended December 31, 1998, 1997 and 1996; Consolidated Statements of Retained Earnings for the years ended December 31, 1998, 1997 and 1996; Notes to Consolidated Financial Statements; Independent Auditors' Report. CSPCo: Independent Auditors' Report; Consolidated Statements of Income for the years ended December 31, 1998, 1997 and 1996; Consolidated Balance Sheets as of December 31, 1998 and 1997; Consolidated Statements of Cash Flows for the years ended December 31, 1998, 1997 and 1996; Consolidated Statements of Retained Earnings for the years ended December 31, 1998, 1997 and 1996; Notes to Consolidated Financial Statements.
55 63
PAGE ---- I&M: Independent Auditors' Report; Consolidated Statements of Income for the years ended December 31, 1998, 1997 and 1996; Consolidated Balance Sheets as of December 31, 1998 and 1997; Consolidated Statements of Cash Flows for the years ended December 31, 1998, 1997 and 1996; Consolidated Statements of Retained Earnings for the years ended December 31, 1998, 1997 and 1996; Notes to Consolidated Financial Statements. KEPCo: Independent Auditors' Report; Statements of Income for the years ended December 31, 1998, 1997 and 1996; Statements of Retained Earnings for the years ended December 31, 1998, 1997 and 1996; Balance Sheets as of December 31, 1998 and 1997; Statements of Cash Flows for the years ended December 31, 1998, 1997 and 1996; Notes to Financial Statements. OPCo: Independent Auditors' Report; Consolidated Statements of Income for the years ended December 31, 1998, 1997 and 1996; Consolidated Statements of Cash Flows for the years ended December 31, 1998, 1997 and 1996; Consolidated Balance Sheets as of December 31, 1998 and 1997; Consolidated Statements of Retained Earnings for the years ended December 31, 1998, 1997 and 1996; Notes to Consolidated Financial Statements. 2. FINANCIAL STATEMENT SCHEDULES: Financial Statement Schedules are listed in the Index to Financial Statement Schedules (Certain schedules have been omitted because the required information is contained in the notes to financial statements or because such schedules are not required or are not applicable.) S-1 Independent Auditors' Report S-2 3. EXHIBITS: Exhibits for AEGCo, AEP, APCo, CSPCo, I&M, KEPCo and OPCo are listed in the Exhibit Index and are incorporated herein by reference E-1
(b) No Reports on Form 8-K were filed during the quarter ended December 31, 1998. 56 64 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/ A. A. PENA -------------------------------------- (A. A. PENA, VICE PRESIDENT, TREASURER AND CHIEF FINANCIAL OFFICER) Date: March 19, 1999 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/ A. A. PENA Vice President, Treasurer, March 19, 1999 - ------------------------------------ Chief Financial Officer (A. A. PENA) and Director (III) PRINCIPAL ACCOUNTING OFFICER: /s/ L. V. ASSANTE Controller and March 19, 1999 - ------------------------------------ Chief Accounting Officer (L. V. ASSANTE) (IV) A MAJORITY OF THE DIRECTORS: *HENRY W. FAYNE *JOHN R. JONES, III *WM. J. LHOTA *JAMES J. MARKOWSKY *By: /s/ A. A. PENA March 19, 1999 ----------------------------------- (A. A. PENA, ATTORNEY-IN-FACT)
57 65 SIGNATURES PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED. AMERICAN ELECTRIC POWER COMPANY, INC. BY: /s/ H. W. FAYNE -------------------------------- (H. W. FAYNE, VICE PRESIDENT AND CHIEF FINANCIAL OFFICER) Date: March 19, 1999 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/ H. W. FAYNE Vice President and March 19, 1999 - ------------------------------------ Chief Financial Officer (H. W. FAYNE) (III) PRINCIPAL ACCOUNTING OFFICER: /s/ L. V. ASSANTE Controller and March 19, 1999 - ------------------------------------ Chief Accounting Officer (L. V. ASSANTE) (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/ H. W. FAYNE March 19, 1999 ----------------------------------- (H. W. FAYNE, ATTORNEY-IN-FACT)
58 66 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/ A. A. PENA -------------------------------------- (A. A. PENA, VICE PRESIDENT, TREASURER AND CHIEF FINANCIAL OFFICER) Date: March 19, 1999 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/ A. A. PENA Vice President, Treasurer, Chief March 19, 1999 - -------------------------------------- Financial Officer (A. A. PENA) and Director (III) PRINCIPAL ACCOUNTING OFFICER: /s/ L. V. ASSANTE Controller and March 19, 1999 - -------------------------------------- Chief Accounting Officer (L. V. ASSANTE) (IV) A MAJORITY OF THE DIRECTORS: *HENRY W. FAYNE *WM. J. LHOTA *JAMES J. MARKOWSKY *J. H. VIPPERMAN *By: /s/ A. A. PENA March 19, 1999 --------------------------------- (A. A. PENA, ATTORNEY-IN-FACT)
59 67 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/ A. A. PENA -------------------------------------- (A. A. PENA, VICE PRESIDENT, TREASURER AND CHIEF FINANCIAL OFFICER) Date: March 19, 1999 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/ A. A. PENA Vice President, Treasurer, March 19, 1999 - ---------------------------------------- Chief Financial Officer (A. A. PENA) and Director (III) PRINCIPAL ACCOUNTING OFFICER: /s/ L. V. ASSANTE Controller and March 19, 1999 - ---------------------------------------- Chief Accounting Officer (L. V. ASSANTE) (IV) A MAJORITY OF THE DIRECTORS: *HENRY W. FAYNE *WM. J. LHOTA *JAMES J. MARKOWSKY *J. H. VIPPERMAN *By: /s/ A. A. PENA March 19, 1999 ---------------------------------- (A. A. PENA, ATTORNEY-IN-FACT)
60 68 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/ A. A. PENA -------------------------------------- (A. A. PENA, VICE PRESIDENT, TREASURER AND CHIEF FINANCIAL OFFICER) Date: March 19, 1999 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/ A. A. PENA Vice President, Treasurer, March 19, 1999 - ---------------------------------------- Chief Financial Officer (A. A. PENA) and Director (III) PRINCIPAL ACCOUNTING OFFICER: /s/ L. V. ASSANTE Controller and March 19, 1999 - ---------------------------------------- Chief Accounting Officer (L. V. ASSANTE) (IV) A MAJORITY OF THE DIRECTORS: *K. G. BOYD *C. R. BOYLE, III *G. A. CLARK *HENRY W. FAYNE *JAMES A. KOBYRA *WM. J. LHOTA *JAMES J. MARKOWSKY *D. B. SYNOWIEC *J. H. VIPPERMAN *W. E. WALTERS *E. H. WITTKAMPER *By: /s/ A. A. Pena. March 19, 1999 ------------------------------ (A. A. PENA, ATTORNEY-IN-FACT)
61 69 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/ A. A. PENA -------------------------------------- (A. A. PENA, VICE PRESIDENT, TREASURER AND CHIEF FINANCIAL OFFICER) Date: March 19, 1999 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 --------- ----- ---- (V) PRINCIPAL EXECUTIVE OFFICER: *E. LINN DRAPER, JR. Chairman of the Board, Chief Executive Officer and Director (VI) PRINCIPAL FINANCIAL OFFICER: /s/ A. A. PENNA Vice President, Treasurer, March 19, 1999 - --------------------------------------- Chief Financial Officer (A. A. PENA) and Director (VII) PRINCIPAL ACCOUNTING OFFICER: /s/ L. V. ASSANTE Controller and March 19, 1999 - --------------------------------------- Chief Accounting Officer (L. V. ASSANTE) (VIII) A MAJORITY OF THE DIRECTORS: *HENRY W. FAYNE *WM. J. LHOTA *JAMES J. MARKOWSKY *J. H. VIPPERMAN March 19, 1999 *By: /s/ A. A. Pena ------------------------------ (A. A. PENA, ATTORNEY-IN-FACT)
62 70 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/ A. A. PENA -------------------------------------- (A. A. PENA, VICE PRESIDENT, TREASURER AND CHIEF FINANCIAL OFFICER) Date: March 19, 1999 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/ A. A. PENA Vice President, Treasurer, March 19, 1999 - --------------------------------------- Chief Financial Officer (A. A. PENA) and Director (III) PRINCIPAL ACCOUNTING OFFICER: /s/ L. V. ASSANTE Controller and March 19, 1999 - --------------------------------------- Chief Accounting Officer (L. V. ASSANTE) (IV) A MAJORITY OF THE DIRECTORS: *HENRY W. FAYNE *WM. J. LHOTA *JAMES J. MARKOWSKY *J. H. VIPPERMAN *By: /s/ A. A. PENA. March 19, 1999 ---------------------------------- (A. A. PENA, ATTORNEY-IN-FACT)
63 71
INDEX TO FINANCIAL STATEMENT SCHEDULES Page ---- INDEPENDENT AUDITORS' REPORT .......................................................... S-2 The following financial statement schedules for the years ended December 31, 1998, 1997 and 1996 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
S-1 72 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, 1998 and 1997, and for each of the three years in the period ended December 31, 1998, and have issued our reports thereon dated February 23, 1999; such financial statements and reports are included in your respective 1998 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 23, 1999 S-2 73
=========================================================================================================================== 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, 1998....... $6,760 $23,646 $8,290(a) $27,621(b) $11,075 ====== ======= ====== ======= ======= 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 ====== ======= ====== ======= ======= - --------------------- (a) Recoveries on accounts previously written off. (b) Uncollectible accounts written off. =========================================================================================================================== =========================================================================================================================== APPALACHIAN POWER COMPANY AND SUBSIDIARIES SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES - --------------------------------------------------------------------------------------------------------------------------- COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E - --------------------------------------------------------------------------------------------------------------------------- ADDITIONS ------------------------- BALANCE 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, 1998....... $1,333 $5,093 $1,306(a) $5,498(b) $2,234 ====== ====== ====== ====== ====== 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 ====== ====== ======= ====== ====== - --------------------- (a) Recoveries on accounts previously written off. (b) Uncollectible accounts written off. =========================================================================================================================== =========================================================================================================================== COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES - --------------------------------------------------------------------------------------------------------------------------- COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E - --------------------------------------------------------------------------------------------------------------------------- ADDITIONS ------------------------- BALANCE AT CHARGED TO CHARGED TO BALANCE AT BEGINNING COSTS AND OTHER END OF DESCRIPTION OF PERIOD EXPENSES ACCOUNTS DEDUCTIONS PERIOD =========================================================================================================================== (IN THOUSANDS) D EDUCTED FROM ASSETS: Accumulated Provision for Uncollectible Accounts: Year Ended December 31, 1998....... $1,058 $7,551 $5,278(a) $11,289(b) $2,598 ====== ====== ====== ======= ====== 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 ====== ====== ====== ======= ====== - --------------------- (a) Recoveries on accounts previously written off. (b) Uncollectible accounts written off. ===========================================================================================================================
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========================================================================================================================== INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES - --------------------------------------------------------------------------------------------------------------------------- COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E - --------------------------------------------------------------------------------------------------------------------------- ADDITIONS ------------------------- BALANCE 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, 1998......... $1,188 $4,630 $221(a) $4,012(b) $2,027 ====== ====== ==== ====== ====== 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 ====== ====== ==== ====== ====== - --------------------- (a) Recoveries on accounts previously written off. (b) Uncollectible accounts written off. ========================================================================================================================== ========================================================================================================================== KENTUCKY POWER COMPANY SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES - --------------------------------------------------------------------------------------------------------------------------- COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E - --------------------------------------------------------------------------------------------------------------------------- ADDITIONS ------------------------- BALANCE 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, 1998......... $525 $1,280 $392(a) $1,349(b) $848 ==== ====== ==== ====== ==== 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 ==== ====== ==== ====== ==== - --------------------- (a) Recoveries on accounts previously written off. (b) Uncollectible accounts written off. ========================================================================================================================== ========================================================================================================================== OHIO POWER COMPANY AND SUBSIDIARIES SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES - --------------------------------------------------------------------------------------------------------------------------- COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E - --------------------------------------------------------------------------------------------------------------------------- ADDITIONS ------------------------- BALANCE 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, 1998......... $2,501 $3,255 $941(a) $5,019(b) $1,678 ====== ====== ==== ====== ====== 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 ====== ====== ==== ====== ====== - --------------------- (a) Recoveries on accounts previously written off. (b) Uncollectible accounts written off. ==========================================================================================================================
S-4 75 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. 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 1998 Annual Report (for the fiscal year ended December 31, 1998) 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, File No. 1-3525, Exhibit 3(a)]. * 3(b) -- Copy of Certificate of Amendment of the Restated Certificate of Incorporation of AEP, dated January 13, 1999. * 3(c) -- Composite copy of the Restated Certificate of Incorporation of AEP, as amended. 3(d) -- Copy of By-Laws of AEP, as amended through January 28, 1998 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1997, File No. 1-3525, Exhibit 3(b)]. 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)].
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EXHIBIT NUMBER DESCRIPTION - -------------- ----------- AEP**(continued) 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 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1997, File No. 1-3525, Exhibit 10(f)]. +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)].
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EXHIBIT NUMBER DESCRIPTION - -------------- ----------- AEP** (continued) +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)]. +10(m) -- AEP System Survivor Benefit Plan, effective January 27, 1998 [Quarterly Report on Form 10-Q of AEP for the quarter ended September 30, 1998, File No. 1-3525, Exhibit 10]. +*10(n) -- Letter agreement between AEP and Donald M. Clements, Jr. dated August 19, 1994. +*10(o) -- AEP Senior Executive Severance Plan for Merger with Central and South West Corporation, effective March 1, 1999. *13 -- Copy of those portions of the AEP 1998 Annual Report (for the fiscal year ended December 31, 1998) 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
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EXHIBIT NUMBER DESCRIPTION - -------------- ----------- APCO** (continued) 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); Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1998, Exhibit 4(b)]. 4(b) -- 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); Registration Statement No. 333-49071, Exhibit 4(b)]. *4(c) -- Company Order and Officers' Certificate, dated April 22, 1998, establishing certain terms of the 7.30% Senior Notes, Series B, 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)].
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EXHIBIT NUMBER DESCRIPTION - -------------- ----------- APCO** (continued) 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)]. +10(j) -- AEP System Survivor Benefit Plan, effective January 27, 1998 [Quarterly Report on Form 10-Q of AEP for the quarter ended September 30, 1998, File No. 1-3525, Exhibit 10]. +10(k) -- AEP Senior Executive Severance Plan for Merger with Central and South West Corporation, effective March 1, 1999 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1998, File No. 1-3525, Exhibit 10(o)]. *12 -- Statement re: Computation of Ratios. *13 -- Copy of those portions of the APCo 1998 Annual Report (for the fiscal year ended December 31, 1998) 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, 1998, 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)].
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EXHIBIT NUMBER DESCRIPTION - -------------- ----------- CSPCO** (continued) 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 [Registration Statement No. 333-54025, Exhibits 4(a), 4(b), 4(c) and 4(d)]. *4(c) -- Copy of Company Order and Officers' Certificate, dated June 18, 1998, establishing certain terms of the Unsecured Medium Term Notes, Series B. *4(d) -- Copy of Instructions, dated June 18, 1998, from CSPCo to Bankers Trust Company, establishing certain terms of the 6.55% Unsecured Medium Term Notes, Series B, 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)].
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EXHIBIT NUMBER DESCRIPTION - -------------- ----------- CSPCO** (continued) 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 1998 Annual Report (for the fiscal year ended December 31, 1998) 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)]. * 4(b) -- Copy of indenture (for unsecured debt securities), dated as of October 1, 1998, between I&M and The Bank of New York, as Trustee. * 4(c) -- Copy of Company Order and Officers' Certificate, dated October 29, 1998, establishing certain terms of the Unsecured Medium Term Notes, Series A.
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EXHIBIT NUMBER DESCRIPTION - -------------- ----------- I&M** (continued) * 4(d) -- Copy of Instructions, dated November 4, 1998, from I&M to The Bank of New York, establishing certain terms of the 6.45% 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)(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)(4) -- 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)(5) -- 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, 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 1, 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
E-8 83
EXHIBIT NUMBER DESCRIPTION - -------------- ----------- I&M** (continued) 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 1998 Annual Report (for the fiscal year ended December 31, 1998) 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, 1998, 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 [Annual Report on Form 10-K of KEPCo for the fiscal year ended December 31, 1997, Exhibits 4(b), 4(c) and 4(d)]. *4(c) -- Copy of Instructions, dated November 4, 1998, from KEPCo to Bankers Trust Company, establishing certain terms of the 6.45% Unsecured Medium Term Notes, Series A, due 2008. 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)].
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EXHIBIT NUMBER DESCRIPTION - -------------- ----------- KEPCO** (continued) 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 1998 Annual Report (for the fiscal year ended December 31, 1998) 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)(iv); 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 [Registration Statement No. 333-49595, Exhibits 4(a), 4(b) and 4(c)]. *4(c) -- Copy of Instructions, dated December 1, 1998, from OPCo to Bankers Trust Company, establishing certain terms of the 6.24% Unsecured Medium Term Notes, Series A, due 2008. *4(d) -- Copy of Company Order and Officers' Certificate, dated April 29, 1998, establishing certain terms of the 7 3/8% Senior Notes, Series A, due 2038.
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EXHIBIT NUMBER DESCRIPTION - -------------- ----------- OPCO** (continued) 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, 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); 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)].
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EXHIBIT NUMBER DESCRIPTION - -------------- ----------- OPCO** (continued) +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)]. +10(l) -- AEP System Survivor Benefit Plan, effective January 27, 1998 [Quarterly Report on Form 10-Q of AEP for the quarter ended September 30, 1998, File No. 1-3525, Exhibit 10]. +10(m) -- AEP Senior Executive Severance Plan for Merger with Central and South West Corporation, effective March 1, 1999 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1998, File No. 1-3525, Exhibit 10(o)]. *12 -- Statement re: Computation of Ratios. *13 -- Copy of those portions of the OPCo 1998 Annual Report (for the fiscal year ended December 31, 1998) 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, 1998, 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. E-12 EX-3 2 EX-3(B) CERT OF AMEND OF RESTATED INCORP Exhibit 3(b) CERTIFICATE OF AMENDMENT OF THE CERTIFICATE OF INCORPORATION OF AMERICAN ELECTRIC POWER COMPANY, INC. Under Section 805 of the Business Corporation Law The undersigned, being respectively the Vice President and Secretary of American Electric Power Company, Inc., hereby certify that: 1. The name of the corporation is AMERICAN ELECTRIC POWER COMPANY, INC. The name under which the corporation was formed is American Gas and Electric Company. 2. The Department of State on February 18, 1925 filed the certificate of consolidation forming the corporation. 3.(A) The certificate of incorporation of the corporation, as heretofore amended, is hereby amended pursuant to section 801(b)(7) of the Business Corporation Law, to effect an increase in the aggregate number of shares which the corporation shall have authority to issue from 300,000,000 shares of Common Stock, of the par value of $6.50 each, to 600,000,000 shares of Common Stock, of the par value of $6.50 each. (B) Paragraph 4.1 of the certificate of incorporation of the corporation, as heretofore amended, is hereby amended to read as follows: 4.1 The aggregate number of shares which the corporation is authorized to issue is 600,000,000 shares of Common Stock, of the par value of $6.50 each. 4. The manner in which this amendment to the certificate of incorporation of the corporation, as heretofore amended, was authorized was by the (i) unanimous affirmative vote of the Board of Directors of the corporation at its meeting duly called and held on the 28th day of January, 1998, a quorum being present, and (ii) affirmative vote of the holders of a majority of all outstanding shares entitled to vote thereon at the annual meeting of shareholders of the corporation duly called and held on the 27th day of May, 1998, a quorum being present. IN WITNESS WHEREOF, the undersigned have signed this certificate this 13th day of January, 1999, and do affirm the contents to be true under the penalties of perjury. /S/ HENRY W. FAYNE Henry W. Fayne, Vice President /S/ SUSAN TOMASKY Susan Tomasky, Secretary EX-3 3 EX-3(C) AEPCO COMPOSITE OF RESTATED CERT/INCORP Exhibit 3(c) RESTATED CERTIFICATE OF INCORPORATION OF AMERICAN ELECTRIC POWER COMPANY, INC. Under Section 807 of the Business Corporation Law As filed with the Department of State of the State of New York on November 5, 1997 RESTATED CERTIFICATE OF INCORPORATION OF AMERICAN ELECTRIC POWER COMPANY, INC. Under Section 807 of the Business Corporation Law The undersigned, being respectively the Vice President and Assistant Secretary of American Electric Power Company, Inc., hereby certify that: I. Name. The name of the corporation is AMERICAN ELECTRIC POWER COMPANY, INC. The name under which the corporation was formed is American Gas and Electric Company. II. Date of Filing of Certificate of Incorporation. The certificate of consolidation forming the corporation was filed by the Department of State on February 18, 1925. III. Original Certificate Superseded. The certificate of incorporation, as amended heretofore, is hereby restated without further amendment or change to read as herein set forth in full: 1. The name of the corporation shall be AMERICAN ELECTRIC POWER COMPANY, INC. 2. The purposes for which the corporation is formed are: (a) To acquire, hold and dispose of the stock, bonds, notes, debentures and other securities and obligations (hereinafter called "securities") of any person, firm, association, or corporation, private, public or municipal, or of any body politic, including, without limitation, securities of electric and gas utility companies; and while the owner of such securities, to possess and exercise in respect thereof all the rights, powers and privileges of ownership thereof, including voting power; (b) To aid in any manner permitted by law any person, firm, association or corporation in whose securities the corporation may be interested, directly or indirectly, and to do any other act or thing permitted by law for the preservation, protection, improvement or enhancement of the value of such securities or the property represented thereby or securing the same or owned, held or possessed by such person, firm, association or corporation; (c) To acquire, construct, own, maintain, operate and dispose of real or personal property used or useful in the business of an electric utility company or gas utility company and such other real or personal property as may be permitted by law; and (d) To do everything necessary, proper, advisable or convenient for the accomplishment of the foregoing purposes, and to do all other things incidental to them or connected with them that are not forbidden by law or by this certificate of incorporation. 3. The city and county in which the office of the corporation is to be located are the City and County of New York. 4.1. The aggregate number of shares which the corporation is authorized to issue is 600,000,000 shares of Common Stock of the par value of $6.50 each. 4.2. Each share of the Common Stock shall be equal in all respects to every other share of the Common Stock. Every holder of record of the Common Stock shall have one vote for each share of Common Stock held by him for the election of directors and upon all other matters; provided, however, that at all elections of directors by stockholders each holder of record of shares of the Common Stock then entitled to vote, shall be entitled to as many votes as shall equal the number of votes which (except for this provision as to cumulative voting) he would be entitled to cast for the election of directors with respect to his shares of Common Stock multiplied by the number of directors to be elected, and such holder may cast all of such votes for a single director or may distribute them among the number of directors to be voted for, or any two or more or them, as he may see fit, which right, when exercised, shall be termed cumulative voting. 4.3. The corporation may, at any time and from time to time, issue and dispose of any of the authorized and unissued shares of the Common Stock for such consideration as may be fixed by the Board of Directors, subject to any provisions of law then applicable, and subject to the provisions of any resolutions of the stockholders of the corporation relating to the issue and disposition of such shares. 4.4. Upon any issuance for money or other consideration of any stock of the corporation, or of any securities convertible into any stock of the corporation, of any class whatsoever which may be authorized from time to time, no holder of stock of any kind shall have any preemptive or other right to subscribe for, purchase or receive any proportionate or other share of the stock or securities so issued, but the Board of Directors may dispose of all or any portion of such stock or securities as and when it may determine free of any such rights, whether by offering the same to stockholders or by sale or other disposition as the Board of Directors may deem advisable; provided, however, that if the Board of Directors shall determine to issue and sell any shares of Common Stock (including, for the purposes of this paragraph, any security convertible into Common Stock, but excluding shares of Common Stock and securities convertible into Common Stock theretofore reacquired by the corporation after having been duly issued, and excluding shares of Common Stock and securities convertible into Common Stock issued to satisfy conversion or option rights theretofore granted by the corporation) solely for money and other than by: (i) a public offering thereof, or (ii) an offering thereof to or through underwriters or dealers who shall agree promptly to make a public offering thereof, or (iii) any other offering thereof which shall have been authorized or approved by the affirmative vote, cast in person or by proxy, of the holders of record of a majority of the outstanding shares of Common Stock entitled to vote at the stockholders' meeting at which action shall have been taken with respect to such other offering, such shares of Common Stock shall first be offered pro rata, except that the corporation shall not be obligated to offer or to issue any fractional interest in a full share of Common Stock, to the holders of record of the then outstanding shares of Common Stock (excluding outstanding shares of Common Stock held for the benefit of holders of scrip certificates or other instruments representing fractional interests in a full share of Common Stock) upon terms which, in the judgment of the Board of Directors of the corporation, shall be not less favorable (without deduction of such reasonable compensation for the sale, underwriting or purchase of such shares by underwriters or dealers as may lawfully be paid by the corporation) to the purchaser than the terms upon which such shares are offered to others than such holders of Common Stock; and provided that the time within which such preemptive rights shall be exercised may be limited to such time as to the Board of Directors may seem proper, not less, however, than fourteen (14) days after the mailing of notice that such preemptive rights are available and may be exercised. 5. Directors shall hold office after the expiration of their terms until their successors are elected and have qualified. Directors need not be stockholders. 6. To the fullest extent permitted by the New York Business Corporation Law as it exists on the date hereof or as it may hereafter be amended, no director of the corporation shall be liable to the corporation or its stockholders for damages for any breach of duty as a director. Any repeal or modification of the foregoing sentence by the stockholders of the corporation shall not adversely affect any right or protection of a director of the corporation existing at the time of such repeal or modification. 7.1.(A) In addition to any affirmative vote required by law or this certificate of incorporation (any other provision of this certificate of incorporation notwithstanding), and except as otherwise expressly provided in paragraph 7.2: (1) any merger or consolidation of the corporation or any Subsidiary (as hereinafter defined) with (i) any Interested Stockholder (as hereinafter defined) or (ii) any other corporation (whether or not itself an Interested Stockholder) which is, or after such merger or consolidation would be, an Affiliate (as hereinafter defined) of an Interested Stockholder; or (2) any sale, lease, license, exchange, mortgage, pledge, transfer or other disposition (in one transaction or a series of transactions) to or with any Interested Stockholder or any Affiliate of any Interested Stockholder of any assets of the corporation or any Subsidiary having an aggregate Fair Market Value (as hereinafter defined) of $100,000,000 or more; or (3) the issuance or transfer by the corporation or any Subsidiary (in one transaction or a series of transactions) of any securities of the corporation or any Subsidiary to any Interested Stockholder or any Affiliate of any Interested Stockholder having an aggregate Fair Market Value of $100,000,000 or more, other than the issuance of securities upon the conversion of convertible securities of the corporation or any Subsidiary which were not acquired by such Interested Stockholder (or such Affiliate) from the corporation or a Subsidiary; or (4) the adoption of any plan or proposal for the liquidation or dissolution of the corporation proposed by or on behalf of any Interested Stockholder or any Affiliate of any Interested Stockholder; or (5) any reclassification of securities (including any reverse stock split), or recapitalization or reorganization of the corporation, or any merger or consolidation of the corporation with any of its Subsidiaries, or any self tender offer for or repurchase of securities of the corporation by the corporation or any Subsidiary or any other transaction (whether of not with or into or otherwise involving any Interested Stockholder) which has the effect, directly or indirectly, of increasing the proportionate share of the outstanding shares of any class or series of equity or convertible securities of the corporation or any Subsidiary which is directly or indirectly owned by any Interested Stockholder or any Affiliate of any Interested Stockholder; shall require the affirmative vote of the holders of at least (i) seventy-five per centum of the combined voting power of the then issued and outstanding capital stock of all classes and series of the corporation having voting powers (the "Voting Stock"), voting together as a single class, and (ii) a majority of the combined voting power of the then issued and outstanding Voting Stock beneficially owned by persons other than such Interested Stockholder, voting together as a single class, given at any annual meeting of stockholders or at any special meeting called for that purpose. Such affirmative vote shall be required notwithstanding the fact that no vote may be required, or that a lesser percentage may be specified, by law, by any other provision of this certificate of incorporation or in any agreement with any national securities exchange or otherwise. (B) The term "Business Combination" as used herein shall mean any transaction which is referred to in any one or more of clauses (1) through (5) of sub-paragraph (A) of this paragraph 7.1. 7.2. The provisions of paragraph 7.1 shall not be applicable to any particular Business Combination, and such Business Combination shall require only such affirmative vote, if any, as is required by law, any other provision of this certificate of incorporation, and any agreement with any national securities exchange, if all of the conditions specified in either of the following sub-paragraphs (A) or (B) are met: (A) The Business Combination shall have been approved by a majority of the Disinterested Directors (as hereinafter defined). (B) All of the following conditions shall have been met: (1) The aggregate amount of the cash and the Fair Market Value as of the date of the consummation of the Business Combination (the "Consummation Date") of consideration other than cash to be received per share by holders of Common Stock in such Business Combination shall be at least equal to the highest of the following (it being intended that the requirements of this clause (1) shall be required to be met with respect to every share of outstanding Common Stock, whether or not the Interested Stockholder has previously acquired any shares of Common Stock): (i) (if applicable) the highest per share price (including any brokerage commissions, transfer taxes and soliciting dealers' fees) paid by the Interested Stockholder for any shares of Common Stock acquired by it (x) within the five-year period immediately prior to the first public announcement of the terms of the proposed Business Combination (the "Announcement Date") or (y) in the transaction in which it became an Interested Stockholder, whichever is higher; (ii) the Fair Market Value per share of Common Stock on the Announcement Date or on the date on which the Interested Stockholder became an Interested Stockholder (such latter date is referred to herein as the "Determination Date"), whichever is higher; and (iii) an amount which bears the same or greater percentage relationship to the Fair Market Value per share of Common Stock on the Announcement Date as the highest per share price determined in clause (B)(1)(i) above bears to the Fair Market Value per share of Common Stock on the date of the commencement of the acquisition of the Common Stock by such Interested Stockholder (2) The aggregate amount of cash and the Fair Market Value as of the Consummation Date Of consideration other than cash to be received per share by holders of shares of any other class or series of outstanding Voting Stock shall be at least equal to the highest of the following (it being intended that the requirements of this clause (2) shall be required to be met with respect to every class or series of outstanding Voting Stock, whether or not the Interested Stockholder has previously acquired any shares of a particular class or series of Voting Stock): (i) (if applicable) the highest per share price (including any brokerage commissions, transfer taxes and soliciting dealers' fees) paid by the Interested Stockholder for any shares of such class or series of Voting Stock acquired by it (x) within the five-year period immediately prior to the Announcement Date or (y) in the transaction in which it became an Interested Stockholder, whichever is higher; (ii) the Fair Market Value per share of such class or series of Voting Stock on the Announcement Date or on the Determination Date, whichever is higher; (iii) (if applicable) the highest preferential amount per share to which the holders of shares of such class or series of Voting Stock are entitled in the event of any liquidation, dissolution or winding up of the corporation, whether voluntary or involuntary; and (iv) an amount which bears the same or greater percentage relationship to the Fair Market Value per share of such class or series of Voting Stock on the Announcement Date as the highest per share price determined in clause (B)(2)(i) above bears to the Fair Market Value per share of such Voting Stock on the date of the commencement of the acquisition of such Voting Stock by such Interested Stockholder. (3) The consideration to be received by holders of a particular class or series of outstanding Voting Stock (including Common Stock) shall be in cash or in the same form as the Interested Stockholder has previously paid for shares of such class or series of Voting Stock. If the Interested Stockholder has paid for shares of any class or series of Voting Stock with varying forms of consideration, the form of consideration to be received by each holder of such class or series of Voting Stock shall be, at the option of such holder, either cash or the form used by the Interested Stockholder to acquire the largest number of shares of such class or series of Voting Stock previously acquired by it prior to the Announcement Date. The price determined in accordance with clauses (1) and (2) of this sub-paragraph (B) shall be subject to appropriate adjustment in the event of any stock dividend, stock split, combination of shares or similar event. (4) After the Determination Date and prior to the Consummation Date: (i) except as approved by a majority of the Disinterested Directors, there shall have been no failure to declare and pay at the regular dates therefor the full amount of any dividends (whether or not cumulative) payable on any class or series of stock of the corporation having a preference over the Common Stock as to dividends or upon liquidation; and (ii) there shall have been (x) no reduction in the quarterly rate of dividends paid on the Common Stock (except as necessary to reflect any subdivision of the Common Stock), except as approved by a majority of the Disinterested Directors, and (y) an increase in such quarterly rate of dividends paid on such Common Stock as necessary to reflect any reclassification (including any reverse stock split), recapitalization, reorganization, self tender offer for or repurchase of securities of the corporation by the corporation or any Subsidiary or any similar transaction which has the effect of reducing the number of outstanding shares of the Common Stock, unless the failure so to increase such quarterly rate is approved by a majority of the Disinterested Directors; and (iii) such Interested Stockholder shall not have become the beneficial owner of any additional shares of Voting Stock except as part of the transaction which results in such Interested Stockholder becoming an Interested Stockholder or upon conversion of convertible securities acquired by it prior to becoming an Interested Stockholder or as a result of a pro rata stock dividend or stock split; and (iv) such Interested Stockholder shall not have received the benefit, directly or indirectly (except proportionately as a stockholder), of any loans, advances, guarantees, pledges or other financial assistance or tax credits or other tax advantages provided by the corporation or any Subsidiary, whether in anticipation of or in connection with such Business Combination or otherwise; and (v) such Interested Stockholder shall not have caused any material change in the corporation's business or capital structure, including, without limitation, the issuance of shares of capital stock of the corporation to any third party. (5) A proxy or information statement describing the proposed Business Combination and complying with the requirements of the Securities Exchange Act of 1934, as amended (the "Act"), and the rules and regulations thereunder (or any subsequent provisions replacing the Act, rules and regulations), shall be mailed by and at the expense of the Interested Stockholder to public stockholders of the corporation at least 30 days prior to the Consummation Date (whether or not such proxy or information statement is required to be mailed pursuant to the Act). The proxy or information statement shall contain at the front thereof in a prominent place (i) any recommendation as to the advisability (or inadvisability) of the Business Combination which a majority of the Disinterested Directors may choose to state, and (ii) if a majority of the Disinterested Directors so requests, the opinion of a reputable national investment banking firm as to the fairness (or not) of such Business Combination from the point of view of the remaining public stockholders of the corporation (such investment banking firm to be engaged solely on behalf of the remaining public stockholders, to be paid a reasonable fee for their services by the corporation upon receipt of such opinion, to be unaffiliated with such Interested Stockholder, and, to be selected by a majority of the Disinterested Directors). (6) The holders of all outstanding shares of Voting Stock not beneficially owned by the Interested Stockholder prior to the consummation of any Business Combination shall be entitled to receive in such Business Combination cash or other consideration for their shares of such Voting Stock in compliance with clauses (1), (2) and (3) of sub-paragraph (B) of this paragraph 7.2 (provided, however, that the failure of any such holders who are exercising their statutory rights to dissent from such Business Combination and receive payment of the fair value of their shares to exchange their shares in such Business Combination shall not be deemed to have prevented the condition set forth in this clause (6) from being satisfied). 7.3. The following terms shall be deemed to have the meanings specified below: (A) The term "person" shall mean any individual, firm, corporation, group (as such term is used in Regulation 13D-G of the rules and regulations under the Act, as in effect on January 1, 1988) or other entity. (B) The term "Interested Stockholder" shall mean any person (other than the corporation, any Subsidiary or any pension, profit sharing, employee stock ownership, employee savings or other employee benefit plan, or any dividend reinvestment plan, of the corporation or any Subsidiary or any trustee of or fiduciary with respect to any such plan acting in such capacity) who or which: (1) is the beneficial owner, directly or indirectly, of more than five per centum of the combined voting power of the then outstanding Voting Stock; or (2) is an Affiliate of the corporation and at any time within the five-year period immediately prior to the date in question was the beneficial owner, directly or indirectly, of more than five per centum of the combined voting power of the then outstanding Voting Stock; or (3) is an assignee of or has otherwise succeeded to any shares of Voting Stock which were at any time within the five-year period immediately prior to the date in question beneficially owned by an Interested Stockholder, if such assignment or succession shall have occurred in the course of a transaction or series of transactions not involving a public offering within the meaning of the Securities Act of 1933, as amended (or any subsequent provisions replacing such). (C) A person shall be deemed a "beneficial owner" of any Voting Stock: (1) which such person or any of its Affiliates or Associates (as hereinafter defined) beneficially owns, directly or indirectly; or (2) which such person or any of its Affiliates or Associates has (i) the right to acquire (whether such right is exercisable immediately or only after the passage of time), pursuant to any agreement, arrangement or understanding or upon the exercise of conversion rights, exchange rights, warrants or options, or otherwise, or (ii) the right to vote pursuant to any agreement, arrangement or understanding; or (3) which is beneficially owned, directly or indirectly, by any other person with which such person or any of its Affiliates or Associates has any agreement, arrangement or understanding for the purpose of acquiring, holding, voting or disposing of any shares of Voting Stock. (D) For the purpose of determining whether a person is an Interested Stockholder pursuant to sub-paragraph (B) of this paragraph 7.3, the number of shares of Voting Stock deemed to be outstanding shall include shares deemed owned through application of sub-paragraph (C) of this paragraph 7.3, but shall not include any other shares of Voting Stock which may be issuable pursuant to any agreement, arrangement or understanding, or upon exercise of conversion rights, exchange rights, warrants or options, or otherwise. (E) The term "Affiliate" of, or a person "affiliated" with, a specified person shall mean a person that directly, or indirectly through one or more intermediaries, controls, or is controlled by, or is under common control with, the person specified. (F) The term "Associate" as used to indicate a relationship with any person shall mean (1) any corporation or organization (other than the corporation or a Subsidiary) of which such person is an officer or partner or is, directly or indirectly, the beneficial owner of ten per centum or more of any class or series of equity securities, (2) any trust or other estate in which such person has a substantial beneficial interest or as to which such person serves as trustee or in a similar fiduciary capacity, and (3) any relative or spouse of such person, or any relative of such spouse, who has the same home as such person. (G) The term "Subsidiary" shall mean any corporation of which a majority of any class or series of equity security is owned, directly or indirectly, by the corporation or by a Subsidiary or by the corporation and one or more Subsidiaries; provided, however, that for the purposes of the definition of Interested Stockholder set forth in sub-paragraph (B) of this paragraph 7.3, the term "Subsidiary" shall mean only a corporation of which a majority of each class or series of equity security is owned, directly or indirectly, by the corporation. (H) The term "Fair Market Value" shall mean: (1) in the case of stock, the highest closing sale price during the 30-day period immediately preceding the date in question of a share of such stock on the Composite Tape for New York Stock Exchange-Listed Stocks, or, if such stock is not quoted on the Composite Tape, on the New York Stock Exchange, or if such stock is not listed on such Exchange, on the principal United States securities exchange registered under the Act on which such stock is listed or, if such stock is not listed on any such exchange, the highest closing bid quotation with respect to a share of such stock during the 30-day period preceding the date in question on the National Association of Securities Dealers, Inc. Automated Quotations System or any similar system then in use, or if no such quotations are available, the fair market value on the date in question of a share of such stock as determined by a majority of the Disinterested Directors in good faith, in each case with respect to any class or series of such stock, appropriately adjusted for any dividend or distribution in shares of such stock or any subdivision or reclassification of outstanding shares of such stock into a greater number of shares of such stock or any combination or reclassification of outstanding shares of such stock into a smaller number of shares of such stock; and (2) in the case of property other than cash or stock, the fair market value of such property on the date in question as determined by a majority of the Disinterested Directors in good faith. (I) In the event of any Business Combination in whic the corporation is the survivor, the phrase "consideration other than cash to be received" as used in clauses (1) and (2) of sub-paragraph (B) of paragraph 7.2 shall include the shares of Common Stock and/or the shares of any other class or series of outstanding Voting Stock retained by the holders of such shares. (J) The term "Disinterested Director" shall mean any member of the Board of Directors of the corporation who is unaffiliated with, and not a nominee of, the Interested Stockholder and who was a member of the Board of Directors prior to the Determination Date, and any successor of a Disinterested Director who is unaffiliated with, and not a nominee of, the Interested Stockholder and is recommended to succeed a Disinterested Director by a majority of the total number of Disinterested Directors then on the Board of Directors. (K) References to "highest per share price" shall in each case with respect to any class or series of stock reflect an appropriate adjustment for any dividend or distribution in shares of such stock or any subdivision or reclassification of outstanding shares of such stock into a greater number of shares of such stock or any combination or reclassification of outstanding shares of such stock into a smaller number of shares of such stock. 7.4. A majority of the Board of Directors of the corporation shall have the power and duty to determine for the purpose of these paragraphs 7.1 through 7.6, on the basis of information known to them after reasonable inquiry, whether a person is an Interested Stockholder. Once the Board of Directors has made a determination, pursuant to the preceding sentence, that a person is an Interested Stockholder, a majority of the total number of directors of the corporation who would qualify as Disinterested Directors shall have the power and duty to interpret all of the terms and provisions of these paragraphs 7.1 through 7.6, and to determine on the basis of information known to them after reasonable inquiry all facts necessary to ascertain compliance therewith, including, without limitation, (A) the number of shares of Voting Stock beneficially owned by any person, (B) whether a person is an Affiliate or Associate of another, (C) whether the assets which are the subject of any Business Combination have, or the consideration to be received for the issuance or transfer of securities by the corporation or any Subsidiary in any Business Combination has, an aggregate Fair Market Value of $100,000,000 or more and (D) whether all of the applicable conditions set forth in sub-paragraph (B) of paragraph 7.2 have been met with respect to any Business Combination. Any determination pursuant to this paragraph 7.4 made in good faith shall be binding and conclusive on all parties. 7.5. Nothing contained in these paragraphs 7.1 through 7.6 shall be construed to relieve any Interested Stockholder from any fiduciary obligation imposed by law. 7.6. Notwithstanding any other provisions of this certificate of incorporation or the by-laws of the corporation (and notwithstanding the fact that a lesser percentage may be specified by law, this certificate of incorporation or the by-laws of the corporation), the affirmative vote of the holders of at least (A) seventy-five per centum of the combined voting power of the then issued and outstanding Voting Stock, voting together as a single class, and (B) a majority of the combined voting power of the then issued and outstanding Voting Stock beneficially owned by persons other than an Interested Stockholder, voting together as a single class, given at any annual meeting of stockholders or at any special meeting called for that purpose, shall be required to amend, alter, change or repeal, or adopt any provisions inconsistent with, these paragraphs 7.1 through 7.6; provided, however, that the foregoing provisions of this paragraph 7.6 shall not apply to, and such vote shall not be required for, any such amendment, alteration, change, repeal or adoption approved by a majority of the disinterested Directors, and any such amendment, alteration, change, repeal or adoption so approved shall require only such vote, if any, as is required by law, any other provision of this certificate of incorporation or the by-laws of the corporation. 8. The Secretary of State of the State of New York is hereby designated as the agent of the corporation upon whom any process in any action or proceeding against it may be served. The address to which the Secretary of State shall mail a copy of any process against the corporation served upon him is: c/o CT Corporation System, 1633 Broadway, New York, NY 10019. 9. The name of the registered agent upon whom and the address of th registered agent at which process against the corporation may be served is: c/o CT Corporation System, 1633 Broadway, New York, NY 10019. IV. Manner of Authorization. The foregoing restatement of the certificate of incorporation was authorized by the unanimous affirmative vote of the Board of Directors of the corporation at its meeting duly called and held on the 29th day of October, 1997, a quorum being present. IN WITNESS WHEREOF, the undersigned have signed this certificate this 29th day of October, 1997, and do affirm the contents to be true under the penalties of perjury. /S/ G. P. MALONEY G. P. Maloney, Vice President /S/ JOHN F. DI LORENZO, JR. John F. Di Lorenzo, Jr., Assistant Secretary EX-10 4 EX 10(N) AGREEMENT WITH D. M. CLEMENTS, JR. EXHIBIT 10(n) Mr. Donald M. Clements, Jr. 6355 Wayside Drive Beaumont, Texas 77707 August 19, 1994 Dear Don: This is to confirm your acceptance of our offer of employment as Senior Vice President, Corporate Development of the American Electric Power Service Corporation, effective September 1, 1994 or as soon thereafter as you are able to begin work. You will report to me in this position. Among other duties that may be assigned, you will be responsible for exploring and securing new business opportunities for the AEP System. This may include possible alliances or combinations within the utility industry, non-traditional arrangements with major customers, and the deployment of our extensive engineering expertise in new ventures. Your starting salary will be $170,000 a year and reviewed on an annual basis. You will be entitled to 20 days of vacation annually beginning in 1995 and assigned a company car for business and personal use. Subject to their specific terms, including Board approval as necessary, you will be eligible for our Management Incentive Compensation Plan (MICP) upon hire, and our Performance Share Incentive Plan (PSIP) beginning January 1, 1995. The MICP presently has an annual target award of 25% of base salary for your position, 100% of which will be based on Corporate Performance under the Plan. Actual awards may range from 0 to 150% of target and are paid as soon after year-end results are confirmed. If you join the Company prior to October 1, 1994, you will receive a pro-rata award for 1994. The PSIP for your position presently provides an annual award of 25% of your base salary converted to AEP share units at market value. Those units are subsequently multiplied from 0 to 200% to establish actual awards based on comparative three year Total Shareholder Return. Dividends are credited during the performance period and converted to equivalent performance share units. PSIP payments are made annually at the end of each three year performance cycle based on then share market value. The Board determines whether payment will be in cash, AEP stock, or a combination of both. If in stock, the Board may require its retention for an indefinite period. At the end of your first and second calendar years of employment you will be eligible for transition performance awards of one-third and two-thirds respectively, of the three-year performance award that is made for that year. As exceptions to our relocation expense reimbursement program, details of which will be separately provided to you, we will provide you a furnished apartment until May 1, 1995, pending relocation of your family when school is out next spring. We will gross-up for the effect of income tax on this housing. We will further provide you a $5,000 payment to cover miscellaneous relocation expenses, also grossed-up for tax. We will recognize all of your employment with Gulf States Utilities as if credited service under the American Electric Power pension plan. Your pension when you retire at any time after vesting will be based on your actual service at retirement plus such credited service, as if you had been continuously employed for the combined period. It will be paid in two parts that actually earned through AEP service and the credited service supplement, offset by the dollar amount of any retirement benefits you are entitled to receive from Gulf States. You will be eligible under their terms and conditions for all other benefit programs and perquisites appropriate to your position and status as an employee and officer of the AEP Service Corporation. Our Human Resources Department will send you documents describing our benefit plans and other appropriate informational material by separate cover. This will include information regarding our relocation policy and relocation assistance. They will also request certain information to expedite the employment process and to comply with applicable law. As this offer is contingent on your successful completion of a pre-employment physical, they will advise you of the procedures to accomplish that as soon as possible. Don, we are very pleased that you will be joining the AEP System and I am personally delighted at the opportunity to be working with you again. Sincerely, /s/E. Linn Draper, Jr. E. Linn Draper, Jr. EX-10 5 EX-10(O)AEP SR SEVERANCE PLAN FOR MERGER WITH CSW EXHIBIT 10(o) AMERICAN ELECTRIC POWER SYSTEM SENIOR EXECUTIVE SEVERANCE PLAN FOR MERGER WITH CENTRAL AND SOUTH WEST CORPORATION Introduction American Electric Power Company, Inc. ("AEP"), a New York corporation, and Central and South West Corporation ("CSW"), a Delaware corporation, have entered into an Agreement and Plan of Merger dated as of December 21, 1997 (the "Merger Agreement"), whereby AEP and CSW will be parties to a merger (the "Combination") with AEP as the parent of CSW. AEP recognizes that the uncertainty during the pendency of the Combination, and the inevitable adjustments that will occur during the transition period following the Combination, may result in the loss or distraction of employees of its subsidiaries to the detriment of AEP and its shareholders. AEP considers the avoidance of such loss and distraction to be essential to protecting and enhancing the best interests of AEP and its shareholders. AEP also believes that during the pendency of the Combination and the transition period thereafter, AEP should be able to receive and rely on dedicated service from employees of its subsidiaries without concern that those employees might be distracted or concerned by personal uncertainties and risks. In addition, AEP believes that it is consistent with the employment practices and policies of its subsidiaries and in the best interests of AEP and its shareholders to treat fairly those employees whose employment terminates as a result of the Combination. Accordingly, AEP has determined that appropriate steps should be taken by its subsidiaries to assure AEP of the continued employment and attention and dedication to duty of the employees of its subsidiaries and to seek to ensure the availability of their continued service, notwithstanding the Combination. Therefore, in order to fulfill the above purposes, the following plan has been developed and is hereby adopted by American Electric Power Service Corporation, a subsidiary of AEP. ARTICLE I ESTABLISHMENT OF PLAN As of March 1, 1999, American Electric Power Service Corporation hereby establishes a separation compensation plan known as the American Electric Power System Senior Executive Severance Plan For Merger With Central And South West Corporation, as set forth in this document. ARTICLE II DEFINITIONS As used herein the following words and phrases shall have the following respective meanings unless the context clearly indicates otherwise. (a) "Annual Compensation" means the sum of a Participant's Annual Salary and the Participant's Target Annual Incentive. (b) "Annual Salary" means the Participant's regular annual base salary immediately prior to the Participant's termination of employment, including compensation converted to other benefits under a flexible pay arrangement maintained by the Corporation or deferred pursuant to a written plan or agreement with the Corporation, but excluding overtime pay, allowances, premium pay, compensation paid or payable under any of the Corporation's long-term or short-term incentive plans or any similar payments. (c) "Board" means the Board of Directors of American Electric Power Company, Inc., a New York corporation. (d) "Code" means the Internal Revenue Code of 1986, as amended from time to time. (e) "Corporation" means American Electric Power Service Corporation, a New York corporation, and any of its subsidiary companies, divisions, organizations or affiliates. (f) "Date of Termination" means the date on which a Participant ceases to be employed by the Corporation. (g) "Effective Time" means the Effective Time, as defined in the Merger Agreement. (h) "Participant" means an individual who is designated as such pursuant to Section 3.1. (i) "Plan" means the American Electric Power System Senior Executive Severance Plan For Merger With Central And South West Corporation. (j) "Separation Benefits" means the benefits described in Section 4.3 that are provided to qualifying Participants under the Plan. (k) "Separation Period" means the period beginning on a Participant's Date of Termination and ending on the earlier of (i) the third anniversary thereof, or (ii) the first day of the month coincident with or next following the Participant's 65th birthday. (l) "Target Annual Incentive" means the award that the Participant would have received under the Senior Officer Annual Incentive Compensation Plan or the AEP Energy Services, Inc. Incentive Compensation Plan for the year in which the Participant's Date of Termination occurs, if 100% of the annual target award had been earned. ARTICLE III ELIGIBILITY 3.1 Participation. Each of the individuals named on Schedule 1 hereto shall be a Participant in the Plan. With the approval of the Board, Schedule 1 may be amended by the Corporation from time to time to add individuals as Participants; provided, however, the Corporation shall not have the right to amend Schedule 1 to remove any individual, except that a Participant shall be removed from Schedule 1 if the Participant's salary, duties or responsibilities are materially altered for reasons other than the Combination, or the Participant's employment is terminated for cause. 3.2 Duration of Participation. A Participant shall only cease to be a Participant in the Plan as a result of an amendment or termination of the Plan complying with Article VI of the Plan, or when the Participant ceases to be employed by the Corporation, unless, at the time the Participant ceases to be employed, such Participant is entitled to payment of a Separation Benefit as provided in the Plan or there has been an event or occurrence described in Section 4.2(a) which would enable the Participant to terminate employment and receive a Separation Benefit. A Participant entitled to payment of a Separation Benefit or any other amount under the Plan shall remain a Participant in the Plan until the full amount of the Separation Benefit and any other amounts payable under the Plan have been paid to the Participant. ARTICLE IV SEPARATION BENEFITS 4.1 Right to Separation Benefit. A Participant shall be entitled to receive Separation Benefits in accordance with Section 4.3 if the Participant ceases to be employed by the Corporation for any reason specified in Section 4.2(a). 4.2 Termination of Employment. (a) Terminations Which Give Rise to Separation Benefits Under This Plan. Except as set forth in subsection (b) below, a Participant shall be entitled to Separation Benefits if at any time before the second anniversary of the Effective Time (or, if the Combination has not occurred, before the expiration of the Plan as set forth in Section 6.1 hereof): (i) the Participant is involuntarily terminated by the Corporation; or (ii) the Participant's Annual Salary is reduced below the higher of (x) the amount in effect on March 1, 1999 and (y) the highest amount in effect at any time thereafter, excluding situations where the salary reduction is due to the reassignment of a Participant returning to active employment after a period of disability, and the Participant ceases to be employed by the Corporation or by the Participant's own action within 90 days after the occurrence of such reduction; or (iii) the Chief Executive Officer of the Corporation, in his or her sole discretion, determines that the Participant's duties and responsibilities or the program of incentive compensation and retirement and welfare benefits offered to the Participant are materially and adversely diminished in comparison to the duties and responsibilities or the program of benefits enjoyed by the Participant on March 1, 1999, and the Participant ceases to be employed by the Participant's own action within 90 days after the occurrence after such reduction. (b) Terminations Which Do Not Give Rise to Separation Benefits Under This Plan. If a Participant's employment is terminated for cause, disability, retirement, or voluntarily by the Participant in the absence of an event described in subsection (a)(ii) or (iii) of this Section 4.2, the Participant shall not be entitled to Separation Benefits under the Plan. (i) A termination for disability shall have occurred where a participant is terminated because illness or injury has prevented the Participant from performing the Participant's duties (as they existed immediately prior to the illness or injury) on a full time basis for 180 consecutive business days; provided, however, a termination for Disability shall not have occurred if such termination is coincident with or subsequent to a termination which otherwise gives rise to Separation Benefits under this Plan as set forth in this Section 4.2. (ii) A termination by retirement shall have occurred where a Participant's termination is due to the Participant's voluntary late, normal or early retirement under a pension plan sponsored by the Corporation, as defined in such plan; provided, however, a termination by Retirement shall not have occurred if such termination is coincident with or subsequent to a termination which otherwise gives rise to Separation Benefits under this Plan as set forth in this Section 4.2. (iii) A termination for cause shall have occurred where a Participant is terminated because of: (A) the willful and continued failure of the Participant to perform substantially the Participant's duties with the Corporation (other than any such failure resulting from incapacity due to physical or mental illness), after a written demand for substantial performance is delivered to the Participant by the Board or an elected officer of the Corporation which specifically identifies the manner in which the Board or the elected officer believes that the Participant has not substantially performed the Participant's duties, or (B) the willful engaging by the Participant in illegal conduct or gross misconduct which is materially and demonstrably injurious to AEP and the Corporation, as determined by the Chief Executive Officer of the Corporation. For purposes of this provision, no act or failure to act, on the part of the Participant, shall be considered "willful" unless it is done, or omitted to be done, by the Participant in bad faith or without reasonable belief that the Participant's action or omission was in the best interests of AEP or the Corporation. Any act, or failure to act, based upon authority given pursuant to a resolution duly adopted by the Board or upon the advice of counsel for AEP or the Corporation, shall be conclusively presumed to be done, or omitted to be done, by the Participant in good faith and in the best interests of AEP or the Corporation. 4.3 Separation Benefits. (a) If a Participant's employment is terminated in circumstances entitling the Participant to a Separation Benefit as provided in Section 4.2(a), and subject to the provisions of Section 4.5, the Corporation shall pay such Participant, within ten days of the Date of Termination, a cash lump sum as set forth in subsection (b) below and continuing benefits as set forth in subsection (c) below. For purposes of determining the benefits set forth in subsections (b) and (c), if the termination of the Participant's employment is based upon a reduction of the Participant's Annual Salary or benefits as described in subsection (a)(ii) or (a)(iii) of Section 4.2, such reduction shall be ignored. (b) The cash lump sum referred to in Section 4.3(a) shall equal the aggregate of the following amounts: (i) an amount equal to the sum of (1) the portion of the Participant's Annual Salary through the Date of Termination to the extent not theretofore paid, (2) the product of (x) the Target Annual Incentive and (y) a fraction, the numerator of which is the number of days in such calendar year through the Date of Termination, and the denominator of which is 365, and (3) any accrued vacation pay, in each case to the extent not theretofore paid and in full satisfaction of the rights of the Participant thereto; and (ii) an amount equal to three times the Participant's Annual Compensation. (c) The continuing benefits referred to above shall be as follows: (i) During the Separation Period, the Participant and the Participant's family shall be provided with medical and dental insurance benefits as if the Participant's employment had not been terminated; provided, however, that if the Participant becomes reemployed with another employer and is eligible to receive medical or other welfare benefits under another employer-provided plan, the medical and other welfare benefits described herein shall be secondary to those provided under such other plan during such applicable period of eligibility. For purposes of determining eligibility (but not the time of commencement of benefits) of the Participant for retiree medical and dental insurance benefits under the Corporation's plans, practices, programs and policies, the Participant shall be considered to have remained employed during the Separation Period and to have retired on the last day of such Separation Period; and (ii) The Corporation shall, at its sole expense as incurred, provide the Participant with outplacement services the scope and provider of which shall be selected by the Participant in the Participant's sole discretion (but at a cost to the Employer of not more than $30,000) or, at the Participant's option, the use of comparable and accessible office space, office supplies and equipment and secretarial services for a period not to exceed one year. To the extent any benefits described in this Section 4.3(c) cannot be provided pursuant to the appropriate plan or program maintained by the Corporation, the Corporation shall provide such benefits outside such plan or program at no additional cost (including without limitation tax cost) to the Participant. 4.4 Other Benefits Payable. (a) The cash lump sum and continuing benefits described in Section 4.3 above shall be payable in addition to, and not in lieu of, all other accrued or vested or earned but deferred compensation (including voluntary deferrals of regular salary and deferrals of long-term or short-term incentive compensation), rights, options or other benefits which may be owed to a Participant upon or following termination, including but not limited to sick pay, amounts or benefits payable under any bonus or other compensation plans, stock option plan, stock ownership plan, stock purchase plan, life insurance plan, health plan, disability plan or similar or successor plan but excluding any severance pay or pay in lieu of notice required to be paid to such Participant under applicable law. (b) Notwithstanding the foregoing; (i) The Severance payments and benefits provided under Section 4.3 hereof shall be subject to, and conditioned upon, the waiver of any other cash severance payment provided by the Corporation. No amount shall be payable under this Plan to, or on behalf of the Participant, if the Participant elects benefits under any other cash severance plan or program, or any other special pay arrangement with respect to the termination of the Participant's employment. (ii) The Participant agrees that at all times following termination, the Participant will not, without the prior written consent of AEP or the Corporation, disclose to any person, firm or corporation any confidential information of AEP or the Corporation which is now known to the Participant or which hereafter may become known to the Participant as a result of the Participant's employment or association with AEP or the Corporation and which could be helpful to a competitor, unless such disclosure is required under the terms of a valid and effective subpoena or order issued by a court or governmental body; provided, however, that the foregoing shall not apply to confidential information which becomes publicly disseminated by means other than a breach of this provision. It is recognized that damages in the event of breach of this Section 4.4 (b)(ii) by the Participant would be difficult, if not impossible, to ascertain, and it is therefore agreed that AEP or the Corporation, in addition to and without limiting any other remedy or right AEP or the Corporation may have, shall have the right to an injunction or other equitable relief in any court of competent jurisdiction, enjoining any such breach, and the Participant hereby waives any and all defenses the Participant may have on the ground of lack of jurisdiction or competence of the court to grant such an injunction or other equitable relief. The existence of this right shall not preclude AEP or the Corporation from pursuing any other rights or remedies at law or in equity which AEP or the Corporation may have. 4.5 Payment Obligations Absolute. The obligations of the Corporation to pay the Separation Benefits described in Section 4.3 and the other benefits described in Section 4.4 shall be absolute and unconditional and shall not be affected by any circumstances, including, without limitation, any set-off, counterclaim, defense or other right which the Corporation may have against any Participant. In no event shall a Participant be obligated to seek other employment or take any other action by way of mitigation of the amounts payable to a Participant under any of the provisions of this Plan, nor shall the amount of any payment hereunder be reduced by any compensation earned by a Participant as a result of employment by another employer, except as specifically provided in Section 4.3(c)(i). ARTICLE V SUCCESSOR TO CORPORATION This Plan shall bind any successor of AEP or the Corporation, their assets or their businesses (whether direct or indirect, by purchase, merger, consolidation or otherwise) in the same manner and to the same extent that AEP or the Corporation would be obligated under this Plan if no succession had taken place. In the case of any transaction in which a successor would not by the foregoing provision or by operation of law be bound by this Plan, AEP or the Corporation shall require such successor expressly and unconditionally to assume and agree to perform AEP's or the Corporation's obligations under this Plan, in the same manner and to the same extent that AEP or the Corporation would be required to perform if no such succession had taken place. The term "Corporation," as used in this Plan, shall mean the Corporation as hereinbefore defined and any successor or assignee to the business of assets which by reason hereof becomes bound by this Plan. ARTICLE VI DURATION, AMENDMENT AND TERMINATION 6.1 Duration. This Plan shall terminate on the date the closing conditions set forth in Article VII of the Merger Agreement are not met or the date the Merger Agreement is terminated pursuant to Article IX of the Merger Agreement, unless it is extended for an additional period or periods by resolution adopted by the Board. If the Combination occurs, this Plan shall terminate two years after the closing date of the Combination. 6.2 Amendment. Except as provided in Section 6.1, the Plan shall not be subject to amendment, change, substitution, deletion, revocation or termination in any respect which adversely affects the rights of Participants. 6.3 Form of Amendment. The form of any amendment of the Plan shall be a written instrument signed by a duly authorized officer of the Corporation, certifying that the amendment has been approved by the Board. ARTICLE VII MISCELLANEOUS 7.1 Indemnification. If a Participant institutes any reasonable legal action in seeking to obtain or enforce or is required to defend in any reasonable legal action the validity or enforceability of, any right or benefit provided by this Plan, the Corporation will pay for all actual and reasonable legal fees and expenses incurred (as incurred) by such Participant, regardless of the outcome of such action. 7.2 Employment Status. This Plan does not constitute a contract of employment or impose on the Participant or the Corporation any obligation to retain the Participant as an employee, to change the status of the Participant's employment, or to change the Corporation's policies regarding the termination of employment. 7.3 Claim Procedure. If a Participant makes a written request alleging a right to receive benefits under this Plan or alleging a right to receive an adjustment in benefits being paid under the Plan, the Corporation shall treat it as a claim for benefit. All claims for benefit under the Plan shall be sent to the Human Resources Department of the Corporation and must be received within 30 days after the Date of Termination. If the Corporation determines that any individual who has claimed a right to receive benefits, or different benefits, under the Plan is not entitled to receive all or any part of the benefits claimed, it will inform the claimant in writing of its determination and the reasons therefor in terms calculated to be understood by the claimant. The notice will be sent within 90 days of the claim unless the Corporation determines additional time, not exceeding 90 days, is needed. The notice shall make specific reference to the pertinent Plan provisions on which the denial is based, and describe any additional material or information, if any, necessary for the claimant to perfect the claim and the reason any such addition material or information is necessary. Such notice shall, in addition, inform the claimant what procedure the claimant should follow to take advantage of the review procedures set forth below in the event the claimant desires to contest the denial of the claim. The claimant may within 90 days thereafter submit in writing to the Corporation a notice that the claimant contests the denial of the claim by the Corporation and desires a further review. The Corporation shall within 60 days thereafter review the claim and authorize the claimant to appear personally and review pertinent documents and submit issues and comments relating to the claim to the persons responsible for making the determination on behalf of the Corporation. The Corporation will render its final decision with specific reasons therefore in writing and will transmit it to the claimant within 60 days of the written request for review, unless the Corporation determines additional time, not exceeding 60 days, is needed, and so notifies the claimant. If the Corporation fails to respond to a claim filed in accordance with the foregoing within 60 days or any such extended period, the Corporation shall be deemed to have denied the claim. 7.4 Validity and Severability. The invalidity or unenforceability of any provision of the Plan shall not affect the validity or enforceability of any other provision of the Plan, which shall remain in full force and effect, and any prohibition or unenforceability in any jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction. 7.5 Governing Law. The validity, interpretation, construction and performance of the Plan shall in all respects be governed by the law of Ohio, without reference to principles of conflicts of laws, except to the extent pre-empted by federal law. SCHEDULE 1 PARTICIPANTS IN THE AMERICAN ELECTRIC POWER SYSTEM SENIOR EXECUTIVE SEVERANCE PLAN EX-13 6 AEPCO 1998 ANNUAL REPORT AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES SELECTED CONSOLIDATED FINANCIAL DATA
Year Ended December 31, 1998 1997 1996 1995 1994 INCOME STATEMENTS DATA (in millions): Operating Revenues $6,346 $5,880 $5,849 $5,670 $5,505 Operating Income 957 984 1,008 965 932 Income Before Extraordinary Item 536 620 587 530 500 Extraordinary Loss - UK Windfall Tax - 109 - - - Net Income 536 511 587 530 500 December 31, 1998 1997 1996 1995 1994 BALANCE SHEETS DATA (in millions): Electric Utility Plant $20,146 $19,597 $18,970 $18,496 $18,175 Accumulated Depreciation and Amortization 8,416 7,964 7,550 7,111 6,827 Net Electric Utility Plant $11,730 $11,633 $11,420 $11,385 $11,348 Total Assets $19,483 $16,615 $15,883 $15,900 $15,736 Common Shareholders' Equity 4,842 4,677 4,545 4,340 4,229 Cumulative Preferred Stocks of Subsidiaries: Not Subject to Mandatory Redemption 46 47 90 148 233 Subject to Mandatory Redemption* 128 128 510 523 590 Long-term Debt* 7,006 5,424 4,884 5,057 4,980 Obligations Under Capital Leases* 533 538 414 405 400 *Including portion due within one year Year Ended December 31, 1998 1997 1996 1995 1994 COMMON STOCK DATA: Earnings per Common Share: Before Extraordinary Item $2.81 $ 3.28 $3.14 $2.85 $2.71 Extraordinary Loss - UK Windfall Tax - (0.58) - - - Net Income $2.81 $ 2.70 $3.14 $2.85 $2.71 Average Number of Shares Outstanding (in thousands) 190,774 189,039 187,321 185,847 184,666 Market Price Range: High $53-5/16 $ 52 $44-3/4 $40-5/8 $37-3/8 Low 42-1/16 39-1/8 38-5/8 31-1/4 27-1/4 Year-end Market Price 47-1/16 51-5/8 41-1/8 40-1/2 32-7/8 Cash Dividends Paid $2.40 $2.40 $2.40 $2.40 $2.40 Dividend Payout Ratio 85.4% 88.7%(a) 76.5% 84.1% 88.6% Book Value per Share $25.24 $24.62 $24.15 $23.25 $22.83 (a) Dividend Payout Ratio before Extraordinary Loss - UK Windfall Tax is 73.1%.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES 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 from forward looking statements are: electric load and customer growth; abnormal weather conditions; available sources and costs of fuels; availability of generating capacity; the impact of the proposed merger with Central and South West Corporation (CSW) including any regulatory conditions imposed on the merger or the inability to consummate the merger with CSW; the speed and degree to which competition is introduced to our power generation business, the structure and timing of a competitive market and its impact on energy prices or fixed rates; the ability to recover stranded costs in connection with possible deregulation of generation; new legislation and government regulations; the ability of the Company to successfully control its costs; the success of new business ventures; international developments affecting our foreign investments; the economic climate and growth in our service territory; unforeseen events affecting the Company's nuclear plant which is on an extended safety related shutdown; problems or failures related to Year 2000 readiness of computer software and hardware; inflationary trends; electricity and gas market prices; interest rates and other risks and unforeseen events. This discussion contains a "Year 2000 Readiness Disclosure" within the meaning of the Year 2000 Information and Readiness Disclosure Act. Growth Of The Business In 1998 management continued to implement its growth-oriented strategy with a goal of being America's Energy Partner and a global energy and related services company. We have adopted a strategy to expand our geographic reach and to build and acquire capabilities across a broader spectrum of the energy products and services value chain. AEP is working to position itself to be successful in an increasingly competitive market that will allow customers to choose their energy supplier. AEP made several acquisitions in 1998 that expanded its energy operations overseas and in the United States. The expansion of the foreign energy business in 1998 included the purchase of CitiPower, an Australian electric distribution utility, the acquisition of an equity interest in Pacific Hydro, an Australian hydroelectric generating company, and continued on- schedule construction of two generating units in China. The $1.1 billion acquisition of CitiPower, completed on December 31, 1998, was accounted for using the purchase method of accounting. CitiPower serves approximately 240,000 customers in the city of Melbourne. CitiPower will contribute to earnings beginning in the first quarter of 1999. In March 1998 the Company invested $10 million to acquire a 20% equity interest in Pacific Hydro. Pacific Hydro operates four hydroelectric power stations in Australia with an installed capacity of 40 megawatts (MW) and has interests in two hydroelectric projects under construction in the Philippines. The generating units under construction in China are owned 70% by the Company with the remaining 30% owned by two Chinese partners. Construction of the two unit 250 MW, coal-fired station is proceeding on schedule. The first unit began commercial operation in February of 1999 and the second unit is expected to go into commercial service in July of 1999. These units are expected to contribute to earnings in 1999. In addition, the Company has a 50% investment in Yorkshire Electricity Group plc (Yorkshire), a United Kingdom (UK) distribution electric company. The investment was made in April 1997 and contributed $38.5 million to nonregulated, nonoperating income in 1998. In September 1998 certain residential and commercial customers in the UK could choose their electricity supplier marking the start of a transition to competition. Yorkshire serves approximately 2.2 million customers. One disappointment we suffered in 1998 was the withdrawal of a joint venture partner. In 1997 the Company announced a joint venture with Conoco, an energy subsidiary of DuPont. The venture was to provide energy management and financing for steam and electric generation facilities for commercial and industrial customers. Conoco withdrew from the joint venture after its parent announced plans to sell Conoco. The past year also saw the expansion of AEP's domestic energy operations. On December 1, 1998, the Company purchased the midstream gas operations of Equitable Resources, Inc. for approximately $340 million including working capital funds. The midstream operations include a fully integrated natural gas gathering, processing, storage and transportation operation in Louisiana and a gas trading and marketing operation in Houston, Texas. Assets include an intrastate pipeline system, four natural gas processing plants plus a fifth plant under construction, one natural gas storage facility and an additional storage facility under construction. The gas trading operation included in this purchase was merged with AEP's existing gas trading organization which began operating in December 1997. This acquisition is expected to enhance AEP's gas trading operations by improving management's knowledge of the Henry Hub gas market. Traditionally a major marketer of electricity, AEP has recently become a major participant in the electricity trading market. Our electricity trading operation, which commenced in mid 1997, significantly expanded its trading volume in 1998. Electricity trading involves the trading of contracts for the future delivery or receipt of electricity in both regulated and non-regulated operations. It also involves the purchase and sale of options, swaps and other electricity derivative financial instruments. Open access transmission, the introduction of competition to the wholesale electricity market and the development of a trading market and settlement process have fostered the growth of electricity trading in the United States. The electricity trading market is a highly volatile market which requires enhanced credit and market risk management skills. Electricity trading requires little capital investment and profit margins are usually smaller than margins on traditional electricity sales. The Company's goal is to utilize its knowledge of energy markets to trade electricity and gas to contribute to net income, thereby enhancing both customer and shareholder value. In December 1997 the Company and CSW agreed to merge. The merger is intended to expand AEP's geographic reach. The benefits of the merger include costs savings; improved prices and services; increased financial strength; greater diversity in fuel, generation and service territory; and increased scale (the size of the Company which contributes to business success in a competitive market). At the 1998 annual meeting AEP shareholders approved the issuance of common shares to effect the merger and approved an increase in the number of authorized shares of AEP Common Stock from 300,000,000 to 600,000,000 shares. CSW stockholders approved the merger at their May 1998 annual meeting. Approval of the merger has been requested from the Federal Energy Regulatory Commission (FERC), the Securities and Exchange Commission, the Nuclear Regulatory Commission (NRC) and all of CSW's state regulatory commissions: Arkansas, Louisiana, Oklahoma and Texas. In the near future, AEP and CSW plan to make the final two filings associated with approval of the merger with the Federal Communications Commission and the Department of Justice. Regulatory approvals for the merger have been received from the Arkansas Public Service Commission (APSC) and the NRC. In December 1998 the APSC approved a stipulated agreement related to a proposed merger regulatory plan submitted by the Company, CSW and CSW's Arkansas operating subsidiary, Southwestern Electric Power Company. The regulatory plan, agreed to with the APSC staff, provides for a sharing of net merger savings through a $6 million rate reduction over 5 years following the completion of the merger. The application to the NRC by CSW's operating subsidiary, Central Power and Light Company (CPL), requesting permission to transfer indirect control of the license from CSW to AEP for CPL's interest in the South Texas Project nuclear generating station was approved by the NRC in November 1998. In October 1998 the Oklahoma Corporation Commission (OCC) approved plans by AEP and CSW to submit an amended filing seeking approval of the proposed merger. The amended application is being made as a result of an Oklahoma administrative law judge's recommendation that the merger filing be dismissed without prejudice for lack of sufficient information regarding the potential impact of the merger on the retail electric market in Oklahoma. Submission of the amended application will reset Oklahoma's 90-day statutory time period for OCC action on the merger phase of the application. The filing of the amended application should not affect the timing of the merger closing. A settlement agreement between AEP, CSW and certain key parties to the Texas merger proceeding has been reached. The staff of the Public Utility Commission of Texas was not a signatory to the settlement agreement, which resolves all issues for the signatories. The settlement provides for, among other things, rate reductions totaling approximately $180 million over a six year period following completion of the merger to share net merger savings of $84 million and settle existing rate issues of $96 million. Hearings are scheduled for April 1999. In July 1998 the FERC issued an order which confirmed that a 250 megawatt firm contract path with the Ameren System is available. The contract path was obtained by AEP and CSW to meet the requirement of the Public Utility Holding Company Act of 1935 that the two systems operate on an integrated and coordinated basis. In November 1998 the FERC issued an order establishing hearing procedures for the merger and scheduled the hearings to begin on June 1, 1999. The FERC order indicated that the review of the proposed merger will address the issues of competition, market power and customer protection and instructed the companies to refile an updated market power study. The proposed merger of CSW into AEP would result in common ownership of two UK regional electricity companies (RECs), Yorkshire and Seeboard, plc. AEP has a 50% ownership interest in Yorkshire and CSW has a 100% interest in Seeboard. Although the merger of CSW into AEP is not subject to approval by UK regulatory authorities, the common ownership of two UK RECs could be referred by the UK Secretary of State for Trade and Industry to the UK Monopolies and Mergers Commission for investigation. AEP has received a request from the staff of the Kentucky Public Service Commission (KPSC) to file an application seeking KPSC approval for the indirect change in control of Kentucky Power Company that will occur as a result of the proposed merger. Although AEP does not believe that the KPSC has the jurisdictional authority to approve the merger, management will prepare a merger application filing to be made with the KPSC, which is expected to be filed by April 15, 1999. Under the governing statute the KPSC must act on the application within 60 days. Therefore this is not expected to impact the timing of the merger. The merger is conditioned upon, among other things, the approval of the above state and federal regulatory agencies. The transaction must satisfy many conditions, a number of which may not be waived by the parties, including the condition that the merger must be accounted for as a pooling of interests. The merger agreement will terminate on December 31, 1999 unless extended by either party as provided in the merger agreement. Although consummation of the merger is expected to occur in the fourth quarter of 1999, the Company is unable to predict the outcome or the timing of the required regulatory proceedings. Business Outlook The most significant factors affecting the Company's future earnings are the ability to recover its costs as the domestic electric generating business becomes more competitive and the performance of the recently acquired energy investments and business ventures described above. The Company continues to evaluate domestic and international markets for investments to grow the business in the best interests of our shareholders, customers and employees. The performance of any future acquisitions, mergers and investments will also impact future earnings. The introduction of competition and customer choice for retail customers in the Company's domestic service territory has been slow and continues at a deliberate pace as legislators and regulatory officials recognize the complexity of the issues. Federal legislation has been proposed to mandate competition and customer choice at the retail level. In February 1999 the Virginia general assembly passed legislation, subject to the governor's signature, that would provide Virginia retail customers the ability to choose their electric supplier beginning in 2002. The legislation provides for the recovery of "just and reasonable net stranded costs". Prior to January 1, 2001 the Virginia State Corporation Commission must establish rates that will be "capped" through as long as July 1, 2007. Statement of Financial Accounting Standards (SFAS) 71 "Accounting for the Effects of Certain Types of Regulation" will no longer apply to the Company's Virginia retail jurisdiction once the "capped" rates are established. When this occurs the application of SFAS 71 will be discontinued for the Virginia retail jurisdiction portion of the generating business and net regulatory assets applicable to the Virginia generating business would have to be written off to the extent that they are not probable of recovery. Although management does not believe that the impact of the new legislation on regulatory assets would have a material adverse impact on results of operations, cash flows or financial condition, the amount of an impairment loss, if any, cannot be estimated with any certainty until the "capped" rates are determined (See requirements of EITF 97-4 discussed below). All of the other states within our service territory have initiatives to implement or review customer choice, although the timing is uncertain. The Company supports customer choice and deregulation of generation and is proactively involved in discussions at both the state and federal levels regarding the best competitive market structure and method to transition to a competitive marketplace. As the pricing of generation in the electric energy market evolves from regulated cost-of-service ratemaking to market-based rates, many complex issues must be resolved, including the recovery of stranded costs. Stranded costs are those costs above market and potentially would not be recoverable in a competitive market. At the wholesale level recovery of stranded costs under certain conditions was addressed by the FERC when it established rules for open transmission access and competition in the wholesale markets. However, the issue of stranded cost is generally unresolved at the retail level where it is much larger than it is at the wholesale level. The amount of stranded costs the Company could experience depends on the timing and extent to which competition is introduced to its generation business and the future market prices of electricity. The recovery of stranded cost is dependent on the terms of future legislation and related regulatory proceedings. Under the provisions of SFAS 71, regulatory assets (deferred expenses) and regulatory liabilities (deferred revenues) are included in the consolidated balance sheets of regulated utilities in accordance with regulatory actions in order to match expenses and revenues with cost-based rates. In order to maintain net regulatory assets on the balance sheet, SFAS 71 requires that rates charged to customers be cost-based and provide for the recovery of the deferred expenses over future accounting periods. In the event a portion of AEP's business no longer meets the requirements of SFAS 71, SFAS 101 "Accounting for the Discontinuance of Application of Statement 71" requires that net regulatory assets be written off for that portion of the business. The provisions of SFAS 71 and SFAS 101 never anticipated that deregulation would include an extended transition period or that it could provide for recovery of stranded costs during and after the transition period. In 1997 the Financial Accounting Standards Board's Emerging Issues Task Force (EITF) addressed such a situation with the consensus reached on issue 97-4 that requires the application of SFAS 71 to a segment of a regulated electric utility cease when that segment is subject to a legislatively approved plan for competition 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 71 would require that regulatory assets and impaired plant be written off unless they are recoverable in future rates. Although certain FERC orders 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 of December 31, 1998 AEP's generation business is cost-based regulated. The enactment of enabling legislation in Virginia to deregulate the generation business will cause a portion of the Company's generation business to become deregulated. This could ultimately result in adverse impacts on results of operations and cash flows depending on the market price of electricity and the ability of the Company to recover its stranded costs. 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 generating assets. However, if in the future AEP'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 would be adversely affected. Cost Containment and Process Improvements Efforts continue to reduce the costs of AEP's products and services in order to maintain competitiveness. The accounting department completed its consolidation of operations and the marketing department completed its reorganization in 1998 producing significant cost reductions. In 1998 plans were announced to close one of the Company's coal mining operations in October 1999 and the Company reviewed its staffing levels for power generation and energy delivery and developed plans to reduce staff in 1999. The cost of staff reductions planned for 1999 was provided for in the fourth quarter of 1998. Although cost savings are expected to result from the power generation and energy delivery reorganizations and the planned mine closing, the Company continues to incur expenses related to investments in new business growth and development; marketing and customer services; and the reengineering and improvement of business processes. During 1998, AEP completed installation of a new unified customer service system which is designed to support customer requests for service, billings, accounts receivable, credit and collection functions. On January 1, 1999, the Company's new financial data base and PeopleSoft client server accounting and purchasing software became operational. The move to client server business software and related online data bases will empower AEP employees to maximize the benefits of their personal computers and will position AEP to access the power of the Internet and other new technologies. Fuel Costs The management and control of coal costs is critical to AEP's competitive position. Approximately 90% of AEP's generation is coal fired and approximately 13% of the 54 million tons of coal burned in 1998 were supplied by affiliated mines with the remainder acquired 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 when spot market prices are favorable. We have agreed in our Ohio jurisdiction to certain limitations on the current recovery of affiliated coal costs. At December 31, 1998, the Company had deferred $106 million for future recovery under the agreements which established the limitation. See discussion in Note 2 of the Notes to Consolidated Financial Statements. Our analysis shows that we should be able to recover the Ohio jurisdictional portion of the costs of our affiliated mining operations including future mine closure costs before the expiration of the agreement in 2009. The Company has announced plans to close the Muskingum mine in 1999. A provision for Muskingum mine closing cost of $45 million was recorded in 1998. Management intends to seek recovery of its non-Ohio jurisdictional portion of its investment in and the liabilities and closing costs of affiliated mines estimated at $100 million after tax. Should it become apparent that these affiliated mining costs will not be recovered from Ohio and/or non-Ohio jurisdictional customers, the other mines may have to be closed and future earnings, cash flows and possibly financial condition would be adversely affected. In addition compliance with Phase II requirements of the Clean Air Act Amendments of 1990 (CAAA), which become effective in January 2000, could also cause the remaining mining operations to close. Unless the cost of any mine closure and the coal cost deferrals in the Ohio jurisdiction are recovered either in regulated rates or as a stranded cost under a plan to transition the generation business to competition, future earnings, cash flows and possibly financial condition would be adversely affected. Costs for Spent Nuclear Fuel and Decommissioning AEP, as the owner of the Cook Nuclear Plant, like other nuclear power plants, has a significant future financial commitment to safely dispose of spent nuclear fuel (SNF) and decommission and decontaminate the plant. The Nuclear Waste Policy Act of 1982 established federal responsibility for the permanent off-site disposal of SNF and high-level radioactive waste. By law we participate in the Department of Energy's (DOE) SNF disposal program which is described in Note 4 of the Notes to Consolidated Financial Statements. Since 1983 we have collected $272 million from customers for the disposal of nuclear fuel consumed at the Cook Plant. $115 million of these funds have been deposited in external trust funds to provide for the future disposal of spent nuclear fuel and $157 million has been remitted to the DOE. Under the provisions of the Nuclear Waste Policy Act, collections from customers are to provide the DOE with money to build a repository for spent fuel. However, in December 1996, the DOE notified AEP that it would be unable to begin accepting SNF by the January 1998 deadline required by law. As a result of DOE's failure to make sufficient progress toward a permanent repository or otherwise assume responsibility for SNF, AEP along with a number of unaffiliated utilities and states filed suit in the U.S. Court of Appeals for the District of Columbia Circuit requesting, among other things, that the court order DOE to meet its obligations under the law. The court ordered the parties to proceed with contractual remedies but declined to order DOE to begin accepting SNF for disposal. DOE estimates its planned site for the nuclear waste will not be ready until 2010. In June 1998, AEP filed a complaint in the U.S. Court of Federal Claims seeking damages in excess of $150 million due to the DOE's partial material breach of its unconditional contractual deadline to begin disposing of SNF generated by the Cook Nuclear Plant. Similar lawsuits have been filed by other utilities. As long as the delay in the availability of a government approved storage repository for SNF continues, the cost of both temporary and permanent storage will increase. The cost to decommission the Cook Plant is affected by both NRC regulations and the delayed SNF disposal program. Studies completed in 1997 estimate the cost to decommission the Cook Plant ranges from $700 million to $1,152 million in 1997 dollars. This estimate could escalate due to continued uncertainty in the SNF disposal program and the length of time that SNF may need to be stored at the plant site. External trust funds have been established with amounts collected from customers to decommission the plant. At December 31, 1998, the total decommissioning trust fund balance was $443 million which includes earnings on the trust investments. We will work with regulators and customers to recover the remaining estimated cost of decommissioning the Cook Plant. However, AEP's future results of operations, cash flows and possibly its financial condition would be adversely affected if the cost of SNF disposal and decommissioning continues to increase and cannot be recovered. COOK NUCLEAR PLANT SHUTDOWN We shut down both units of the Cook Nuclear Plant in September 1997 due to questions, which arose during a NRC architect engineer design inspection, regarding the operability of certain safety systems. The NRC issued a Confirmatory Action Letter in September 1997 requiring AEP to address the issues identified in the letter. We are working with the NRC to resolve the remaining open issue in the letter. In April 1998 the NRC notified I&M that it had convened a Restart Panel for Cook Plant. A list of required restart activities was provided by the NRC in July 1998 and in October the NRC expanded the list. In order to identify and resolve the issues necessary to restart the Cook units, AEP is and will be meeting with the Panel on a regular basis, until the units are returned to service. In January 1999 we announced that we will conduct additional engineering reviews at the Cook Plant that will delay restart of the units. Previously, the units were scheduled to return to service at the end of the first and second quarters of 1999. The decision to delay restart resulted from internal assessments that indicated a need to conduct expanded system readiness reviews. A new restart schedule will be developed based on the results of the expanded reviews and should be available in June 1999. When maintenance and other activities required for restart are complete, AEP will seek concurrence from the NRC to return the Cook Plant to service. Until these additional reviews are completed, management is unable to determine when the units will be returned to service. Unless the costs of the extended outage and restart efforts are recovered from customers, there would be a material adverse effect on results of operations, cash flows and possibly financial condition. One of the steps AEP has taken toward expediting the restart of the Cook units is to augment its existing nuclear generation management and staff with personnel experienced in restarting unaffiliated companies' nuclear plants during NRC supervised extended outages. The incremental costs incurred in 1997 and 1998 for restart of the Cook units were $6 million and $78 million, respectively, and recorded as operation and maintenance expense. Currently incremental restart expenses are approximately $12 million a month. In July 1998 AEP received an "adverse trend letter" from the NRC indicating that NRC senior managers determined that there had been a slow decline in performance at the Cook Plant during the 18 month period preceding the letter. The letter indicated that the NRC will closely monitor efforts to address issues at Cook Plant through additional inspection activities. In October 1998 the NRC issued AEP a Notice of Violation and proposed a $500,000 civil penalty for alleged violations at the Cook Plant discovered during five inspections conducted between August 1997 and April 1998. AEP paid the penalty. The cost of electricity supplied to certain retail customers rose due to the outage of the two units since higher cost coal-fired generation and coal based purchased power were substituted for low cost nuclear generation. AEP's Indiana and Michigan retail jurisdictional fuel cost recovery mechanisms permit the recovery, subject to regulatory commission review and approval, of changes in fuel costs including the fuel component of purchased power in the Indiana jurisdiction and changes in replacement power in the Michigan jurisdiction. Under these fuel cost recovery mechanisms, retail rates contain a fuel cost adjustment factor that reflects estimated fuel costs for the period during which the factor will be in effect subject to reconciliation to actual fuel costs in a future proceeding. When actual fuel costs exceed the estimated costs reflected in the billing factor a regulatory asset is recorded and revenues are accrued. Therefore, a regulatory asset has been recorded and revenues accrued in anticipation of the future reconciliation and billing under the fuel cost recovery mechanisms of the higher fuel costs to replace Cook energy during the extended outage. At December 31, 1998, the regulatory asset was $65 million. The Indiana Utility Regulatory Commission approved, subject to future reconciliation or refund, agreements authorizing AEP, during the billing months of July 1998 through March 1999, to include in rates a fuel cost adjustment factor less than that requested by AEP. The agreements provide the parties to the proceedings with the opportunity to conduct discovery regarding certain issues that were raised in the proceedings, including the appropriateness of the recovery of replacement energy cost due to the extended Cook Plant outage, in anticipation of resolving the issues in a future fuel cost adjustment proceeding. Management believes that it should be allowed to recover the deferred Cook replacement energy costs; however, if recovery of the replacement costs is denied, future results of operations and cash flows would be adversely affected by the writeoff of the regulatory asset. Environmental Concerns and Issues We take great pride in our efforts to economically produce and deliver electricity while minimizing the impact on the environment. Over the years AEP has spent more than a billion dollars to equip its facilities with the latest cost effective clean air and water technologies and to research new technologies. We are also proud of our award winning efforts to reclaim our mining properties. We intend to continue in a leadership role fostering economically prudent efforts to protect and preserve the environment. By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically disposed of or treated in captive disposal facilities or are beneficially utilized. In addition, our generating plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls (PCBs) and other hazardous and nonhazardous materials. We are currently incurring costs to safely dispose of such substances. Additional costs could be incurred to comply with new laws and regulations if enacted. The Comprehensive Environmental Response, Compensation and Liability Act (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 1998, we are involved in litigation with respect to three sites overseen by the Federal EPA and have been named by the Federal EPA as a potentially responsible party (PRP) for three other sites. There is one additional site for which AEP has received an information request which could lead to PRP designation. Our liability has been resolved for a number of sites with no significant effect on results of operations. In those instances where we have been named a PRP or defendant, our disposal or recycling activity was in accordance with the then-applicable laws and regulations. Unfortunately, Superfund does not recognize compliance as a defense, but imposes strict liability on parties who fall within its broad statutory categories. While the potential liability for each Superfund site must be evaluated separately, several general statements can be made regarding our potential future liability. AEP's disposal of materials at a particular site is often unsubstantiated and the quantity of materials deposited at a site was small and often nonhazardous. Typically many parties are named as PRPs for each site and, although liability is joint and several, generally several of the parties are financially sound enterprises. Therefore, our present estimates do not anticipate material cleanup costs for identified sites for which we have been declared PRPs. However, if for reasons not currently identified significant cleanup costs are attributed in the future to AEP, results of operations, cash flows and possibly financial condition would be adversely affected unless the costs can be recovered from customers. In December 1998 the Company purchased gas assets from Equitable Resources, Inc. (Equitable). The purchase contract contains details of partial indemnification by Equitable for certain environmental and soil and ground water contamination cleanup liabilities which existed at the time of AEP's purchase. An outside consultant has estimated total environmental liabilities for the acquired entities to range from $10 million to $16 million. By contract the Company must seek indemnification by December 1, 2000. The indemnification clause requires that AEP incur $3 million of cleanup liabilities before seeking reimbursement. Based upon the consultant's estimate, environmental liabilities resulting from the gas asset acquisition should not have a material impact on results of operations, cash flows or financial condition. In December 1998, the Company purchased CitiPower, an Australian distribution utility, from Entergy, an unaffiliated company. CitiPower operates under Australian environmental laws. Prior to the purchase, AEP hired an outside consultant, experienced in Australian environmental laws, to identify CitiPower's exposure. The consultant's assessment identified sites with contaminated land, PCBs and storm water runoff. Cost of environmental remediation are estimated at $3.5 million by the consultant. Based upon this estimate, environmental costs from the acquisition of CitiPower are not expected to have a material impact on results of operations, cash flows or financial condition. Federal EPA is required by the CAAA to issue rules to implement the law. In 1996 Federal EPA issued final rules governing nitrogen oxides (NOx) emissions that must be met after January 1, 2000 (Phase II of CAAA). The final rules will require substantial reductions in NOx emissions from certain types of boilers including those in AEP's power plants. To comply with Phase II of CAAA, the Company plans to install NOx emission control equipment on certain units and switch fuel at other units. Total capital costs to meet the requirements of Phase II of CAAA are estimated to be approximately $90 million of which $69 million has been incurred through December 31, 1998. On September 24, 1998, the administrator of Federal EPA signed final rules which require reductions in NOx emissions in 22 eastern states, including the states in which the Company's generating plants are located. The implementation of the final rules would be achieved through the revision of state implementation plans (SIPs) by September 1999. SIPs are a procedural method used by each state to comply with Federal EPA rules. The final rules anticipate the imposition of a NOx reduction on utility sources of approximately 85% below 1990 emission levels by the year 2003. On October 30, 1998, a number of utilities, including the operating companies of the AEP System, filed petitions in the U.S. Court of Appeals for the District of Columbia Circuit seeking a review of the final rules. Should the states fail to adopt the required revisions to their SIPs within one year of the date the final rules were signed (September 24, 1999), Federal EPA has proposed to implement a federal plan to accomplish the NOx reductions. Federal EPA also proposed the approval of portions of petitions filed by eight northeastern states that would result in imposition of NOx emission reductions on utility and industrial sources in upwind midwestern states. These reductions are substantially the same as those required by the final NOx rules and could be adopted by Federal EPA in the event the states fail to implement SIPs in accordance with the final rules. Preliminary estimates indicate that compliance costs could result in required capital expenditures of approximately $1.2 billion for the AEP System. Compliance costs cannot be estimated with certainty and the actual costs incurred to comply could be significantly different from this preliminary estimate depending upon the compliance alternatives selected to achieve reductions in NOx emissions. Unless such costs are recovered from customers, they would have a material adverse effect on results of operations, cash flows and possibly financial condition. At the Third Conference of the Parties to the United Nations Framework Convention on Climate Change held in Kyoto, Japan in December 1997 more than 160 countries, including the United States, negotiated a treaty requiring legally-binding reductions in emissions of greenhouse gases, chiefly carbon dioxide, which many scientists believe are contributing to global climate change. The treaty, which requires the advice and consent of the United States Senate for ratification, would require the United States to reduce greenhouse gas emissions seven percent below 1990 levels in the years 2008-2012. Although the United States has agreed to the treaty and signed it on November 12, 1998, President Clinton has indicated that he will not submit the treaty to the Senate for consideration until it contains requirements for "meaningful participation by key developing countries" and the rules, procedures, methodology and guidelines of the treaty's market-based policy instruments, joint implementation programs and compliance enforcement provisions have been negotiated. At the Fourth Conference of the Parties, held in Buenos Aires, Argentina, in November 1998, the parties agreed to a work plan to complete negotiations on outstanding issues with a view toward approving them at the Sixth Conference of the Parties to be held in December 2000. We will continue to work with the Administration and Congress to monitor the development of public policy on this issue. If the Kyoto treaty is approved by Congress, the costs to comply with the emission reductions required by the treaty are 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 Net Income Net income increased 5% to $536 million or $2.81 per share from $511 million or $2.70 per share in 1997 primarily due to the effect of a 1997 extraordinary loss of $109 million. The extraordinary loss, recorded in 1997, was a result of the UK's one-time windfall tax which was based on a revision or recomputation of the original privatization value of certain privatized utilities, including Yorkshire. In 1997 net income decreased 13% to $511 million primarily due to the extraordinary loss of $109 million from the UK's one-time windfall tax. Income Before Extraordinary Item In 1998 income before the extraordinary loss, recorded in 1997, decreased 14% to $536 million or $2.81 per share from $620 million or $3.28 per share in 1997. Several major items reduced 1998 earnings including the cost of restart activities during an extended outage at the Cook Nuclear Plant, a write-down of Yorkshire's investment in Ionica, a UK telecommunications company, severance accruals for reductions in power generation and energy delivery staff and mild winter and fall weather. AEP's 1997 income before the extraordinary loss increased 6% to $620 million or $3.28 per share from $587 million or $3.14 per share in 1996. The increase was primarily attributable to increased transmission service revenues, reduced preferred stock dividends due to a redemption program and an increase in nonoperating income from equity earnings, exclusive of the extraordinary loss, since the April 1997 investment in Yorkshire. Revenues Increase Operating revenues increased 8% in 1998 and were relatively unchanged in 1997. Increased revenues from retail, wholesale and transmission service customers were the primary reasons for the increase in 1998. The slight increase in 1997 is primarily due to increased transmission service revenues. The changes in the components of revenues are as follows: Increase (Decrease) From Previous Year (Dollars in Millions) 1998 1997 Amount % Amount % Retail: Residential $ 37.6 $(34.7) Commercial 57.0 1.8 Industrial 90.1 18.2 Other 3.8 0.4 188.5 3.8 (14.3) (0.3) Wholesale 206.8 25.9 6.1 0.8 Transmission 68.0 61.7 33.3 43.2 Miscellaneous 2.8 4.8 5.5 10.9 Total $466.1 7.9 $ 30.6 0.5 Retail revenues increased 4% in 1998 reflecting a 2% sales increase and higher fuel recoveries. The increase in retail fuel recoveries reflects higher cost coal fired generation and purchased power replacing power usually generated at the Cook Nuclear Plant. The Cook Plant has been unavailable since September 1997. Although residential sales were flat reflecting mild winter and fall weather in 1998, revenues from residential customers increased 2%. The accrual of revenues for the recovery of the Cook related increased fuel costs accounted for the increase in residential revenues. The rise in commercial revenues resulted from a 4% increase in sales reflecting increased usage and growth in the number of customers. Industrial revenues increased 6% reflecting a sales increase of 2% following the resumption of operations by a major industrial customer after an extended labor strike. Also contributing to the increase in industrial revenues were favorable contract price adjustments to certain major industrial customers and the pass-through of higher power costs during periods of peak demand. In 1997 retail revenues decreased slightly although retail sales rose one half of a percent. Residential revenues and sales each declined 2% reflecting mild weather. Sales to commercial customers increased slightly causing a small increase in commercial revenues. Industrial sales increased 2% accounting for the increase in industrial revenues. The increase in lower priced sales to industrial customers resulted from increased usage. The 26% increase in wholesale revenues in 1998 is attributable to trading of electricity with other utilities and power marketers in the Company's traditional marketing area and increased power marketing sales. Revenues from the trading of electricity are recorded net of purchases. Regulated trading activities are conducted as part of AEP's electric power wholesale marketing and trading operations and involve the purchase and sale of substantial amounts of electricity. Power marketing sales are for the resale of power purchased from unaffiliated companies to other unaffiliated companies. Although wholesale revenues rose, total wholesale sales declined due to a reduction in coal conversion service sales. These sales are for the generation of electricity from the purchaser's coal and as a result do not include fuel costs. Consequently, the drop in coal conversion service sales did not have a significant effect on wholesale revenues. In 1997 wholesale revenues increased slightly primarily due to the commencement of trading activities in July 1997 and a significant increase in coal conversion service sales. Since the price of coal conversion service sales is for the generation of electricity from coal provided by the electricity purchaser and excludes fuel cost, a large change in coal conversion service sales has a small impact on revenues. The 62% increase in transmission service revenues in 1998 is attributable to a substantial rise in the quantity of energy transmitted for other entities over AEP's transmission lines. The increase in 1997 of 43% in transmission service revenues was also due to an increase in the volume of other companies' electricity transmitted through AEP's transmission system. The issuance in 1996 of open transmission access rules by the FERC facilitated the growth in transmission services. The level of wholesale transactions, including transmission services, tends to fluctuate due to the highly competitive nature of the short-term energy market and other factors, such as affiliated and unaffiliated generating plant availability, the weather and the economy. The FERC rules which introduced a greater degree of competition into the wholesale energy market have had a major effect on wholesale sales and increased transmission service revenues as more electricity is traded in the short-term (spot) market. The Company's sales and in turn its results of operations were impacted by the quantities of energy and services sold to wholesale customers as well as the sale prices and cost of goods sold. Future results of operations will be affected by the quantity and price of both retail and wholesale transactions which often depend on factors the Company does not control including the level of competition, the weather and affiliated and unaffiliated power plant availability. However, we work to keep abreast of these factors and to take advantage of them whenever possible. Operating Expenses Increase Operating expenses increased 10% in 1998 and 1% in 1997. Changes in the components of operating expenses were as follows: Increase (Decrease) From Previous Year (Dollars in Millions) 1998 1997 Amount % Amount % Fuel $ 90.1 5.5 $ 26.4 1.6 Purchased Power 301.7 223.9 48.6 56.5 Other Operation 75.7 6.2 17.3 1.4 Maintenance 59.7 12.3 (19.6) (3.9) Depreciation and Amortization (11.1) (1.9) (9.7) (1.6) Taxes Other Than Federal Income Taxes 2.8 0.6 (8.0) (1.6) Federal Income Taxes (25.1) (7.3) (0.9) (0.3) Total $493.8 10.1 $ 54.1 1.1 Fuel expense increased in 1998 and 1997 primarily due to an increase in the average cost of fuel consumed reflecting the reduced availability of lower cost nuclear generation due to the unplanned shutdown of both of AEP's nuclear units which began in September 1997 and continued throughout 1998. The significant increases in purchased power expense in both 1998 and 1997 were primarily due to purchases of electricity for resale to other utilities and power marketers and for replacement of energy usually generated at the Cook Plant. The increase in purchases made for resale to other entities reflects an expanding and evolving wholesale marketplace. Other operation expenses increased in 1998 due to the extended Cook Plant outage, power marketing and trading compensation and severance accruals for reductions in power generation and energy delivery staff. Maintenance expense increased in 1998 largely due to expenditures to prepare the Cook Plant units for restart and to restore service interrupted by two severe snowstorms. The decrease in federal income tax expense attributable to operations in 1998 was primarily due to a decrease in pre-tax operating income. Nonoperating Income The significant decline in nonoperating income in 1998 was due to losses from non-regulated energy trading activity and the write-down of Yorkshire's investment in Ionica ($30 million). The trading of gas and electricity outside of AEP's traditional marketing area is marked-to-market and recorded in nonoperating income. The increase in nonoperating income in 1997 was mainly due to income from the Company's share of earnings from its April 1997 investment in Yorkshire. The $34 million of equity in Yorkshire earnings included $10 million of tax benefits related to a reduction of the UK corporate income tax rate from 33% to 31% effective April 1, 1997. The utilization of foreign tax credits also contributed to the increase in nonoperating income. Interest Charges and Preferred Stock Dividend Requirements In 1997 interest charges on both long-term and short-term debt increased reflecting additional borrowing primarily to fund the Company's investment in non-regulated operations including the investment in Yorkshire. Preferred stock dividend requirements of the subsidiaries decreased in 1997 due to the reacquisition of over 4 million shares of cumulative preferred stock. Financial Condition AEP's financial condition continues to be strong. The 1998 payout ratio was 85.4%. It has been a management objective to reduce the payout ratio through efforts to increase earnings in order to enhance AEP's ability to invest in new energy based businesses that can leverage our core competencies and improve shareholder value. AEP's three-year total shareholder return ranked 14th among the companies in the S&P Electric Utility Index. While this placed us just below the midpoint, it has been and continues to be management's goal to be in the top quartile of the S&P Electric Utility Index for three-year total shareholder return. Capital Investments The total consideration paid by AEP to acquire CitiPower was approximately $1.1 billion which was financed by the issuance of debt in Australia and an equity investment by AEP Resources, Inc. (AEPR). The purchase, for approximately $340 million, of domestic gas assets in Louisiana was funded with part of the proceeds from an issuance of $400 million of 6-1/2% senior notes by AEPR. For more information see Note 6 of the Notes to Consolidated Financial Statements. Also AEP's 70% interest in the construction of two 125 MW units in China required approximately $61 million of investment during 1998. Consolidated construction expenditures for all subsidiaries are expected to be $2.4 billion over the next three years. All expenditures for domestic electric utility construction, estimated to be $2.2 billion for the next three years, are expected to be financed with internally generated funds. Capital Resources - Structure and Liquidity AEP's ratio of common equity to total capitalization including amounts due within one year was 40.3% for 1998, compared with 45.5% for 1997 and 45.3% for 1996. The decline in 1998 reflects borrowing to support the acquisitions which were completed in December. The Company and its subsidiaries issued $1.9 billion principal amount of long-term obligations in 1998 at interest rates ranging from 5% to 10.53%. The Company also increased its borrowing under a long-term revolving credit agreement which expires in June 2000 by $270 million. The principal amount of long-term debt retirements, including maturities, totaled $563 million with interest rates ranging from 2.85% to 9.60%. The operating subsidiaries senior secured debt/first mortgage bond ratings are listed in the following table: Company Moody's S&P Fitch D & P APCo A3 A A A CSPCo A3 A- A- A I&M Baa1 A- BBB+ BBB+ KPCo Baa1 A BBB+ BBB+ OPCo A3 A- A- A The operating subsidiaries generally issue short-term debt to provide for interim financing of capital expenditures that exceed internally generated funds. They periodically reduce their outstanding short-term debt through issuances of long-term debt and additional capital contributions by the parent company. The companies formed to pursue non-regulated businesses use short-term debt (through a revolving credit facility) which is replaced with long-term debt when financial market conditions are favorable and capital contributions by the parent company. They also assume outstanding debt as part of the acquisition of existing business entities. Short-term debt increased $62 million from the prior year-end balance and increased by $235 million in 1997. At December 31, 1998, AEP Co., Inc. (the parent company) and its subsidiaries had unused short-term lines of credit of $763 million, and several of AEP's subsidiaries engaged in non-regulated energy investments and businesses had available $60 million under a $600 million revolving credit agreement which expires in June 2000. The sources of funds available to AEP are dividends from its subsidiaries, short-term and long-term borrowings and proceeds from the issuance of common stock. AEP issued 1,826,000 shares of common stock in 1998, 1,755,000 shares in 1997 and 1,600,000 shares in 1996 through a Dividend Reinvestment and Direct Stock Purchase Plan and the Employee Savings Plan raising $86 million, $77 million and $65 million, respectively. Additional sales of common stock and/or equity linked securities may be necessary in the future to support the Company's growth. Unless the domestic electric operating utility subsidiaries meet certain earnings or coverage tests, they cannot issue additional mortgage bonds. In order to issue mortgage bonds (without refunding existing debt), each subsidiary must have pre-tax earnings equal to at least two times the annual interest charges on mortgage bonds after giving effect to the issuance of the new debt. The following debt coverages of AEP's principal domestic electric operating utility subsidiaries remained strong in 1998: Coverages at December 31, 1998 Mortgage APCo 3.88 CSPCo 6.36 I&M 6.39 KPCo 4.40 OPCo 13.43 As the above table indicates, the major domestic electric operating utility subsidiaries presently exceed the minimum coverage requirements. Market Risks The Company as a major power producer and a trader of wholesale electricity and natural gas has certain market risks inherent in its business activities. The trading of electricity and natural gas and related financial derivative instruments exposes the Company to market risk. Market risk represents the risk of loss that may impact the Company due to adverse changes in commodity market prices and rates. In 1998 the Company substantially increased the volume of its wholesale electricity and natural gas marketing and trading activities. Various policies and procedures have been established to manage market risk exposures including the use of a risk measurement model utilizing Value at Risk (VaR). Throughout the year ending December 31, 1998, the highest, lowest and average quarterly VaR in the wholesale trading portfolio was less than $11 million at a 95% confidence level with a holding period of three business days. The Company used the variance-covariance method for calculating VaR based on three months of daily prices. Based on this VaR analysis, at December 31, 1998 a near term change in commodity prices is not expected to have a material effect on the Company's results of operations, cash flows or financial condition. At December 31, 1997, the exposure for financial derivatives in electricity and natural gas marketing activities were not material to the Company's consolidated results of operations, financial position or cash flows. Investments in foreign ventures expose the Company to risk of foreign currency fluctuations. The Company's exposure to changes in foreign currency exchange rates related to these foreign ventures and investments is not expected to be significant for the foreseeable future since these foreign investments are considered long-term and not expected to be liquidated in the near-term. The Company does not presently utilize derivatives to manage its exposures to foreign currency exchange rate movements. The Company is exposed to changes in interest rates primarily due to short- and long-term borrowings to fund its business operations. The debt portfolio has both fixed and variable interest rates, terms from one day to forty years and an average duration of five years at December 31, 1998. The Company measures interest rate market risk exposure utilizing a VaR model. The model is based on the Monte Carlo method of simulated price movements with a 95% confidence level and a one year holding period. The volatilities and correlations were based on three years of monthly prices. The risk of potential loss in fair value attributable to the Company's exposure to interest rates, primarily related to long-term debt with fixed interest rates, was $589 million at December 31, 1998 and $501 million at December 31, 1997. The Company would not expect to liquidate its entire debt portfolio in a one year holding period. Therefore, a near term change in interest rates should not materially affect results of operations or the consolidated financial position of the Company. The Company is currently utilizing interest rate swaps to manage its exposure to interest rate fluctuations in Australia. The Company has investments in debt and equity securities which are held in nuclear trust funds. Approximately 85% of the trust fund value is invested in tax exempt and taxable bonds, short-term debt instruments or cash. The trust investments and their fair value are discussed in Note 11 of the Notes to Consolidated Financial Statements. Instruments in the trust funds have not been included in the market risk calculation for interest rates as these instruments are marked-to-market and changes in market value are reflected in a corresponding decommissioning liability. Any differences between the trust fund assets and the ultimate liability should be recoverable from ratepayers. Inflation affects AEP's cost of replacing utility plant and the cost of operating and maintaining its plant. The rate-making process limits our recovery to the historical cost of assets resulting in economic losses when the effects of inflation are not recovered from customers on a timely basis. However, economic gains that result from the repayment of long-term debt with inflated dollars partly offset such losses. Other Matters Year 2000 Readiness Disclosure On or about midnight on December 31, 1999, digital computing systems may begin to produce erroneous results or fail, unless these systems are modified or replaced, because such systems may be programmed incorrectly and interpret the date of January 1, 2000 as being January 1st of the year 1900 or another incorrect date. In addition, certain systems may fail to detect that the year 2000 is a leap year. Problems can also arise earlier than January 1, 2000, as dates in the next millennium are entered into non-Year 2000 ready programs. Readiness Program - Internally, the Company is modifying or replacing its computer hardware and software programs to minimize Year 2000-related failures and repair such failures if they occur. This includes both information technology systems (IT), which are mainframe and client server applications, and embedded logic systems (non-IT), such as process controls for energy production and delivery. Externally, the problem is being addressed with entities that interact with the Company, including suppliers, customers, creditors, financial service organizations and other parties essential to the Company's operations. In the course of the external evaluation, the Company has sought written assurances from third parties regarding their state of Year 2000 readiness. Another issue we are addressing is the impact of electric power grid problems that may occur outside of our transmission system. AEP, along with other electric utilities in North America, regularly submits information to the North American Electric Reliability Council (NERC) as part of NERC's Year 2000 readiness program. NERC then publicly reports summary information to the U.S. Department of Energy (DOE) regarding the Year 2000 readiness of electric utilities. In 1999 AEP plans to participate in two NERC-sponsored coordinated electric industry Year 2000 readiness drills. The second NERC report, dated January 11, 1999 and entitled: Preparing the Electric Power Systems of North American for Transition to the Year 2000 - A Status Report and Work Plan, Fourth Quarter 1998, states that: "With more than 44% of mission critical components tested through November 30, 1998, findings continue to indicate that transition through critical Year 2000 (Y2K) rollover dates is expected to have minimal impact on electric system operations in North America." The Company continues to set a target date of June 30, 1999 for having all mission critical and high priority systems and components Y2K ready. Through the Electric Power Research Institute, an electric industry-wide effort has been established to deal with Year 2000 problems affecting embedded systems. Under this effort, participating utilities, including AEP, are working together to assess specific vendors' system problems and test plans. The state regulatory commissions in the Company's service territory are also reviewing the Year 2000 readiness of the Company. Company's State of Readiness - Work has been prioritized in accordance with business risk. The highest priority has been assigned to activities that potentially affect safety, the physical generation and delivery of energy and communications; followed by back office activities such as customer service/billing, regulatory reporting, internal reporting and administrative activities (e.g. payroll, procurement, accounts payable); and finally, those activities that would cause inconvenience or productivity loss in normal business operations. The following chart shows our progress toward becoming ready for the Year 2000 as of December 31, 1998: IT SYSTEMS NON-IT SYSTEMS COMPLETION COMPLETION DATE/ESTIMATED PERCENT DATE/ESTIMATED PERCENT YEAR 2000 PROJECT PHASES COMPLETION DATE COMPLETE COMPLETION DATE COMPLETE Launch: Initiation of 2/24/1998 100% 5/31/1998 100% the Year 2000 activities within the organization. Establishment of organizational structure, personnel assignments and budget for the workgroup. Continuous management update and awareness program. Inventory and Assessment: Identifying all Company 7/31/1998 100% 2/15/1999 99% computer systems that could be affected by the millennium change. Prioritize repair efforts based upon criticality to maintaining ongoing operations. Remediation/Testing: The process of modifying, 6/30/1999 Mainframe 6/30/1999 37% replacing or retiring 70% those mission critical and high priority digital-based systems with problems Client processing dates past the Server: Year 2000. Testing these 18% systems to ensure that after modifications have been implemented correct date processing occurs and full functionality has been maintained. The above chart does not reflect progress of recently acquired midstream gas operations and CitiPower. The mission critical systems for the midstream gas operations are expected to be ready by June 30, 1999 and the mission critical systems for CitiPower are expected to be ready by October 1, 1999. Costs to Address the Company's Year 2000 Issues - Through December 31, 1998, the Company has spent $21 million on the Year 2000 project and estimates spending an additional $35 million to $47 million to achieve Year 2000 readiness. Most Year 2000 costs are for software, IT consultants and salaries and are expensed; however, in certain cases the Company has acquired hardware that was capitalized. The Company intends to fund these expenditures through internal sources. Although significant, the cost of becoming Year 2000 compliant is not expected to have a material impact on the Company's results of operations, cash flows or financial condition. Risks of the Company's Year 2000 Issues - The applications posing the greatest business risk to the Company's operations should they experience Y2K problems are: * Automated power generation, transmission and distribution systems * Telecommunications systems * Energy trading systems * Time-in-use, demand and remote metering systems for commercial and industrial customers * Work management and billing systems. The potential problems related to erroneous processing by, or failure of, these systems are: * Power service interruptions to customers * Interrupted revenue data gathering and collection * Poor customer relations resulting from delayed billing and settlement. CitiPower operates under a legal and regulatory regime which may expose it to customer claims, that may differ from claims under the US legal and regulatory regime, for service interruptions and/or power quality problems resulting from Y2K problems. In addition, although as discussed the Company is monitoring its relationships with third parties, such as suppliers, customers and other electric utilities, these third parties nonetheless represent a risk that cannot be assessed with precision or controlled with certainty. Due to the complexity of the problem and the interdependent nature of computer systems, if our corrective actions, and/or the actions of others not affiliated with AEP, fail for critical applications, Year 2000-related issues may materially adversely affect AEP. Company's Contingency Plans - To address possible failures of electric generation and delivery of electrical energy due to Year 2000 related failures, we have established a draft Year 2000 contingency plan and submitted it to the East Central Area Reliability Council (ECAR) in December 1998 as part of NERC's review of regional and individual electric utility contingency plans in 1999. NERC's target date is June 1999 for the completion of this contingency plan. In addition, the Company intends to establish contingency plans for its business units to address alternatives if Year 2000 related failures occur. AEP's contingency plans will be developed by the end of 1999. AEP's plans build upon the disaster recovery, system restoration, and contingency planning that we have had in place. New Accounting Standards In 1997 the FASB issued SFAS 130 "Reporting Comprehensive Income" and SFAS No. 131 "Disclosures About Segments of an Enterprise and Related Information." SFAS 130 establishes the standards for reporting and displaying components of "comprehensive income," which is the total of net income and all transactions not included in net income affecting equity except those with shareholders. The Company adopted SFAS 130 in the first quarter of 1998. For 1998 there were no material differences between net income and comprehensive income. SFAS 131 initiates reporting standards for annual and interim financial statements about operating segments of a business for which separate financial information is available and regularly evaluated by the chief operating decision maker in allocating resources and reviewing performance. Information about products and services and geographic areas is to be reported at an enterprise-level instead of by segment. SFAS 131 was required to be adopted by the Company for the year ended December 31, 1998 with restatement of prior period comparative information. Adoption of SFAS 131 did not have any effect on results of operations, cash flows or financial condition. In the first quarter of 1998 the Company adopted the American Institute of Certified Public Accountants' (AICPA) Statement of Position (SOP) 98-1, "Accounting for the Costs of Computer Software Developed or Obtained for Internal Use". The SOP requires the capitalization and amortization of certain costs of acquiring or developing internal use computer software. Previously the Company expensed all software acquisition and development costs. The SOP had to be adopted at the beginning of a fiscal year with no restatement or retroactive adjustment of prior periods. The adoption of the SOP effective January 1, 1998 did not have a material effect on results of operations, cash flows or financial condition. In February 1998, the FASB issued SFAS 132 "Employers' Disclosure about Pensions and Other Postretirement Benefits" which revised employers' disclosures about pensions and other postretirement benefit plans and suggested that the disclosure be combined. It did not change the measurement or recognition requirements for postretirement benefit accounting. The adoption of SFAS 132 did not have a material effect on results of operations, cash flows or financial condition. Prior periods were restated to comply with SFAS 132 presentation requirements. EITF 98-10 "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" was issued in November 1998 to address the application of mark-to-market accounting for energy trading contracts. Under the provisions of this standard, which must be adopted by the Company in January 1999, energy trading contracts can no longer be accounted for on a settlement basis. Instead they are to be marked-to-market. Adoption of EITF 98-10 is not expected to have a significant impact on results of operations, cash flows or financial condition. The FASB issued SFAS 133 "Accounting for Derivative Instruments and Hedging Activities" in June 1998. SFAS 133 establishes accounting and reporting standards for derivative instruments. It requires that all derivatives be recognized as either an asset or a liability and measured at fair value in the financial statements. If certain conditions are met a derivative may be designated as a hedge of possible changes in fair value of an asset, liability or firm commitment; variable cash flows of forecasted transactions; or foreign currency exposure. The accounting/reporting for changes in a derivative's fair value (gains and losses) depend on the intended use and resulting designation of the derivative. Management is currently studying the provisions of SFAS 133 to determine the impact of its adoption on January 1, 2000 on results of operations, cash flows and financial condition. In April 1998 the AICPA issued SOP 98-5 "Reporting on the Costs of Start-up Activities". The SOP clarifies the accounting and reporting for one time start-up activities and organization costs, requiring that they be expensed as incurred. The adoption of this standard in January 1999 is not expected to have a material effect on results of operations, cash flows or financial condition. Litigation Corporate Owned Life Insurance The Internal Revenue Service (IRS) agents auditing the AEP System's consolidated federal income tax returns requested a ruling from their National Office that certain interest deductions claimed by the Company relating to AEP's corporate owned life insurance (COLI) program should not be allowed. As a result of a suit filed by AEP in United States District Court (discussed below) this request for ruling was withdrawn by the IRS agents. Adjustments have been or will be proposed by the IRS disallowing COLI interest deductions for taxable years 1991-96. A disallowance of the COLI interest deductions through December 31, 1998 would reduce earnings by approximately $316 million (including interest). The Company has made no provision for any possible adverse earnings impact from this matter. In 1998 the Company made payments of taxes and interest attributable to COLI interest deductions for taxable years 1991-97 to avoid the potential assessment by the IRS of any additional above market rate interest on the contested amount. The payments to the IRS are included on the balance sheet in other property and investments pending the resolution of this matter. The Company will seek refund, either administratively or through litigation, of all amounts paid plus interest. In order to resolve this issue without further delay, on March 24, 1998, the Company filed suit against the United States in the United States District Court for the Southern District of Ohio. Management believes that it has a meritorious position and will vigorously pursue this lawsuit. In the event the resolution of this matter is unfavorable, it will have a material adverse impact on results of operations, cash flows and possibly financial condition. AEP is involved in a number of other 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. AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF INCOME (in thousands - except per share amounts)
Year Ended December 31, 1998 1997 1996 OPERATING REVENUES $6,345,902 $5,879,820 $5,849,234 OPERATING EXPENSES: Fuel 1,717,177 1,627,066 1,600,659 Purchased Power 436,388 134,718 86,095 Other Operation 1,303,084 1,227,368 1,210,027 Maintenance 542,935 483,268 502,841 Depreciation and Amortization 579,997 591,071 600,851 Taxes Other Than Federal Income Taxes 493,386 490,595 498,567 Federal Income Taxes 316,201 341,280 342,222 TOTAL OPERATING EXPENSES 5,389,168 4,895,366 4,841,262 OPERATING INCOME 956,734 984,454 1,007,972 NONOPERATING INCOME (net) 9,463 59,572 2,212 INCOME BEFORE INTEREST CHARGES AND PREFERRED DIVIDENDS 966,197 1,044,026 1,010,184 INTEREST CHARGES 419,088 405,815 381,328 PREFERRED STOCK DIVIDEND REQUIREMENTS OF SUBSIDIARIES 10,926 17,831 41,426 INCOME BEFORE EXTRAORDINARY ITEM 536,183 620,380 587,430 EXTRAORDINARY LOSS - UK WINDFALL TAX - (109,419) - NET INCOME $ 536,183 $ 510,961 $ 587,430 AVERAGE NUMBER OF SHARES OUTSTANDING 190,774 189,039 187,321 EARNINGS PER SHARE: Before Extraordinary Item $2.81 $3.28 $3.14 Extraordinary Loss - (0.58) - Net Income $2.81 $2.70 $3.14 CASH DIVIDENDS PAID PER SHARE $2.40 $2.40 $2.40 CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (in thousands) Year Ended December 31, 1998 1997 1996 RETAINED EARNINGS JANUARY 1 $1,605,017 $1,547,746 $1,409,645 NET INCOME 536,183 510,961 587,430 DEDUCTIONS: Cash Dividends Declared 457,638 453,453 449,353 Other 1 237 (24) RETAINED EARNINGS DECEMBER 31 $1,683,561 $1,605,017 $1,547,746 See Notes to Consolidated Financial Statements. /TABLE AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED BALANCE SHEETS (in thousands - except share data)
December 31, 1998 1997 ASSETS ELECTRIC UTILITY PLANT: Production $ 9,591,211 $ 9,493,158 Transmission 3,570,717 3,501,580 Distribution 4,779,772 4,654,234 General (including mining assets and nuclear fuel) 1,641,676 1,604,671 Construction Work in Progress 562,891 342,842 Total Electric Utility Plant 20,146,267 19,596,485 Accumulated Depreciation and Amortization 8,416,397 7,963,636 NET ELECTRIC UTILITY PLANT 11,729,870 11,632,849 OTHER PLANT 841,451 62,213 OTHER PROPERTY AND INVESTMENTS 2,515,103 1,294,291 CURRENT ASSETS: Cash and Cash Equivalents 172,985 91,481 Accounts Receivable: Customers 557,382 559,203 Miscellaneous 360,783 115,075 Allowance for Uncollectible Accounts (11,075) (6,760) Fuel - at average cost 215,699 224,967 Materials and Supplies - at average cost 279,823 263,613 Accrued Utility Revenues 186,006 189,191 Energy Marketing and Trading Contracts 372,380 2,306 Prepayments and Other 83,686 81,366 TOTAL CURRENT ASSETS 2,217,669 1,520,442 REGULATORY ASSETS 1,846,718 1,817,540 DEFERRED CHARGES 332,391 288,011 TOTAL $19,483,202 $16,615,346 See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED BALANCE SHEETS
December 31, 1998 1997 CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock-Par Value $6.50: 1998 1997 Shares Authorized. .600,000,000 300,000,000 Shares Issued. . . .200,816,469 198,989,981 (8,999,992 shares were held in treasury) $ 1,305,307 $ 1,293,435 Paid-in Capital 1,852,912 1,778,782 Retained Earnings 1,683,561 1,605,017 Total Common Shareholders' Equity 4,841,780 4,677,234 Cumulative Preferred Stocks of Subsidiaries:* Not Subject to Mandatory Redemption 46,002 46,724 Subject to Mandatory Redemption 127,605 127,605 Long-term Debt* 6,799,641 5,129,463 TOTAL CAPITALIZATION 11,815,028 9,981,026 OTHER NONCURRENT LIABILITIES 1,428,968 1,246,537 CURRENT LIABILITIES: Long-term Debt Due Within One Year* 206,476 294,454 Short-term Debt 616,604 555,075 Accounts Payable 618,019 353,256 Taxes Accrued 381,905 380,771 Interest Accrued 75,184 76,361 Obligations Under Capital Leases 81,661 101,089 Energy Marketing and Trading Contracts 360,248 1,983 Other 461,540 322,687 TOTAL CURRENT LIABILITIES 2,801,637 2,085,676 DEFERRED INCOME TAXES 2,601,402 2,560,921 DEFERRED INVESTMENT TAX CREDITS 350,946 376,250 DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2 222,042 231,320 DEFERRED CREDITS 263,179 133,616 COMMITMENTS AND CONTINGENCIES (Note 4) TOTAL $19,483,202 $16,615,346 *See Accompanying Schedules.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF CASH FLOWS (in thousands)
Year Ended December 31, 1998 1997 1996 OPERATING ACTIVITIES: Net Income $ 536,183 $ 510,961 $ 587,430 Adjustments for Noncash Items: Depreciation and Amortization 619,557 608,217 590,657 Deferred Federal Income Taxes 41,449 (6,549) (21,478) Deferred Investment Tax Credits (25,304) (25,241) (25,808) Amortization of Operating Expenses and Carrying Charges (net) 14,786 12,001 55,458 Equity in Earnings of Yorkshire Electricity Group plc (38,459) (33,780) - Extraordinary Item - UK Windfall Tax - 109,419 - Deferred Costs Under Fuel Clause Mechanisms (73,219) (52,469) 51 Changes in Certain Current Assets and Liabilities: Accounts Receivable (net) (141,637) (136,186) (39,049) Fuel, Materials and Supplies 2,108 (1,427) 35,831 Accrued Utility Revenues 3,185 (14,225) 32,953 Accounts Payable 200,195 147,029 (13,915) Taxes Accrued (826) (33,402) (6,019) Payment of Disputed Tax and Interest Related to COLI (302,739) (3,080) - Other (net) 194,247 116,654 40,951 Net Cash Flows From Operating Activities 1,029,526 1,197,922 1,237,062 INVESTING ACTIVITIES: Construction Expenditures (792,118) (760,394) (577,691) Investment in Yorkshire Electricity Group plc - (363,436) - Investment in CitiPower (1,054,081) - - Investment in Gas Assets (340,131) - - Other (26,370) 2,142 12,283 Net Cash Flows Used For Investing Activities (2,212,700) (1,121,688) (565,408) FINANCING ACTIVITIES: Issuance of Common Stock 85,515 76,745 65,461 Issuance of Long-term Debt 2,491,113 880,522 407,291 Retirement of Cumulative Preferred Stock (547) (433,329) (70,761) Retirement of Long-term Debt (915,294) (348,157) (601,278) Change in Short-term Debt (net) 61,529 235,380 (45,430) Dividends Paid on Common Stock (457,638) (453,453) (449,353) Net Cash Flows From (Used For) Financing Activities 1,264,678 (42,292) (694,070) Net Increase (Decrease) in Cash and Cash Equivalents 81,504 33,942 (22,416) Cash and Cash Equivalents January 1 91,481 57,539 79,955 Cash and Cash Equivalents December 31 $ 172,985 $ 91,481 $ 57,539 See Notes to Consolidated Financial Statements. /TABLE AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. Significant Accounting Policies: Organization - American Electric Power (AEP or the Company) is one of the United States' (US) largest investor-owned public utility holding companies engaged in the generation, purchase, transmission and distribution of electric power to 3 million retail customers in its seven state service territory which covers portions of Ohio, Michigan, Indiana, Kentucky, West Virginia, Virginia and Tennessee. Electric power is also supplied at wholesale to neighboring utility systems and power marketers. AEP also has other energy holdings in the US, the United Kingdom (UK), China and Australia. The organization of AEP consists of American Electric Power Company, Inc. (AEP Co., Inc.), the parent holding company; seven domestic regulated electric utility operating companies (domestic utility subsidiaries); a domestic generating subsidiary, AEP Generating Company (AEGCo); three active coal-mining companies; a service company, American Electric Power Service Corporation (AEPSC); AEP Resources, Inc. (AEPR) which invests in, owns and operates non-regulated energy-related domestic and international projects; AEP Energy Services, Inc. (AEPES) which markets and trades energy commodities; and other subsidiaries that provide non-regulated energy and communication services. The following domestic utility subsidiaries pool their generating and transmission facilities and operate them as an integrated system: Appalachian Power Company (APCo), Columbus Southern Power Company (CSPCo), Indiana Michigan Power Company (I&M), Kentucky Power Company (KPCo) and Ohio Power Company (OPCo). The remaining two domestic utility subsidiaries, Kingsport Power Company (KGPCo) and Wheeling Power Company (WPCo) are distribution companies that purchase power from APCo and OPCo, respectively. AEPSC provides management and professional services to the AEP System subsidiaries. The active coal-mining companies are wholly-owned by OPCo and sell most of their production to OPCo. AEGCo has a 50% interest in the Rockport Plant which is comprised of two of the AEP System's six 1,300 megawatt (mw) generating units. AEPR owns 50% of Yorkshire Electricity Group plc (Yorkshire), a supply and distribution electric company in the UK (see Note 7); 70% of a joint venture which is constructing a two-unit power plant nearing completion in China; 20% of Pacific Hydro, an Australian hydroelectric generating company; all of the assets of a midstream natural gas operation in Louisiana and 100% of CitiPower, a Melbourne, Australia distribution utility. The acquisitions of the midstream natural gas assets and CitiPower were completed in December 1998 (see Note 6). AEPES currently markets and trades natural gas. The non-regulated subsidiaries are engaged in providing power engineering, consulting and management services around the world and fiber, wireless and information communication services in the US. Although the domestic utility subsidiaries are managed centrally by AEPSC and operate as American Electric Power they and AEPSC have not changed their names and remain separate legal entities. Rate Regulation - The AEP System is subject to regulation by the Securities and Exchange Commission (SEC) under the Public Utility Holding Company Act of 1935 (1935 Act). The rates charged by the domestic utility subsidiaries are approved by the Federal Energy Regulatory Commission (FERC) or the state utility commissions as applicable. The FERC regulates wholesale rates and the state commissions regulate retail rates. Principles of Consolidation - The consolidated financial statements include AEP Co., Inc. and its wholly-owned and majority-owned subsidiaries consolidated with their wholly-owned subsidiaries. Significant intercompany items are eliminated in consolidation. Yorkshire and Pacific Hydro are accounted for using the equity method. Basis of Accounting - As the owner of cost-based rate-regulated electric public utility companies, AEP Co., Inc.'s consolidated financial statements reflect the actions of regulators that result in the recognition of revenues and expenses in different time periods than enterprises that are not rate regulated. In accordance with Statement of Financial Accounting Standards (SFAS) 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. Regulated Utility Plant - Electric utility plant, which represents the costs of service rate-regulated fixed assets of the domestic electric utility subsidiaries, is stated at original cost and is generally subject to first mortgage liens. Additions, major replacements and betterments are added to the plant accounts. Retirements from the plant accounts and associated removal costs, net of salvage, are deducted from accumulated depreciation. The costs of labor, materials and overheads incurred to operate and maintain regulated domestic utility plant are included in operating expenses. The distribution utility plant assets of CitiPower are included in other plant. Allowance for Funds Used During Construction (AFUDC) - AFUDC is a noncash nonoperating income item that is recovered over the service life of utility plant through depreciation and represents the estimated cost of borrowed and equity funds used to finance construction projects. The amounts of AFUDC for 1998, 1997 and 1996 were not significant. Depreciation, Depletion and Amortization - Depreciation is provided on a straight-line basis over the estimated useful lives of property other than coal-mining property and is calculated largely through the use of composite rates by functional class. The annual composite depreciation rates for regulated utility plant for 1998, 1997 and 1996 were as follows: Functional Class Annual Composite of Property Depreciation Rates Production: Steam-Nuclear 3.4% Steam-Fossil-Fired 3.2% to 4.4% Hydroelectric-Conventional and Pumped Storage 2.7% to 3.4% Transmission 1.7% to 2.7% Distribution 3.3% to 4.2% General 2.5% to 3.8% The domestic utility subsidiaries presently recover amounts to be used for demolition and removal of non-nuclear plant through depreciation charges included in rates. Depreciation, depletion and amortization of coal-mining assets is provided over each asset's estimated useful life or the estimated life of the mine, whichever is shorter, ranging up to 30 years, and is calculated using the straight-line method for mining structures and equipment. The units-of-production method is used to amortize coal rights and mine development costs based on estimated recoverable tonnages at a current average rate of $1.85 per ton in 1998, $1.91 per ton in 1997 and $1.49 per ton in 1996. These costs are included in the cost of coal charged to fuel expense. Cash and Cash Equivalents - Cash and cash equivalents include temporary cash investments with original maturities of three months or less. Foreign Currency Translation - The financial statements of subsidiaries outside the US are measured using the local currency as the functional currency. Assets and liabilities are translated to US dollars at year-end rates of exchange and revenues and expenses are translated at monthly average exchange rates throughout the year. Currency translation gain and loss adjustments are accumulated in shareholders' equity. The accumulated total of such adjustments at December 31, 1998 and 1997 is not material. Currency transaction gains and losses are recorded in income. Derivative Financial Instruments - During 1998, the Company substantially increased the volume of its wholesale electricity and natural gas marketing and trading transactions (trading activities). Trading activities involve the sale of energy under physical forward contracts at fixed and variable prices and the trading of energy contracts including exchange traded futures and options, over-the-counter options and swaps. The majority of these transactions represent physical forward contracts in the Company's traditional marketing area and are typically settled by entering into offsetting contracts. The net revenues from these transactions in the Company's traditional economic marketing area are included in regulated revenues for ratemaking, regulatory accounting and reporting purposes. The Company has also purchased and sold electricity and gas options, futures and swaps, and entered into forward purchase and sale contracts for electricity outside its traditional marketing area. These transactions represent non-regulated trading activities that are included in nonoperating income. The unrealized mark-to-market gains and losses from such non-regulated trading activity are reported as assets and liabilities, respectively. The Company enters into contracts to manage the exposure to unfavorable changes in the cost of debt to be issued. These anticipatory debt instruments are entered into in order to manage the change in interest rates between the time a debt offering is initiated and the issuance of the debt (usually a period of 60 days). Gains or losses are deferred and amortized over the life of the debt issuance. There were no such forward contracts outstanding at December 31, 1998 or 1997. See Note 11 - Financial Instruments, Credit and Risk Management for further discussion. Operating Revenues and Fuel Costs - Revenues include the accrual of electricity consumed but unbilled at month-end as well as billed revenues. Fuel costs are matched with revenues in accordance with rate commission orders. Generally in the retail jurisdictions, changes in fuel costs are deferred or revenues accrued until approved by the regulatory commission for billing or refund to customers in later months. Wholesale jurisdictional fuel cost changes are expensed and billed as incurred. Levelization of Nuclear Refueling Outage Costs - In accordance with SFAS 71 incremental operation and maintenance costs associated with refueling outages at I&M's Cook Plant are deferred and amortized over the period beginning with the commencement of an outage and ending with the beginning of the next outage. Income Taxes - The Company follows the liability method of accounting for income taxes as prescribed by SFAS 109, "Accounting for Income Taxes." Under the liability method, deferred income taxes are provided for all temporary differences between the 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 reacquisition 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. 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 costs of preferred stock reacquired is credited to paid-in capital and amortized to retained earnings. Other Plant - Other plant is comprised primarily of the plant and its related construction work in progress for midstream gas operations, an Australian distribution company and a Chinese generation project. Other Property and Investments - Other property and investments are comprised primarily of nuclear decommissioning and spent nuclear fuel disposal trust funds; licenses for operating franchises and goodwill for the Australian distribution company; amounts for corporate owned life insurance and a related disputed tax payment; and the investment in Yorkshire and Pacific Hydro which are accounted for under the equity method of accounting. Securities held in trust funds for decommissioning nuclear facilities and for the disposal of spent nuclear fuel are recorded at market value in accordance with SFAS 115, "Accounting for Certain Investments in Debt and Equity Securities." Securities in the trust funds have been classified as available-for-sale due to their long-term purpose. Unrealized gains and losses from securities in these trust funds are not reported in equity but result in adjustments to the liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the spent nuclear fuel disposal trust funds. Excluding decommissioning and spent nuclear fuel disposal trust funds and the investment in Yorkshire and Pacific Hydro, other property and investments are stated at cost. EPS - Earnings per share is determined based upon the weighted average number of shares outstanding. There are no dilutive potential common shares. Therefore, the computation of earnings per share is the same for basic earnings per share and diluted earnings per share. Comprehensive Income - There were no material differences between net income and comprehensive income. Reclassification - In the fourth quarter of 1998 the Company changed the presentation of its trading activities from a gross basis (purchases and sales reported separately) to a net basis (net amount from transactions reported as revenues). This reclassification had no impact on net income. Certain prior year amounts have been reclassified to conform to current year presentation. Such reclassification had no impact on previously reported net income. 2. Rate Matters: OPCo's Recovery of Fuel Costs - Under the terms of a 1992 stipulation agreement the cost of coal burned at the Gavin Plant is subject to a 15-year predetermined price of $1.575 per million Btu's with quarterly escalation adjustments through November 2009. A 1995 Settlement Agreement set the fuel component of the electric fuel component (EFC) factor at 1.465 cents per Kwh for the period June 1, 1995 through November 30, 1998. With the end of the period covered by the 1995 Settlement Agreement, the escalated Gavin predetermined price cap under the stipulation agreement will determine Ohio jurisdictional fuel recoveries. To the extent the actual cost of coal burned at the Gavin Plant is below the predetermined prices, the stipulation agreement provides OPCo with the opportunity to recover over its term the Ohio jurisdictional share of OPCo's investment in and the liabilities and future shut-down costs of its affiliated mines as well as any fuel costs incurred above the predetermined rate. The Company announced plans to close the Muskingum mine which supplies all of its output to OPCo. The mine will be closed in October 1999 and efforts will begin to reclaim the properties, sell or scrap all mining equipment, terminate both capital and operating leases and perform other miscellaneous activities necessary to shut down the mine. Reclamation activities should be completed approximately two years after shutdown, postremediation monitoring is anticipated to continue for five years after completion of reclamation. The Company established a liability for mine closing costs of $44.6 million comprised of a curtailment loss of $24.7 million, provisions for workers compensation claims incurred through October 1998 of $4.7 million, severance costs of $4.1 million (related to approximately 200 employees), postremediation monitoring costs of $4.9 million, write-off of remaining materials and supplies of $4.6 million and other mine site closure costs of $1.6 million. Pursuant to terms of the agreements, $18.5 million of these accrued mine closure costs have been deferred for the Muskingum mine, the remainder are included in fuel expense on the Consolidated Statements of Income. For the three years ended December 31, 1998, 1997 and 1996 revenues and net income from the Muskingum mining operation were $110.2 million and $1,000; $66.3 million and zero; and $65.5 million and $1.8 million; respectively. After full recovery of the deferrals or after November 2009, whichever comes first, 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 market price at the time. Pursuant to these agreements OPCo has deferred for future recovery $106 million at December 31, 1998. Based on the estimated future cost of coal burned at Gavin Plant, management believes that the Ohio jurisdictional portion of the investment in and liabilities and closing costs of the affiliated mining operations including deferred amounts will be recovered under the terms of the predetermined price agreement. Management intends to seek from non-Ohio jurisdictional ratepayers recovery of the non-Ohio jurisdictional portion of the investment in and the liabilities and closing costs of the affiliated Meigs, Muskingum and Windsor mines. The non-Ohio jurisdictional portion of shutdown costs for these mines which includes the investment in the mines, leased asset buy-outs, reclamation costs and employee benefits is estimated to be approximately $100 million after tax at December 31, 1998. Management anticipates closing the Windsor mine in December 2000 in order to comply with the Phase II requirements of the Clean Air Act Amendments of 1990 (CAAA) or it could close earlier depending on the economics of continued operation under the terms of the above stipulation agreement. Unless the cost of affiliated coal production and/or shutdown costs of the Meigs, Muskingum and Windsor mines can be recovered, results of operations, cash flows and possibly financial condition would be adversely affected. 3. Effects of Regulation and Phase-In Plans: In accordance with SFAS 71 the consolidated financial statements include assets (deferred expenses) and liabilities (deferred income) recorded in accordance with regulatory actions to match expenses and revenues 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. Management has reviewed the evidence currently available and concluded that it continues to meet the requirements to apply SFAS 71. In the event a portion of the Company's business no longer met these requirements, net regulatory assets would have to be written off for that portion of the business 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 cost. Recognized regulatory assets and liabilities are comprised of the following at: December 31, 1998 1997 (in thousands) Regulatory Assets: Amounts Due From Customers For Future Income Taxes $1,324,217 $1,372,926 Deferred Fuel Costs 193,430 75,552 Unamortized Loss on Reacquired Debt 90,997 96,793 Other 238,074 272,269 Total Regulatory Assets $1,846,718 $1,817,540 Regulatory Liabilities: Deferred Investment Tax Credits $350,946 $376,250 Other Regulatory Liabilities* 147,569 78,802 Total Regulatory Liabilities $498,515 $455,052 * Included in Deferred Credits on Consolidated Balance Sheets At January 1, 1997 rate phase-in plan deferrals existed for the Zimmer Plant and Rockport Plant Unit 1. The Zimmer Plant is a 1,300 mw coal-fired plant which commenced commercial operation in 1991. CSPCo owns 25.4% of the plant with the remainder owned by two unaffiliated companies. As a result of an Ohio Supreme Court decision, in January 1994 the PUCO approved a temporary 3.39% surcharge effective February 1, 1994. In June 1997 the Company completed recovery of its Zimmer Plant phase-in plan deferrals and discontinued the 3.39% temporary rate surcharge. In 1997 and 1996 $15.4 million and $31.5 million, respectively, of net phase-in deferrals were collected through the surcharge. The Rockport Plant consists of two 1,300 mw coal-fired units. I&M and AEGCo each own 50% of one unit (Rockport 1) and lease a 50% interest in the other unit (Rockport 2) from unaffiliated lessors under an operating lease. The gain on the sale and leaseback of Rockport 2 was deferred and is being amortized, with related taxes, over the initial lease term which expires in 2022. Rate phase-in plans in the Indiana and the FERC jurisdictions provided for the recovery and straight-line amortization of deferred Rockport Plant Unit 1 costs over a ten year period that ended in 1997. In 1997 and 1996 amortization and recovery of the deferred Rockport Plant Unit 1 phase-in plan costs were $11.9 million and $15.6 million, respectively. During the recovery period net income was unaffected by the recovery of the phase-in deferrals. 4. Commitments and Contingencies: Construction and Other Commitments - The AEP System has substantial construction commitments to support its utility operations including the replacement of the Cook Plant Unit 1 steam generators. Such commitments do not presently include any expenditures for new generating capacity. Aggregate construction expenditures for 1999-2001 are estimated to be $2.4 billion including construction cost estimates for the newly acquired CitiPower and midstream gas assets. Long-term domestic fuel supply contracts contain clauses for periodic price adjustments, and most domestic jurisdictions have fuel clause mechanisms that provide for recovery of changes in the cost of fuel with the regulators' review and approval. The contracts are for various terms, the longest of which extends to the year 2014, and contain various clauses that would release the Company from its obligation under certain force majeure conditions. The AEP System has contracted to sell approximately 1,100 mw of capacity domestically on a long-term basis to unaffiliated utilities. Certain contracts totaling 750 mw of capacity are unit power agreements requiring the delivery of energy only if the unit capacity is available. The power sales contracts expire from 1999 to 2010. Nuclear Plant - I&M owns and operates the two-unit 2,110 mw Cook Plant under licenses granted by the Nuclear Regulatory Commission (NRC). The operation of a nuclear facility involves special risks, potential liabilities, and specific regulatory and safety requirements. Should a nuclear incident occur at any nuclear power plant facility in the US, the resultant liability could be substantial. By agreement I&M is partially liable together with all other electric utility companies that own nuclear generating units for a nuclear power plant incident. In the event nuclear losses or liabilities are underinsured or exceed accumulated funds and recovery in rates is not possible, results of operations, cash flows and financial condition could be negatively affected. Nuclear Plant Shutdown - I&M shut down both units of the Cook Nuclear Plant in September 1997 due to questions, which arose during a NRC architect engineer design inspection, regarding the operability of certain safety systems. The NRC issued a Confirmatory Action Letter in September 1997 requiring I&M to address the issues identified in the letter. I&M is working with the NRC to resolve the remaining open issue in the letter. In April 1998 the NRC notified I&M that it had convened a Restart Panel for Cook Plant. A list of required restart activities was provided by the NRC in July 1998 and in October the NRC expanded the list. In order to identify and resolve the issues necessary to restart the Cook units, I&M is and will be meeting with the Panel on a regular basis, until the units are returned to service. In January 1999 I&M announced that it will conduct additional engineering reviews at the Cook Plant that will delay restart of the units. Previously, the units were scheduled to return to service at the end of the first and second quarters of 1999. The decision to delay restart resulted from internal assessments that indicated a need to conduct expanded system readiness reviews. A new restart schedule will be developed based on the results of the expanded reviews and should be available in June 1999. When maintenance and other activities required for restart are complete, I&M will seek concurrence from the NRC to return the Cook Plant to service. Until these additional reviews are completed, management is unable to determine when the units will be returned to service. Unless the costs of the extended outage and restart efforts are recovered from customers, there would be a material adverse effect on results of operations, cash flows and possibly financial condition. The incremental cost incurred in 1997 and 1998 for restart of the Cook units were $6 million and $78 million, respectively, and recorded as operation and maintenance expense. Currently incremental restart expenses are approximately $12 million a month. In July 1998 I&M received an "adverse trend letter" from the NRC indicating that NRC senior managers determined that there had been a slow decline in performance at the Cook Plant during the 18 month period preceding the letter. The letter indicated that the NRC will closely monitor efforts to address issues at Cook Plant through additional inspection activities. In October 1998 the NRC issued I&M a Notice of Violation and proposed a $500,000 civil penalty for alleged violations at the Cook Plant discovered during five inspections conducted between August 1997 and April 1998. I&M paid the penalty. The cost of electricity supplied to certain retail customers rose due to the outage of the two units since higher cost coal-fired generation and coal based purchased power were substituted for low cost nuclear generation. I&M's Indiana and Michigan retail jurisdictional fuel cost recovery mechanisms permit the recovery, subject to regulatory commission review and approval, of changes in fuel costs including the fuel component of purchased power in the Indiana jurisdiction and changes in replacement power in the Michigan jurisdiction. The Indiana Utility Regulatory Commission approved, subject to future reconciliation or refund, agreements authorizing I&M, during the billing months of July 1998 through March 1999, to include in rates a fuel cost adjustment factor less than that requested by I&M. The agreements provide the parties to the proceedings with the opportunity to conduct discovery regarding certain issues that were raised in the proceedings, including the appropriateness of the recovery of replacement energy cost due to the extended Cook Plant outage, in anticipation of resolving the issues in a future fuel cost adjustment proceeding. A regulatory asset in the amount of $65 million has been recorded at December 31, 1998. Historically, the Company has been permitted to recover through the fuel recovery mechanism the cost of replacement energy during outages. Management believes that it should be allowed to recover the deferred Cook replacement energy costs; however, if recovery of the replacement costs is denied, future results of operations and cash flows would be adversely affected by the writeoff of the regulatory asset. Nuclear Incident Liability - Public liability is limited by law to $9 billion should an incident occur at any licensed reactor in the United States. Commercially available insurance provides $200 million of coverage. In the event of a nuclear incident at any nuclear plant in the US the remainder of the liability would be provided by a deferred premium assessment of $88 million on each licensed reactor payable in annual installments of $10 million. As a result, I&M could be assessed $176 million per nuclear incident payable in annual installments of $20 million. The number of incidents for which payments could be required is not limited. Nuclear insurance pools and other insurance policies provide $3 billion of property damage, decommissioning and decontamination coverage for the Cook Plant. Additional insurance provides coverage for extra costs resulting from a prolonged accidental Cook Plant outage. Some of the policies have deferred premium provisions which could be triggered by losses in excess of the insurer's resources. The losses could result from claims at the Cook Plant or certain other unaffiliated nuclear units. I&M could be assessed up to $23.2 million annually under these policies. Spent Nuclear Fuel (SNF) Disposal - Federal law provides for government responsibility for permanent SNF disposal and assesses nuclear plant owners fees for SNF disposal. A fee of one mill per kilowatthour for fuel consumed after April 6, 1983 is being collected from customers and remitted to the US Treasury. Fees and related interest of $190 million for fuel consumed prior to April 7, 1983 have been recorded as long-term debt. I&M has not paid the government the pre-April 1983 fees due to continued delays and uncertainties related to the federal disposal program. At December 31, 1998, funds collected from customers towards payment of the pre-April 1983 fee and related earnings thereon approximate the liability. Decommissioning and Low Level Waste Accumulation Disposal - Decommissioning costs are accrued over the service life of the Cook Plant. The licenses to operate the two nuclear units expire in 2014 and 2017. After expiration of the licenses the plant is expected to be decommissioned through dismantlement. The Company's latest estimate for decommissioning and low level radioactive waste accumulation disposal costs ranges from $700 million to $1,152 million in 1997 nondiscounted dollars. The wide range is caused by variables in assumptions including the estimated length of time SNF may need to be stored at the plant site subsequent to ceasing operations. This, in turn, depends on future developments in the federal government's SNF disposal program. Continued delays in the federal fuel disposal program can result in increased decommissioning costs. I&M is recovering estimated decommissioning costs in its three rate-making jurisdictions based on at least the lower end of the range in the most recent decommissioning study at the time of the last rate proceeding. I&M records decommissioning costs in other operation expense and records an increase in its noncurrent liabilities equal to the decommissioning cost recovered in rates; such amounts were $29 million in 1998, $28 million in 1997 and $27 million in 1996. Decommissioning costs recovered from customers are deposited in external trusts. Trust fund earnings increase the fund assets and the recorded liability and decrease the amount needed to be recovered from ratepayers. During 1998 I&M withdrew $3 million and expects to withdrawal $8 million in 1999 for decommissioning of original steam generators removed from Unit 2. At December 31, 1998 and 1997, I&M has recognized a decommissioning liability of $446 million and $381 million, respectively, which is included in other noncurrent liabilities. Clean Air Act/Air Quality - The US Environmental Protection Agency (Federal EPA) is required by the CAAA to issue rules to implement the law. In 1996 Federal EPA issued final rules governing nitrogen oxides (NOx) emissions that must be met after January 1, 2000 (Phase II of CAAA). The final rules will require substantial reductions in NOx emissions from certain types of boilers including those in AEP's power plants. To comply with Phase II of CAAA, the Company plans to install NOx emission control equipment on certain units and switch fuel at other units. Total capital costs to meet the requirements of Phase II of CAAA are estimated to be approximately $90 million of which $69 million has been incurred through December 31, 1998. On September 24, 1998, Federal EPA finalized rules which require reductions in NOx emissions in 22 eastern states, including the states in which the Company's generating plants are located. The implementation of the final rules would be achieved through the revision of state implementation plans (SIPs) by September 1999. SIPs are a procedural method used by each state to comply with Federal EPA rules. The final rules anticipate the imposition of a NOx reduction on utility sources of approximately 85% below 1990 emission levels by the year 2003. On October 30, 1998, a number of utilities, including the operating companies of the AEP System, filed petitions in the US Court of Appeals for the District of Columbia Circuit seeking a review of the final rules. Should the states fail to adopt the required revisions to their SIPs within one year of the date of the final rules (September 24, 1999), Federal EPA has proposed to implement a federal plan to accomplish the NOx reductions. Federal EPA also proposed the approval of portions of petitions filed by eight northeastern states that would result in imposition of NOx emission reductions on utility and industrial sources in upwind midwestern states. These reductions are substantially the same as those required by the final NOx rules and could be adopted by Federal EPA in the event the states fail to implement SIPs in accordance with the final rules. Preliminary estimates indicate that compliance costs could result in required capital expenditures of approximately $1.2 billion for the AEP System. Compliance costs cannot be estimated with certainty and the actual costs incurred to comply could be significantly different from this preliminary estimate depending upon the compliance alternatives selected to achieve reductions in NOx emissions. Unless such costs are recovered from customers, they would have a material adverse effect on results of operations, cash flows and possibly financial condition. Litigation - The Internal Revenue Service (IRS) agents auditing the AEP System's consolidated federal income tax returns requested a ruling from their National Office that certain interest deductions claimed by the Company relating to AEP's corporate owned life insurance (COLI) program should not be allowed. As a result of a suit filed in US District Court (discussed below) this request for ruling was withdrawn by the IRS agents. Adjustments have been or will be proposed by the IRS disallowing COLI interest deductions for taxable years 1991-96. A disallowance of the COLI interest deductions through December 31, 1998 would reduce earnings by approximately $316 million (including interest). The Company has made no provision for any possible adverse earnings impact from this matter. In 1998 the Company made payments of taxes and interest attributable to COLI interest deductions for taxable years 1991-97 to avoid the potential assessment by the IRS of any additional above market rate interest on the contested amount. The payments to the IRS are included on the balance sheet in other property and investments pending the resolution of this matter. The Company will seek refund, either administratively or through litigation, of all amounts paid plus interest. In order to resolve this issue without further delay, on March 24, 1998, the Company filed suit against the US in the US District Court for the Southern District of Ohio. Management believes that it has a meritorious position and will vigorously pursue this lawsuit. In the event the resolution of this matter is unfavorable, it will have a material adverse impact on results of operations, cash flows and possibly financial condition. The Company is involved in a number of other legal proceedings and claims. While management is unable to predict the ultimate outcome of litigation, it is not expected that the resolution of these matters will have a material adverse effect on the results of operations, cash flows or financial condition. 5. Proposed Merger In December 1997 the Company and Central and South West Corporation (CSW) agreed to merge. At the 1998 annual meeting AEP shareholders approved the issuance of common shares to effect the merger and approved an increase in the number of authorized shares of AEP Common Stock from 300,000,000 to 600,000,000 shares. CSW stockholders approved the merger at their May 1998 annual meeting. Approval of the merger has been requested from the FERC, the SEC, the NRC and all of CSW's state regulatory commissions: Arkansas, Louisiana, Oklahoma and Texas. In the near future, AEP and CSW plan to make the final two filings associated with approval of the merger with the Federal Communications Commission and the Department of Justice. Regulatory approvals for the merger have been received from the Arkansas Public Service Commission (APSC) and the NRC. In December 1998 the APSC approved a stipulated agreement related to a proposed merger regulatory plan submitted by the Company, CSW and CSW's Arkansas operating subsidiary, Southwestern Electric Power Company. The regulatory plan, agreed to with the APSC staff, provides for a sharing of net merger savings through a $6 million rate reduction over 5 years following the completion of the merger. The application to the NRC by CSW's operating subsidiary, Central Power and Light Company (CPL), requesting permission to transfer indirect control of the license from CSW to AEP for CPL's interest in the South Texas Project nuclear generating station was approved by the NRC in November 1998. In October 1998 the Oklahoma Corporation Commission (OCC) approved plans by AEP and CSW to submit an amended filing seeking approval of the proposed merger. The amended application is being made as a result of an Oklahoma administrative law judge's recommendation that the merger filing be dismissed without prejudice for lack of sufficient information regarding the potential impact of the merger on the retail electric market in Oklahoma. An amended application was filed in Oklahoma in February 1999. Submission of the amended application will reset Oklahoma's 90-day statutory time period for OCC action on the merger phase of the application. A settlement agreement between AEP, CSW and certain key parties to the Texas merger proceeding has been reached. The staff of the Public Utility Commission of Texas was not a signatory to the settlement agreement, which resolves all issues for the signatories. The settlement provides for, among other things, rate reductions totaling approximately $180 million over a six year period following completion of the merger to share net merger savings of $84 million and settle existing rate issues of $96 million. Hearings are scheduled for April 1999. In July 1998 the FERC issued an order which confirmed that a 250 megawatt firm contract path with the Ameren System is available. The contract path was obtained by AEP and CSW to meet the requirement of the 1935 Act that the two systems operate on an integrated and coordinated basis. In November 1998 the FERC issued an order establishing hearing procedures for the merger and scheduled the hearings to begin on June 1, 1999. The FERC order indicated that the review of the proposed merger will address the issues of competition, market power and customer protection and instructed the companies to refile an updated market power study which was done in January 1999. The proposed merger of CSW into AEP would result in common ownership of two UK regional electricity companies (RECs), Yorkshire and Seeboard, plc. AEP has a 50% interest in Yorkshire and CSW has a 100% interest in Seeboard. Although the merger of CSW into AEP is not subject to approval by UK regulatory authorities, the common ownership of two UK RECs could be referred by the UK Secretary of State for Trade and Industry to the UK Monopolies and Mergers Commission for investigation. AEP has received a request from the staff of the Kentucky Public Service Commission (KPSC) to file an application seeking KPSC approval for the indirect change in control of Kentucky Power Company that will occur as a result of the proposed merger. Although AEP does not believe that the KPSC has the jurisdictional authority to approve the merger, management will prepare a merger application filing to be made with the KPSC, which is expected to be filed by April 15, 1999. Under the governing statute the KPSC must act on the application within 60 days. Therefore this is not expected to impact the timing of the merger. The merger is conditioned upon, among other things, the approval of the above state and federal regulatory agencies. The transaction must satisfy many conditions a number of which may not be waived by the parties, including the condition that the merger must be accounted for as a pooling of interests. The merger agreement will terminate on December 31, 1999 unless extended by either party as provided in the merger agreement. Although consummation of the merger is expected to occur in the fourth quarter of 1999, the Company is unable to predict the outcome or the timing of the required regulatory proceedings. As of December 31, 1998 the Company had deferred $20 million of incremental costs incurred in connection with the proposed merger. The amounts deferred are included in deferred charges on the Consolidated Balance Sheets. 6. Acquisitions The Company completed two non-regulated energy related acquisitions in 1998 through a subsidiary, AEPR. Both acquisitions have been included in the December 31, 1998 consolidated financial statements using the purchase method of accounting. The first acquisition was of CitiPower, an Australian distribution utility, that serves approximately 240,000 customers in Melbourne with 3,100 miles of distribution lines in a service area of approximately 100 square miles. All of the stock of CitiPower was acquired on December 31, 1998 for approximately $1.1 billion. The acquisition of CitiPower had no effect on the results of operations for 1998. The financial statements reflect a preliminary purchase price allocation. Estimated goodwill of $557 million has been recorded in other property and investments which will be amortized over a period of not more than 40 years. The second acquisition was of midstream gas operations that include a fully integrated natural gas gathering, processing, storage and transportation operation in Louisiana and a gas trading and marketing operation in Houston. The gas operations were acquired for approximately $340 million, including working capital funds, on December 1, 1998 with one month of earnings reflected in AEP's consolidated results of operations for the year ended December 31, 1998. The financial statements reflect a preliminary purchase price allocation. Estimated goodwill of approximately $158 million for the midstream gas storage operations and $17 million for the gas trading and marketing operation has been recorded in other property and investments and is being amortized on a straight-line basis over not more than 40 years and 10 years, respectively. 7. Yorkshire Acquisition and UK Windfall Tax In April 1997 the Company and New Century Energies, Inc. through an equally owned joint venture, Yorkshire Power Group Limited (YPG), acquired all of the outstanding shares of Yorkshire. Total consideration paid by the joint venture was approximately $2.4 billion which was financed by a combination of equity and non-recourse debt. The Company uses the equity method of accounting for its investment in YPG. The Company's investment in the joint venture was $325.8 million and $287.4 million at December 31, 1998 and 1997, respectively, and is included in other property and investments. In July 1997 the British government enacted a new law that imposed a one-time windfall tax on a revised privatization value which originally had been computed in 1990 on certain privatized utilities. The windfall tax is actually an adjustment by the UK government of the original privatization price. The windfall tax liability for Yorkshire was 134 million pounds sterling ($219 million) and was paid in two equal installments made in December 1997 and December 1998. The Company's $109.4 million share of the tax is reported as an extraordinary loss in 1997. The 1998 equity earnings from the Yorkshire investment are $38.5 million and are included in nonoperating income. Equity earnings from the Yorkshire investment for 1997, excluding the extraordinary loss, were $34 million. The following amounts which are not included in AEP's consolidated financial statements represent summarized consolidated financial information of YPG: December 31, 1998 1997 (in millions) Assets: Property, Plant and Equipment $1,602.2 $1,644.6 Current Assets 552.2 602.2 Goodwill (net) 1,547.3 1,602.5 Other Assets 294.5 292.9 Total Assets $3,996.2 $4,142.2 Capitalization and Liabilities: Common Shareholders' Equity $ 666.4 $ 542.1 Long-term Debt 2,121.3 704.3 Other Noncurrent Liabilities 413.5 488.7 Long-term Debt Within One Year 13.3 1,776.4 Current Liabilities 781.7 630.7 Total Capitalization and Liabilities $3,996.2 $4,142.2 Twelve Months Ended Nine Months Ended December 31, 1998 December 31, 1997 (in millions) Income Statement Data: Operating Revenues $2,284.0 $1,492.9 Operating Income 298.0 202.3 Income Before Extraordinary Item 76.9 67.5 Net Income (Loss) 76.9 (151.3) 8. Staff Reductions During 1998 an internal evaluation of the power generation organization was conducted with a goal of developing an optimum organizational structure for a competitive generation market. The study was completed in October 1998 and called for the elimination of approximately 450 positions. In addition, a review of energy delivery staffing levels in 1998 identified 65 positions for elimination. Severance accruals totaling $25.5 million were recorded in December 1998 for reductions in power generation and energy delivery staffs and were charged to other operation expense in the Consolidated Statements of Income. In January 1999, employment terminated for 65 energy delivery employees. In February 1999 the power generation staff reductions were made. 9. Benefit Plans: AEP System Pension and Other Postretirement Benefit Plans - The AEP System sponsors a qualified pension plan and a nonqualified pension plan. All employees, except participants in the United Mine Workers of America (UMWA) pension plans are covered by one or both of the pension plans. Other Postretirement Benefit Plans (OPEB) are sponsored by the AEP System to provide medical and death benefits for retired employees. The following tables provide a reconciliation of the changes in the plans' benefit obligations and fair value of assets over the two-year period ending December 31, 1998, and a statement of the funded status as of December 31 for both years: Pension Plan OPEB 1998 1997 1998 1997 (in thousands) Reconciliation of benefit obligation: Obligation at January 1 $1,909,400 $1,676,200 $ 849,700 $726,400 Service Cost 45,100 36,000 17,500 14,000 Interest Cost 133,200 128,600 59,300 55,900 Participant Contributions - - 5,900 5,300 Plan Amendments (a) 48,400 - - - Actuarial Loss 96,000 170,500 133,100 90,900 Acquisitions (b) 100 - 2,800 - Benefit Payments (105,900) (101,900) (46,600) (42,800) Obligation at December 31 $2,126,300 $1,909,400 $1,021,700 $849,700 Reconciliation of fair value of plan assets: Fair value of plan assets at January 1 $2,370,300 $2,009,500 $311,900 $232,500 Actual Return on Plan Assets 385,900 462,700 52,600 44,100 Company Contributions 400 - 72,600 72,800 Participant Contributions - - 5,900 5,300 Benefit Payments (105,900) (101,900) (46,600) (42,800) Fair value of plan assets at December 31 $2,650,700 $2,370,300 $396,400 $311,900 Funded status: Funded status at December 31 $ 524,400 $ 460,900 $(625,300)$(537,800) Unrecognized Net Transition (Asset) Obligation (49,200) (59,100) 360,700 416,400 Unrecognized Prior-Service Cost 157,400 123,500 - - Unrecognized Actuarial (Gain) Loss (756,300) (640,800) 175,000 66,100 Accrued Benefit Liability $(123,700) $(115,500) $ (89,600)$ (55,300) (a) Early retirement factors for the Company pension plan were changed to provide more generous benefits to participants retiring between ages 55 and 60. (b) On December 1, 1998 the Company acquired midstream gas operations resulting in approximately 170 new employees becoming participants in the Company's pension and OPEB plans. The following table provides the amounts recognized in the consolidated balance sheets as of December 31 of both years: Pension Plan OPEB 1998 1997 1998 1997 (in thousands) Accrued Benefit Liability $(123,700) $(115,500) $(89,600) $(55,300) Additional Minimum Liability (3,400) (900) - - Intangible Asset 3,400 900 - - Net Amount Recognized $(123,700) $(115,500) $(89,600) $(55,300) The Company's nonqualified pension plan had an accumulated benefit obligation in excess of plan assets of $25 million and $19.4 million at December 31, 1998 and 1997, respectively. There are no plan assets in the nonqualified plan due to the nature of the plan. The Company's OPEB plans had accumulated benefit obligations in excess of plan assets of $625.3 million and $537.8 million at December 31, 1998 and 1997, respectively. The following table provides the components of net periodic benefit cost for the plans for fiscal years 1998 and 1997: Pension Plan OPEB 1998 1997 1998 1997 (in thousands) Service cost $ 45,100 $ 36,000 $ 17,500 $ 14,000 Interest cost 133,200 128,600 59,300 55,900 Expected return on plan assets (172,000) (154,200) (28,500) (22,200) Amortization of transition (asset) obligation (9,900) (9,900) 32,000 32,000 Amortization of prior-service cost 14,400 13,800 - - Amortization of net actuarial (gain) loss (2,600) (4,700) 200 (400) Net periodic benefit cost 8,200 9,600 80,500 79,300 Curtailment loss - - 24,100(a) - Net periodic benefit cost after curtailments $ 8,200 $ 9,600 $104,600 $ 79,300 (a) Curtailment charges were recognized during 1998 in anticipation of the October 31, 1999 shutdown of Muskingum Mine by Central Ohio Coal Company, a subsidiary of AEP. The assumptions used in the measurement of the Company's benefit obligation are shown in the following table: Pension Plan OPEB 1998 1997 1998 1997 Weighted-average assumptions as of December 31 Discount rate 6.75% 7.00% 6.75% 7.00% Expected return on plan assets 9.00% 9.00% 8.75% 8.75% Rate of compensation increase 3.2% 3.2% N/A N/A For measurement purposes, a 5.5% annual rate of increase in the per capita cost of covered health care benefits was assumed for 1999. The rate was assumed to decrease gradually each year to a rate of 4.25% for 2005 and remain at that level thereafter. Assumed health care cost trend rates have a significant effect on the amounts reported for the OPEB health care plans. A 1% change in assumed health care cost trend rates would have the following effects: 1% Increase 1% Decrease (in thousands) Effect on total of service and interest cost components of net periodic postretirement health care benefit cost $ 9,700 $ (8,400) Effect on the health care component of the accumulated postretirement benefit obligation 113,000 (99,800) CitiPower, a subsidiary acquired on December 31, 1998 sponsors a defined benefit pension plan. At December 31, 1998, the fair value of the plan assets was $24.6 million and the accumulated benefit obligation of this plan was $25.3 million. This plan's actuarial assumptions are not significantly different from AEP's. AEP System Savings Plan - The AEP System Savings Plan is a defined contribution plan offered to non-UMWA employees. The cost for contributions to this plan totaled $20.5 million in 1998, $19.6 million in 1997 and $19 million in 1996. Other UMWA Benefits - The Company provides UMWA pension, health and welfare benefits for certain unionized mining employees, retirees, and their survivors who meet eligibility requirements. The benefits are administered by UMWA trustees and contributions are made to their trust funds. Contributions based on hours worked are expensed as paid as part of the cost of active mining operations and were not material in 1998, 1997 and 1996. Based upon the UMWA actuary estimate, the Company's share of unfunded pension liability was $28 million at June 30, 1998. In the event the Company should significantly reduce or cease mining operations or contributions to the UMWA trust funds, a withdrawal obligation will be triggered for both the pension and health and welfare plans. If the mining operations had been closed on December 31, 1998 the estimated annual withdrawal liability for all UMWA benefit plans would have been $6.5 million. The UMWA withdrawal liability for the anticipated shutdown of Central Ohio Coal Company's Muskingum mine has been included as a curtailment loss in the net periodic benefit cost under the Company's OPEB plans in 1998. 10. Business Segments As of December 31, 1998, the Company adopted SFAS 131, "Disclosure about Segments of an Enterprise and Related Information." SFAS 131 established standards for reporting information about operating segments in annual financial statements and requires selected information about operating segments in interim financial reports issued to shareholders. It also established standards for related disclosures about products and services, and geographic areas. Operating segments are defined as components of an enterprise about which separate financial information is available and evaluated regularly by the chief operating decision maker. The Company's reportable segments are primarily differentiated based on whether the business activity is conducted within a regulated environment. The Company manages its operations on this basis because of the substantial impact of regulatory oversight on business processes, cost structures and operating results. The Company's principal business segment is its cost based rate regulated Domestic Electric Utilities business consisting of seven regulated utility operating companies providing retail, commercial, industrial and wholesale electric services in seven Atlantic and Midwestern states. Also included in this segment are the Company's electric power wholesale marketing and trading activities that are conducted as part of regulated operations and subject to regulatory ratemaking oversight. The World Wide Energy Investments segment represents principally international investments in energy-related projects and operations. It also includes the development and management of such projects and operations. Such investment activities include electric generation, supply and distribution, and natural gas pipeline, storage and other natural gas services. Other business segments include non-regulated electric and gas trading activities, telecommunication services, and the marketing of various energy saving products and services. Intersegment revenues, ie. revenues from transactions with operating segments, are not material. As of December 31, 1998 and 1997 less than 6% of long-lived assets were located in foreign countries.
World Regulated Domestic Wide Energy Reconciling AEP Year Electric Utilities Investments Other Adjustments Consolidated (in thousands) 1998 Revenues from external customers $6,345,900 $57,600 $(28,300) $(29,300) $6,345,900 Revenues from transactions with other operating segments - 1,600 1,900 (3,500) - Interest revenues 400 200 600 Interest expense 399,200 16,900 3,000 419,100 Depreciation, depletion and amortization expense 580,000 1,000 1,400 (2,400) 580,000 Net income (loss) for equity method subsidiaries - 38,600 - 38,600 Income tax expense (benefit) 299,100 (15,300) (21,200) 262,600 Segment net income (loss) 563,400 12,300 (39,500) 536,200 Total assets 16,837,300 2,063,300 582,600 19,483,200 Investments in equity method subsidiaries 100 335,200 - 335,300 Gross property additions 699,700 1,481,000 23,000 2,203,700 1997 Revenues from external customers $5,879,800 $14,600 $ 2,200 $(16,800) $5,879,800 Revenues from transactions with other operating segments - - - - - Interest revenues - 1,700 - 1,700 Interest expense 390,300 14,900 600 405,800 Depreciation, depletion and amortization expense 591,100 - - - 591,100 Net income for equity method subsidiaries - 33,300 - - 33,300 Income tax expense (benefit) 330,100 (25,000) (6,600) 298,500 Extraordinary Loss - UK Windfall Tax - (109,400) - - (109,400) Segment net income (loss) 602,900 (79,600) (12,300) 511,000 Total assets 16,223,700 367,100 24,500 16,615,300 Investments in equity method subsidiaries 100 287,300 - 287,400 Gross property additions 694,400 62,400 3,600 760,400 1996 Revenues from external customers $5,849,200 $12,500 $ - $(12,500) $5,849,200 Revenues from transactions with other operating segments - 100 - (100) - Interest revenues - - - - - Interest expense 381,000 300 - - 381,300 Depreciation, depletion and amortization expense 600,900 - - - 600,900 Income tax expense (benefit) 325,500 (1,000) (1,900) 322,600 Segment net income (loss) 597,600 (6,600) (3,600) 587,400 Total assets 15,858,900 5,100 19,000 15,883,000 Investments in equity method subsidiaries 100 - - 100 Gross property additions 577,700 - - 577,700
11. Financial Instruments, Credit and Risk Management The Company is subject to market risk as a result of changes in commodity prices, foreign currency exchange rates, and interest rates. The Company has a wholesale electricity and gas trading and marketing operation that manages the exposure to commodity price movements using physical forward purchase and sale contracts at fixed and variable prices, and financial derivative instruments including exchange traded futures and options, over-the-counter options, swaps and other financial derivative contracts at both fixed and variable prices. Physical forward electricity contracts and certain qualifying hedges within AEP's traditional economic market area are recorded as net operating revenues in the month when the physical contract settles. Net gains for the year ended December 31, 1998 were $111 million. Physical forward electricity contracts outside AEP's traditional marketing area, and all financial electricity trading transactions which do not qualify as a hedge, and/or where the underlying physical commodity is outside AEP's traditional economic market area are marked to market and recorded net in nonoperating income. Net losses for the year ended December 31, 1998 were $37 million. All physical and financial instruments for natural gas are marked to market and are included on a net basis in nonoperating income. Net gains for the year ended December 31, 1998 were $6 million. The unrealized mark-to-market gains and losses from such trading of financial instruments are reported as assets and liabilities, respectively. These activities were not material in prior periods. Investment in foreign ventures exposes the Company to risk of foreign currency fluctuations. Also, the Company is exposed to changes in interest rates primarily due to short- and long-term borrowings used to fund its business operations. The debt portfolio has both fixed and variable interest rates with terms from one day to forty years and an average duration of 5 years at December 31, 1998. The Company does not presently utilize derivatives to manage its exposures to foreign currency exchange rate movements. Market Valuation - The book value 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. The book value amount of the pre-April 1983 spent nuclear fuel disposal liability approximates the Company's best estimate of its fair value. The book value amounts and fair values of the Company's significant financial instruments at December 31, 1998 are summarized in the following table. The fair values of long-term debt and preferred stock are based on quoted market prices for the same or similar issues and the current dividend or interest rates offered for instruments of the same remaining maturities. The fair value of those financial instruments that are marked-to-market are based on management's best estimates using over-the-counter quotations, exchange prices, volatility factors and valuation methodology. The estimates presented herein are not necessarily indicative of the amounts that the Company could realize in a current market exchange. Book Value Fair Value (in thousands) Non-Derivatives 1998 Long-term Debt $7,006,100 $7,291,200 Preferred Stock 127,600 134,100 1997 Long-term Debt 5,423,900 5,670,400 Preferred Stock 127,600 136,000 Derivatives Trading Assets Notional Amount Fair Value Average Fair Value (in thousands) Electric Physicals $ (62,000) $ 46,100 $ 40,800 Options (4,700) 32,200 79,000 Swaps (15,600) 3,400 1,000 Gas Futures (70,300) 5,900 1,900 Physicals (285,200) 43,600 29,900 Options (3,600) 18,000 11,700 Swaps 1,477,900 245,600 143,000 Trading Liabilities Electric Futures 20,300 (7,200) (1,800) Physicals 27,500 (50,600) (46,300) Options 9,700 (28,700) (78,300) Swaps 16,200 (7,700) (1,900) Gas Physicals 283,900 (42,400) (28,700) Options 4,700 (22,600) (14,100) Swaps (1,524,900) (231,200) (135,700) At December 31, 1998 the fair value of the assets and liabilities related to the wholesale electric forward contracts was $367 million and $356 million, respectively. The respective notional amounts were $828 million and $772 million, respectively. The average fair value amounts outstanding during the period were $922 million of assets and $882 million of liabilities. AEP routinely enters into exchange traded futures and options transactions for electricity and natural gas as part of its wholesale trading operations. These transactions are executed through brokerage accounts with brokers who are registered with the Commodity Futures Trading Commission. Brokers require cash or cash related instruments to be deposited on these accounts as margin calls against the customer's open position. The amount of these deposits at December 31, 1998 was $10 million. Credit and Risk Management - In addition to market risk associated with price movements, AEP is also subject to the credit risk inherent in its risk management activities. Credit risk refers to the financial risk arising from commercial transactions and/or the intrinsic financial value of contractual agreements with trading counter parties, by which there exists a potential risk of nonperformance. The Company has established and enforced credit policies that minimize or eliminate this risk. AEP accepts as counter parties to forwards, futures, and other derivative contracts primarily those entities that are classified as Investment Grade, or those that can be considered as such due to the effective placement of credit enhancements and/or collateral agreements. Investment Grade is the designation given to the four highest debt rating categories (i.e., AAA, AA, A, BBB) of the major rating services, e.g., ratings BBB- and above at Standard & Poor's and Baa3 and above at Moody's. When adverse market conditions have the potential to negatively affect a counter party's credit position, the Company will require further enhancements to mitigate risk. Since the formation of the trading business in July of 1997, the Company has experienced no significant losses due to the credit risk associated with its risk management activities; furthermore, the Company does not anticipate any future material effect on its results of operations, cash flow or financial condition as a result of counter party nonperformance. Other Financial Instruments - Nuclear Trust Funds Recorded at Market Value - The trust investments, reported in other property and investments, are recorded at market value in accordance with SFAS 115 and consist of tax-exempt municipal bonds and other securities. At December 31, 1998 and 1997 the fair values of the trust investments were $648 million and $566 million, respectively, and had a cost basis of $584 million and $527 million, respectively. Accumulated gross unrealized holding gains were $65 million and $41 million at December 31, 1998 and 1997, respectively and accumulated gross unrealized holding losses were $1.1 million and $1.2 million at December 31, 1998 and 1997, respectively. The change in market value in 1998, 1997, and 1996 was a net unrealized holding gain of $24 million, $19.1 million, and $2.6 million, respectively. The trust investments' cost basis by security type were: December 31, 1998 1997 (in thousands) Tax-Exempt Bonds $326,239 $335,358 Equity Securities 95,854 74,398 Treasury Bonds 71,194 44,200 Corporate Bonds 10,661 9,167 Cash, Cash Equivalents and Accrued Interest 80,065 63,392 Total $584,013 $526,515 Proceeds from sales and maturities of securities of $225 million during 1998 resulted in $8.2 million of realized gains and $2.8 million of realized losses. Proceeds from sales and maturities of securities of $147.3 million during 1997 resulted in $3.9 million of realized gains and $1.4 million of realized losses. Proceeds from sales and maturities of securities of $115.3 million during 1996 resulted in $2.6 million of realized gains and $2.1 million of realized losses. The cost of securities for determining realized gains and losses is original acquisition cost including amortized premiums and discounts. At December 31, 1998, the year of maturity of trust fund investments other than equity securities, was: (in thousands) 1999 $106,316 2000 - 2003 157,224 2004 - 2008 175,751 After 2008 48,868 Total $488,159 An AEP Resources' subsidiary established a non-recourse variable-rate credit facility in the aggregate amount of $775 million on December 31, 1998. Certain assets of the subsidiary support the facility. The facility is comprised of three tranches: $244 million maturing on December 31, 2000, $488 million maturing on December 31, 2003, and a $43 million short-term capital facility. As of December 31, 1998 $732 million were outstanding at an average interest rate of 5.833%. The subsidiary entered into several interest rate swap agreements for $586 million of the borrowings under the credit facility. The swap agreements involve the exchange of floating-rate for fixed-rate interest payments. Interest is recognized currently based on the fixed rate of interest resulting from use of these swap agreements. Market risks arise from the movements in interest rates. If counterparties to an interest rate swap agreement were to default on contractual payments, the subsidiary could be exposed to increased costs related to replacing the original agreement. However, the subsidiary does not anticipate non-performance by any counterparty to any interest rate swap in effect as of December 31, 1998. As of December 31, 1998, the subsidiary was a party to interest rate swaps having a aggregate notional amount of $586 million, with $342 million maturing on December 31, 2000, and $244 million maturing on December 31, 2003. The average fixed interest rate payable on the aggregate of the interest rate swaps is 5.32%. The floating rate for interest rate swaps was 4.9% at December 31, 1998. The estimated fair value of the interest rate swaps, which represents the estimated amount the subsidiary would pay to terminate the swaps at December 31, 1998, based on quoted interest rates, is a net liability of $5 million. In accordance with the debt covenants included in the financing provisions of this facility, the subsidiary must hedge at least 80% of its energy purchase requirements through energy trading derivative instruments entered into with market participants, predominantly generators. As of December 31, 1998, the subsidiary had outstanding energy trading derivatives with a total contracted load of 12,545 GWh's. These contracts have maturities in the range of 3 months to twelve years. Management's estimate of the fair value of these derivatives as of December 31, 1998, is $3.3 million in excess of book value. 12. Federal Income Taxes: The details of federal income taxes as reported are as follows: Year Ended December 31, 1998 1997 1996 (in thousands) Charged (Credited) to Operating Expenses (net): Current $294,139 $346,290 $375,528 Deferred 37,877 11,124 (17,008) Deferred Investment Tax Credits (15,815) (16,134) (16,298) Total 316,201 341,280 342,222 Charged (Credited) to Nonoperating Income (net): Current (47,718) (16,038) (5,636) Deferred 3,572 (17,673) (4,470) Deferred Investment Tax Credits (9,489) (9,107) (9,510) Total (53,635) (42,818) (19,616) Total Federal Income Tax as Reported $262,566 $298,462 $322,606 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, 1998 1997 1996 (in thousands) Income Before Preferred Stock Dividend Requirements of Subsidiaries $547,109 $ 638,211 $628,856 Extraordinary Loss - UK Windfall Tax (Note 7) - (109,419) - Federal Income Taxes 262,566 298,462 322,606 Pre-Tax Book Income $809,675 $ 827,254 $951,462 Federal Income Tax on Pre-Tax Book Income at Statutory Rate (35%) $283,386 $289,539 $333,012 Increase (Decrease) in Federal Income Tax Resulting from the Following Items: Depreciation 57,663 53,239 50,537 Corporate Owned Life Insurance (16,428) (18,240) (12,009) Investment Tax Credits (net) (25,304) (25,241) (25,813) Extraordinary Loss - UK Windfall Tax - 38,297 - Other (36,751) (39,132) (23,121) Total Federal Income Taxes as Reported $262,566 $298,462 $322,606 Effective Federal Income Tax Rate 32.4% 36.1% 33.9% The following tables show the elements of the net deferred tax liability and the significant temporary differences: December 31, 1998 1997 (in thousands) Deferred Tax Assets $ 879,322 $ 807,226 Deferred Tax Liabilities (3,480,724) (3,368,147) Net Deferred Tax Liabilities $(2,601,402) $(2,560,921) Property Related Temporary Differences $(2,170,077) $(2,161,484) Amounts Due From Customers For Future Federal Income Taxes (395,605) (410,255) Deferred State Income Taxes (193,867) (201,843) All Other (net) 158,147 212,661 Total Net Deferred Tax Liabilities $(2,601,402) $(2,560,921) The Company has settled with the 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 being audited by the IRS. With the exception of interest deductions related to AEP's corporate owned life insurance program, which are discussed under the heading, Litigation, in Note 4, management is not aware of any issues for open tax years that upon final resolution are expected to have a material adverse effect on results of operations. 13. Supplementary Information: Year Ended December 31, 1998 1997 1996 (in thousands) Purchased Power - Ohio Valley Electric Corporation (44.2% owned by AEP System) $42,612 $29,631 $22,156 Cash was paid for: Interest (net of capitalized amounts) $413,341 $390,491 $373,570 Income Taxes $281,709 $398,833 $404,297 Noncash Investing and Financing Activities: Acquisitions under Capital Leases $119,188 $234,846 $136,988 Assumption of Liabilities related to Acquisitions $151,506 $ - $ - 14. Leases: Leases of property, plant and equipment are for periods up to 35 years and require payments of related property taxes, maintenance and operating costs. The majority of the leases have purchase or renewal options and will be renewed or replaced by other leases. Lease rentals are primarily charged to operating expenses in accordance with rate-making treatment. The components of rentals are as follows: Year Ended December 31, 1998 1997 1996 (in thousands) Operating Leases $254,467 $257,042 $262,451 Amortization of Capital Leases 91,359 104,732 114,050 Interest on Capital Leases 37,516 31,601 28,696 Total Rental Payments $383,342 $393,375 $405,197 Properties under capital leases and related obligations on the Consolidated Balance Sheets are as follows: December 31, 1998 1997 (in thousands) LEASED ASSETS IN ELECTRIC UTILITY PLANT: Production $ 46,532 $ 47,246 Transmission 4 3 Distribution 14,650 14,660 General: Nuclear Fuel (net of amortization) 103,939 103,939 Mining Plant and Other 530,291 516,843 Total Electric Utility Plant 695,416 682,691 Accumulated Amortization 208,548 196,145 Net Electric Utility Plant 486,868 486,546 LEASED ASSETS IN OTHER PROPERTY 54,102 57,763 Accumulated Amortization 8,387 5,917 Net Other Property 45,715 51,846 Net Property under Capital Leases $532,583 $538,392 Capital Lease Obligations:* Noncurrent Liability $450,922 $437,303 Liability Due Within One Year 81,661 101,089 Total Capital Lease Obligations $532,583 $538,392 *Represents the present value of future minimum lease payments for plant and nuclear fuel. The noncurrent portion of capital lease obligations is included in other noncurrent liabilities in the Consolidated Balance Sheet. Properties under operating leases and related obligations are not included in the Consolidated Balance Sheets. Future minimum lease rentals, consisted of the following at December 31, 1998: Noncancelable Capital Operating Leases Leases (in thousands) 1999 $109,395 $ 239,361 2000 97,132 237,522 2001 79,976 234,147 2002 67,103 228,144 2003 45,161 227,618 Later Years 148,121 3,437,925 Total Future Minimum Lease Rentals 546,888 (a) $4,604,717 Less Estimated Interest Element 118,244 Estimated Present Value of Future Minimum Lease Rentals 428,644 Unamortized Nuclear Fuel 103,939 Total $532,583 (a) Minimum lease rentals do not include nuclear fuel rentals. The rentals are paid in proportion to heat produced and carrying charges on the unamortized nuclear fuel balance. There are no minimum lease payment requirements for leased nuclear fuel. 15. Capital Stocks and Paid-In Capital: Changes in capital stocks and paid-in capital during the period January 1, 1996 through December 31, 1998 were:
Cumulative Preferred Stocks Shares of Subsidiaries Cumulative Not Subject Subject to Common Stock- Preferred Stocks Paid-in To Mandatory Mandatory Par Value $6.50(a) of Subsidiaries Common Stock Capital Redemption Redemption(b) (Dollars in Thousands) January 1, 1996 195,634,992 6,709,751 $1,271,627 $1,658,524 $ 148,240 $ 522,735 Issuances 1,600,000 - 10,400 55,061 - - Retirements and Other - (707,518) - 1,969 (57,917) (12,835) December 31, 1996 197,234,992 6,002,233 1,282,027 1,715,554 90,323 509,900 Issuances 1,754,989 - 11,408 65,337 - - Retirements and Other - (4,258,947) - (2,109) (43,599) (382,295) December 31, 1997 198,989,981 1,743,286 1,293,435 1,778,782 46,724 127,605 Issuances 1,826,488 - 11,872 73,643 - - Retirements and Other - (7,220) - 487 (722) - December 31, 1998 200,816,469 1,736,066 $1,305,307 $1,852,912 $ 46,002 $ 127,605 (a) Includes 8,999,992 shares of treasury stock. (b) Including portion due within one year.
16. Lines of Credit and Commitment Fees: At December 31, 1998 and 1997, unused short-term bank lines of credit were available in the amounts of $763 million and $442 million, respectively. In addition several of the subsidiaries engaged in providing non-regulated energy services share a line of credit under a revolving credit agreement. The amounts of credit available under the revolving credit agreement were $60 million and $330 million at December 31, 1998 and 1997, respectively. The short-term bank lines of credit and the revolving credit agreement require the payment of facility fees of approximately 1/10 of 1% on the daily amount of such commitments. Outstanding short-term debt consisted of: December 31, 1998 1997 (dollars in thousands) Balance Outstanding: Notes Payable $197,304 $199,285 Commercial Paper 419,300 355,790 Total $616,604 $555,075 Year-End Weighted Average Interest Rate: Notes Payable 5.8% 6.3% Commercial Paper 6.2% 6.8% Total 6.1% 6.6% 17. Unaudited Quarterly Financial Information: Quarterly Periods Ended 1998 March 31 June 30 Sept. 30 Dec. 31 (In Thousands - Except Per Share Amounts) Operating Revenues $1,509,410 $1,560,944 $1,845,228 $1,430,320 Operating Income 255,932 227,190 311,579 162,033 Net Income 150,586 118,084 195,365 72,148 Earnings per Share 0.79 0.62 1.02 0.38 Fourth quarter 1998 earnings declined primarily as a result of unseasonably mild weather, severance accruals and the negative impact of the extended Cook Plant outage. Quarterly Periods Ended 1997 March 31 June 30 Sept. 30 Dec. 31 (In Thousands - Except Per Share Amounts) Operating Revenues $1,492,069 $1,382,158 $1,507,075 $1,498,518 Operating Income 271,978 221,255 275,090 216,131 Income Before Extraordinary Item 172,562 121,139 201,746 124,933 Net Income 172,562 121,139 91,181 126,079 Earnings per Share Before Extraordinary Item* 0.92 0.64 1.07 0.66 Earnings per Share 0.92 0.64 0.48 0.66 *Amounts for 1997 do not add to $3.28 earnings per share due to rounding. The third quarter of 1997 includes an extraordinary loss of $110.6 million or $0.59 per share for a UK Windfall Tax which retroactively adjusted upward Yorkshire's privatization price discussed in Note 7. See "Reclassification" in Note 1 regarding reclassification of prior period amounts. AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES SCHEDULE OF CONSOLIDATED CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES
December 31, 1998 Call Price per Shares Shares Amount (In Share (a) Authorized(b) Outstanding Thousands) Not Subject to Mandatory Redemption: 4.08% - 4.56% $102-$110 932,403 460,016 $ 46,002 Subject to Mandatory Redemption: 5.90% - 5.92% (c) (d) 1,950,000 388,100 $ 38,810 6.02% - 6-7/8% (c) (e) 1,950,000 637,950 63,795 7% (f) (f) 250,000 250,000 25,000 Total Subject to Mandatory Redemption (c) $127,605 ______________________________________________________________________________________________________ December 31, 1997 Call Price per Shares Shares Amount (In Share (a) Authorized(b) Outstanding Thousands) Not Subject to Mandatory Redemption: 4.08% - 4.56% $102-$110 932,403 467,236 $ 46,724 Subject to Mandatory Redemption: 5.90% - 5.92% (c) (d) 1,950,000 388,100 $ 38,810 6.02% - 6-7/8% (c) (e) 1,950,000 637,950 63,795 7% (f) (f) 250,000 250,000 25,000 Total Subject to Mandatory Redemption (c) $127,605 NOTES TO SCHEDULE OF CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES (a) At the option of the subsidiary the shares may be redeemed at the call price plus accrued dividends. The involuntary liquidation preference is $100 per share for all outstanding shares. (b) As of December 31, 1998 the subsidiaries had 7,193,024, 22,200,000 and 7,583,313 shares of $100, $25 and no par value preferred stock, respectively, that were authorized but unissued. (c) Shares outstanding and related amounts are stated net of applicable retirements through sinking funds (genera lly at par) and reacquisitions of shares in anticipation of future requirements. The subsidiaries reacquired enough shares in 1997 to meet all sinking fund requirements on certain series until 2008 and on certain series until 2009 when all remaining outstanding shares must be redeemed.The sinking fund provisions of the series subject to mandatory redemption aggregate $5,000,000 eachyear for the years 2000, 2001, 2002 and $15,000,000 in 2003. (d) Not callable prior to 2003; after that the call price is $100 per share. (e) Not callable prior to 2000; after that the call price is $100 per share. (f) With sinking fund. Redemption is restricted prior to 2000.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES SCHEDULE OF CONSOLIDATED LONG-TERM DEBT OF SUBSIDIARIES Weighted Average Maturity Interest Rate Interest Rates at December 31, December 31, December 31, 1998 1998 1997 1998 1997 (in thousands) FIRST MORTGAGE BONDS 1998-2002 7.23% 6.35%-8.95% 6.35%-9.15% $ 759,000 $1,131,411 2003-2006 6.70% 6%-8% 6%-8% 846,000 846,000 2022-2025 7.90% 7.10%-8.80% 7.10%-8.80% 1,020,768 1,120,419 INSTALLMENT PURCHASE CONTRACTS (a) 1998-2002 4.40% 4.05%-5.15% 3.70%-7-1/4% 145,000 189,500 2007-2025 6.42% 5.00%-7-7/8% 5.45%-7-7/8% 776,245 756,745 NOTES PAYABLE (b) 1998-2008 5.97% 5.49%-9.60% 5.29%-9.60% 1,493,360 527,681 SENIOR UNSECURED NOTES 2003-2008 6.54% 6.24%-6.91% 6.73%-6.91% 786,000 144,000 2038 7.30% 7.20%-7-3/8% - 340,000 - JUNIOR DEBENTURES 2025 - 2038 8.05% 7.60%-8.72% 7.92%-8.72% 620,000 495,000 OTHER LONG-TERM DEBT (c) 269,319 250,357 Unamortized Discount (net) (49,575) (37,196) Total Long-term Debt Outstanding (d) 7,006,117 5,423,917 Less Portion Due Within One Year 206,476 294,454 Long-term Portion $6,799,641 $5,129,463 NOTES TO SCHEDULE OF CONSOLIDATED LONG-TERM DEBT OF SUBSIDIARIES (a) For certain series of installment purchase contracts interest rates are subject to periodic adjustment. Certain series will be purchased on demand at periodic interest-adjustment dates. Letters of credit from banks and standby bond purchase agreements support certain series. (b) Notes payable represent outstanding promissory notes issued under term loan agreements and revolving credit agreements with a number of banks and other financial institutions. At expiration all notes then issued and outstanding are due and payable. Interest rates are both fixed and variable. Variable rates generally relate to specified short-term interest rates. (c) Other long-term debt consists of a liability along with accrued interest for disposal of spent nuclear fuel (see Note 4 of the Notes to Consolidated Financial Statements) and financing obligation under sale lease back agreements. (d) Long-term debt outstanding at December 31, 1998 is payable as follows: Principal Amount (in thousands) 1999 $ 206,476 2000 786,222 2001 512,028 2002 294,546 2003 934,547 Later Years 4,321,873 Total Principal Amount 7,055,692 Unamortized Discount 49,575 Total $7,006,117
Management's Responsibility The management of American Electric Power Company, Inc. is responsible for the integrity and objectivity of the information and representations in this annual report, including the consolidated financial statements. These statements have been prepared in conformity with generally accepted accounting principles, using informed estimates where appropriate, to reflect the Company's financial condition and results of operations. The information in other sections of the annual report is consistent with these statements. The Company's Board of Directors has oversight responsibilities for determining that management has fulfilled its obligation in the preparation of the financial statements and in the ongoing examination of the Company's established internal control structure over financial reporting. The Audit Committee, which consists solely of outside directors and which reports directly to the Board of Directors, meets regularly with management, Deloitte & Touche LLP - Certified Public Accountants and the Company's internal audit staff to discuss accounting, auditing and reporting matters. To ensure auditor independence, both Deloitte & Touche LLP and the internal audit staff have unrestricted access to the Audit Committee. The financial statements have been audited by Deloitte & Touche LLP, whose report appears on the next page. The auditors provide an objective, independent review as to management's discharge of its responsibilities insofar as they relate to the fairness of the Company's reported financial condition and results of operations. Their audit includes procedures believed by them to provide reasonable assurance that the financial statements are free of material misstatement and includes a review of the Company's internal control structure over financial reporting. Independent Auditors' Report To the Shareholders and Board of Directors of American Electric Power Company, Inc.: We have audited the accompanying consolidated balance sheets of American Electric Power Company, Inc. and its subsidiaries as of December 31, 1998 and 1997, and the related consolidated statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 1998. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of American Electric Power Company, Inc. and its subsidiaries as of December 31, 1998 and 1997, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1998 in conformity with generally accepted accounting principles. /s/ Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 23, 1999 EX-21 7 AEP SUBSIDIARIES EXHIBIT 21 Subsidiaries of American Electric Power Company, Inc. As of January 1, 1999 The voting stock of each company shown indented is owned by the company immediately above which is not indented to the same degree. Subsidiaries not indented are directly owned by American Electric Power Company, Inc.
Percentage of Voting Securities Location of Owned By Name of Company Incorporation Immediate Parent American Electric Power Service Corporation New York 100.0 AEP Communications, Inc. Ohio 100.0 AEP Communications, LLC Virginia 100.0 AEP Energy Services, Inc. Ohio 100.0 AEP Generating Company Ohio 100.0 AEP Investments, Inc. Ohio 100.0 AEP Power Marketing, Inc. Ohio 100.0 AEP Resources Service Company Ohio 100.0 AEP Energy Services International, Limited Cayman Islands 100.0 AEP Resources, Inc. Ohio 100.0 AEP Resources Australia Holdings Pty Ltd Australia 100.0 AEP Resources CitiPower I Pty Ltd Australia 100.0 Australia's Energy Partnership Australia 99.0 (a) Marregon II Pty Ltd Australia 100.0 CitiPower Pty Australia 100.0 Marregon Pty Ltd Australia 100.0 AEP Resources CitiPower II Pty Ltd Australia 100.0 Australia's Energy Partnership Australia 1.0 (a) Marregon II Pty Ltd Australia 100.0 CitiPower Pty Australia 100.0 Marregon Pty Ltd Australia 100.0 AEP Resources Australia Pty., Ltd. Australia 100.0 AEP Resources Delaware, Inc. Delaware 100.0 AEP Resources Gas Holding Company Delaware 100.0 AEP Resources Investments, Inc. Delaware 100.0 LIG Pipeline Company Nevada 100.0 LIG, Inc. Nevada 100.0 Louisiana Intrastate Gas Company,L.L.C. Louisiana 10.0 (b) LIG Chemical Company Louisiana 100.0 LIG Liquids Company,L.L.C. Louisiana 10.0 (c) LIG Liquids Company,L.L.C. Louisiana 90.0 (c) Tuscaloosa Pipeline Company Louisiana 100.0 Louisiana Intrastate Gas Company,L.L.C. Louisiana 90.0 (b) LIG Chemical Company Louisiana 100.0 LIG Liquids Company,L.L.C. Louisiana 10.0 (c) LIG Liquids Company,L.L.C. Louisiana 90.0 (c) Tuscaloosa Pipeline Company Louisiana 100.0 AEP Resources Ventures, Inc. Delaware 100.0 AEP Acquisition, L.L.C. Delaware 50.0 (d) Jefferson Island Storage & Hub L.L.C. Delaware 100.0 AEP Resources Ventures II, Inc. Delaware 100.0 AEP Acquisition, L.L.C. Delaware 50.0 (d) AEP Resources Ventures III, Inc. Delaware 100.0 AEP Resources International, Limited Cayman Islands 100.0 AEP Pushan Power, LDC Cayman Islands 99.0 (e) Nanyang General Light Electric Co., Ltd. People's Republic of China 70.0 (f) AEP Resources Mauritius Company Mauritius 99.0 (e) AEP Resources Mauritius Investment Company Mauritius 100.0 AEP Resources Project Management Company, Ltd.Cayman Islands 100.0 AEP Pushan Power, LDC Cayman Islands 1.0 (e) Nanyang General Light Electric Co., Ltd. People's Republic of China 70.0 (f) AEP Resources Mauritius Company Mauritius 1.0 (e) AEP Resources Limited Great Britain 100.0 AEPR Global Investments B.V. Netherlands 100.0 AEPR Global Holland Holding B.V. Netherlands 100.0 AEPR Global Ventures B.V. Netherlands 100.0 Appalachian Power Company Virginia 98.6 (g) Cedar Coal Co. West Virginia 100.0 Central Appalachian Coal Company West Virginia 100.0 Central Coal Company West Virginia 50.0 (h) Central Operating Company West Virginia 50.0 (h) Southern Appalachian Coal Company West Virginia 100.0 West Virginia Power Company West Virginia 100.0 Columbus Southern Power Company Ohio 100.0 Colomet, Inc. Ohio 100.0 Conesville Coal Preparation Company Ohio 100.0 Simco Inc. Ohio 100.0 Franklin Real Estate Company Pennsylvania 100.0 Indiana Franklin Realty, Inc. Indiana 100.0 Indiana Michigan Power Company Indiana 100.0 Blackhawk Coal Company Utah 100.0 Price River Coal Company, Inc. Indiana 100.0 Kentucky Power Company Kentucky 100.0 Kingsport Power Company Virginia 100.0 Ohio Power Company Ohio 99.1 (i) Cardinal Operating Company Ohio 50.0 (j) Central Coal Company West Virginia 50.0 (h) Central Ohio Coal Company Ohio 100.0 Central Operating Company West Virginia 50.0 (h) Southern Ohio Coal Company West Virginia 100.0 Windsor Coal Company West Virginia 100.0 Ohio Valley Electric Corporation Ohio 44.2 (k) Indiana-Kentucky Electric Corporation Indiana 100.0 Wheeling Power Company West Virginia 100.0 (a) Owned 99% by AEP Resources CitiPower I Pty Ltd and 1% by AEP Resources CitiPower II Pty Ltd (b) Owned 90% by LIG Pipeline Company and 10% by LIG, Inc. (c) Owned 90% by Louisiana Intrastate Gas Company, L.L.C. and 10% by Lig Chemical Company (d) Owned 50% by Aep Resources Ventures, Inc and 50% by AEP Resources Ventures II. (e) Owned 99% by AEP Resources International, Ltd. and 1% by AEP Resources Project Management Company, Ltd. (f) AEP Pushan Power LDC owns 70% and the remaining 30% is owned by two unaffiliated companies. (g) 13,499,500 shares of Common Stock, all owned by parent, have one vote each and 3,587 shares of Preferred Stock, all owned by public, have one vote each. (h) Owned 50% by Appalachian Power Company and 50% by Ohio Power Company. (i) 27,952,473 shares of Common Stock, all owned by parent, have one vote each and 256,200 shares of Preferred Stock, all owned by public, have one vote each. (j) Ohio Power Company owns 50% of the stock; the other 50% is owned by a corporation not affiliated with American Electric Power Company, Inc. (k) American Electric Power Company, Inc. and Columbus Southern Power Company own 39.9% and 4.3% of the stock, respectively, and the remaining 55.8% is owned by unaffiliated companies.
EX-23 8 CONSENT OF DELOITTE & TOUCHE Exhibit 23 INDEPENDENT AUDITORS' CONSENT We consent to the incorporation by reference in Post-Effective Amendment No. 3 to Registration Statement No. 33-01052 of American Electric Power Company, Inc. on Form S-8 and Post-Effective Amendment No. 3 to Registration Statement No. 33-01734 of American Electric Power Company, Inc. on Form S-3 of our reports dated February 23, 1999, appearing in and incorporated by reference in this Annual Report on Form 10-K of American Electric Power Company, Inc. for the year ended December 31, 1998. Deloitte & Touche LLP Columbus, Ohio March 29, 1999 EX-24 9 POWER OF ATTORNEY Exhibit 24 POWER OF ATTORNEY AMERICAN ELECTRIC POWER COMPANY, INC. Annual Report on Form lO-K for the Fiscal Year Ended December 31, 1998 The undersigned directors of AMERICAN ELECTRIC POWER COMPANY, INC., a New York corporation (the "Company"), do hereby constitute and appoint E. LINN DRAPER, JR., ARMANDO A. PENA and HENRY W. FAYNE, and each of them, their attorneys-in-fact and agents, to execute for them, and in their names, and in any and all of their capacities, the Annual Report of the Company on Form lO-K, pursuant to Section 13 of the Securities Exchange Act of 1934, for the fiscal year ended December 31, 1998, and any and all amendments thereto, and to file the same, with all exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform every act and thing required or necessary to be done, as fully to all intents and purposes as the undersigned might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, may lawfully do or cause to be done by virtue hereof. IN WITNESS WHEREOF, the undersigned have signed these presents this 24th day of February, 1999. /s/ John P. DesBarres /s/ Angus E. Peyton John P. DesBarres Angus E. Peyton /s/ E. Linn Draper, Jr. /s/ Donald G. Smith E. Linn Draper, Jr. Donald G. Smith /s/ Robert M. Duncan /s/ Linda Gillespie Stuntz Robert M. Duncan Linda Gillespie Stuntz /s/ Robert W. Fri /s/ Kathryn D. Sullivan Robert W. Fri Kathryn D. Sullivan /s/ Lester A. Hudson, Jr. /s/ Morris Tanenbaum Lester A. Hudson, Jr. Morris Tanenbaum /s/ Leonard J. Kujawa Leonard J. Kujawa EX-27 10 ARTICLE UT FIN. DATA SCH. FOR 10-Q
UT 0000004904 AMERICAN ELECTRIC POWER COMPANY, INC. 1,000 12-MOS DEC-31-1998 DEC-31-1998 PER-BOOK 11,729,870 3,356,554 2,217,669 332,391 1,846,718 19,483,202 1,305,307 1,852,912 1,683,561 4,841,780 127,605 46,002 6,799,641 197,304 0 419,300 206,476 0 450,922 81,661 6,312,511 19,483,202 6,345,902 334,548 5,054,620 5,389,168 956,734 9,463 966,197 419,088 536,183 10,926 536,183 457,638 202,889 1,029,526 2.81 2.81 Represents preferred stock dividend requirements of subsidiaries; deducted before computation of net income.
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