-----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, CMv/sXbBRN9LrpqwEAvN81iUnpIkXMXk6sgwul1qPQEWLGhGSO2MENnsNxXAhUKQ aHgMPw7buQzQIjx+OSnLeQ== 0000004904-96-000034.txt : 19960329 0000004904-96-000034.hdr.sgml : 19960329 ACCESSION NUMBER: 0000004904-96-000034 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 8 CONFORMED PERIOD OF REPORT: 19951231 FILED AS OF DATE: 19960328 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: AMERICAN ELECTRIC POWER COMPANY INC CENTRAL INDEX KEY: 0000004904 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 134922640 STATE OF INCORPORATION: NY FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-03525 FILM NUMBER: 96539831 BUSINESS ADDRESS: STREET 1: 1 RIVERSIDE PLZ CITY: COLUMBUS STATE: OH ZIP: 43215 BUSINESS PHONE: 6142231000 FORMER COMPANY: FORMER CONFORMED NAME: KINGSPORT UTILITIES INC DATE OF NAME CHANGE: 19660906 10-K 1 AEPCO 1995 10-K SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K (Mark One) x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 [FEE REQUIRED] For the fiscal year ended December 31, 1995 TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED] For the transition period from _____________ to ______________ COMMISSION REGISTRANT; STATE OF INCORPORATION; I.R.S. EMPLOYER FILE NUMBER ADDRESS; AND TELEPHONE NUMBER IDENTIFICATION NO. 1-3525 AMERICAN ELECTRIC POWER COMPANY, INC. 13-4922640 (A New York Corporation) 1 Riverside Plaza Columbus, Ohio 43215 Telephone (614) 223-1000 0-18135 AEP GENERATING COMPANY 31-1033833 (An Ohio Corporation) 1 Riverside Plaza Columbus, Ohio 43215 Telephone (614) 223-1000 1-3457 APPALACHIAN POWER COMPANY 54-0124790 (A Virginia Corporation) 40 Franklin Road, S.W. Roanoke, Virginia 24011 Telephone (540) 985-2300 1-2680 COLUMBUS SOUTHERN POWER COMPANY 31-4154203 (An Ohio Corporation) 215 North Front Street Columbus, Ohio 43215 Telephone (614) 464-7700 1-3570 INDIANA MICHIGAN POWER COMPANY 35-0410455 (An Indiana Corporation) One Summit Square P. O. Box 60 Fort Wayne, Indiana 46801 Telephone (219) 425-2111 1-6858 KENTUCKY POWER COMPANY 61-0247775 (A Kentucky Corporation) 1701 Central Avenue Ashland, Kentucky 41101 Telephone (800) 572-1113 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 J(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 J(2) to such Form 10-K. Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes . No. . SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT: NAME OF EACH EXCHANGE REGISTRANT TITLE OF EACH CLASS ON WHICH REGISTERED AEP Generating Company None American Electric Common Stock, Power Company, Inc. $6.50 par value New York Stock Exchange Appalachian Power Cumulative Preferred Company Stock Voting, no par value: 4-1/2% Philadelphia Stock Exchange 4.50% Philadelphia Stock Exchange 7.40% New York Stock Exchange Columbus Southern 8-3/8% Junior Subordinated Power Company Deferrable Interest Debentures, Series A, Due 2025 New York Stock Exchange Indiana Michigan Cumulative Preferred Power Company Stock, Non-Voting, $100 par value: 4-1/8% Chicago Stock Exchange 7.08% New York Stock Exchange Kentucky Power Company 8.72% Junior Subordinated Deferrable Interest Debentures, Series A, Due 2025 New York Stock Exchange Ohio Power Company 8.16% Junior Subordinated Deferrable Interest Debentures, Series A, Due 2025 New York Stock Exchange Indicate by check mark if disclosure of delinquent filers with respect to American Electric Power Company, Inc. and Appalachian 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 proxy statement of American Electric Power Company, Inc. or definitive information statement of Appalachian Power Company 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 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 statement of Ohio Power Company incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT: REGISTRANT TITLE OF EACH CLASS AEP Generating Company None American Electric Power Company, Inc. None Appalachian Power Company None Columbus Southern Power Company None Indiana Michigan Power Company None Kentucky Power Company None Ohio Power Company 4-1/2% Cumulative Preferred Stock, Voting, $100 par value AGGREGATE MARKET VALUE NUMBER OF SHARES OF VOTING STOCK HELD OF COMMON STOCK BY NON-AFFILIATES OF OUTSTANDING OF THE REGISTRANTS AT THE REGISTRANTS AT FEBRUARY 2, 1996 FEBRUARY 2, 1996 AEP Generating Company None 1,000 ($1,000 par value) American Electric Power Company, Inc. $8,164,000,000 186,635,000 ($6.50 par value) Appalachian Power Company $43,000,000 13,499,500 (no par value) Columbus Southern Power Company None 16,410,426 (no par value) Indiana Michigan Power Company None 1,400,000 (no par value) Kentucky Power Company None 1,009,000 ($50 par value) Ohio Power Company $68,000,000 27,952,473 (no par value) NOTE ON MARKET VALUE OF VOTING STOCK HELD BY NON-AFFILIATES All of the common stock of AEP Generating Company, Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company and Ohio Power Company is owned by American Electric Power Company, Inc. (see Item 12 herein). The voting stock owned by non- affiliates of (i) Appalachian Power Company consists of 552,348 shares of Cumulative Preferred Stock, no par value; and (ii) Ohio Power Company consists of 862,403 shares of Cumulative Preferred Stock, $100 par value. Some of the series of Cumulative Preferred Stock are not regularly traded. The aggregate market value of the Cumulative Preferred Stock is based on the average of the high and low prices on the closest trading date to February 2, 1996 for series traded on the New York or Philadelphia Stock Exchange, or the most recent reported bid prices for those series not recently traded. Where recent market price information was not available with respect to a series, the market price for such series is based on the price of a recently traded series with an adjustment related to any difference in the current yields of the two series. DOCUMENTS INCORPORATED BY REFERENCE PART OF FORM 10-K INTO WHICH DOCUMENT DESCRIPTION IS INCORPORATED Portions of Annual Reports of the following companies for the fiscal year ended December 31, 1995: Part II AEP Generating Company American Electric Power Company, Inc. Appalachian Power Company Columbus Southern Power Company Indiana Michigan Power Company Kentucky Power Company Ohio Power Company Portions of Proxy Statement of American Electric Power Company, Inc., dated March 9, 1996, for Annual Meeting of Shareholders Part III Portions of Information Statements of the following companies for 1996 Annual Meeting of Shareholders, to be filed within 120 days after December 31, 1995: Part III Appalachian Power Company Ohio Power Company THIS COMBINED FORM 10-K IS SEPARATELY FILED BY AEP GENERATING COMPANY, AMERICAN ELECTRIC POWER COMPANY, INC., APPALACHIAN POWER COMPANY, COLUMBUS SOUTHERN POWER COMPANY, INDIANA MICHIGAN POWER COMPANY, KENTUCKY POWER COMPANY AND OHIO POWER COMPANY. INFORMATION CONTAINED HEREIN RELATING TO ANY INDIVIDUAL REGISTRANT IS FILED BY SUCH REGISTRANT ON ITS OWN BEHALF. EXCEPT FOR AMERICAN ELECTRIC POWER COMPANY, INC., EACH REGISTRANT MAKES NO REPRESENTATION AS TO INFORMATION RELATING TO THE OTHER REGISTRANTS. TABLE OF CONTENTS PAGE NUMBER Glossary of Terms i PART I Item 1. Business 1 Item 2. Properties 29 Item 3. Legal Proceedings 33 Item 4. Submission of Matters to a Vote of Security Holders 34 Executive Officers of the Registrants 34 PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters 37 Item 6. Selected Financial Data 37 Item 7. Management's Discussion and Analysis of Results of Operations and Financial Condition 37 Item 8. Financial Statements and Supplementary Data 38 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 38 PART III Item 10. Directors and Executive Officers of the Registrants 39 Item 11. Executive Compensation 40 Item 12. Security Ownership of Certain Beneficial Owners and Management 44 Item 13. Certain Relationships and Related Transactions 45 PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K 46 Signatures 48 Index to Financial Statement Schedules S-1 Independent Auditors' Report S-2 Exhibit Index E-1 GLOSSARY OF TERMS When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below. TERM MEANING AEGCo AEP Generating Company, an electric utility subsidiary of AEP. AEP American Electric Power Company, Inc. AEP System or the System The American Electric Power System, an integrated electric utility system, owned and operated by AEP's electric utility subsidiaries. AFUDC Allowance for funds used during construction. Defined in regulatory systems of accounts as the net cost of borrowed funds used for construction and a reasonable rate of return on other funds when so used. APCo Appalachian Power Company, an electric utility subsidiary of AEP. Buckeye Buckeye Power, Inc., an unaffiliated corporation. CCD Group CSPCo, CG&E and DP&L. CG&E The Cincinnati Gas & Electric Company, an unaffiliated utility company. Cook Plant The Donald C. Cook Nuclear Plant, owned by I&M. CSPCo Columbus Southern Power Company, an electric utility subsidiary of AEP. DOE United States Department of Energy. DP&L The Dayton Power and Light Company, an unaffiliated utility company. Federal EPA United States Environmental Protection Agency. FERC Federal Energy Regulatory Commission (an independent commission within the DOE). I&M Indiana Michigan Power Company, an electric utility subsidiary of AEP. IURC Indiana Utility Regulatory Commission. KEPCo Kentucky Power Company, an electric utility subsidiary of AEP. KPSC Kentucky Public Service Commission. MPSC Michigan Public Service Commission. NEIL Nuclear Electric Insurance Limited. NPDES National Pollutant Discharge Elimination System. NRC Nuclear Regulatory Commission. Ohio EPA Ohio Environmental Protection Agency. OPCo Ohio Power Company, an electric utility subsidiary of AEP. OVEC Ohio Valley Electric Corporation, an electric utility company in which AEP and CSPCo own a 44.2% equity interest. PCB's Polychlorinated biphenyls. PUCO The Public Utilities Commission of Ohio. PUHCA Public Utility Holding Company Act of 1935, as amended. RCRA Resource Conservation and Recovery Act of 1976, as amended. Rockport Plant A generating plant, consisting of two 1,300,000-kilowatt coal-fired generating units, near Rockport, Indiana. SEC Securities and Exchange Commission. Service Corporation American Electric Power Service Corporation, a service subsidiary of AEP. SO{2} 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 [THIS PAGE INTENTIONALLY LEFT BLANK] PART I Item 1. BUSINESS GENERAL AEP was incorporated under the laws of the State of New York in 1906 and reorganized in 1925. It is a public utility holding company which owns, directly or indirectly, all of the outstanding common stock of its electric utility and other subsidiaries. Substantially all of the operating revenues of AEP and its subsidiaries are derived from the furnishing of electric service. 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, 1995, the subsidiaries of AEP had a total of 18,502 employees. AEP, as such, has no employees. The operating subsidiaries of AEP are: APCO (organized in Virginia in 1926) is engaged in the generation, purchase, transmission and distribution of electric power to approximately 859,000 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, 1995, APCo and its wholly owned subsidiaries had 4,338 employees. Among the principal industries served by APCo are coal mining, primary metals, chemicals, textiles, paper, stone, clay, glass and concrete products, rubber, plastic products and furniture. In addition to its AEP System interconnections, APCo also is interconnected with the following unaffiliated utility companies: Carolina Power & Light Company, Duke Power Company and VEPCo. A comparatively small part of the properties and business of APCo is located in the northeastern end of the Tennessee Valley. APCo has several points of interconnection with TVA and has entered into agreements with TVA under which APCo and TVA interchange and transfer electric power over portions of their respective systems. CSPCO (organized in Ohio in 1937, the earliest direct predecessor company having been organized in 1883) is engaged in the generation, purchase, transmission and distribution of electric power to approximately 599,000 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, 1995, CSPCo had 2,174 employees. CSPCo's service area is comprised of two areas in Ohio, which include portions of twenty-five counties. One area includes the City of Columbus and the other is a predominantly rural area in south central Ohio. Approximately 80% of CSPCo's retail revenues are derived from the Columbus area. Among the principal industries served are food processing, chemicals, primary metals, electronic machinery and paper products. In addition to its AEP System interconnections, CSPCo also is interconnected with the following unaffiliated utility companies: CG&E, DP&L and Ohio Edison Company. I&M (organized in Indiana in 1925) is engaged in the generation, purchase, transmission and distribution of electric power to approximately 537,000 customers in northern and eastern Indiana and southwestern Michigan, and in supplying electric power at wholesale to other electric utility companies, rural electric cooperatives and municipalities. At December 31, 1995, I&M had 3,525 employees. Among the principal industries served are primary metals, transportation equipment, fabricated metal products, electrical and electronic machinery, 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 Power Company, Illinois Power Company, Indianapolis Power & Light Company, Louisville Gas and Electric Company, Northern Indiana Public Service Company, PSI Energy Inc. and Richmond Power & Light Company. KEPCO (organized in Kentucky in 1919) is engaged in the generation, purchase, transmission and distribution of electric power to approximately 165,000 customers in an area in eastern Kentucky, and in supplying electric power at wholesale to other utilities and municipalities in Kentucky. At December 31, 1995, KEPCo had 748 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 42,000 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, 1995, Kingsport Power Company had 101 employees. OPCO (organized in Ohio in 1907 and reincorporated in 1924) is engaged in the generation, purchase, transmission and distribution of electric power to approximately 668,000 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, 1995, OPCo and its wholly owned subsidiaries had 4,998 employees. Among the principal industries served by OPCo are primary metals, rubber and plastic products, stone, clay, glass and concrete products, petroleum refining, chemicals and electrical and electronic machinery. In addition to its AEP System interconnections, OPCo also is interconnected with the following unaffiliated utility companies: CG&E, The Cleveland Electric Illuminating Company, DP&L, Duquesne Light Company, Kentucky Utilities Company, Monongahela Power Company, Ohio Edison Company, The Toledo Edison Company and West Penn Power Company. WHEELING POWER COMPANY (organized in West Virginia in 1883 and reincorporated in 1911) provides electric service to approximately 41,000 customers in northern West Virginia. Wheeling Power Company has no generating facilities of its own. It purchases electric power distributed to its customers from OPCo. At December 31, 1995, Wheeling Power Company had 135 employees. Another principal electric utility subsidiary of AEP is AEGCo, which was organized in Ohio in 1982 as an electric generating company. AEGCo sells power at wholesale to I&M, KEPCo and VEPCo. AEGCo has no employees. See Item 2 for information concerning the properties of the subsidiaries of AEP. The Service Corporation provides accounting, administrative, information systems, engineering, financial, legal, maintenance and other services at cost to the AEP System companies. The executive officers of AEP and its public utility subsidiaries are all employees of the Service Corporation. REGULATION GENERAL AEP and its subsidiaries are subject to the broad regulatory provisions of PUHCA administered by the SEC. The public utility subsidiaries' retail rates and certain other matters are subject to regulation by the public utility commissions of the states in which they operate. Such subsidiaries are also subject to regulation by the FERC under the Federal Power Act in respect of rates for interstate sale at wholesale and transmission of electric power, accounting and other matters and construction and operation of hydroelectric projects. I&M is subject to regulation by the NRC under the Atomic Energy Act of 1954, as amended, with respect to the operation of the Cook Plant. POSSIBLE CHANGE TO PUHCA The provisions of PUHCA, administered by the SEC, regulate all aspects of a registered holding company system, such as the AEP System. PUHCA requires that the operations of a registered holding company system be limited to a single integrated public utility system and such other businesses as are incidental or necessary to the operations of the system. In addition, PUHCA governs, among other things, financings, sales or acquisitions of assets and intra-system transactions. On June 20, 1995, the SEC released a report from its Division of Investment Management recommending a conditional repeal of PUHCA, including its limits on financing and on geographic and business diversification. Specific federal authority, however, would be preserved over access to the books and records of registered holding company systems, audit authority over registered holding companies and their subsidiaries and oversight over affiliate transactions. This authority would be transferred to the FERC. In October 1995, legislation was introduced in the U.S. Senate to repeal PUHCA and transfer certain federal authority to the FERC as recommended in the SEC report. 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. On December 28, 1994, the SEC proposed revisions to its rules governing transactions between associated companies in a registered holding company system. These proposed revisions to the rules would price transactions governed by SEC rules at a market-based price if it is lower than cost. In its June 1995 report, the Division of Investment Management recommended that the proposed revisions to the rules be withdrawn. In addition, proposals have been made for Congress to repeal PUHCA or modify its provisions governing intra-system transactions. The effect of possible SEC revisions of these cost provisions or the repeal or amendment of PUHCA on AEP's intra-system transactions depends on whether the assurance of full cost recovery is eliminated immediately or phased-in and whether it is eliminated for all intra-system transactions or only some. If the cost recovery assurance is eliminated immediately for all intra-system transactions, it could have a material adverse effect on results of operations and financial condition of AEP and OPCo. CONFLICT OF REGULATION Public utility subsidiaries of AEP can be subject to regulation of the same subject matter by two or more jurisdictions. In such situations, it is possible that the decisions of such regulatory bodies may conflict or that the decision of one such body may affect the cost of providing service and so the rates in another jurisdiction. In a case involving OPCo, the U.S. Court of Appeals for the District of Columbia held that the determination of costs to be charged to associated companies by the SEC under PUHCA precluded the FERC from determining that such costs were unreasonable for ratemaking purposes. The U.S. Supreme Court also has held that a state commission may not conclude that a FERC approved wholesale power agreement is unreasonable for state ratemaking purposes. Certain actions that would overturn these decisions or otherwise affect the jurisdiction of the SEC and FERC are under consideration by the U.S. Congress and these regulatory bodies. Such conflicts of jurisdiction often result in litigation and, if resolved adversely to a public utility subsidiary of AEP, could have a material adverse effect on the results of operations or financial condition of such subsidiary or AEP. CLASSES OF SERVICE The principal classes of service from which the major electric utility subsidiaries of AEP derive revenues and the amount of such revenues (from kilowatt-hour sales) during the year ended December 31, 1995 are as follows:
AEGCO APCO CSPCO I&M KEPCO OPCO AEP SYSTEM (a) (IN THOUSANDS) Retail Residential Without Electric Heating $ -- $ 240,385 $ 329,881 $ 239,266 $ 43,938 $ 277,780 $1,151,981 With Electric Heating -- 331,445 115,386 109,504 63,609 145,688 801,956 Total Residential -- 571,830 445,267 348,770 107,547 423,468 1,953,937 Commercial -- 284,866 371,461 256,319 58,606 257,300 1,265,776 Industrial -- 366,329 143,162 298,256 96,647 639,177 1,606,451 Miscellaneous -- 32,270 16,041 6,482 847 8,065 67,047 Total Retail -- 1,255,295 975,931 909,827 263,647 1,328,010 4,893,211 Wholesale (sales for resale) 231,659 269,493 75,466 357,441 60,567 457,758 680,905 Total from KWH Sales 231,659 1,524,788 1,051,397 1,267,268 324,214 1,785,768 5,574,116 Provision for Revenue Refunds -- (1,100) -- -- -- -- (1,100) Total Net of Provision for Revenue Refunds 231,659 1,523,688 1,051,397 1,267,268 324,214 1,785,768 5,573,016 Other Operating Revenues 136 21,351 20,465 15,889 3,930 37,229 97,314 Total Electric Operating Revenues $231,795 $1,545,039 $1,071,862 $1,283,157 $328,144 $1,822,997 $5,670,330
(a) Includes revenues of other subsidiaries not shown and reflects elimination of intercompany transactions. SALE OF POWER AEP's electric utility subsidiaries own or lease generating stations with total generating capacity of 23,759 megawatts. See Item 2 for more information regarding the generating stations. They operate their generating plants as a single interconnected and coordinated electric utility system and share the costs and benefits in the AEP System Power Pool. Most of the electric power generated at these stations is sold, in combination with transmission and distribution services, to retail customers of AEP's utility subsidiaries in their service territories. These sales are made at rates that are established by the public utility commissions of the state in which they operate. See RATES. Some of the electric power is sold at wholesale to non-affiliated companies. AEP SYSTEM POWER POOL APCo, CSPCo, I&M, KEPCo and OPCo are parties to the Interconnection Agreement, dated July 6, 1951, as amended (the Interconnection Agreement), defining how they share the costs and benefits associated with the System's generating plants. This sharing is based upon each company's "member-load- ratio," which is calculated monthly on the basis of each company's maximum peak demand in relation to the sum of the maximum peak demands of all five companies during the preceding 12 months. In addition, since 1995, APCo, CSPCo, I&M, KEPCo and OPCo have been parties to the AEP System Interim Allowance Agreement which provides, among other things, for the transfer of SO{2} Allowances associated with transactions under the Interconnection Agreement. The following table shows the net credits or (charges) allocated among the parties under the Interconnection Agreement and Interim Allowance Agreement during the years ended December 31, 1993, 1994 and 1995: 1993 1994 1995(a) (in thousands) APCo $(260,000) $(254,000) $(252,000) CSPCo (141,000) (105,000) (143,000) I&M 183,000 107,000 118,000 KEPCo 1,000 12,000 23,000 OPCo 217,000 240,000 254,000 (a) Includes credits and charges from allowance transfers related to the transactions. In July 1994, APCo, CSPCo, I&M, KEPCo and OPCo entered into the AEP System Interim Allowance Agreement (IAA). Reference is made to ENVIRONMENTAL AND OTHER MATTERS - CLEAN AIR ACT AMENDMENTS OF 1990 for a discussion of SO{2} Allowances. The IAA provides for and governs the terms of the following allowance transactions among the parties which began January 1, 1995: (1) an annual reallocation of certain SO{2} Allowances initially allocated by the Federal EPA to OPCo's Gavin Plant; (2) transfer of SO{2} Allowances associated with energy transactions among APCo, CSPCo, I&M, KEPCo and OPCo, (3) a monthly cash settlement for SO{2} Allowances consumed in connection with power sales to non-affiliated electric utilities; and (4) transfers of SO{2} Allowances for current and future period compliance. The IAA does not provide for the allocation of costs and proceeds related to the sale or purchase of SO{2} Allowances to or from non-affiliated companies. The IAA was accepted by the FERC on December 30, 1994. WHOLESALE SALES OF POWER TO NON-AFFILIATES AEGCo, APCo, CSPCo, I&M, KEPCo and OPCo also sell electric power on a wholesale basis to non-affiliated electric utilities and power marketers. Such sales are either made by the AEP System and then allocated among APCo, CSPCo, I&M, KEPCo and OPCo based on member-load-ratios or made by individual companies pursuant to various long-term power agreements. The following table shows the amounts contributed to operating income of the various companies from such sales during the years ended December 31, 1993, 1994 and 1995: 1993(a) 1994(a) 1995(a) (in thousands) AEGCo(b) $ 32,500 $ 30,800 $ 29,200 APCo(c) 23,600 25,000 24,100 CSPCo(c) 12,000 11,700 12,000 I&M(c)(d) 35,300 34,600 34,700 KEPCo(c) 4,900 4,800 5,000 OPCo(c) 20,700 20,000 20,200 Total System $129,000 $126,900 $125,200 (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 1993, 1994 and 1995 were made on a short-term basis, except that $16,800,000, $21,800,000 and $22,500,000, 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 1993, 1994 and 1995 amounts for I&M include $21,600,000, $21,600,000 and $21,000,000 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 100 megawatts of electric power through 1997 and to sell at times up to 200 megawatts of peaking power through March 1997 to unaffiliated utilities. In addition, commencing January 1996, the AEP System began supplying 205 megawatts of electric power to an unaffiliated utility for 15 years and commencing September 1996, the AEP System will begin supplying 50 megawatts of electric power to an unaffiliated utility for five years. 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 1995 was 574, 112, 536, 17 and 138 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. In 1995, customers gave notices of termination, effective in 1998, for 419, 5 and 67 megawatts for APCo, I&M and OPCo, respectively. In June 1993, certain municipal customers of APCo, who have since given APCo notice to terminate their contracts in 1998, filed an application with the FERC for transmission service in order to reduce by 50 megawatts the power these customers purchase under existing Electric Service Agreements (ESAs) and to purchase power from a third party. APCo maintains that its agreements with these customers are full-requirements contracts which preclude the customers from purchasing power from third parties. On February 10, 1994, the FERC issued an order finding that the ESAs are not full requirements contracts and that the ESAs give these municipal wholesale customers the option of substituting alternative sources of power for energy purchased from APCo. On May 24, 1994, APCo appealed the February 10, 1994 order of the FERC to the U.S. Court of Appeals for the District of Columbia Circuit. On July 1, 1994, the FERC ordered the requested transmission service and granted a complaint filed by the municipal customers directing certain modifications to the ESAs in order to accommodate their power purchases from the third party. Following FERC's denial of APCo's requests for rehearing, on December 20, 1995, APCo appealed the July 1, 1994 Orders to the U.S. Court of Appeals for the District of Columbia. Effective August 1994, these municipal customers reduced their purchases by 40 megawatts. Certain of these customers further reduced their purchases by an additional 21 megawatts effective February 1996. TRANSMISSION SERVICES AEP's electric utility subsidiaries own and operate transmission and distribution lines and other facilities to deliver electric power. See Item 2 for more information regarding the transmission and distribution lines. AEP's electric utility subsidiaries operate their transmission lines as a single interconnected and coordinated system and share the cost and benefits in the AEP System Transmission Pool. Most of the transmission and distribution services is sold, in combination with electric power, to retail customers of AEP's utility subsidiaries in their service territories. These sales are made at rates that are established by the public utility commissions of the state in which they operate. See RATES. Some transmission services also are separately sold to non-affiliated companies. AEP SYSTEM TRANSMISSION POOL APCo, CSPCo, I&M, KEPCo and OPCo are parties to the Transmission Agreement, dated April 1, 1984, as amended (the Transmission Agreement), defining how they share the costs associated with their relative ownership of the extra-high- voltage transmission system (facilities rated 345 kv and above) and certain facilities operated at lower voltages (138 kv and above). Like the Interconnection Agreement, this sharing is based upon each company's "member- load-ratio." See SALE OF POWER. The following table shows the net credits or (charges) allocated among the parties to the Transmission Agreement during the years ended December 31, 1993, 1994 and 1995: 1993 1994 1995 (in thousands) APCo $ (3,200) $(10,200) $ (5,400) CSPCo (31,200) (30,100) (31,100) I&M 47,400 50,300 46,700 KEPCo 3,800 4,300 3,500 OPCo (16,800) (14,300) (13,700) 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 amounts contributed to operating income of the various companies from such services during the years ended December 31, 1993, 1994 and 1995: 1993 1994 1995 (in thousands) APCo $ 2,900 $ 4,100 $ 6,000 CSPCo 2,500 3,100 4,200 I&M 7,700 6,700 4,800 KEPCo 600 800 1,200 OPCo 9,900 15,700 17,800 Total System $23,600 $30,400 $34,000 The AEP System has long-term contracts with non-affiliated companies for transmission of approximately 690 megawatts of electric power and contracts with non-affiliated companies for transmission during 1996 of approximately 1,400 megawatts of electric power. On April 12, 1993, APCo, CSPCo, I&M, KEPCo and OPCo and two other AEP System companies filed a transmission tariff with the FERC under which these AEP System companies would provide limited transmission service to certain companies. The tariff covered the terms and conditions of the service, as well as the price which the companies pay for transmission services, regardless of the source of electric power generation. On September 3, 1993, the FERC issued an order accepting the transmission service tariff for filing, with the tariff becoming effective on September 7, 1993, subject to refund. On May 11, 1994, the FERC issued an order on rehearing and indicated that an open access tariff should offer third parties access to the transmission system on the same or comparable basis, and under the same or comparable terms and conditions, as the transmission provider's access to its system. On March 29, 1995, the FERC issued a Notice of Proposed Rulemaking ("Mega- NOPR"). The Mega-NOPR proposes to require each public utility that owns or controls interstate transmission facilities to file open access network and point-to-point transmission tariffs that offer services comparable to the utility's own uses of its transmission system. The Mega-NOPR also proposes to 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 proposed rule, the FERC issued recommended PRO-FORMA tariffs which reflect the Commission's preliminary views on the minimum non-price terms and conditions for non-discriminatory transmission service. In connection with the Mega-NOPR, the Commission offered certain waivers of its regulations to utilities willing to adopt the PRO-FORMA tariffs prior to issuance of the final rule. The Mega-NOPR also would allow a utility to seek recovery of certain prudently-incurred stranded costs that result from unbundled transmission service. On July 18, 1995, the AEP System companies filed an Offer of Settlement in their transmission tariff case, in which the companies proposed to adopt the FERC's PRO-FORMA transmission tariffs at certain stated rates that were lower than those requested in their initial tariff filing. The Offer of Settlement was approved by the FERC on February 14, 1996, except for certain pricing issues, which are still pending resolution by FERC. AEP has proposed creation of an independent system operator to operate the transmission system in a region of the United States. See COMPETITION AND BUSINESS CHANGE - AEP POSITION ON COMPETITION. OVEC AEP, CSPCo and several unaffiliated utility companies jointly own OVEC, which supplies the power requirements of a uranium enrichment plant near Portsmouth, Ohio owned by the DOE. The aggregate equity participation of AEP and CSPCo in OVEC is 44.2%. The DOE demand under OVEC's power agreement, which is subject to change from time to time, is 1,305,000 kilowatts. On October 1, 1996, it is scheduled to increase to approximately 1,905,000 kilowatts and to remain at about that level through the remaining term of the contract. The proceeds from the sale of power by OVEC, aggregating $299,000,000 in 1995, 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 1995. The power agreement with DOE terminates on December 31, 2005, subject to early termination by DOE on not less than three years notice. The power agreement among OVEC and the sponsoring companies expires by its terms on March 12, 2006. BUCKEYE Contractual arrangements among OPCo, Buckeye and other investor-owned electric utility companies in Ohio provide for the transmission and delivery, over facilities of OPCo and of other investor-owned utility companies, of power generated by the two units at the Cardinal Station owned by Buckeye and back-up power to which Buckeye is entitled from OPCo under such contractual arrangements, to facilities owned by 27 of the rural electric cooperatives which operate in the State of Ohio at 301 delivery points. Buckeye is entitled under such arrangements to receive, and is obligated to pay for, the excess of its maximum one-hour coincident peak demand plus a 15% reserve margin over the 1,226,500 kilowatts of capacity of the generating units which Buckeye currently owns in the Cardinal Station. Such demand, which occurred on January 18, 1994, was recorded at 1,146,933 kilowatts. CERTAIN INDUSTRIAL CUSTOMERS Ravenswood Aluminum Corporation and Ormet Corporation operate major aluminum reduction plants in the Ohio River Valley at Ravenswood, West Virginia, and in the vicinity of Hannibal, Ohio, respectively. OPCo supplies all of the power requirements of these plants pursuant to long-term contracts with such companies which, subject to certain curtailment provisions, terminate in 1997 in the case of Ormet and 1998 in the case of Ravenswood. The power requirements of such plants presently aggregate approximately 890,000 kilowatts. OPCo is currently negotiating with Ormet and Ravenswood regarding the extension of their contracts. See LEGAL PROCEEDINGS for a discussion of litigation involving Ormet. AEGCO Since its formation in 1982, AEGCo's business has consisted of the ownership and financing of its 50% interest in the Rockport Plant and, since 1989, leasing of its 50% interest in Unit 2 of the Rockport Plant. The operating revenues of AEGCo are derived from the sale of capacity and energy associated with its interest in the Rockport Plant to I&M, KEPCo and VEPCo, pursuant to unit power agreements. Pursuant to these unit power agreements, AEGCo is entitled to recover its full cost of service from the purchasers and will be entitled to recover future increases in such costs, including increases in fuel and capital costs. See UNIT POWER AGREEMENTS. Pursuant to a capital funds agreement, AEP has agreed to provide cash capital contributions, or in certain circumstances subordinated loans, to AEGCo, to the extent necessary to enable AEGCo, among other things, to provide its proportionate share of funds required to permit continuation of the commercial operation of the Rockport Plant and to perform all of its obligations, covenants and agreements under, among other things, all loan agreements, leases and related documents to which AEGCo is or becomes a party. See CAPITAL FUNDS AGREEMENT. UNIT POWER AGREEMENTS A unit power agreement between AEGCo and I&M (the I&M Power Agreement) provides for the sale by AEGCo to I&M of all the power (and the energy associated therewith) available to AEGCo at the Rockport Plant. I&M is obligated, whether or not power is available from AEGCo, to pay as a demand charge for the right to receive such power (and as an energy charge for any associated energy taken by I&M) such amounts, as when added to amounts received by AEGCo from any other sources, will be at least sufficient to enable AEGCo to pay all its operating and other expenses, including a rate of return on the common equity of AEGCo as approved by FERC, currently 12.16%. The I&M Power Agreement will continue in effect until the date that the last of the lease terms of Unit 2 of the Rockport Plant has expired unless extended in specified circumstances. Pursuant to an assignment between I&M and KEPCo, and a unit power agreement between KEPCo and AEGCo, AEGCo sells KEPCo 30% of the power (and the energy associated therewith) available to AEGCo from both units of the Rockport Plant. KEPCo has agreed to pay to AEGCo in consideration for the right to receive such power the same amounts which I&M would have paid AEGCo under the terms of the I&M Power Agreement for such entitlement. The KEPCo unit power agreement expires on December 31, 1999, unless extended. A unit power agreement among AEGCo, I&M, VEPCo, and APCo provides for, among other things, the sale of 70% of the power and energy available to AEGCo from Unit 1 of the Rockport Plant to VEPCo by AEGCo from January 1, 1987 through December 31, 1999. VEPCo has agreed to pay to AEGCo in consideration for the right to receive such power those amounts which I&M would have paid AEGCo under the terms of the I&M Power Agreement for such entitlement. Approximately 34% of AEGCo's operating revenue in 1995 was derived from its sales to VEPCo. CAPITAL FUNDS AGREEMENT AEGCo and AEP have entered into a capital funds agreement pursuant to which, among other things, AEP has unconditionally agreed to make cash capital contributions, or in certain circumstances subordinated loans, to AEGCo to the extent necessary to enable AEGCo to (i) maintain such an equity component of capitalization as required by governmental regulatory authorities, (ii) provide its proportionate share of the funds required to permit commercial operation of the Rockport Plant, (iii) enable AEGCo to perform all of its obligations, covenants and agreements under, among other things, all loan agreements, leases and related documents to which AEGCo is or becomes a party (AEGCo Agreements), and (iv) pay all indebtedness, obligations and liabilities of AEGCo (AEGCo Obligations) under the AEGCo Agreements, other than indebtedness, obligations or liabilities owing to AEP. The Capital Funds Agreement will terminate after all AEGCo Obligations have been paid in full. INDUSTRY PROBLEMS The electric utility industry, including the operating subsidiaries of AEP, has encountered at various times in the last 15 years significant problems in a number of areas, including: delays in and limitations on the recovery of fuel costs from customers; proposed legislation, initiative measures and other actions designed to prohibit construction and operation of certain types of power plants under certain conditions and to eliminate or reduce the extent of the coverage of fuel adjustment clauses; inadequate rate increases and delays in obtaining rate increases; jurisdictional disputes with state public utilities commissions regarding the interstate operations of integrated electric systems; requirements for additional expenditures for pollution control facilities; increased capital and operating costs; construction delays due, among other factors, to pollution control and environmental considerations and to material, equipment and fuel shortages; the economic effects on net income (which when combined with other factors may be immediate and adverse) associated with placing large generating units and related facilities in commercial operation, including the commencement at that time of substantial charges for depreciation, taxes, maintenance and other operating expenses, and the cessation of AFUDC with respect to such units; uncertainties as to conservation efforts by customers and the effects of such efforts on load growth; depressed economic conditions in certain regions of the United States; increasingly competitive conditions in the wholesale and retail markets; proposals to deregulate certain portions of the industry and revise the rules and responsibilities under which new generating capacity is supplied; and substantial increases in construction costs and difficulties in financing due to high costs of capital, uncertain capital markets, charter and indenture limitations restricting conventional financing, and shortages of cash for construction and other purposes. SEASONALITY Sales of electricity by the AEP System tend to increase and decrease because of the use of electricity by residential and commercial customers for cooling and heating and relative changes in temperature. FRANCHISES The operating companies of the AEP System hold franchises to provide electric service in various municipalities in their service areas. These franchises have varying provisions and expiration dates. In general, the operating companies consider their franchises to be adequate for the conduct of their business. COMPETITION AND BUSINESS CHANGE GENERAL The public utility subsidiaries of AEP, like other electric utilities, have traditionally provided electric generation and energy delivery, consisting of transmission and distribution services, as a single product to their retail customers. FERC has proposed that utilities be required, and the public utility subsidiaries of AEP have agreed, to sell transmission services separately from their other services. Proposals are being made that would also require electric utilities to sell distribution services separately. These proposals generally allow competition in the generation and sale of electric power, but not in its transmission and distribution. Competition in the generation and sale of electric power will require resolution of complex issues, including who will pay for the unused generating plant of, and other stranded costs incurred by, the utility when a customer stops buying power from the utility; will all customers have access to the benefits of competition; how will the rules of competition be established; what will happen to conservation and other regulatory-imposed programs; how will the reliability of the transmission system be ensured; and how will the utility's obligation to serve be changed. As a result, it is not clear how or when competition in generation and sale of electric power will be instituted. However, if competition in generation and sale of electric power is instituted, the public utility subsidiaries of AEP believe that they have a favorable competitive position because of their relatively low costs. If stranded costs are not recovered from customers, however, the public utility subsidiaries of AEP, like all electric utilities, will be required by existing accounting standards to recognize stranded investment losses. WHOLESALE The public utility subsidiaries of AEP, like the electric industry generally, face increasing competition to sell available power on a wholesale basis, primarily to other public utilities and also to power marketers. The Energy Policy Act of 1992 was designed, among other things, to foster competition in the wholesale market (a) through amendments to PUHCA, facilitating the ownership and operation of generating facilities by "exempt wholesale generators" (which may include independent power producers as well as affiliates of electric utilities) and (b) through amendments to the Federal Power Act, authorizing the FERC under certain conditions to order utilities which own transmission facilities to provide wholesale transmission services for other utilities and entities generating electric power. The principal factors in competing for such sales are price (including fuel costs), availability of capacity and reliability of service. The public utility subsidiaries of AEP believe that they maintain a favorable competitive position on the basis of all of these factors. However, because of the availability of capacity of other utilities and the lower fuel prices in recent years, price competition has been, and is expected for the next few years to be, particularly important. The Mega-NOPR proposes that utilities be required to 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 Mega- NOPR also would allow a utility to seek recovery of certain prudently-incurred stranded costs that result from unbundled transmission service. The public utility subsidiaries of AEP are preparing to functionally separate their wholesale power sales from their transmission functions, as proposed in the Mega-NOPR and required by their transmission tariffs. RETAIL The public utility subsidiaries of AEP generally have the exclusive right to sell electric power at retail within their service areas. However, they do compete with self-generation and with distributors of other energy sources, such as natural gas, fuel oil and coal, within their service areas. The primary factors in such competition are price, reliability of service and the capability of customers to utilize sources of energy other than electric power. With respect to self-generation, the public utility subsidiaries of AEP believe that they maintain a favorable competitive position on the basis of all of these factors. With respect to alternative sources of energy, the public utility subsidiaries of AEP believe that the reliability of their service and the limited ability of customers to substitute other cost-effective sources for electric power place them in a favorable competitive position, even though their prices may be higher than the costs of some other sources of energy. Significant changes in the global economy in recent years have led to increased price competition for industrial companies in the United States, including those served by the AEP System. Such industrial companies have requested price reductions from their suppliers, including their suppliers of electric power. In addition, industrial companies which are downsizing or reorganizing often close a facility based upon its costs, which may include, among other things, the cost of electric power. The public utility subsidiaries of AEP cooperate with such customers to meet their business needs through, for example, various off-peak or interruptible supply options and believe that, as low cost suppliers of electric power, they should be less likely to be materially adversely affected by this competition and may be benefitted by attracting new industrial customers to their service territories. The legislatures and/or the regulatory commissions in several states are considering "retail customer choice" which, in general terms, means the transmission by an electric utility of electric power generated by an entity of the customer's choice over its transmission and distribution system to a retail customer in such utility's service territory. A requirement to transmit directly to retail customers would have the result of permitting retail customers to purchase electric power, at the election of such customers, not only from the electric utility in whose service area they are located but from another electric utility, an independent power producer or an intermediary, such as a power marketer. Although AEP's power generation would have competitors under some of these proposals, its transmission and distribution would not. If competition develops in retail power generation, the public utility subsidiaries of AEP believe that they have a favorable competitive position because of their relatively low costs. MICHIGAN: On June 19, 1995, the MPSC approved an experimental five-year retail wheeling program and ordered Consumers Power Company and Detroit Edison Company, unaffiliated utilities, to make retail delivery services available to a group of industrial customers, in the amount of 60 megawatts and 90 megawatts, respectively. The experiment will commence when each utility needs new capacity. The experiment seeks, as its goal, to determine whether a retail wheeling program best serves the public interest in a manner that promotes retail competition in a non-discriminatory fashion. During the experiment, the MPSC will collect information regarding the effects of retail wheeling. In January 1996, the Governor of Michigan endorsed a proposal of the Michigan Jobs Commission to promote competition and customer choice in energy. Under the proposal, by January 1997, industrial and commercial customers would be permitted to choose suppliers for new electrical load and tariffs would be unbundled. By January 1998, an independent wholesale power pool with an independent operator would be formed. By 2001, power generation for industrial and commercial would not be subject to rate regulation and franchise territories would be eliminated. OHIO: On April 15, 1994, the Ohio Energy Strategy Task Force released its final report. The report contained seven broad implementation strategies along with 53 specific initiatives to be undertaken by government and the private sector. One strategy recommended continuing to encourage competition in the electric utility industry in a manner which maximizes benefits and efficiencies for all customers. An initiative under this strategy recommends facilitating informal roundtable discussions on issues concerning competition in the electric utility industry and promoting increased competitive options for Ohio businesses that do not unduly harm the interests of utility company shareholders or ratepayers. The PUCO has begun such discussions. As a result, on February 15, 1996, the PUCO adopted guidelines for interruptible electric service, including a buy-through provision that will enable customers to avoid being interrupted during utility capacity deficiencies by having the utility purchase off-system replacement power for the customer. In March 1996, H.B. 653 was introduced in the Ohio House of Representatives. The bill proposes that all customers be permitted to select their electricity suppliers effective January 1, 1998. The bill eliminates price regulation of electricity generation functions in favor of market based prices. Service area rights for Ohio's electricity suppliers would be confined to distribution service. Transmission and distribution services would continue to be regulated at the federal and state levels, respectively. The bill would require Ohio's electric utilities to functionally unbundle their generation, transmission and distribution services. Electric utilities would be permitted to recover transition costs provided that such recovery does not cause prices to exceed those in effect on the effective date of the legislation. VIRGINIA: In September 1995, the Virginia SCC instituted a proceeding to review and consider policy regarding restructuring and the role of competition in the electric utility industry in Virginia. The Virginia SCC has directed its staff to conduct an investigation of current issues in the electric utility industry and to file a report of its observation and recommendations on issues identified in the Virginia SCC order. In addition, the Virginia legislature has adopted a resolution establishing a subcommittee to study, in consultation with the Virginia SCC, restructuring and potential changes in the electric utility industry in Virginia and determine the need for legislative changes. AEP POSITION ON COMPETITION In October 1995, AEP announced that it favored freedom for customers to purchase electric power from anyone that they choose. Generation and sale of electric power would be in the competitive marketplace. To facilitate reliable, safe and efficient service, AEP supports creation of independent system operators to operate the transmission system in a region of the United States. In addition, AEP supports the evolution of regional power exchanges which would establish a competitve 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. Implementation of this proposal would require legislative changes and regulatory approvals. POSSIBLE STRATEGIC RESPONSES In response to the competitive forces and regulatory changes being faced by AEP and its public utility subsidiaries, as discussed under this heading and under REGULATION, AEP and its public utility subsidiaries have from time to time considered, and expect to continue to consider, various strategies designed to enhance their competitive position and to increase their ability to adapt to and anticipate changes in their utility business. These strategies may include business combinations with other companies, internal restructurings involving the complete or partial separation of their generation, transmission and distribution businesses, acquisitions of related or unrelated businesses, and additions to or dispositions of portions of their franchised service territories. AEP and its public utility subsidiaries may from time to time be engaged in preliminary discussions, either internally or with third parties, regarding one or more of these potential strategies. No assurances can be given as to whether any potential transaction of the type described above may actually occur, or as to its ultimate effect on the financial condition or competitive position of AEP and its public utility subsidiaries. NEW BUSINESS DEVELOPMENT AEP continues to consider new business opportunities, particularly those which allow use of its expertise. These endeavors began in 1982 and are conducted through AEP Energy Services, Inc. (AEPES) and AEP Resources, Inc. (Resources). Resources' primary business is development of, and investment in, exempt wholesale generators, foreign utility companies, qualifying cogeneration facilities and other power projects. Resources currently does not have an interest in any power projects. Resources, however, has entered into a strategic alliance with Cogentrix Energy, Inc. and Zurn Industries, Inc. to develop, own and operate industrial power projects in the United States and Canada. In addition, Resources is investigating opportunities to develop and invest in new, and invest in existing, generation projects in China, Australia, Mexico and India. In 1994, AEP Resources International, Limited (AEPRI), a wholly owned subsidiary of Resources, signed an agreement of intent with Northeast China Electric Power Group Corp. (NEPG) to design two 1,300-megawatt, coal-fired electric generating units in Suizhong, Liaoning Province, China. The feasibility study for this project has been approved by the Chinese Ministry of Electric Power and is awaiting approval by the State Planning Commission. AEPRI is also involved in the advanced stages of negotiations to establish a joint venture with two Chinese partners to develop and own two 125-megawatt, coal-fired units in Henan Province, China. AEPES offers engineering, construction, project management and other consulting services for projects involving transmission, distribution or generation of electric power both domestically and internationally. AEP has received approval from the SEC under PUHCA to finance up to $300,000,000, and has requested approval to finance up to 50% of its consolidated retained earnings (approximately $700,000,000), for investment in exempt wholesale generators and foreign utility companies. AEP also has requested authority from the SEC under PUHCA to invest up to $100,000,000 in subsidiaries engaged in the business of marketing energy commodities, including electricity and gas. These continuing efforts to invest in and develop new business opportunities offer the potential of earning returns which may exceed those of rate-regulated operations. However, they also involve a higher degree of risk which must be carefully considered and assessed. AEP may make substantial investments in these and other new businesses. CONSTRUCTION PROGRAM NEW GENERATION The AEP System companies are engaged in a continuing construction program, involving assessment of needs, selection of sites, design and acquisition of equipment, and installation of the generating, transmission, distribution and other facilities necessary to provide for generation, transmission and distribution of electric power. At the present time, there are no specific commitments for additions of new generating stations on the AEP System. Size, technology, type, ownership (among AEP operating companies), means of acquisition and precise timing of future capacity additions on the AEP System have not yet been determined. However, the resource plan filed by AEP's electric utility subsidiaries with various state commissions indicates no need for new generation until sometime after the year 2000. Initial future capacity additions will most likely be short lead time, simple-cycle, gas-fired combustion turbines. The current resource plan indicates no need for new coal- fired baseload generation until sometime after the year 2010. The size of any new coal-fired generation will most likely be significantly smaller than the 1,300-megawatt units last added to the AEP System, to better match projected load growth. Proposals have been made, some of which have been adopted, that require the public utility subsidiaries of AEP to file with state commissions resource plans, indicating their plans to satisfy expected demand for electric power in their service territory. When the AEP System needs new generation, some of these proposals also require the public utility subsidiaries of AEP which wish to provide the new generation to compete with exempt wholesale generators, independent power producers and other utilities. Although the specific guidelines for such competition have not yet been developed and may vary from jurisdiction to jurisdiction (see the discussion below), significant factors will include price and reliability. For some years, the AEP System has put in place a series of customer programs for encouraging electric conservation and load management (CLM). The CLM programs also are referred to in the electric utility industry as "demand- side management" programs (DSM) since they affect the demand for electric power as opposed to its supply. The AEP System utilizes integrated resource planning and has in place a detailed analysis procedure in which effective demand-side and supply-side options are both considered in order to determine the least cost approach to provide reliable electric service for its customers, taking into account environmental and other considerations. INDIANA: In May 1995, the IURC adopted rules for integrated resource planning guidelines, including consideration of resource bidding and independent power producers, and for demand-side management. I&M filed its first integrated resource plan in November 1995. MICHIGAN: The MPSC has adopted guidelines governing the acquisition of new capacity by large Michigan electric utilities. The guidelines do not apply to I&M. OHIO: On December 17, 1992, the PUCO issued an order proposing rules for competitive bidding for new generating capacity, including transmission access for winning bidders. The proposed rules would establish a rebuttable presumption of prudence where new generating capacity is acquired through competitive bidding and provide other incentives to use competitive bidding. The proposed rules also contain procedures to ensure that bidders for a utility's new capacity will have open access to certain transmission facilities and prohibit the utility acquiring new capacity from withholding SO{2} Allowances from potential bidders. CSPCo and OPCo filed comments on the proposed rules generally supporting promulgation of rules governing competitive bidding but stating that the rules should not address access to transmission facilities or SO{2} Allowances, because existing federal laws address such concerns. VIRGINIA: On October 24, 1994, the Virginia SCC began a proceeding to consider whether to adopt standards related to integrated resource planning, conservation, demand-side management and energy efficiency in power generation and supply for jurisdictional electric utilities. On September 27, 1995, the Virginia SCC declined to adopt the proposed standards, but reaffirmed its goals for integrated resource planning, investment in cost-effective conservation and demand management programs. Virginia electric utilities are to continue to file biennial twenty-year resource plans. The Virginia SCC also has adopted minimum requirements for any electric utility that elects to acquire new generation through a bidding program. An electric utility is not required to use the bidding process and may participate in the bidding process. WEST VIRGINIA: On October 8, 1993, the West Virginia PSC issued an order proposing rules that generally require electric utilities to procure competitively all new sources of generation. APCo and Wheeling Power Company filed comments stating that the rules should not require competitive bidding and should permit the utility to participate in the bidding process. PROPOSED TRANSMISSION FACILITIES APCO: On March 23, 1990, APCo and VEPCo announced plans, subject to regulatory approval, for major new transmission facilities. APCo will construct approximately 115 miles of 765,000-volt line from APCo's Wyoming station in southern West Virginia to APCo's Cloverdale station near Roanoke, Virginia. VEPCo will construct approximately 102 miles of 500,000-volt line from APCo's Joshua Falls station east of Lynchburg, Virginia to VEPCo's Ladysmith station north of Richmond, Virginia. The construction of the transmission lines and related station improvements will provide needed reinforcement for APCo's internal load, reinforce the ability to exchange electric power between the two companies and relieve present constraints on the transmission of electric power from potential independent power producers in the APCo service area to VEPCo. APCo's cost is estimated at $245,000,000 while VEPCo's cost is estimated at $164,000,000. Completion of the project is presently scheduled for 2000 but the actual service date will be dependent upon the time necessary to meet various regulatory requirements. Hearings before the Virginia SCC were concluded in September 1993. A report was issued by the hearing examiner in December 1993 which recommended that the Virginia SCC grant APCo approval to construct the proposed 765,000-volt line. In an interim order issued on December 13, 1995, the Virginia SCC found that major additional transmission capacity was needed to serve APCo's native load customers. The Virginia SCC further asked that APCo provide additional information on possible routing modifications and utilization of the additional transmission capacity prior to a final ruling. APCo refiled with the West Virginia PSC in February 1993 its application for certification. An application filed in June 1992 was withdrawn at the request of the West Virginia PSC to permit additional time for review by the West Virginia PSC. The West Virginia PSC rejected APCo's application for certification in May 1993, directing APCo to supplement its line siting information. APCo intends to refile its application with the West Virginia PSC. Hearings are expected to be held in late 1996 or early 1997, with a decision expected in late 1997 or early 1998. The Jefferson National Forest (JNF) is directing the preparation of an Environmental Impact Statement (EIS) which will be required prior to the granting of special use permits for crossing Federal lands. The present schedule of the JNF calls for completion of the draft EIS in June 1996 and the final EIS in early 1998. APCO AND KEPCO: APCo and KEPCo have announced an improvement plan to be implemented during a four-year period (1996-1999) to reinforce their 138,000- volt transmission system. Included in this plan is a new transmission line to link KEPCo's Big Sandy Plant to communities in eastern Kentucky. APCo's and KEPCo's estimated project costs are $5,115,000 and $84,184,000, respectively. Work on the project is scheduled to begin later in 1996, pending approval from the KPSC. 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 1993, 1994 and 1995 and their current estimate of 1996 construction expenditures, in each case including AFUDC but excluding nuclear fuel and other assets acquired under leases. The construction expenditures for the years 1993-1995 were applied, and it is anticipated that the estimated construction expenditures for 1996 will be applied, approximately as follows to construction of the following classes of assets:
1993 1994 1995 1996 ACTUAL ACTUAL ACTUAL ESTIMATE (in thousands) AEGCO Generating plant and facilities $ 3,100 $ 3,900 $ 4,000 $ 1,900 TOTAL $ 3,100 $ 3,900 $ 4,000 $ 1,900 APCO Generating plant and facilities $ 51,200 $ 65,600 $ 42,400 $ 55,700 Transmission lines and facilities 36,700 38,700 35,200 31,300 Distribution lines and facilities 98,200 116,500 121,400 102,900 General plant and other facilities 4,800 9,500 18,600 13,900 TOTAL $190,900 $230,300 $217,600 $203,800 CSPCO Generating plant and facilities $ 33,300 $ 24,800 $ 30,500 $ 20,400 Transmission lines and facilities 10,100 3,600 10,700 10,800 Distribution lines and facilities 40,700 50,800 56,600 50,800 General plant and other facilities 2,200 2,300 1,700 12,500 TOTAL $ 86,300 $ 81,500 $ 99,500 $ 94,500
1993 1994 1995 1996 ACTUAL ACTUAL ACTUAL ESTIMATE (in thousands) I&M Generating plant and facilities $ 50,200 $ 49,700 $ 46,200 $ 33,600 Transmission lines and facilities 10,100 20,300 22,600 17,600 Distribution lines and facilities 41,300 42,300 41,500 40,900 General plant and other facilities 6,700 2,200 2,700 18,500 TOTAL $108,300 $114,500 $113,000 $110,600 KEPCO Generating plant and facilities $ 8,100 $ 22,600 $ 6,200 $ 25,400 Transmission lines and facilities 6,700 6,400 7,900 33,000 Distribution lines and facilities 20,300 23,700 23,900 23,200 General plant and other facilities 0 500 1,300 3,400 TOTAL $ 35,100 $ 53,200 $ 39,300 $ 85,000 OPCO Generating plant and facilities (a) $112,700 $ 83,800 $ 40,000 $ 36,200 Transmission lines and facilities 28,600 15,300 23,500 22,000 Distribution lines and facilities 46,000 45,200 51,400 52,200 General plant and other facilities 10,500 4,700 2,000 12,700 TOTAL $197,800 $149,000 $116,900 $123,100 AEP SYSTEM (b) Generating plant and facilities (a) $258,600 $250,400 $169,300 $173,200 Transmission lines and facilities 92,800 85,400 102,500 115,400 Distribution lines and facilities 252,300 286,900 302,800 277,000 General plant and other facilities 24,400 19,400 26,600 61,400 TOTAL $628,100 $642,100 $601,200 $627,000
(a) Excludes expenditures associated with flue-gas desulfurization system which was constructed by a non-affiliate at the Gavin Plant and is being leased by OPCo. Actual expenditures for such system for 1993, 1994 and 1995 and the current estimate for 1996 are $256,673,000, $176,220,000, $48,804,000 and $12,915,000, respectively. See ENVIRONMENTAL AND OTHER MATTERS - ACID RAIN PROGRAM - AEP SYSTEM COMPLIANCE PLAN. (b) Includes expenditures of other subsidiaries not shown. Reference is made to the footnotes to the financial statements entitled COMMITMENTS AND CONTINGENCIES incorporated by reference in Item 8, for further information with respect to the construction plans of AEP and its operating subsidiaries for the next three years. The System construction program is reviewed continuously and is revised from time to time in response to changes in estimates of customer demand, business and economic conditions, the cost and availability of capital, environmental requirements and other factors. Changes in construction schedules and costs, and in estimates and projections of needs for additional facilities, as well as variations from currently anticipated levels of net earnings, Federal income and other taxes, and other factors affecting cash requirements, may increase or decrease the estimates of 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 1993, 1994 and 1995 and the current estimate for 1996 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. 1993 1994 1995 1996 ACTUAL ACTUAL ACTUAL ESTIMATE (in thousands) AEGCo $ 0 $ 0 $ 0 $ 0 APCo 16,800 32,000 7,800 8,500 CSPCo 15,800 13,700 10,000 1,300 I&M 0 0 0 400 KEPCo 1,000 9,500 600 600 OPCo (a) 31,600 22,400 3,100 0 AEP System (a) $65,200 $77,600 $21,500 $10,800 (a)Excludes expenditures associated with flue-gas desulfurization system which was constructed by a non-affiliate at the Gavin Plant and is being leased by OPCo. Actual expenditures for such system for 1993, 1994 and 1995 and the current estimate for 1996 are $256,673,000, $176,220,000, $48,804,000 and $12,915,000, respectively. See ENVIRONMENTAL AND OTHER MATTERS - ACID RAIN PROGRAM - AEP SYSTEM COMPLIANCE PLAN. FINANCING It has been the practice of AEP's operating subsidiaries to finance current construction expenditures in excess of available internally generated funds by initially issuing unsecured short-term debt, principally commercial paper and bank loans, at times up to levels authorized by regulatory agencies, and then to reduce the short-term debt with the proceeds of subsequent sales by such subsidiaries of long-term debt securities and preferred stock, and cash capital contributions by AEP. It has been the practice of AEP, in turn, to finance cash capital contributions to the common stock equities of the operating 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 1995, AEP issued 1,400,000 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 apital requirements. During the period 1993-1995, external funds from financings and capital contributions by AEP amounted, with respect to APCo and KEPCo to approximately 31% and 53%, respectively, of the aggregate construction expenditures shown above. During this same period, the amount of funds used to retire long-term and short-term debt and preferred stock of AEGCo, CSPCo, I&M and OPCo exceeded the amount of funds from financings and capital contributions by AEP. The ability of AEP and its operating 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 their charters and 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, 1996, and the respective amounts of short-term debt outstanding on that date, on a corporate basis, are shown in the following tabulation:
TOTAL AEP SHORT-TERM DEBT AEP AEGCO APCO CSPCO I&M KEPCO OPCO SYSTEM(a) (in millions) Amount authorized $150 $80 $228 $175 $175 $150 $223 $1,256 Amount outstanding: Notes payable $ 18 $22 $ -- $ 13 $ 52 $ 16 $ -- $ 128 Commercial paper 32 -- 126 21 38 11 9 237 $ 50 $22 $126 $ 34 $ 90 $ 27 $ 9 $ 365
(a) Includes short-term debt of other subsidiaries not shown. Reference is made to the footnotes to the financial statements incorporated by reference in Item 8 for further information with respect to unused short- term bank lines of credit. In order to issue additional first mortgage bonds and preferred stock, it is necessary for APCo, CSPCo, I&M, KEPCo and OPCo to comply with earnings coverage requirements contained in their respective mortgages and charters. The most restrictive of these provisions in each instance generally requires (1) for the issuance of first mortgage bonds for purposes other than the refunding of outstanding first mortgage bonds, a minimum, before income tax, earnings coverage of twice the pro forma annual interest charges on first mortgage bonds and (2) for the issuance of additional preferred stock by APCo, I&M and OPCo, a minimum, after income tax, gross income coverage of one and one-half times pro forma annual interest charges and preferred stock dividends, in each case for a period of twelve consecutive calendar months within the fifteen calendar months immediately preceding the proposed new issue. In computing such coverages, the companies include as a component of earnings revenues collected subject to refund (where applicable) and, to the extent not limited by the instrument under which the computation is made, AFUDC, including amounts positioned and classified as an allowance for borrowed funds used during construction. These coverage provisions have from time to time restricted the ability of one or more of the above subsidiaries of AEP to issue senior securities. The respective mortgage and preferred stock coverages of APCo, CSPCo, I&M, KEPCo and OPCo under their respective mortgage and charter provisions, calculated on the foregoing basis and in accordance with the respective amounts then recorded in the accounts of the companies, assuming the respective short- term debt of the companies at those dates were to remain outstanding for a twelve-month period at the respective rates of interest prevailing at those dates, were at least those stated in the following table: DECEMBER 31, 1993 1994 1995 APCo Mortgage coverage 3.64 3.12 3.47 Preferred stock coverage 2.04 1.65 1.78 CSPCo Mortgage coverage 2.91 3.64 3.90 I&M Mortgage coverage 5.49 6.23 6.25 Preferred stock coverage 2.48 2.74 2.63 KEPCo Mortgage coverage 2.19 2.60 2.86 OPCo Mortgage coverage 5.24 5.04 6.17 Preferred stock coverage 2.88 2.58 3.04 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 its operating subsidiaries to issue short- and long-term debt securities and preferred stock in the amounts required to finance their business may depend upon the timely approval of rate increase applications. If one or more of the operating subsidiaries are unable to continue the issuance and sale of securities on an orderly basis, such company or companies will be required to consider the use of alternative financing arrangements, if available, which may be more costly or the curtailment of construction and other outlays. AEP's subsidiaries have also utilized, and expect to continue to utilize, additional financing arrangements, such as leasing arrangements, including the leasing of utility assets, coal mining and transportation equipment and facilities and nuclear fuel. Pollution control revenue bonds have been used in the past and may be used in the future in connection with the construction of pollution control facilities; however, Federal tax law has limited the utilization of this type of financing except for purposes of certain financing of solid waste disposal facilities and of certain refunding of outstanding pollution control revenue bonds issued before August 16, 1986. Shares of AEP Common Stock may be sold by AEP from time to time at prices below the then current book value per share and repurchased by AEP at prices above book value. Such sales or purchases, if any, would have a dilutive effect on the book value of then outstanding shares but are not expected to have a material adverse effect on AEP's business including its future financing plans or capabilities and pending construction projects. RATES GENERAL The rates charged by the electric utility subsidiaries of AEP are approved by the FERC or one of the state utility commissions as applicable. The FERC regulates wholesale rates and the state commissions regulate retail rates. In recent years the number of rate increase applications filed by the operating subsidiaries of AEP with their respective state commissions and the FERC has decreased. 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. In April 1995, Indiana enacted into law legislation providing that 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. In March 1996, Virginia enacted into law legislation which provides that the Virginia SCC may approve (i) special rates, contracts or incentives to individual customers or classes of customers and (ii) alternative forms of regulation including, but not limited to, the use of price regulation, ranges of authorized returns, categories of services and price indexing. All of the seven states served by the AEP System, as well as the FERC, either permit the incorporation of fuel adjustment clauses in a utility company's rates and tariffs, which are designed to permit upward or downward adjustments in revenues to reflect increases or decreases in fuel costs above or below the designated base cost of fuel set forth in the particular rate or tariff, or permit the inclusion of specified levels of fuel costs as part of such rate or tariff. AEP cannot predict the timing or probability of approvals regarding applications for additional rate changes, the outcome of action by regulatory commissions or courts with respect to such matters, or the effect thereof on the earnings and business of the AEP System. APCO FERC: On February 14, 1992, APCo filed with the FERC applications for an increase in its wholesale rates to Kingsport Power Company and non-affiliated customers in the amounts of approximately $3,933,000 and $4,759,000, respectively. APCo began collecting the rate increases, subject to refund, on September 15, 1992. In addition, the Financial Accounting Standards Board has issued Statement of Financial Accounting Standards No. 106, EMPLOYERS' ACCOUNTING FOR POSTRETIREMENT BENEFITS OTHER THAN PENSIONS (SFAS 106), which requires employers, beginning in 1993, to accrue for the costs of retiree benefits other than pensions. These rates include the higher level of SFAS 106 costs. On November 9, 1993, the administrative law judge issued an initial decision recommending, among other things, the higher level of postretirement benefits other than pensions under SFAS 106. FERC action on APCo's applications is pending. VIRGINIA: On June 27, 1994, the Virginia SCC issued a final order granting APCo an increase in annual revenues of $17,900,000. APCo had requested to increase its Virginia retail rates by $31,400,000 annually and, on May 4, 1993, implemented the rates, subject to refund, based on an interim order. As a result of the final order, APCo made a revenue refund including interest to its Virginia customers in August 1994 of $15,800,000. As a result of certain significant fuel cost reductions, on November 15, 1994, APCo implemented a net decrease in rates charged to its Virginia retail customers of $13,200,000, subject to final approval by the Virginia SCC. The net decrease consisted of a $28,900,000 decrease in the fuel component of its rates offset, in part, by an increase of $15,700,000 in base rates. On December 19, 1994, the Virginia SCC issued an order approving the decrease in the fuel factor component of rates. APCo proposes in the base rate proceeding to amortize Virginia deferred storm damage expenses of $23,900,000 related to two major ice storms in February and March 1994 over a three-year period, consistent with the amortization of previous storm damage expense deferrals approved in a 1992 rate case. The ultimate recovery of the entire deferred storm damage costs is subject to Virginia SCC approval. If not approved, results of operations could be adversely affected. The Virginia SCC Staff has recommended that approximately $12,000,000 of the $23,900,000 in storm damage expenses be treated as if they have previously been recovered in earnings (based on the results of the Staff's earnings test) and the remainder be deferred for future recovery over a five-year period. A hearing examiner's report is pending. CSPCO ZIMMER PLANT: The Zimmer Plant was placed in commercial operation as a 1,300-megawatt coal-fired plant on March 30, 1991. CSPCo owns 25.4% of the Zimmer Plant with the remainder owned by two unaffiliated companies, CG&E (46.5%) and DP&L (28.1%). ZIMMER PLANT - RATE RECOVERY: In May 1992, the PUCO issued an order providing for a phased-in rate increase of $123,000,000 for the Zimmer Plant to be implemented in three steps over a two-year period and disallowed $165,000,000 of Zimmer Plant investment. CSPCo appealed the PUCO ordered Zimmer disallowance and phase-in plan to the Ohio Supreme Court. In November 1993, the Supreme Court issued a decision on CSPCo's appeal affirming the disallowance and finding that the PUCO did not have statutory authority to order phased-in rates. The court instructed the PUCO to fix rates to provide gross annual revenue in accordance with the law and to provide a mechanism to recover the revenues deferred under the phase-in order. As a result of the ruling, 1993 net income was reduced by $144,500,000 after tax to reflect the disallowance and in January 1994, the PUCO approved a 7.11% or $57,167,000 rate increase effective February 1, 1994. The increase is comprised of a 3.72% base rate increase and a temporary 3.39% surcharge, which will be in effect until the phase-in plan deferrals are recovered, currently estimated to be mid-1997. In 1995, $28,500,000 of net phase-in deferrals were collected through the surcharge which reduced the deferrals from $75,400,000 at December 31, 1994 to $46,900,000 at December 31, 1995. In 1993 and 1992, $47,900,000 and $46,000,000, respectively, were deferred under the phase-in plan. The recovery of amounts deferred under the phase-in plan and the increase in rates to the full rate level did not affect net income. From the in-service date of March 1991 until rates went into effect in May 1992, deferred carrying charges of $43,000,000 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. Reference is made to the caption ENVIRONMENTAL AND OTHER MATTERS - ACID RAIN PROGRAM - AEP SYSTEM COMPLIANCE PLAN for information regarding AEP's compliance plan which was approved by the PUCO. KEPCO In September 1995, KEPCo, the Kentucky Attorney General and other interested parties filed an application with the KPSC to implement KEPCo's DSM Three-Year Experimental Plan which consisted of DSM programs for residential, commercial and industrial sectors. Under the plan, program costs, as well as net lost revenues and incentives, would be recovered by sector under an annual surcharge tariff. In December 1995, the KPSC issued an order approving the three-year plan for the period ending December 31, 1998. OPCO An application was filed by OPCo in July 1994 with the PUCO seeking a $152,500,000 annual base retail rate increase to recover, among other things, the costs associated with the Gavin Plant's flue gas desulfurization systems (scrubbers). In February 1995, OPCo and certain other parties to the proceeding entered into a settlement agreement to resolve, among other issues, the pending base rate case and the current electric fuel component (EFC) proceeding. On March 23, 1995, the PUCO issued an order approving the settlement agreement, with certain minor exceptions. Under the terms of the settlement agreement, effective March 23, 1995, base rates increase by $66,000,000 annually which includes recovery of the annual cost of the scrubbers; the EFC rate is fixed at 1.465 cents per kwh from June 1, 1995 through November 30, 1998; OPCo is provided with the opportunity to recover its Ohio jurisdictional share of the investment in, and the liabilities and future shutdown costs of, all affiliated mines as well as any fuel costs incurred above the fixed rate; and OPCo may proceed with its Clean Air Act Amendments of 1990 compliance plan as filed with the PUCO (discussed under ENVIRONMENTAL AND OTHER MATTERS - ACID RAIN PROGRAM - AEP SYSTEM COMPLIANCE PLAN). The settlement agreement allows OPCo to continue to operate its Muskingum and Windsor mines. Based on 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. As discussed above, the PUCO-approved settlement agreement fixes the EFC factor at 1.465 cents per kwh for the period June 1995 through November 1998. After November 2009, the price that OPCo can recover for coal from its affiliated Meigs mine which supplies the Gavin Plant will be limited to the lower of cost or the then-current market price. The predetermined Gavin Plant price agreement, in conjunction with the above- referenced settlement agreement, provide OPCo with an 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 will be recovered under the terms of the predetermined price agreement. In November 1992, the municipal wholesale customers of OPCo filed a complaint with the SEC requesting an investigation of the sale of the Martinka mining operation to an unaffiliated company and an investigation into the pricing of OPCo's affiliated coal purchases back to 1986. OPCo has filed a response with the SEC seeking to dismiss this complaint. FUEL SUPPLY The following table shows the sources of power generated by the AEP System: 1991 1992 1993 1994 1995 Coal 86% 93% 86% 91% 88% Nuclear 13% 6% 13% 8% 11% Hydroelectric and other 1% 1% 1% 1% 1% Variations in the generation of nuclear power are primarily related to refueling outages and, in 1992, a forced outage at Cook Plant Unit 2. See COOK NUCLEAR PLANT. COAL The Clean Air Act Amendments of 1990 provide for the issuance of annual allowance allocations covering sulfur dioxide emissions at levels below historic emission levels for many coal-fired generating units of the AEP System. Phase I of this program began in 1995 and Phase II begins in 2000, with both phases requiring significant changes in coal supplies and suppliers. The full extent of such changes, particularly in regard to Phase II, however, has not been determined. See ENVIRONMENTAL AND OTHER MATTERS - ACID RAIN PROGRAM - AEP SYSTEM COMPLIANCE PLAN for the current compliance plan. In order to meet emission standards for existing and new emission sources, the AEP System companies will, in any event, have to obtain coal supplies, in addition to coal reserves now owned by System companies, through the acquisition of additional coal reserves and/or by entering into additional supply agreements, either on a long-term or spot basis, at prices and upon terms which cannot now be predicted. No representation is made that any of the coal rights owned or controlled by the System will, in future years, produce for the System any major portion of the overall coal supply needed for consumption at the coal-fired generating units of the System. Although AEP believes that in the long run it will be able to secure coal of adequate quality and in adequate quantities to enable existing and new units to comply with emission standards applicable to such sources, no assurance can be given that coal of such quality and quantity will in fact be available. No assurance can be given either that statutes or regulations limiting emissions from existing and new sources will not be further revised in future years to specify lower sulfur contents than now in effect or other restrictions. See ENVIRONMENTAL AND OTHER MATTERS herein. The FERC has adopted regulations relating, among other things, to the circumstances under which, in the event of fuel emergencies or shortages, it might order electric utilities to generate and transmit electric power to other regions or systems experiencing fuel shortages, and to rate-making principles by which such electric utilities would be compensated. In addition, the Federal Government is authorized, under prescribed conditions, to allocate coal and to require the transportation thereof, for the use of power plants or major fuel-burning installations. System companies have developed programs to conserve coal supplies at System plants which involve, on a progressive basis, limitations on sales of power and energy to neighboring utilities, appeals to customers for voluntary limitations of electric usage to essential needs, curtailment of sales to certain industrial customers, voltage reductions and, finally, mandatory reductions in cases where current coal supplies fall below minimum levels. Such programs have been filed and reviewed with officials of Federal and state agencies and, in some cases, the state regulatory agency has prescribed actions to be taken under specified circumstances by System companies, subject to the jurisdiction of such agencies. The mining of coal reserves is subject to Federal requirements with respect to the development and operation of coal mines, and to state and Federal regulations relating to land reclamation and environmental protection, including Federal strip mining legislation enacted in August 1977. Continual evaluation and study is given to possible closure of existing coal mines and divestiture or acquisition of coal properties in light of Federal and state environmental and mining laws and regulations which may affect the System's need for or ability to mine such coal. Western coal purchased by System companies is transported by rail to a terminal on the Ohio River for transloading to barges for delivery to generating stations on the river. Subsidiaries of AEP lease approximately 3,535 coal hopper cars to be used in unit train movements, as well as 14 towboats, 295 jumbo barges and 185 standard barges. Subsidiaries of AEP also own or lease coal transfer facilities at various locations on the river. 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:
1991 1992 1993 1994 1995 Total coal delivered to AEP operated plants (thousands of tons) 45,232 44,738 40,561 49,024 46,867 Sources (percentage): Subsidiaries 28% 25% 20% 15% 14% Long-term contracts 62% 65% 66% 65% 75% Spot or short-term purchases 10% 10% 14% 20% 11% Average price per ton of spot-purchased coal $25.40 $23.88 $23.55 $23.00 $25.15
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:
1991 1992 1993 1994 1995 Dollars per ton AEP System Companies $35.16 $34.31 $33.57 $33.95 $32.52 AEGCo 20.65 20.11 17.74 18.59 18.80 APCo 41.99 43.00 42.65 39.89 38.86 CSPCo 35.18 33.87 33.87 32.80 33.23 I&M 25.57 24.23 23.80 22.85 23.25 KEPCo 31.38 30.24 27.08 26.83 26.91 OPCo 40.18 38.36 38.12 41.10 37.58 CENTS PER MILLION BTU'S AEP System Companies 158.88154.41150.89152.41145.26 AEGCo 123.33 120.90 107.71 112.06 112.87 APCo 169.48 173.05 173.32 161.37 156.96 CSPCo 152.55 143.94 143.66 140.45 140.79 I&M 139.16 135.11 129.39 123.62 125.50 KEPCo 132.25 126.92 113.90 113.40 114.77 OPCo 171.65 163.89 161.25 173.51 157.62 The coal supplies at AEP System plants vary from time to time 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, 1995, the System's coal inventory was approximately 55 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 1995 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 1995 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.
ESTIMATED REQUIRE- AVERAGE SULFUR CONTENT TOTAL CONSUMPTION MENTS FOR REMAINDER OF DELIVERED COAL During 1995 of Useful Lives Pounds of SO{2} (IN THOUSANDS OF TONS) (IN MILLIONS OF TONS) BY WEIGHT PER MILLION BTU'S AEGCo (a) 5,267 261 0.3% 0.7 APCo 8,988 446 0.8% 1.3 CSPCo (b) 5,367 234 2.9% 4.9 I&M (c) 6,723 300 0.5% 1.1 KEPCo 2,953 91 1.2% 2.0 OPCo 17,910 650 2.2% 3.7
(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 1995, whereas the maximum sulfur content permitted, for emission standard purposes, for existing plants in the regions in which APCo's generating stations are located ranged between 0.78% and 2% by weight depending in some circumstances on the calorific value of the coal which can be obtained for some generating stations. CSPCO: CSPCo has coal supply agreements with unaffiliated suppliers for the delivery of approximately 3,400,000 tons per year through 1998. Some of this coal is washed to improve its quality and consistency for use principally at Unit 4 of the Conesville Plant. CSPCo has been informed by CG&E and DP&L that, with respect to the CCD Group units partly owned but not operated by CSPCo, sufficient coal has been contracted for or is believed to be available for the approximate lives of the respective units operated by them. Under the terms of the operating agreements with respect to CCD Group units, each operating company is contractually responsible for obtaining the needed fuel. I&M: I&M has three 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 67,750,000 tons expires on December 31, 2014 and another contract with remaining deliveries of 56,400,000 tons expires on December 31, 2004. The third contract with deliveries of 750,000 tons per year expires in late 1996. All of the coal consumed at I&M's Tanners Creek Plant is obtained from unaffiliated suppliers under long-term contracts and/or on a spot purchase basis. KEPCO: Substantially all of the coal consumed at KEPCo's Big Sandy Plant is obtained from unaffiliated suppliers under long-term contracts and/or on a spot purchase basis. KEPCo has coal supply agreements with unaffiliated suppliers pursuant to which KEPCo will receive approximately 2,500,000 tons of coal in 1996. To the extent that KEPCo has additional coal requirements, it may purchase coal from the spot market and/or suppliers under contract to supply other System companies. OPCO: The coal consumed at OPCo's generating plants is obtained from both affiliated and unaffiliated suppliers. The coal obtained from unaffiliated suppliers is purchased under long-term contracts and/or on a spot purchase basis. OPCo and certain of its coal-mining subsidiaries own or control coal reserves in the State of Ohio which contain approximately 212,000,000 tons of clean recoverable coal, which ranges in sulfur content between 3.4% and 4.5% sulfur by weight (weighted average, 3.8%), which can be recovered based upon existing mining plans and projections and employing current mining practices and techniques. OPCo and certain of its mining subsidiaries own an additional 113,000,000 tons of clean recoverable coal in Ohio which ranges in sulfur content between 2.4% and 3.4% sulfur by weight (weighted average 2.7%). 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 106,000,000 tons of clean recoverable coal ranging in sulfur content between 1.4% and 3.3% sulfur by weight (weighted average, 2.0%) of which approximately 29,000,000 tons can be recovered based upon existing mining plans and projections and employing current mining practices and techniques. NUCLEAR I&M has made commitments to meet certain of the nuclear fuel requirements of the Cook Plant. The nuclear fuel cycle consists of the mining and milling of uranium ore to uranium concentrates; the conversion of uranium concentrates to uranium hexafluoride; the enrichment of uranium hexafluoride; the fabrication of fuel assemblies; the utilization of nuclear fuel in the reactor; and the reprocessing or other disposition of spent fuel. Steps currently are being taken, based upon the planned fuel cycles for the Cook Plant, to review and evaluate I&M's requirements for the supply of nuclear fuel beyond the existing contractual commitments shown in the following table. I&M has made and will make purchases of uranium in various forms in the spot and short-term market until it decides that deliveries under mid- or long-term supply contracts are warranted. The following table shows the year through which contracts have been entered into to provide the requirements of the units for the various segments of the nuclear fuel cycle.
URANIUM CONCENTRATES CONVERSION ENRICHMENT (1) FABRICATION REPROCESSING (2) Unit 1 -- -- 2000 2000 -- Unit 2 -- -- 2000 2000 --
1) I&M has a requirements-type contract with DOE. I&M has partially terminated the contract, subject to revocation of the termination, so that it may procure enrichment services cost-effectively from the spot market. 2) No reprocessing facility in the United States currently is in operation. I&M has contracted for reprocessing services at a facility on which construction has been halted. Lack of reprocessing services has resulted in the need to increase on-site storage capacity for spent fuel. For purposes of the storage of high-level radioactive waste in the form of spent nuclear fuel, I&M has completed modifications to its spent nuclear fuel storage pool to permit normal operations through 2010. I&M's costs of nuclear fuel consumed do not assume any residual or salvage value for residual plutonium and uranium. NUCLEAR WASTE AND DECOMMISSIONING The Nuclear Waste Policy Act of 1982, as amended, establishes Federal responsibility for the permanent off-site disposal of spent nuclear fuel and high-level radioactive waste. Disposal costs are paid by fees assessed against owners of nuclear plants and deposited into the Nuclear Waste Fund created by the Act. In 1983, I&M entered into a contract with DOE for the disposal of spent nuclear fuel. Under terms of the contract, for the disposal of nuclear fuel consumed after April 6, 1983 by I&M's Cook Plant, I&M is paying to the fund a fee of one mill per kilowatt-hour, which I&M is currently recovering from customers. For the disposal of nuclear fuel consumed prior to April 7, 1983, I&M must pay the U.S. Treasury a fee estimated at approximately $71,964,000, exclusive of interest of $91,096,000 at December 31, 1995. The aggregate amount has been recorded as long-term debt. Because of the current uncertainties surrounding DOE's program to provide for permanent disposal of spent nuclear fuel, I&M has not yet paid any of the pre-April 1983 fee. At December 31, 1995, funds collected from customers to pay the pre-April 1983 fee and accrued interest approximated the long-term debt liability. On June 20, 1994, a group of 14 unaffiliated utilities owning and operating nuclear plants and a group of states each 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 imposes on DOE an unconditional obligation to begin acceptance of spent nuclear fuel and high level radioactive waste by January 31, 1998. DOE has indicated in its Notice of Inquiry of May 25, 1994 that its preliminary view is that it has no statutory obligation to begin to accept spent nuclear fuel beginning in 1998 in the absence of an operational repository. In April 1995, DOE issued its Final Interpretation affirming its earlier view. On May 30, 1995, I&M filed a petition for review seeking the same relief requested earlier by the group of utilities. This action was consolidated with the earlier petition. I&M also seeks, if warranted, relief from the financial burden of fees being paid to DOE. Studies completed in 1994 estimate decommissioning and low-level radioactive waste disposal costs for the Cook Plant to range from $634,000,000 to $988,000,000 in 1993 nondiscounted dollars. The wide range is caused by variables in assumptions, including the estimated length of time spent nuclear fuel must be stored at the Cook Plant subsequent to ceasing operations, which depends on future developments in the federal government's spent nuclear fuel disposal program. Continued delays in the federal fuel disposal program can result in increased decommissioning costs. I&M is recovering decommissioning costs in its three rate-making jurisdictions based on at least the lower end of the range in the most recent respective decommissioning study available at the time of the rate proceeding (the study range utilized in the Indiana rate case, I&M's primary jurisdiction, was $588,000,000 to $1.102 billion in 1991 dollars). I&M records decommissioning costs in other operation expense and records a noncurrent liability equal to the decommissioning cost recovered in rates which was $30,000,000 in 1995, $26,000,000 in 1994 and $13,000,000 in 1993. At December 31, 1995, I&M had recognized a decommissioning liability of $269,000,000. I&M will continue to reevaluate periodically the cost of decommissioning and to seek regulatory approval to revise its rates as necessary. Funds recovered through the rate-making process for disposal of spent nuclear fuel consumed prior to April 7, 1983 and for nuclear decommissioning have been segregated and deposited in external funds for the future payment of such costs. Trust fund earnings decrease the amount to be recovered from ratepayers. The ultimate cost of retiring I&M's Cook Plant may be materially different from the estimates contained in the site-specific study and the funding targets as a result of (a) the type of decommissioning plan selected, (b) the escalation of various cost elements (including, but not limited to, general inflation), (c) the further development of regulatory requirements governing decommissioning, (d) the absence to date of significant experience in decommissioning such facilities and (e) the technology available at the time of decommissioning differing significantly from that assumed in these studies. Accordingly, management is unable to provide assurance that the ultimate cost of decommissioning the Cook Plant will not be significantly greater than current projections. In February 1996, the Financial Accounting Standards Board (FASB) issued an exposure draft entitled ACCOUNTING FOR CERTAIN LIABILITIES RELATED TO CLOSURE OR REMOVAL OF LONG-LIVED ASSETS. The exposure draft proposes that the present value of any decommissioning or other closure or removal obligation be recorded as a liability when the obligation is incurred. A corresponding asset would be recorded in the plant investment account and recovered through depreciation charges over the asset's life. A proposed transition rule would require that an entity report a charge to income for the cumulative effect of initially applying the proposed standard. Management is studying the proposed standard and evaluating its potential impact. The Low-Level Waste Policy Act of 1980 (LLWPA) mandates that the responsibility for the disposal of low-level waste rests with the individual states. Low-level radioactive waste consists largely of ordinary trash 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. As 1986 approached it became apparent that no new disposal facilities would be operational, and enforcement of the LLWPA would leave no disposal capacity for the majority of the low-level waste generated in the United States. Congress, therefore, passed the Low-Level Waste Policy Amendments Act of 1985. Michigan, the state where the Cook Plant is located, was a member of the Midwest Compact, but its membership was revoked in 1991. Michigan is responsible for developing a disposal site for the low-level waste generated in Michigan. In 1994, Michigan amended its law regarding disposal sites to provide for allowing a volunteer to host a facility. Although progress has been made, the site selection process is very long and management is unable to predict when a permanent 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 is the first opportunity for the Cook Plant to dispose of waste at that site since November 1990 when South Carolina denied access to its disposal site. To the extent necessary, the Cook Plant's low-level radioactive waste is being stored on- site. I&M has an on-site radioactive material storage facility at the Cook Plant for temporary preshipment storage of the plant's low-level radioactive waste. The facility can hold as much low-level waste as the Cook Plant is expected to produce through approximately 2001, and the building could be expanded to accommodate the storage of such waste through approximately 2017. Currently, the Cook Plant produces less than 7,000 cubic feet of low-level waste annually. ENERGY POLICY ACT - NUCLEAR FEES The Energy Policy Act of 1992 (Energy Act), contains a provision to fund the decommissioning and decontamination of DOE's existing uranium enrichment facilities from a combination of sources including assessments against electric utilities which purchased enrichment services from DOE facilities. I&M's remaining estimated liability is $45,703,000, subject to inflation adjustments, and is payable in annual assessments over the next 11 years. I&M recorded a regulatory asset concurrent with the recording of the liability. The payments are being recorded and recovered as fuel expense. In a case involving an unaffiliated utility, the U.S. Court of Federal Claims decided in June 1995 that these assessments are unlawful. On November 13, 1995, the Federal Government appealed this decision to the U.S. Court of Appeals for the Federal Circuit. I&M has filed with DOE claims for refunds under certain of its enrichment services contracts based on this decision. I&M also intends to pursue refund claims on other enrichment services contracts directly to the U.S. Court of Federal Claims. ENVIRONMENTAL AND OTHER MATTERS AEP's subsidiaries are subject to regulation by Federal, state and local authorities with regard to air and water-quality control and other environmental matters, and are subject to zoning and other regulation by local authorities. It is expected that costs related to environmental requirements will eventually be reflected in the rates of AEP's electric utility subsidiaries and that, in the long term, AEP's electric utility subsidiaries will be able to provide for such environmental controls as are required. 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. Except as noted herein, AEP's subsidiaries which own or operate generating facilities generally are in compliance with pollution control laws and regulations. AIR POLLUTION CONTROL CLEAN AIR ACT AMENDMENTS OF 1990: For the AEP System, compliance with the Clean Air Act Amendments of 1990 (CAAA) is requiring substantial expenditures which are being recovered through increases in the rates of AEP's operating subsidiaries. OPCo is incurring a major portion of such costs. There can be no assurance that all such costs will be recovered. See CONSTRUCTION PROGRAM - CONSTRUCTION EXPENDITURES. The Acid Rain Program provisions of the CAAA create an emission allowance program pursuant to which utilities are authorized to emit a designated quantity of sulfur dioxide, measured in tons per year, on a system wide or aggregate basis. Emission reductions are required by virtue of the establishment of annual allowance allocations at a level below historical emission levels for many utility units. For units that emitted sulfur dioxide above a rate of 2.5 pounds per million Btu heat input in 1985, the CAAA establish sulfur dioxide allowance limitations (caps or ceilings on emissions) premised upon sulfur dioxide emissions at a rate of 2.5 pounds per million Btu heat input at 1985 utilization levels as of the Phase I deadline of January 1, 1995. The following AEP System units are Phase I-affected units: I&M's Breed Plant and Tanners Creek Unit 4; CSPCo's Beckjord Unit 6, Conesville Units 1-4, Picway Unit 5 and Stuart Units 1-4; and OPCo's Gavin Units 1-2, Muskingum River Units 1-5, Cardinal Unit 1, Mitchell Units 1-2 and Kammer Units 1-3. Phase I permits have been issued for all Phase I-affected units in the AEP System. All fossil fuel-fired steam generating units with capacity greater than 25 megawatts are affected in Phase II of the acid rain control program. All Phase II-affected units are allocated allowances with which compliance must be accomplished beginning January 1, 2000. The basis for Phase II allowance allocation depends on 1985 sulfur dioxide emission rates - if a unit emitted sulfur dioxide in 1985 at a rate in excess of 1.2 pounds per million Btu heat input, the allowance allocation is premised upon an emission rate of 1.2 pounds at 1985 utilization levels as of the Phase II deadline of January 1, 2000; if a unit emitted sulfur dioxide in 1985 at a rate of less than 1.2 pounds, the allowance allocation is in most instances premised upon the actual 1985 emission rate. The Acid Rain Title also contains provisions concerning nitrogen oxides emissions. In March 1994, Federal EPA issued final regulations governing nitrogen oxides emissions from tangentially fired and dry bottom wall-fired boilers at Phase I units which were appealed to the U.S. Court of Appeals for the District of Columbia Circuit by APCo, CSPCo, I&M, KEPCo and OPCo and a group of unaffiliated utilities based on the failure of Federal EPA to correctly define low NOx burner technology. On November 29, 1994, the court remanded the rules to Federal EPA and on April 13, 1995, Federal EPA issued revised regulations pursuant to the court's remand. Compliance with these emission limitations is determined on an annual basis beginning in 1996. OPCo's Mitchell Units 1 & 2 and CSPCo's Conesville Units 3 & 4 and Picway Unit 5 are Phase I units subject to these regulations. On January 19, 1996, Federal EPA published proposed Nox emission limitations in the FEDERAL REGISTER for wet bottom wall-fired boilers, cyclone boilers, units applying cell burner technology and all other types of boilers. These proposed emission limitations are purported to be comparable in cost to the controls applicable to tangentially fired boilers and non-cell burner dry bottom wall-fired boilers. These emission limitations are required to be met by Phase II-affected sources after January 1, 2000. Also on January 19, 1996, Federal EPA published proposed revisions to the existing emission limitations for tangentially fired and dry bottom wall-fired boilers. Federal EPA must take final action on the proposed revisions by January 1, 1997. These limitations are expected to be more restrictive than those which are currently applicable. The CAAA contain additional provisions, other than the Acid Rain Title, which could require reductions in emissions of nitrogen oxides from fossil fuel-fired power plants. Title I, dealing generally with non-attainment of ambient air quality standards, establishes a tiered system for classifying degrees of non-attainment with air quality standards for ozone. Depending upon the severity of non-attainment within a given non-attainment area, reductions in nitrogen oxides emissions from fossil fuel-fired power plants may be required as part of a state's plan for achieving attainment with ozone air quality standards. On February 25, 1994, the West Virginia Division of Environmental Protection issued a consent order for APCo's Amos Units 1 and 2, requiring reductions in nitrogen oxides emissions from these units after June 1, 1995. The reduction in nitrogen oxides emissions will be less than that required under Title IV of the CAAA but will be required at an earlier time. On September 6, 1994, Federal EPA officially redesignated Putnam, Wood and Kanawha counties to ozone attainment. West Virginia does not plan to impose Nox reduction requirements under Title I of the CAAA as part of its ozone maintenance plan in any of the five former moderate ozone non-attainment counties, barring any other mandate from Federal EPA to do so. While ozone non-attainment is largely restricted to urban areas, AEP System generating stations could be determined to be affecting ozone concentrations and may therefore, eventually be required to reduce nitrogen oxides emissions pursuant to Title I. In addition, certain environmental organizations and northeastern states have filed comments with Federal EPA contending that nitrogen oxides emissions from the midwest must be reduced in order to achieve the National Ambient Air Quality Standard for ozone in the northeast. Similar comments have been filed by these organizations and others with the FERC in connection with the proposed rulemaking involving open access to transmission facilities. See TRANSMISSION SERVICES - TRANSMISSION SERVICES FOR NON-AFFILIATES. All AEP coal-fired plants are potentially subject to the imposition of additional emission controls resulting from these initiatives. The Environmental Council of States formed the Ozone Transport Assessment Group (OTAG) in early 1995 to develop estimates of levels of reduction in volatile organic compound and/or nitrogen oxides emissions required for significant reductions in ozone concentrations in the eastern United States. OTAG, consisting of the environmental commissioners and air directors of 37 eastern states, Federal EPA and representatives from environmental and industry groups, is currently scheduled to complete modeling and technical work by the fall of 1996 - with evaluation of technical findings and recommendations on regional emission controls to be submitted to Federal EPA by January 1997. The cost of meeting Nox emissions reduction requirements which might be imposed to achieve the ozone ambient air quality standard cannot be precisely predicted but could be substantial. Utility boilers are potentially subject to additional control requirements under Title III of the CAAA governing hazardous air pollutant emissions. Federal EPA is directed to conduct studies concerning the potential public health impacts of pollutants identified by the legislation as hazardous in connection with their emission from electric utility steam generating units. Federal EPA was required to report the results of this study to Congress by November 1993 and is required to regulate emissions of these pollutants from electric utility steam generating units if it is determined that such regulation is necessary and appropriate, based on the results of the study. Federal EPA informed Congress that completion of this study has been delayed significantly beyond the November 1993 deadline. Federal EPA is subject to a judicial consent decree requiring completion of the study and submission of it by April 15, 1996. Additionally, Federal EPA is directed to study the deposition of hazardous pollutants to the Great Lakes, the Chesapeake Bay, Lake Champlain and other coastal waters. As part of this assessment, Federal EPA is authorized to adopt regulations to prevent serious adverse effects to public health and serious or widespread environmental effects. It is possible that emissions from electric utility steam generating units may be regulated under this water body deposition assessment program. The CAAA expand the enforcement authority of the Federal government by increasing the range of civil and criminal penalties for violations of the Clean Air Act and enhancing administrative civil provisions, adding a citizen suit provision and imposing a national operating permit system, emission fee program and enhanced monitoring, record keeping and reporting requirements for existing and new sources. ACID RAIN PROGRAM - AEP SYSTEM COMPLIANCE PLAN: In 1992, the PUCO approved a system-wide Phase I Acid Rain Program compliance plan. The AEP System's compliance plan centers around the compliance method selected for OPCo's two- unit 2,600-megawatt Gavin Plant which was emitting about 25% of the System's total sulfur dioxide emissions. Under an Ohio law, utilities could obtain advance PUCO approval of a least-cost compliance plan which would be deemed prudent in subsequent PUCO rate proceedings. The PUCO approved least-cost plan set forth compliance measures for the System's affected generating units, which included (i) installing leased flue gas desulfurization equipment (scrubbers) to burn Ohio high-sulfur coal at Gavin and (ii) designating Gavin's coal supply sources to include the affiliated Meigs mine at a reduced operating capacity and under predetermined prices, new long-term contracts with unaffiliated sources and spot market purchases. Pursuant to a settlement agreement approved by the PUCO in connection with OPCo's rate case discussed in RATES - OPCO, the PUCO reaffirmed its approval of the compliance plan, which does not seek to fuel switch Cardinal Unit 1 or Muskingum River Units 1-4 to low-sulfur coal at the beginning of Phase I of the CAAA. Under the terms of the compliance plan, OPCo's Muskingum River Unit 5 has been switched to low-sulfur coal. CSPCo's Conesville Units 1-3 have been modified to enable these units to burn coal or natural gas to comply. Actual fuel choice will depend on the cost and availability of gas. Although the compliance plan originally contemplated that CSPCo's Picway Unit 5 also would be modified to enable this unit to burn coal or natural gas to comply, this proposed modification has been indefinitely deferred. Beckjord Unit 6 (owned with CG&E and DP&L) has been switched to moderate sulfur coal. I&M's Tanners Creek Unit 4 has also been switched to moderate sulfur coal and I&M's Breed Plant was retired in 1994. Eight additional units are subject to Phase I rules, but no operating or fuel changes are planned, because they will hold allowances sufficient for compliance. Since the approved plan reflects fuel switching to comply at OPCo's Muskingum River Plant and Cardinal Unit 1, mining operations at OPCo's wholly- owned coal-mining subsidiaries, Central Ohio Coal Company and Windsor Coal Company, could be shut down resulting in substantial costs. Central Ohio Coal Company and Windsor Coal Company supply coal to Muskingum River Plant and Cardinal Plant, respectively. As a result of the aforementioned PUCO approval of OPCo's least-cost compliance plan, OPCo entered into an agreement in 1992 for construction and lease of the Gavin Plant scrubbers with JMG Funding, Limited Partnership (JMG), an unaffiliated entity. The scrubbers on Gavin Units 1 and 2 commenced operation in December 1994 and March 1995, respectively. On March 15, 1995, OPCo began to lease the scrubbers from JMG. See CONSTRUCTION PROGRAM - CONSTRUCTION EXPENDITURES. Recovery of compliance costs has been and will be sought through the rate- making process. The aforementioned OPCo settlement agreement provides, among other things, for OPCo to recover the annual lease cost of the scrubbers and other compliance costs and provides OPCo with an opportunity to recover its Ohio jurisdictional share of its investment in and the liabilities and closing costs of the affiliated Central Ohio and Windsor mining operations to the extent the actual cost of coal burned at the Gavin Plant is below a predetermined price. AEP intends to also seek timely recovery of all compliance costs, including mine shutdown costs, from its non-Ohio jurisdictional customers. OPCo's 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 $195,000,000 net of tax at December 31, 1995. There can be no assurance that regulators will provide for recovery of all CAAA compliance costs. Compliance with the CAAA, including potential mine closure costs, could have an adverse effect on results of operations and possibly financial condition unless the costs can be recovered from ratepayers and/or from asset dispositions. GLOBAL CLIMATE CHANGE: Increasing concentrations of "greenhouse gases," including carbon dioxide (CO{2}), in the atmosphere have led to concerns about the potential for the earth's climate to change in ways that could result in adverse human health effects, destruction of sensitive ecosystems, inundated low-lying areas caused by sea-level rise, shifts in agricultural production and other serious environmental consequences. The proponents of this view maintain that rising levels of greenhouse gas emissions will cause some of the sun's energy that is normally radiated back into space to be trapped in the atmosphere, warming the biosphere and triggering these detrimental effects. At the Earth Summit in Rio de Janeiro, Brazil in June 1992, 165 nations, including the United States, signed a global climate change treaty. Each country that ratifies the treaty commits itself to a process of achieving the aim of reducing greenhouse gas emissions, including CO{2}, to their 1990 level by the year 2000. On October 7, 1992, the U.S. Senate ratified the treaty. The treaty went into effect on March 21, 1994. In April 1995, the first meeting of the nations that have ratified was held. The parties declared that the existing commitments under the treaty are not adequate to address the threat of global climate change and authorized the immediate commencement of negotiations on a protocol or other legal instrument for emission controls in the post-2000 period. The protocol or other legal instrument is required to set forth "policies and measures," and "quantified limitation and reduction objectives within specified time frames, such as 2005, 2010 and 2020" to be adopted by signatory nations. The negotiations are expected to be complete in early 1997. In accordance with the obligations set forth in the global climate change treaty, on April 21, 1993, President Clinton committed the United States to reducing greenhouse gas emissions to 1990 levels by the year 2000. On October 19, 1993, the President unveiled the Administration's Climate Change Action Plan for meeting this emission reduction target. The plan emphasizes reductions in fossil fuel use, the largest source of CO{2} emissions, primarily through reliance on voluntary energy efficiency programs and partnerships between the Federal government and U.S. industry. One such collaboration is between the electric utility industry and DOE. Known as the Climate Challenge, this initiative has identified flexible, cost-effective measures to reduce, avoid or sequester future greenhouse gas emissions. AEP System companies joined with nearly 800 investor-owned, municipal, rural electric cooperative and Federal utilities in a voluntary agreement signed with DOE on April 20, 1994 that has led to individual utility Participation Accords resulting in substantial reductions in future greenhouse gas emissions. On February 3, 1995, the AEP System entered into its Climate Challenge Participation Accord with DOE. The Accord contains a diverse portfolio of supply-side, demand-side and forest management/tree planting activities that will be undertaken on the AEP System between now and the year 2000 with a projected reduction in CO{2} emissions of 9,550,000 tons from what would have otherwise been emitted but for these actions. As a result of the AEP System's historical practice of using low-cost indigenous coal supplies to produce electricity, AEP System power plants are significant sources of CO{2} emissions. Management is working to support further efforts to properly study the issue of global climate change to define the extent, if any, to which it poses a threat to the environment. Management is concerned that new laws may be passed or new regulations promulgated without sufficient scientific study and support. Since the AEP System is a major emitter of carbon dioxide, its financial condition and results of operations could be materially adversely affected by the imposition of stringent command-and-control limitations on CO{2} emissions if the compliance costs incurred are not fully recovered from ratepayers. In addition, any such severe program to stabilize or reduce CO{2} emissions could impose substantial costs on industry and society and seriously erode the economic base that AEP's operations serve. WEST VIRGINIA: West Virginia promulgated sulfur dioxide limitations which Federal EPA approved in February 1978. The emission limitations for the Mitchell Plant have been approved by Federal EPA for primary ambient air quality (health-related) standards only. West Virginia is obliged to reanalyze sulfur dioxide emission limits for the Mitchell Plant with respect to secondary ambient air quality (welfare-related) standards. Because the Clean Air Act provides no specific deadline for approval of emission limits to achieve secondary ambient air quality standards, it is not certain when Federal EPA will take dispositive action regarding the Mitchell Plant. West Virginia has had a request to increase the sulfur dioxide emission limitation for Kammer pending before Federal EPA for many years, although the change has not been acted upon by Federal EPA. On August 4, 1994, however, Federal EPA issued a Notice of Violation to OPCo alleging that Kammer Plant was operating in violation of the applicable federally enforceable sulfur dioxide emission limit. See Item 3. LEGAL PROCEEDINGS - KAMMER PLANT. A portion of the Notice of Violation relating to compliance has been resolved. Separate proceedings have been initiated by OPCo with both the West Virginia Division of Environmental Protection and Region III, Federal EPA in an effort to obtain approval for utilization of the existing fuel supply beyond the current final compliance date of May 15, 1996. While it is likely that the May 15, 1996 final compliance date will be extended, management cannot predict at this time how long it will be able to utilize the existing fuel supply at the Kammer Plant. STACK HEIGHT REGULATIONS: On June 27, 1985, Federal EPA issued stack height regulations pursuant to an order of the United States Court of Appeals for the District of Columbia Circuit. These regulations were appealed by a number of states, environmental groups and investor-owned electric utilities (including APCo, CSPCo, I&M, KEPCo and OPCo), along with three electric utility trade associations. OPCo also filed a separate petition for review to raise issues unique to its Kammer Plant. Various petitions for reconsideration filed with and denied by Federal EPA were also appealed. This litigation was consolidated into a single case. On January 22, 1988, the U.S. Court of Appeals issued a decision in part upholding the June 1985 stack height rules and remanding certain of the June 1985 rules to Federal EPA for further consideration. With respect to Kammer Plant, the January 1988 court decision rejected OPCo's appeal, holding that Federal EPA acted lawfully in revoking stack height credit previously granted for Kammer Plant in October 1982. As discussed above, OPCo has also commenced administrative proceedings with the State of West Virginia and Federal EPA in an effort to preserve stack height credit for Kammer Plant. While it is not possible to state with particularity the ultimate impact of the final rules on AEP System operations, at present it appears that the most likely AEP System plants at which the final rules could possibly result in more stringent emission limitations are CSPCo's Conesville Plant, AEGCo's and I&M's Rockport Plant, I&M's Tanners Creek Plant and OPCo's Gavin and Kammer plants. Gavin and Rockport plants were not affected by Federal EPA's stack height rules as issued in June 1985. However, the provision exempting these plants was remanded to Federal EPA in the January 1988 court decision. Accordingly, the ultimate impact of the stack height rules on Gavin and Rockport plants will not be known until Federal EPA completes administrative proceedings on remand and reissues final stack height rules. OPCo and AEGCo and I&M intend to participate in the remand rulemaking affecting Gavin and Rockport plants, respectively. State air pollution control agencies will be required to implement the stack height rules by revising emission limitations for sources subject to the rules and submitting such revisions to Federal EPA. On June 1, 1989, Ohio EPA adopted a rule concerning CSPCo's Conesville Plant in response to Federal EPA's stack height rules adopted in 1985. Under Federal EPA policy published in January 1988, emission reductions required by the stack height rules may be obtained at plants other than the plant directly affected by the rules, and thereafter credited to the directly affected plant. Under Ohio EPA's June 1 rule, the sulfur dioxide emission limitations for Conesville Units 5 and 6 remain at 1.2 pounds sulfur dioxide per million Btu heat input as long as the emission rate at CSPCo's retired Poston Units 1-4 remains at 0.0 pounds sulfur dioxide per million Btu heat input. Federal EPA has yet to take action concerning Ohio EPA's June 1 rule. ADMINISTRATIVE DEVELOPMENTS REGARDING SULFUR DIOXIDE: On November 15, 1994, Federal EPA published a notice in the FEDERAL REGISTER proposing to retain the present 24-hour national ambient air quality standard for sulfur dioxide. Federal EPA also sought comment on the need to adopt additional regulations to address short-term peak exposures to sulfur dioxide. Federal EPA is soliciting comments on three alternatives, including the adoption of a short-term standard averaged over a five-minute period. Adoption of any of these proposed approaches, or other targeted programs, could require substantial reductions in sulfur dioxide emissions from the System's coal-fired generating plants which would entail substantial capital and operating costs. In a related action, Federal EPA, on March 7, 1995, proposed requirements for implementing strategies to reduce short-term (five-minute) peak concentrations of sulfur dioxide in order to reduce health risks to exercising asthmatics. The effect on AEP operations of Federal EPA's proposed risk-based targeting strategies for further regulating sulfur dioxide emissions, if finalized, cannot be predicted, but may be significant. Federal EPA is expected to take final action on these proposals in the spring of 1996. LIFE EXTENSION: On July 21, 1992, Federal EPA published final regulations in the FEDERAL REGISTER governing application of new source rules to generating plant repairs and pollution control projects undertaken to comply with the Clean Air Act Amendments of 1990. Generally, the rule provides that plants undertaking pollution control projects will not trigger new source review requirements. The Natural Resources Defense Council and a group of utilities, including five AEP System companies, have filed petitions in the U.S. Court of Appeals for the District of Columbia Circuit seeking a review of the regulations. OTHER REGULATORY DEVELOPMENTS: Federal EPA is considering whether the National Ambient Air Quality Standard for ozone should be revised and is currently expected to make a final decision on this issue in 1997. Federal EPA is also considering revision of the National Ambient Air Quality Standard for particulate matter. Federal EPA is required by court order to make a final determination on this issue by June 28, 1997. WATER POLLUTION CONTROL 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 1996. 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, OPCo has requested a modification of the thermal management plan in the renewed permit for Muskingum River expected to be issued this year. 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. See Item 3. LEGAL PROCEEDINGS - MEIGS MINE with respect to litigation regarding certain discharges from OPCo's Meigs 31 mine. 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 water quality standards are not being met. Implementation of these provisions could result in significant costs to the AEP System if biological monitoring requirements and water quality-based effluent limits are placed in NPDES permits. In March 1995, Federal EPA finalized a set of rules which establish minimum water quality standards, anti-degradation policies and implementation procedures for more stringently controlling releases of toxic pollutants into the Great Lakes system. This regulatory package is called the Great Lakes Water Quality Initiative (GLWQI). The most direct compliance cost impact could be related to I&M's Cook Plant. Management cannot presently determine whether the GLWQI would have a significant adverse impact on AEP operations. The significance of such impact will depend on the outcome of Federal EPA's policy on intake credits and site specific variables as well as Michigan's implementation strategy. Federal EPA's rule is presently under review by the District of Columbia Circuit Court of Appeals in litigation initiated by several industry groups. If Indiana and Ohio eventually adopt the GLWQI criteria for statewide application, AEP System plants located in those states could also be affected. HAZARDOUS SUBSTANCES AND WASTES Section 311 of the Clean Water Act imposes substantial penalties for spills of Federal EPA-listed hazardous substances into water and for failure to report such spills. The Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) expanded the reporting requirements to cover the release of hazardous substances generally into the environment, including water, land and air. AEP's subsidiaries store and use some of these hazardous substances, including PCB's contained in certain capacitors and transformers, but the occurrence and ramifications of a spill or release of such substances cannot be predicted. CERCLA provides governmental agencies with the authority to require clean-up of hazardous waste sites and releases of hazardous substances into the environment. Since liability under CERCLA is strict and can be applied retroactively, AEP System companies which previously disposed of PCB-containing electrical equipment and other hazardous substances may be required to participate in remedial activities at such disposal sites should environmental problems result. AEP System companies are presently identified by Federal EPA as potentially responsible parties (PRPs) for cleanup of seven federal sites, including I&M at four sites, KEPCo at one site, OPCo at one site, and Wheeling Power Company at one site. OPCo is a defendant in a cost recovery suit for the site where OPCo is a PRP and at two additional CERCLA sites. I&M is a defendant in a cost recovery action at one of the sites where I&M is a PRP and for one additional CERCLA site. APCo and I&M each have been named as parties potentially responsible at a state remediation site. Management's present estimates do not anticipate material cleanup costs for identified sites for which AEP subsidiaries have been declared PRPs. However, if for reasons not currently identified significant costs are incurred for cleanup, future results of operations and possibly financial condition would be adversely affected unless the costs can be recovered through rates. Regulations issued by Federal EPA under the Toxic Substances Control Act govern the use, distribution and disposal of PCBs, including PCBs in electrical equipment. Deadlines for removing certain PCB-containing electrical equipment from service have been met. In addition to handling hazardous substances, the System companies generate solid waste associated with the combustion of coal, the vast majority of which is fly ash, bottom ash and flue gas desulfurization wastes. These wastes presently are considered to be non-hazardous under RCRA and applicable state law and the wastes are treated and disposed in surface impoundments or landfills in accordance with state permits or authorization or beneficially utilized. As required by RCRA, EPA evaluated whether high volume coal combustion wastes (such as fly ash, bottom ash and flue gas desulfurization wastes) should be regulated as hazardous waste. In August, 1993 EPA issued a regulatory determination that such high volume coal combustion wastes should not be regulated as hazardous waste. For low volume coal combustion wastes, such as metal and boiler cleaning wastes, Federal EPA will gather additional information and make a regulatory determination by April 1998. Until that time, these low volume wastes are provisionally excluded from regulation under the hazardous waste provisions of RCRA. All presently generated hazardous waste is being disposed of at permitted off-site facilities in compliance with applicable Federal and state laws and regulations. For System facilities which generate such wastes, System companies have filed the requisite notices and are complying with RCRA and applicable state regulations for generators. Nuclear waste produced at the Cook Plant regulated under the Atomic Energy Act is excluded from regulation under RCRA. Federal EPA's technical requirements for underground storage tanks containing petroleum will require retrofitting or replacement of an appreciable number of tanks. Compliance costs for tank replacement and site remediation have not been significant to date. ELECTRIC AND MAGNETIC FIELDS (EMF) EMF is found everywhere there is electricity. Electric fields are created by the presence of electric charges. Magnetic fields are produced by the flow of those charges. This means that EMF is created by electricity flowing in transmission and distribution lines, or being used in household wiring and appliances. A number of studies in the past several years have examined the possibility of adverse health effects from EMF. While some of the epidemiological studies have indicated some association between exposure to EMF and health effects, the majority of studies have indicated no such association. The epidemiological studies that have received the most public attention reflect a weak correlation between surrogate or indirect estimates of EMF exposure and certain cancers. Studies using direct measurements of EMF exposure show no such association. There were two residential epidemiological studies of childhood brain cancer published in early 1996 which showed no association with EMF exposure. Research to date has not shown any causal relationship between EMF exposure and cancer, or any other adverse health effects. Additional studies, which are intended to provide a better understanding of the subject, are continuing. Federal EPA is currently studying whether exposure to EMF is associated with cancer in humans. In 1990, Federal EPA issued a draft report on EMF, received interagency review and public comment, and is in the process of preparing its final report. A December 1992 brochure from Federal EPA, QUESTIONS AND ANSWERS ABOUT ELECTRIC AND MAGNETIC FIELDS (EMFS), states at page 3, "The bottom line is that there is no established cause and effect relationship between EMF exposure and cancer or other disease." The Energy Policy Act of 1992 established a coordinated Federal EMF research program. The program funding is $65,000,000 over five years, half of which is to be provided by private parties including utilities. AEP has committed to contribute $446,571 over the five-year period. AEP's participation is a continuation of its efforts to support further research and to communicate with its customers and employees about this issue. Its operating company subsidiaries provide their residential customers with information and field measurements on request, although there is no scientific basis for interpreting such measurements. A number of lawsuits based on EMF-related grounds have been filed in recent years against electric utilities. A suit was filed on May 23, 1990 against I&M involving claims that EMF from a 345 KV transmission line caused adverse health effects. No specific amount has been requested for damages in this case and no trial date has been set. Some states have enacted regulations to limit the strength of magnetic fields at the edge of transmission line rights-of-way. No state which the AEP System serves has done so. In March 1993, The Ohio Power Siting Board issued its amended rules providing for additional consideration of the possible effects of EMF in the certification of electric transmission facilities. Under the amended EMF rules, persons seeking approval to build electric transmission lines have to provide estimates of EMF from transmission lines under a variety of conditions. In addition, applicants are required to address possible health effects and discuss the consideration of design alternatives with respect to EMF. In April 1993, the State of Indiana enacted a law which provides that the IURC shall determine, based on the preponderance of evidence in the scientific literature, whether rules are necessary to protect the public health from EMF. If the IURC determines that such rules are necessary, the IURC is required to adopt rules that reasonably protect the public health from EMF. Management cannot predict the ultimate impact of the question of EMF exposure and adverse health effects. If further research shows that EMF exposure contributes to increased risk of cancer or other health problems, or if the courts conclude that EMF exposure harms individuals and that utilities are liable for damages, or if states limit the strength of magnetic fields to such a level that the current electricity delivery system must be significantly changed, then the results of operations and financial condition of AEP and its operating subsidiaries could be materially adversely affected unless these costs can be recovered from ratepayers. RESEARCH AND DEVELOPMENT AEP and its subsidiaries are involved in a number of research projects which are directed toward developing more efficient methods of burning coal, reducing the contaminants resulting from combustion of coal, and improving the efficiency and reliability of power transmission, distribution and utilization, including load management. AEP System operating companies are members of the Electric Power Research Institute (EPRI), a nonprofit organization that manages research and development on behalf of the U.S. electric utility industry. EPRI, founded in 1973, manages technical research and development programs for its members to improve power production, delivery and use. Approximately 700 utilities are members. EPRI has agreed to a membership program with AEP whereby dues are being phased in from 1994 through 1996. Recovery of these dues through rates by AEP's operating companies has reasonably coincided with their phase-in dates. It is anticipated that recovery of the final 1996 dues phase-in will be sought in future rate cases. Total research and development expenditures by AEP and its subsidiaries were approximately $19,300,000 for the year ended December 31, 1995, $7,600,000 for the year ended December 31, 1994 and $13,800,000 for the year ended December 31, 1993. This includes expenditures of $6,700,000 for 1995, $2,200,000 for 1994 and $10,900,000 for 1993 related to pressurized fluidized-bed combustion, a process in which sulfur is removed during coal combustion and nitrogen oxide formation is minimized. EPRI dues of $9,600,000 for 1995 and $3,200,000 for 1994 are also included. Item 2. PROPERTIES At December 31, 1995, subsidiaries of AEP owned (or leased where indicated) generating plants with the net power capabilities (winter rating) shown in the following table:
NET KILOWATT OWNER, PLANT TYPE AND NAME LOCATION (NEAR) CAPABILITY AEP GENERATING COMPANY: Steam - Coal-Fired: Rockport Plant (AEGCo share) Rockport, Indiana 1,300,000(a) APPALACHIAN POWER COMPANY: Steam - Coal-Fired: John E. Amos, Units 1 & 2 St. Albans, West Virginia 1,600,000 John E. Amos, Unit 3 (APCo share) St. Albans, West Virginia 433,000(b) Clinch River Carbo, Virginia 705,000 Glen Lyn Glen Lyn, Virginia 335,000 Kanawha River Glasgow, West Virginia 400,000 Mountaineer New Haven, West Virginia 1,300,000 Philip Sporn, Units 1 & 3 New Haven, West Virginia 308,000 Hydroelectric - Conventional: Buck Ivanhoe, Virginia 10,000 Byllesby Byllesby, Virginia 20,000 Claytor Radford, Virginia 76,000 Leesville Leesville, Virginia 40,000 London Montgomery, West Virginia 16,000 Marmet Marmet, West Virginia 16,000 Niagara Roanoke, Virginia 3,000 Reusens Lynchburg, Virginia 12,000 Winfield Winfield, West Virginia 19,000 Hydroelectric - Pumped Storage: Smith Mountain Penhook, Virginia 565,000 5,858,000 COLUMBUS SOUTHERN POWER COMPANY: Steam - Coal-Fired: Beckjord, Unit 6 New Richmond, Ohio 53,000(c) Conesville, Units 1-3, 5 & 6 Coshocton, Ohio 1,165,000 Conesville, Unit 4 Coshocton, Ohio 339,000(c) Picway, Unit 5 Columbus, Ohio 100,000 Stuart, Units 1-4 Aberdeen, Ohio 608,000(c) Zimmer Moscow, Ohio 330,000(c) 2,595,000 INDIANA MICHIGAN POWER COMPANY: Steam - Coal-Fired: Rockport Plant (I&M share) Rockport, Indiana 1,300,000(a) Tanners Creek Lawrenceburg, Indiana 995,000 Steam - Nuclear: Donald C. Cook Bridgman, Michigan 2,110,000 Gas Turbine: Fourth Street Fort Wayne, Indiana 18,000(d) Hydroelectric - Conventional: Berrien Springs Berrien Springs, Michigan 3,000 Buchanan Buchanan, Michigan 2,000 Constantine Constantine, Michigan 1,000 Elkhart Elkhart, Indiana 1,000 Mottville Mottville, Michigan 1,000 Twin Branch Mishawaka, Indiana 3,000 4,434,000 KENTUCKY POWER COMPANY: Steam - Coal-Fired: Big Sandy Louisa, Kentucky 1,060,000 OHIO POWER COMPANY: Steam - Coal-Fired: John E. Amos, Unit 3 (OPCo share) St. Albans, West Virginia 867,000(b) Cardinal, Unit 1 Brilliant, Ohio 600,000 General James M. Gavin Cheshire, Ohio 2,600,000(e) Kammer Captina, West Virginia 630,000 Mitchell Captina, West Virginia 1,600,000 Steam - Coal-Fired: Muskingum River Beverly, Ohio 1,425,000 Philip Sporn, Units 2, 4 & 5 New Haven, West Virginia 742,000 Hydroelectric - Conventional: Racine Racine, Ohio 48,000 8,512,000 Total Generating Capability 23,759,000 SUMMARY: Total Steam - Coal-Fired 20,795,000 Nuclear 2,110,000 Total Hydroelectric - Conventional 271,000 Pumped Storage 565,000 Other 18,000 Total Generating Capability 23,759,000
(a)Unit 1 of the Rockport Plant is owned one-half by AEGCo and one-half by I&M. Unit 2 of the Rockport Plant is leased one-half by AEGCo and one-half by I&M. The leases terminate in 2022 unless extended. (b)Unit 3 of the John E. Amos Plant is owned one-third by APCo and two-thirds by OPCo. (c)Represents CSPCo's ownership interest in generating units owned in common with CG&E and DP&L. (d)Leased from the City of Fort Wayne, Indiana. Since 1975, I&M has leased and operated the assets of the municipal system of the City of Fort Wayne, Indiana under a 35-year lease with a provision for an additional 15-year extension at the election of I&M. (e)The scrubber facilities at the Gavin Plant are leased. The lease terminates in 2010 unless extended. See Item 1 under FUEL SUPPLY, for information concerning coal reserves owned or controlled by subsidiaries of AEP. The following table sets forth the total circuit miles of transmission and distribution lines of the AEP System, APCo, CSPCo, I&M, KEPCo and OPCo and that portion of the total representing 765,000-volt lines: TOTAL CIRCUIT MILES OF TRANSMISSION AND CIRCUIT MILES OF DISTRIBUTION LINES 765,000-VOLT LINES AEP System (a) 125,545(b) 2,022 APCo 48,961 641 CSPCo (a) 14,710 --- I&M 20,784 614 KEPCo 9,944 258 OPCo 28,286 509 (a) Includes 766 miles of 345,000-volt jointly owned lines. (b) Includes lines of other AEP System companies not shown. TITLES The AEP System's electric generating stations are generally located on lands owned in fee simple. The greater portion of the transmission and distribution lines of the System has been constructed over lands of private owners pursuant to easements or along public highways and streets pursuant to appropriate statutory authority. The rights of the System in the realty on which its facilities are located are considered by it to be adequate for its use in the conduct of its business. Minor defects and irregularities customarily found in title to properties of like size and character may exist, but such defects and irregularities do not materially impair the use of the properties affected thereby. System companies generally have the right of eminent domain whereby they may, if necessary, acquire, perfect or secure titles to or easements on privately-held lands used or to be used in their utility operations. Substantially all the physical properties of APCo, CSPCo, I&M, KEPCo and OPCo are subject to the lien of the mortgage and deed of trust securing the first mortgage bonds of each such company. SYSTEM TRANSMISSION LINES AND FACILITY SITING Legislation in the states of Indiana, Kentucky, Michigan, Ohio, Virginia, and West Virginia requires prior approval of sites of generating facilities and/or routes of high-voltage transmission lines. Delays and additional costs in constructing facilities have been experienced as a result of proceedings conducted pursuant to such statutes, as well as in proceedings in which operating companies have sought to acquire rights-of-way through condemnation, and such proceedings may result in additional delays and costs in future years. PEAK DEMAND The AEP System is interconnected through 120 high-voltage transmission interconnections with 29 neighboring electric utility systems. The all-time and 1995 one-hour peak System demands were 25,940,000 and 24,888,000 kilowatts, respectively (which included 7,314,000 and 4,934,000 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 August 15, 1995, respectively. The net dependable capacity to serve the System load on such date, including power available under contractual obligations, was 23,457,000 and 23,364,000 kilowatts, respectively. The all-time and 1995 one-hour internal peak demands were 19,557,000 and 19,516,000 kilowatts, respectively, and occurred on February 5, 1996 and August 14, 1995, respectively. The net dependable capacity to serve the System load on such date, including power dedicated under contractual arrangements, was 23,670,000 and 23,364,000 kilowatts, respectively. The all-time one-hour integrated and internal net system peak demands and 1995 peak demands for AEP's generating subsidiaries are shown in the following tabulation: ALL-TIME ONE-HOUR INTEGRATED 1995 ONE-HOUR INTEGRATED NET SYSTEM PEAK DEMAND NET SYSTEM PEAK DEMAND (in thousands) Number of Number of KILOWATTS DATE KILOWATTS DATE APCo 8,214 February 5, 1996 7,327 February 6, 1995 CSPCo 4,172 June 17, 1994 4,085 August 14, 1995 I&M 5,027 June 17, 1994 4,949 August 15, 1995 KEPCo 1,686 February 5, 1996 1,512 February 6, 1995 OPCo 7,291 June 17, 1994 6,913 August 15, 1995 ALL-TIME ONE-HOUR INTEGRATED 1995 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 6,507 February 9, 1995 CSPCo 3,378 August 14, 1995 3,378 August 14, 1995 I&M 3,864 August 14, 1995 3,864 August 14, 1995 KEPCo 1,418 February 5, 1996 1,363 February 9, 1995 OPCo 5,641 August 14, 1995 5,641 August 14, 1995 HYDROELECTRIC PLANTS Licenses for hydroelectric plants, issued under the Federal Power Act, reserve to the United States the right to take over the project at the expiration of the license term, to issue a new license to another entity, or to relicense the project to the existing licensee. In the event that a project is taken over by the United States or licensed to a new licensee, the Federal Power Act provides for payment to the existing licensee of its "net investment" plus severance damages. Licenses for six System hydroelectric plants expired in 1993 and applications for new licenses for these plants were filed in 1991. The existing licenses for these plants were extended on an annual basis and will be renewed automatically until new licenses are issued. No competing license applications were filed. Four new licenses were issued in 1994. New licenses for two other projects, one in Indiana and one in Michigan, are still pending before the FERC. An original license for the previously unlicensed Constantine project was issued in 1993. In 1995, a notice of intent to relicense the Elkhart project located in Indiana was filed. COOK NUCLEAR PLANT Unit 1 of the Cook Plant, which was placed in commercial operation in 1975, has a nominal net electric rating of 1,020,000 kilowatts. Unit 1's availability factor was 66.3% during 1995 and 71.0% during 1994. 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 94.4% during 1995 and 54.3% during 1994. Outages to refuel affected the availability of Unit 1 in 1995 and Units 1 and 2 in 1994. Units 1 and 2 are licensed by the NRC to operate at 100% of rated thermal power to October 25, 2014 and December 23, 2017, respectively. Costs associated with the operation, maintenance and retirement of nuclear plants continue to be significant and less predictable than costs associated with other sources of generation, in large part due to changing regulatory requirements and safety standards and experience gained in the construction and operation of nuclear facilities. I&M may also incur costs and experience reduced output at its Cook Plant because of the design criteria prevailing at the time of construction and the age of the plant's systems and equipment. In addition, for economic or other reasons, operation of the Cook Plant for the full term of its now assumed life cannot be assured. Nuclear industry-wide and Cook Plant initiatives have contributed to slowing the growth of operating and maintenance costs. However, the ability of I&M to obtain adequate and timely recovery of costs associated with the Cook Plant, including replacement power and retirement costs, is not assured. NUCLEAR INCIDENT LIABILITY The Price-Anderson Act limits public liability for a nuclear incident at any licensed reactor in the United States to $8.9 billion. I&M has insurance coverage for liability from a nuclear incident at its Cook Plant. Such coverage is provided through a combination of private liability insurance, with the maximum amount available of $200,000,000, and mandatory participation for the remainder of the $8.9 billion liability, in an industry retrospective deferred premium plan which would, in case of a nuclear incident, assess all licensees of nuclear plants in the U.S. Under the deferred premium plan, I&M could be assessed up to $158,600,000 payable in annual installments of $20,000,000 in the event of a nuclear incident at Cook or any other nuclear plant in the U.S. There is no limit on the number of incidents for which I&M could be assessed these sums. I&M also has property damage, decontamination and decommissioning insurance for loss resulting from damage to the Cook Plant facilities in the amount of $3.6 billion. Energy Insurance Bermuda (EIB), Nuclear Mutual Limited (NML) and Nuclear Electric Insurance Limited (NEIL) provide $2.75 billion of coverage and nuclear insurance pools provide the remainder. If EIB's, NML's and NEIL's losses exceed their available resources, I&M would be subject to a total retrospective premium assessment of up to $33,000,000. NRC regulations require that, in the event of an accident, whenever the estimated costs of reactor stabilization and site decontamination exceed $100,000,000, the insurance proceeds must be used, first, to return the reactor to, and maintain it in, a safe and stable condition and, second, to decontaminate the reactor and reactor station site in accordance with a plan approved by the NRC. The insurers then would indemnify I&M for property damage up to $3.35 billion less any amounts used for stabilization and decontamination. The remaining $250,000,000, as provided by NEIL (reduced by any stabilization and decontamination expenditures over $3.35 billion), would cover decommissioning costs in excess of funds already collected for decommissioning. See FUEL SUPPLY - NUCLEAR WASTE. NEIL's extra-expense program provides insurance to cover extra costs resulting from a prolonged accidental outage of a nuclear unit. I&M's policy insures against such increased costs up to approximately $3,500,000 per week (starting 21 weeks after the outage) for one year, $2,800,000 per week for the second and third years, or 80% of those amounts per unit if both units are down for the same reason. If NEIL's losses exceed its available resources, I&M would be subject to a total retrospective premium assessment of up to $7,900,000. POTENTIAL UNINSURED LOSSES Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including liabilities relating to damage to the Cook Plant and costs of replacement power in the event of a nuclear incident at the Cook Plant. Future losses or liabilities which are not completely insured, unless allowed to be recovered through rates, could have a material adverse effect on results of operations and the financial condition of AEP, I&M and other AEP System companies. Item 3. LEGAL PROCEEDINGS On April 4, 1991, then Secretary of Labor Lynn Martin announced that the U.S. Department of Labor (DOL) had issued a total of 4,710 citations to operators of 847 coal mines who allegedly submitted respirable dust sampling cassettes that had been altered so as to remove a portion of the dust. The cassettes were submitted in compliance with DOL regulations which require systematic sampling of airborne dust in coal mines and submission of the entire cassettes (which include filters for collecting dust particulates) to the Mine Safety and Health Administration (MSHA) for analysis. The amount of dust contained on the cassette's filter determines an operator's compliance with respirable dust standards under the law. OPCo's Meigs No. 2, Meigs No. 31, Martinka, and Windsor Coal mines received 16, 3, 15 and 2 citations, respectively. MSHA has assessed civil penalties totalling $56,900 for all these citations. OPCo's samples in question involve about 1 percent of the 2,500 air samples that OPCo submitted over a 20-month period from 1989 through 1991 to the DOL. OPCo is contesting the citations before the Federal Mine Safety and Health Review Commission. An administrative hearing was held before an administrative law judge with respect to all affected coal operators. On July 20, 1993, the administrative law judge rendered a decision in this case holding that the Secretary of Labor failed to establish that the presence of a "white center" on the dust sampling filter indicated intentional alteration. In the case of an unaffiliated mine, the administrative law judge ruled on April 20, 1994, that there was not an intentional alteration of the dust sampling filter. The Secretary of Labor appealed to the Federal Mine Safety and Health Review Commission the July 20, 1993 and April 20, 1994 administrative law judge decisions and in November 1995 the Commission affirmed these decisions. All remaining cases, including the citations involving OPCo's mines, have been stayed. On September 30, 1994, Federal EPA served APCo and Global Power Company, an independent contractor retained by APCo, with a complaint alleging violations of the Clean Air Act. The complaint is based on alleged violations of the National Emission Standard for Asbestos related to an asbestos abatement project at APCo's Kanawha River Plant. The complaint seeks a civil administrative penalty of $167,500. On October 27, 1994, APCo and Global jointly filed an answer to this complaint and requested both a formal hearing and informal settlement conference. 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 SO{2} 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 SO{2} 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. See Item 1 for a discussion of certain environmental and rate matters. MEIGS MINE: On July 11, 1993, water from an adjoining sealed and abandoned mine owned by Southern Ohio Coal Company (SOCCo), a mining subsidiary of OPCo, entered Meigs 31 mine, one of two mines currently being operated by SOCCo. Ohio EPA approved a plan to pump water from the mine to certain Ohio River tributaries under stringent conditions for biological and water quality monitoring and restoring the streams after pumping. On July 30, pumping commenced in accordance with the Ohio EPA approved plan and, after all water was removed from the mine, the mine was returned to service in February 1994. In April 1994, the U.S. Court of Appeals for the Sixth Circuit reversed the judgement of the U.S. District Court for the Southern District of Ohio which had granted a preliminary injunction to SOCCo preventing Federal EPA and the Federal Office of Surface Mining, Reclamation and Enforcement (OSM) from interfering with the removal of water from SOCCo's Meigs 31 mine. The West Virginia Division of Environmental Protection (West Virginia DEP) had proposed fining SOCCo $1,800,000 for violations of West Virginia Water Quality Standards and permitting requirements alleged to have resulted from the release of mine water into the Ohio River. As a result of the West Virginia DEP proposing to fine SOCCo, SOCCo filed an action on June 1, 1994 in the U.S. District Court for the Southern District of West Virginia seeking a determination that the state of West Virginia has no jurisdiction to impose penalties with respect to the mine water discharges. SOCCo and the West Virginia DEP have entered into a settlement agreement dated May 8, 1995, under which the West Virginia DEP has released SOCCo from any claims which it may have had and SOCCo has made a donation of $260,000 to the Water Quality Management Fund of the West Virginia DEP. SOCCo has entered into a consent decree and settlement agreement with Federal EPA and OSM which was lodged with the U.S. District Court, Southern District of Ohio, on January 30, 1996 and noticed in the FEDERAL REGISTER on February 15, 1996. The decree and settlement agreement resolve all disputes between SOCCo and Federal EPA and OSM over the legality of the removal of water from SOCCo's Meigs 31 mine. Under the terms of the settlement agreement, SOCCo is responsible for the return of pre-pumping biological conditions in the affected streams if those conditions do not return to pre-pumping status under the plan previously agreed to by SOCCo and the Ohio EPA as a condition to the pumping. SOCCo will pay to the U.S. $1,900,000 as compensation for natural resources alleged to have been affected by the mine dewatering. The $1,900,000 will be used to fund Leading Creek watershed enhancement projects in three Ohio counties. Under the settlement agreement, SOCCo is also required to pay to the U.S. $242,200 as reimbursement for costs incurred in monitoring and assessing the effects of its discharge of water. SOCCo will also pay to the U.S. a civil penalty of $300,000. Of this amount, $200,000 is designated as settlement for claims under the Clean Water Act, and $100,000 is designated as settlement for claims under the Surface Mining Control and Reclamation Act. Finally, SOCCo will provide $100,000 to the State of West Virginia for work in the Ohio River for the benefit of Leading Creek on acceptance by the U.S. Fish and Wildlife Service of an acceptable plan from the State. KAMMER PLANT: In August 1994, Federal EPA issued a Notice of Violation (NOV) to OPCo alleging that its Kammer Plant has been operating in violation of applicable federally enforceable air pollution control requirements for sulfur dioxide since at least January 1, 1989. The Clean Air Act provides that Federal EPA may commence a civil action for injunctive relief and/or civil penalties of up to $25,000 per day for each day of violation. On November 15, 1994, a civil complaint containing the allegations included in the NOV was filed by Federal EPA against OPCo in the U.S. District Court, Northern District of West Virginia. A Partial Consent Decree has been entered by the court, extending until May 15, 1996 the date by which OPCo would need to reduce the sulfur content of the fuel supply for Kammer. Negotiations are in an advanced stage to extend the final compliance date beyond May 15, 1996 and to resolve the penalty issues raised by the civil complaint. It is not anticipated that the ultimate resolution of this matter will have a material adverse impact on results of operations. 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 J(2)(c). EXECUTIVE OFFICERS OF THE REGISTRANTS AEP The following persons are, or may be deemed, executive officers of AEP. Their ages are given as of March 15, 1996. NAME AGE OFFICE (a) E. Linn Draper, Jr. 54 Chairman of the Board, President and Chief Executive Officer of AEP and of the Service Corporation Peter J. DeMaria 61 Controller of AEP; Executive Vice President- Administration and Chief Accounting Officer of the Service Corporation William J. Lhota 56 Executive Vice President of the Service Corporation Gerald P. Maloney 63 Vice President and Secretary of AEP; Executive Vice President-Chief Financial Officer of the Service Corporation James J. Markowsky 51 Executive Vice President-Power Generation of the Service Corporation (a)All of the executive officers listed above have been employed by the Service Corporation or System companies in various capacities (AEP, as such, has no employees) during the past five years, except E. Linn Draper, Jr. who was Chairman of the Board, President and Chief Executive Officer of Gulf States Utilities Company from 1987 until 1992 when he joined AEP and the Service Corporation. All of the above officers are appointed annually for a one- year term by the board of directors of AEP, the board of directors of the Service Corporation, or both, as the case may be. APCO The names of the executive officers of APCo, the positions they hold with APCo, their ages as of March 15, 1996, 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. 54 Director 1992-Present Chairman of the Board and Chief Executive Officer 1993-Present Vice President 1992-1993 Chairman of the Board, President and Chief Executive Officer of AEP and the Service Corporation 1993-Present President of AEP 1992-1993 President and Chief Operating Officer of the Service Corporation 1992-1993 Chairman of the Board, President and Chief Executive Officer of Gulf States Utilities Company 1987-1992 Peter J. DeMaria 61 Director 1988-Present Vice President 1991-Present Controller 1995-Present Treasurer 1978-1995 Controller of AEP 1995-Present Treasurer of AEP 1978-1995 Executive Vice President-Administration and Chief Accounting Officer of the Service Corporation 1984-Present Treasurer of the Service Corporation 1989-1990 William J. Lhota 56 Director 1990-Present President and Chief Operating Officer 1996-Present Vice President 1989-1995 Executive Vice President of the Service Corporation 1993-Present Executive Vice President-Operations of the Service Corporation 1989-1993 Gerald P. Maloney 63 Director and Vice President 1970-Present Vice President of AEP 1974-Present Secretary of AEP 1994-Present Executive Vice President-Chief Financial Officer of the Service Corporation 1991-Present Senior Vice President-Finance of the Service Corporation 1974-1990 James J. Markowsky 51 Director 1993-Present Vice President 1995-Present Executive Vice President-Power Generation of the Service Corporation 1996-Present Executive Vice President-Engineering and Construction of the Service Corporation 1993-1996 Senior Vice President and Chief Engineer of the Service Corporation 1988-1993 (a) Positions are with APCo unless otherwise indicated. OPCO The names of the executive officers of OPCo, the positions they hold with OPCo, their ages as of March 15, 1996, 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. 54 Director 1992-Present Chairman of the Board and Chief Executive Officer 1993-Present Vice President 1992-1993 Chairman of the Board, President and Chief Executive Officer of AEP and the Service Corporation 1993-Present President of AEP 1992-1993 President and Chief Operating Officer of the Service Corporation 1992-1993 Chairman of the Board, President and Chief Executive Officer of Gulf States Utilities Company 1987-1992 Peter J. DeMaria 61 Director 1978-Present Vice President 1991-Present Controller 1995-Present Treasurer 1978-1995 Controller of AEP 1995-Present Treasurer of AEP 1978-1995 Executive Vice President-Administration and Chief Accounting Officer of the Service Corporation 1984-Present Treasurer of the Service Corporation 1989-1990 William J. Lhota 56 Director 1989-Present President and Chief Operating Officer 1996-Present Vice President 1989-1995 Executive Vice President of the Service Corporation 1993-Present Executive Vice President-Operations of the Service Corporation 1989-1993 Gerald P. Maloney 63 Director 1973-Present Vice President 1970-Present Vice President of AEP 1974-Present Secretary of AEP 1994-Present Executive Vice President-Chief Financial Officer of the Service Corporation 1991-Present Senior Vice President-Finance of the Service Corporation 1974-1990 James J. Markowsky 51 Director 1989-Present Vice President 1995-Present Executive Vice President-Power Generation of the Service Corporation 1996-Present Executive Vice President-Engineering and Construction of the Service Corporation 1993-1996 Senior Vice President and Chief Engineer of the Service Corporation 1988-1993 (a) Positions are with OPCo unless otherwise indicated. PART II Item 5.MARKET FOR REGISTRANTS' COMMON EQUITY AND RELATED STOCKHOLDER MATTERS AEP. AEP Common Stock is traded principally on the New York Stock Exchange. The following table sets forth for the calendar periods indicated the high and low sales prices for the Common Stock as reported on the New York Stock Exchange Compsite Tape and the amount of cash dividends paid per share of Common Stock. At December 31, 1995, AEP had approximately 170,980 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. PER SHARE MARKET PRICE QUARTER ENDED HIGH LOW DIVIDEND(1) March 1994 $37-3/8 $29-7/8 $.60 June 1994 32-7/8 27-1/4 .60 September 1994 31-3/4 28 .60 December 1994 33-5/8 30-1/2 .60 March 1995 35-3/4 31-1/4 .60 June 1995 35-3/8 31-1/2 .60 September 1995 36-1/2 33-5/8 .60 December 1995 40-5/8 35-7/8 .60 (1)See Note 5 of the Notes to the Consolidated Financial Statements of AEP for information regarding restrictions on payment of dividends.
Item 6. SELECTED FINANCIAL DATA AEGCO. Omitted pursuant to Instruction J(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 1995 Annual Report (for the fiscal year ended December 31, 1995). APCO. The information required by this item is incorporated herein by reference to the material under SELECTED CONSOLIDATED FINANCIAL DATA in the APCo 1995 Annual Report (for the fiscal year ended December 31, 1995). CSPCO. Omitted pursuant to Instruction J(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 1995 Annual Report (for the fiscal year ended December 31, 1995). KEPCO. Omitted pursuant to Instruction J(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 1995 Annual Report (for the fiscal year ended December 31, 1995). Item 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION AEGCO. Omitted pursuant to Instruction J(2)(a). Management's narrative analysis of the results of operations and other information required by Instruction J(2)(a) is incorporated herein by reference to the material under MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS in the AEGCo 1995 Annual Report (for the fiscal year ended December 31, 1995). 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 1995 Annual Report (for the fiscal year ended December 31, 1995). 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 1995 Annual Report (for the fiscal year ended December 31, 1995). CSPCO. Omitted pursuant to Instruction J(2)(a). Management's narrative analysis of the results of operations and other information required by Instruction J(2)(a) is incorporated herein by reference to the material under MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS in the CSPCo 1995 Annual Report (for the fiscal year ended December 31, 1995). 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 1995 Annual Report (for the fiscal year ended December 31, 1995). KEPCO. Omitted pursuant to Instruction J(2)(a). Management's narrative analysis of the results of operations and other information required by Instruction J(2)(a) is incorporated herein by reference to the material under MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS in the KEPCo 1995 Annual Report (for the fiscal year ended December 31, 1995). 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 1995 Annual Report (for the fiscal year ended December 31, 1995). Item 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA AEGCO. The information required by this item is incorporated herein by reference to the financial statements and supplementary data described under Item 14 herein. AEP. The information required by this item is incorporated herein by reference to the financial statements and supplementary data described under Item 14 herein. APCO. The information required by this item is incorporated herein by reference to the financial statements and supplementary data described under Item 14 herein. CSPCO. The information required by this item is incorporated herein by reference to the financial statements and supplementary data described under Item 14 herein. I&M. The information required by this item is incorporated herein by reference to the financial statements and supplementary data described under Item 14 herein. KEPCO. The information required by this item is incorporated herein by reference to the financial statements and supplementary data described under Item 14 herein. OPCO. The information required by this item is incorporated herein by reference to the financial statements and supplementary data described under Item 14 herein. Item 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE AEGCO, AEP, APCO, CSPCO, I&M, KEPCO AND OPCO. None. PART III Item 10.DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS AEGCO. Omitted pursuant to Instruction J(2)(c). AEP. The information required by this item is incorporated herein by reference to the material under NOMINEES FOR DIRECTOR and SHARE OWNERSHIP OF DIRECTORS AND EXECUTIVE OFFICERS of the definitive proxy statement of AEP, dated March 9, 1996, for the 1996 annual meeting of shareholders. Reference also is made to the information under the caption EXECUTIVE OFFICERS OF THE REGISTRANTS in Part I of this report. APCO. The information required by this item is incorporated herein by reference to the material under ELECTION OF DIRECTORS of the definitive information statement of APCo for the 1996 annual meeting of stockholders, to be filed within 120 days after December 31, 1995. 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 J(2)(c). I&M. The names of the directors and executive officers of I&M, the positions they hold with I&M, their ages as of March 15, 1996, 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. 54 Director 1992-Present Chairman of the Board and Chief Executive Officer 1993-Present Vice President 1992-1993 Chairman of the Board, President and Chief Executive Officer of AEP and of the Service Corporation 1993-Present President of AEP 1992-1993 President and Chief Operating Officer of the Service Corporation 1992-1993 Chairman of the Board, President and Chief Executive Officer of Gulf States Utilities Company 1987-1992 Peter J. DeMaria 61 Director 1992-Present Vice President 1991-Present Controller 1995-Present Treasurer 1978-1995 Controller of AEP 1995-Present Treasurer of AEP 1978-1995 Executive Vice President-Administration and Chief Accounting Officer of the Service Corporation 1984-Present Treasurer of the Service Corporation 1989-1990 William N. D'Onofrio 48 Director 1984-Present Vice President 1984-1995 Director-Regions of the Service Corporation 1996-Present William J. Lhota 56 Director 1989-Present President and Chief Operating Officer 1996-Present Vice President 1989-1995 Executive Vice President of the Service Corporation 1993-Present Executive Vice President-Operations of the Service Corporation 1989-1993 Gerald P. Maloney 63 Director 1978-Present Vice President 1970-Present Vice President of AEP 1974-Present Secretary of AEP 1994-Present Executive Vice President-Chief Financial Officer of the Service Corporation 1991-Present Senior Vice President-Finance of the Service Corporation 1974-1990 James J. Markowsky 51 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 A. H. Potter 48 Director 1994-Present Transmission and Distribution Director 1987-Present D. M. Trenary 59 Director 1994-Present Indiana Region Manager 1994-Present Division Manager 1989-1994 W. E. Walters 48 Director 1991-Present Michiana Region Manager 1994-Present Executive Assistant to President 1987-1994 C. R. Boyle, III 48 Director and Vice President 1996-Present President and Chief Operating Officer of KEPCo1990-1995 G. A. Clark 44 Director 1995-Present Governmental Affairs Manager 1996-Present General Counsel 1994-1995 General Attorney 1991-1993 D. B. Synowiec 52 Director 1995-Present Plant Manager 1990-Present J. H. Vipperman 55 Director and Vice President 1996-Present Executive Vice President- Energy Delivery of the Service Corporation 1996-Present President and Chief Operating Officer of APCo 1990-1995 (a) Positions are with I&M unless otherwise indicated. (b) Dr. Draper is a director of VECTRA Technologies, Inc. and Mr. Lhota is a director of Huntington Bancshares Incorporated. (c) Drs. Draper and Markowsky and Messrs. DeMaria, Lhota and Maloney are directors of AEGCo, APCo, CSPCo, KEPCo and OPCo. Dr. Draper and Messrs. DeMaria and Maloney are also directors of AEP. Mr. Vipperman is a director of APCo, CSPCo, KEPCo and OPCo. KEPCo. Omitted pursuant to Instruction J(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 1996 annual meeting of shareholders, to be filed within 120 days after December 31, 1995. 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 J(2)(c). AEP. The information required by this item is incorporated herein by reference to the material under COMPENSATION OF DIRECTORS, EXECUTIVE COMPENSATION and the performance graph of the definitive proxy statement of AEP, dated March 9, 1996, for the 1996 annual meeting of shareholders. APCO. The information required by this item is incorporated herein by reference to the material under EXECUTIVE COMPENSATION of the definitive information statement of APCo for the 1996 annual meeting of stockholders, to be filed within 120 days after December 31, 1995. CSPCO. Omitted pursuant to Instruction J(2)(c). KEPCO. Omitted pursuant to Instruction J(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 1996 annual meeting of shareholders, to be filed within 120 days after December 31, 1995. 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 1995, 1994 and 1993 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, 1995. SUMMARY COMPENSATION TABLE
LONG-TERM ANNUAL COMPENSATION COMPENSATION All Other Salary Bonus PAYOUTS Compensation NAME AND PRINCIPAL POSITION YEAR ($) ($)(1) LTIP PAYOUTS($)(1) ($)(2) E. LINN DRAPER, JR. - chairman of the board, 1995 685,000 236,325 334,851 30,790 president and chief executive officer of the 1994 620,000 209,436 137,362 29,385 Company and the Service Corporation; chairman 1993 538,333 148,742 18,180 and chief executive officer of other subsidiaries PETER J. DEMARIA - Controller and director of the 1995 330,000 113,850 143,829 20,050 Company; executive vice president-administration 1994 305,000 103,029 59,032 18,750 and chief accounting officer and director of the 1993 280,000 77,364 17,811 Service Corporation; vice president, controller and director of other subsidiaries G. P. MALONEY - Vice president, secretary and 1995 330,000 113,850 141,582 20,060 director of the Company; executive vice president 1994 300,000 101,340 58,094 19,745 - chief financial officer and director of the 1993 269,000 74,325 18,000 Service Corporation; vice president and director of other subsidiaries WILLIAM J. LHOTA - Executive vice president and 1995 300,000 103,500 132,592 19,140 director of the Service Corporation; president, 1994 280,000 94,584 54,409 19,185 chief operating officer and director of other 1993 249,000 68,799 17,160 subsidiaries JAMES J. MARKOWSKY - Executive vice president 1995 285,000 98,325 126,599 17,515 - power generation and director of the Service 1994 267,000 90,193 51,930 14,755 Corporation; vice president and director of 1993 247,000 65,259 11,165 other subsidiaries (1)Amounts in the "Bonus" column reflect payments under the Management Incentive Compensation Plan for performance measured for each of the years ended December 31, 1993, 1994 and 1995. Payments are made in March of the subsequent year. Amounts for 1995 are estimates but should not change significantly. Amounts in the "Long-Term Compensation" column reflect performance share units earned under the Performance Share Incentive Plan (which became effective January 1, 1994) for the one-year and two-year transition performance periods ending December 31, 1994 and 1995, respectively. For 1995, their value was calculated by multiplying the $40.50 closing price of AEP's Common Stock as reported on the New York Stock Exchange on December 29, 1995, the last trading day of fiscal year 1995, by the number of units earned. See below under "Long-Term Incentive Plans - Awards in 1995" and pages 13 and 14 for additional information. (2)For 1995, includes (i) employer matching contributions under the AEP System Employees Savings Plan: $4,500 for each of the named executive officers; (ii) employer matching contributions under the AEP System Supplemental Savings Plan (which became effective January 1, 1994), a non-qualified plan designed to supplement the AEP Savings Plan: Dr. Draper, $16,050; Mr. DeMaria, $5,400; Mr. Maloney, $5,400; Mr. Lhota, $4,500; and Dr. Markowsky, $4,050; and (iii) subsidiary companies director fees: Dr. Draper, $10,240; Mr. DeMaria, $10,150; Mr. Maloney, $10,160; Mr. Lhota, $10,140; and Dr. Markowsky, $8,965. LONG-TERM INCENTIVE PLANS - AWARDS IN 1995 Each of the awards set forth below constitutes a grant of performance share units, 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 units were granted in the form of shares of Common Stock are not included in the table. The ability to earn performance share units 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 units are earned unless AEP shareholders realize a positive TSR over the relevant three-year performance period. The Human Resources Committee may, at its discretion, reduce the number of performance share units 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 units held. No payment will be made for performance below the threshold. Payments of earned awards are deferred in the form of restricted stock units (equivalent to shares of AEP Common Stock) until the officer has met the equivalent stock ownership target discussed in the Human Resources Committee Report. Once officers meet and maintain their respective targets, they may elect either to continue to defer or to receive further earned awards in cash and/or Common Stock.
ESTIMATED FUTURE PAYOUTS OF PERFORMANCE PERFORMANCE SHARE UNITS UNDER NUMBER OF PERIOD UNTIL NON-STOCK PRICE-BASED PLAN Performance Maturation Threshold Target Maximum NAME SHARE UNITS OR PAYOUT (#) (#) (#) E. L. Draper, Jr. 8,302 1995-1997 2,075 8,302 16,604 P. J. DeMaria 3,499 1995-1997 875 3,499 6,998 G. P. Maloney 3,499 1995-1997 875 3,499 6,998 W. J. Lhota 3,181 1995-1997 795 3,181 6,362 J. J. Markowsky 3,022 1995-1997 755 3,022 6,044
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
HIGHEST AVERAGE YEARS OF ACCREDITED SERVICE ANNUAL EARNINGS 15 20 25 30 35 40 45 $ 300,000 $ 69,930 $ 93,240 $116,550 $139,860 $163,170 $183,120 $203,070 400,000 93,930 125,240 156,550 187,860 219,170 245,770 272,370 500,000 117,930 157,240 196,550 235,860 275,170 308,420 341,670 700,000 165,930 221,240 276,550 331,860 387,170 433,720 480,270 900,000 213,930 285,240 356,550 427,860 499,170 559,020 618,870 1,100,000 261,930 349,240 436,550 523,860 611,170 684,320 757,470
The amounts shown in the table are the straight life annuities payable under the Retirement Plan without reduction for the joint and survivor annuity. Retirement benefits listed in the table are not subject to any deduction for Social Security or other offset amounts. The retirement annuity is reduced 3% per year in the case of retirement between ages 60 and 62 and further reduced 6% per year in the case of retirement between ages 55 and 60. If an employee retires after age 62, there is no reduction in the retirement annuity. The Company maintains a supplemental retirement plan which provides for the payment of benefits that are not payable under the Retirement Plan due primarily to limitations imposed by Federal tax law on benefits paid by qualified plans. The table includes supplemental retirement benefits. Compensation upon which retirement benefits are based, for the executive officers named in the Summary Compensation Table above, consists of the average of the 36 consecutive months of the officer's highest aggregate salary and Management Incentive Compensation Plan awards, shown in the "Salary" and "Bonus" columns, respectively, of the Summary Compensation Table, out of the officer's most recent 10 years of service. As of December 31, 1995, the number of full years of service applicable for retirement benefit calculation purposes for such officers were as follows: Dr. Draper, three years; Mr. DeMaria, 36 years; Mr. Maloney, 40 years; Mr. Lhota, 31 years; and Dr. Markowsky, 24 years. Dr. Draper's employment agreement described below 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. The Company will pay supplemental retirement benefits to 19 AEP System employees (including Messrs. DeMaria, Maloney and Lhota and Dr. Markowsky) whose pensions may be adversely affected by amendments to the Retirement Plan made as a result of the Tax Reform Act of 1986. Such payments, if any, will be equal to any reduction occurring because of such amendments. Assuming retirement in 1996 of the executive officers named in the Summary Compensation Table, only Mr. Maloney would be affected and his annual supplemental benefit would be $972. The Company made available a voluntary deferred-compensation program in 1982 and 1986, which permitted certain members of AEP System management to defer receipt of a portion of their salaries. Under this program, a participant was able to defer up to 10% or 15% annually (depending on the terms of the program offered), over a four-year period, of his or her salary, and receive supplemental retirement or survivor benefit payments over a 15-year period. The amount of supplemental retirement payments received is dependent upon the amount deferred, age at the time the deferral election was made, and number of years until the participant retires. The following table sets forth, for the executive officers named in the Summary Compensation Table, the amounts of annual deferrals and, assuming retirement at age 65, annual supplemental retirement payments under the 1982 and 1986 programs.
1982 PROGRAM 1986 PROGRAM Annual Amount of Annual Amount of Annual Supplemental Annual Supplemental Amount Retirement Amount Retirement Deferred Payment Deferred Payment NAME (4-YEAR PERIOD) (15-YEAR PERIOD) (4-YEAR PERIOD) (15-YEAR PERIOD) P. J. DeMaria $10,000 $52,000 $13,000 $53,300 G. P. Maloney 15,000 67,500 16,000 56,400
EMPLOYMENT AGREEMENT Dr. Draper has a contract with the Company and AEP Service Corporation which provides for his employment for an initial term from no later than March 15, 1992 until March 15, 1997. Dr. Draper commenced his employment with the Company and AEP Service Corporation on March 1, 1992. The Company or AEP Service Corporation may terminate the contract at any time and, if this is done for reasons other than cause and other than as a result of Dr. Draper's death or permanent disability, AEP Service Corporation must pay Dr. Draper's then base salary through March 15, 1997, less any amounts received by Dr. Draper from other employment. Directors of I&M receive a fee of $100 for each meeting of the Board of Directors attended in addition to their salaries. The AEP System is an integrated electric utility system and, as a result, the member companies of the AEP System have contractual, financial and other business relationships with the other member companies, such as participation in the AEP System savings and retirement plans and tax returns, sales of electricity, transportation and handling of fuel, sales or rentals of property and interest or dividend payments on the securities held by the companies' respective parents. Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AEGCO. Omitted pursuant to Instruction J(2)(c). AEP. The information required by this item is incorporated herein by reference to the material under Share Ownership of Directors and Executive Officers of the definitive proxy statement of AEP, dated March 9, 1996, for the 1996 annual meeting of shareholders. APCO. The information required by this item is incorporated herein by reference to the material under Share Ownership of Directors and Executive Officers in the definitive information statement of APCo for the 1995 annual meeting of stockholders, to be filed within 120 days after December 31, 1995. CSPCO. Omitted pursuant to Instruction J(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, 1996, by each director and nominee of I&M and each of the executive officers of I&M named in the summary compensation table, and by all directors and executive officers of I&M as a group. It is based on information provided to I&M by such persons. No such person owns any shares of any series of the Cumulative Preferred Stock of I&M. Unless otherwise noted, each person has sole voting power and investment power over the number of shares of AEP Common Stock and stock-based units set forth opposite his name. Fractions of shares and units have been rounded to the nearest whole number.
STOCK NAME SHARES UNITS(a) TOTAL Coulter R. Boyle, III 3,470(b) 629 4,099 Gregory A. Clark 833(b) 327 1,160 Peter J. DeMaria 7,356(b)(c)(d)(e)(f) 5,391 12,747 William N. D'Onofrio 4,154(b)(e) 492 4,646 E. Linn Draper, Jr. 6,119(b)(e) 11,984 18,103 William J. Lhota 13,064(b)(d)(e) 4,944 18,008 Gerald P. Maloney 5,227(b)(d)(e) 5,306 10,533 James J. Markowsky 6,631(b)(f) 4,714 11,345 Albert H. Potter 3,084(b)(e) - 3,084 David B. Synowiec 2,214(b) 398 2,612 Dale M. Trenary 64(b) 412 476 Joseph H. Vipperman 5,092(b)(e) 3,365 8,457 William E. Walters 4,738(b) 278 5,016 All Directors and Executive Officers 147,277(d)(g) 38,240 185,517
(a)This column includes amounts deferred in stock units and held under the Management Incentive Compensation Plan and Performance Share Incentive Plan. (b)Includes shares and share equivalents held in the following plans in the amounts listed below:
AEP EMPLOYEE STOCK AEP PERFORMANCE AEP EMPLOYEES SAVINGS OWNERSHIP PLAN (SHARES) SHARE INCENTIVE PLAN (SHARES)PLAN (SHARE EQUIVALENTS) Mr. Boyle 47 316 3,107 Mr. Clark 8 - 825 Mr. DeMaria 83 944 2,705 Mr. D'Onofrio 59 - 3,595 Dr. Draper - 2,196 1,958 Mr. Lhota 60 812 10,824 Mr. Maloney 85 867 2,775 Dr. Markowsky 66 830 5,718 Mr. Potter 41 - 3,029 Mr. Synowiec 53 - 2,161 Mr. Trenary 41 - 23 Mr. Vipperman 80 564 4,391 Mr. Walters 45 - 4,693 All Directors and Executive Officers 668 6,529 45,804
With respect to the shares and share equivalents held in these plans, such persons have sole voting power, but the investment/disposition power is subject to the terms of such plans. (c)Mr. DeMaria owns 100 shares of Cumulative Preferred Shares 9.50% Series, $100 par value, of Columbus Southern Power Company. (d)Does not include, for Messrs. DeMaria, Lhota and Maloney, 85,231 shares in the American Electric Power System Educational Trust Fund over which Messrs. DeMaria, Lhota and Maloney share voting and investment power as trustees (they disclaim beneficial ownership). The amount of shares shown for all directors and executive officers as a group includes these shares. (e)Includes the following numbers of shares held in joint tenancy with a family member: Mr. DeMaria, 1,232; Mr. D'Onofrio, 500; Dr. Draper, 1,965; Mr. Lhota, 1,368; Mr. Maloney, 1,500; Mr. Potter, 14; and Mr. Vipperman, 57. (f)Includes the following numbers of shares held by family members over which beneficial ownership is disclaimed: Mr. DeMaria, 2,392; and Dr. Markowsky, 17. (g)Represents less than 1% of the total number of shares outstanding. KEPCO. Omitted pursuant to Instruction J(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 1996 annual meeting of shareholders, to be filed within 120 days after December 31, 1995. Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AEP. The information required by this item is incorporated herein by reference to the material under Transactions With Management of the definitive proxy statement of AEP, dated March 9, 1996, for the 1996 annual meeting of shareholders. APCO, I&M AND OPCO. None. AEGCO, CSPCO, AND KEPCO. Omitted pursuant to Instruction J(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. AEGCo: Independent Auditors' Report; Statements of Income for the years ended December 31, 1995, 1994 and 1993; Statements of Retained Earnings for the years ended December 31, 1995, 1994 and 1993; Statements of Cash Flows for the years ended December 31, 1995, 1994 and 1993; Balance Sheets as of December 31, 1995 and 1994; Notes to Financial Statements. AEP and its subsidiaries consolidated: Consolidated Statements of Income for the years ended December 31, 1995, 1994 and 1993; Consolidated Statements of Retained Earnings for the years ended December 31, 1995, 1994 and 1993; Consolidated Statements of Cash Flows for the years ended December 31, 1995, 1994 and 1993; Consolidated Balance Sheets as of December 31, 1995 and 1994; Notes to Consolidated Financial Statements; Schedule of Consolidated Cumulative Preferred Stocks of Subsidiaries at December 31, 1995 and 1994; Schedule of Consolidated Long-term Debt of Subsidiaries at December 31, 1995 and 1994; Independent Auditors' Report. APCo: Independent Auditors' Report; Consolidated Statements of Income for the years ended December 31, 1995, 1995 and 1994; Consolidated Balance Sheets as of December 31, 1995 and 1994; Consolidated Statements of Cash Flows for the years ended December 31, 1995, 1994 and 1993; Consolidated Statements of Retained Earnings for the years ended December 31, 1995, 1994 and 1993; Notes to Consolidated Financial Statements. CSPCo: Independent Auditors' Report; Consolidated Statements of Income for the years ended December 31, 1995, 1994 and 1993; Consolidated Balance Sheets as of December 31, 1995 and 1994; Consolidated Statements of Cash Flows for the years ended December 31, 1995, 1994 and 1993; Consolidated Statements of Retained Earnings for the years ended December 31, 1995, 1994 and 1993; Notes to Consolidated Financial Statements. I&M: Independent Auditors' Report; Consolidated Statements of Income for the years ended December 31, 1995, 1994 and 1993; Consolidated Balance Sheets as of December 31, 1995 and 1994; Consolidated Statements of Cash Flows for the years ended December 31, 1995, 1994 and 1993; Consolidated Statements of Retained Earnings for the years ended December 31, 1995, 1994 and 1993; Notes to Consolidated Financial Statements. KEPCo: Independent Auditors' Report; Statements of Income for the years ended December 31, 1995, 1994 and 1993; Statements of Retained Earnings for the years ended December 31, 1995, 1994 and 1993; Balance Sheets as of December 31, 1995 and 1994; Statements of Cash Flows for the years ended December 31, 1995, 1994 and 1993; Notes to Financial Statements. OPCo: Independent Auditors' Report; Consolidated Statements of Income for the years ended December 31, 1995, 1994 and 1993; Consolidated Balance Sheets as of December 31, 1995 and 1994; Consolidated Statements of Cash Flows for the years ended December 31, 1995, 1994 and 1993; Consolidated Statements of Retained Earnings for the years ended December 31, 1995, 1994 and 1993; 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, 1995. SIGNATURES PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED. THE SIGNATURE OF THE UNDERSIGNED COMPANY SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING REFERENCE TO SUCH COMPANY AND ANY SUBSIDIARIES THEREOF. AEP GENERATING COMPANY BY: /S/ G. P. MALONEY (G. P. MALONEY, VICE PRESIDENT) Date: March 25, 1996 PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED. THE SIGNATURE OF EACH OF THE UNDERSIGNED SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING REFERENCE TO THE ABOVE-NAMED COMPANY AND ANY SUBSIDIARIES THEREOF.
SIGNATURE TITLE DATE (i) Principal Executive Officer: *E. LINN DRAPER, JR. President, Chief Executive Officer and Director (II) PRINCIPAL FINANCIAL OFFICER: /S/ G. P. MALONEY Vice President March 25, 1996 (G. P. MALONEY) and Director (III) PRINCIPAL ACCOUNTING OFFICER: /S/ P. J. DEMARIA Vice President, (P. J. DEMARIA) Controller March 25, 1996 and Director (IV) A MAJORITY OF THE DIRECTORS: *HENRY FAYNE *JOHN R. JONES, III *WM. J. LHOTA *JAMES J. MARKOWSKY *By: /S/ G. P. MALONEY March 25, 1996 (G. P. MALONEY, ATTORNEY-IN-FACT)
SIGNATURES PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED. AMERICAN ELECTRIC POWER COMPANY, INC. BY: /S/ G. P. MALONEY (G. P. MALONEY, VICE PRESIDENT) Date: March 25, 1996 PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED.
SIGNATURE TITLE DATE (i) Principal Executive Officer: *E. LINN DRAPER, JR. Chairman of the Board, President, Chief Executive Officer and Director (II) PRINCIPAL FINANCIAL OFFICER: /S/ G. P. MALONEY Vice President, March 25, 1996 (G. P. MALONEY) Secretary and Director (III) PRINCIPAL ACCOUNTING OFFICER: /S/ P. J. DEMAA Controller and Director March 25, 1996 (P. J. DEMARIA) (IV) A MAJORITY OF THE DIRECTORS: *ROBERT M. DUNCAN *ROBERT W. FRI *ARTHUR G. HANSEN *LESTER A. HUDSON, JR. *ANGUS E. PEYTON *TOY F. REID *DONALD G. SMITH *LINDA GILLESPIE STUNTZ *MORRIS TANENBAUM *ANN HAYMOND ZWINGER *By: /S/ G. P. MALONEY March 25, 1996 (G. P. MALONEY, ATTORNEY-IN-FACT)
SIGNATURES PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED. THE SIGNATURE OF THE UNDERSIGNED COMPANY SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING REFERENCE TO SUCH COMPANY AND ANY SUBSIDIARIES THEREOF. APPALACHIAN POWER COMPANY BY: /S/ G. P. MALONEY (G. P. MALONEY, VICE PRESIDENT) Date: March 25, 1996 PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED. THE SIGNATURE OF EACH OF THE UNDERSIGNED SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING REFERENCE TO THE ABOVE-NAMED COMPANY AND ANY SUBSIDIARIES THEREOF.
SIGNATURE TITLE DATE (i) Principal Executive Officer: *E. LINN DRAPER, JR. Chairman of the Board, Chief Executive Officer and Director (II) PRINCIPAL FINANCIAL OFFICER: /S/ G. P. MALONEY Vice President March 25, 1996 (G. P. MALONEY) and Director (III) PRINCIPAL ACCOUNTING OFFICER: /S/ P. J. DEMARIA Vice President, March 25, 1996 (P. J. DEMARIA) Controller and Director (IV) A MAJORITY OF THE DIRECTORS: *HENRY FAYNE *WM. J. LHOTA *JAMES J. MARKOWSKY *J. H. VIPPERMAN *By: /S/ G. P. MALONEY March 25, 1996 (G. P. MALONEY, ATTORNEY-IN-FACT)
SIGNATURES PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED. THE SIGNATURE OF THE UNDERSIGNED COMPANY SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING REFERENCE TO SUCH COMPANY AND ANY SUBSIDIARIES THEREOF. COLUMBUS SOUTHERN POWER COMPANY BY: /S/ G. P. MALONEY (G. P. MALONEY, VICE PRESIDENT) Date: March 25, 1996 PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED. THE SIGNATURE OF EACH OF THE UNDERSIGNED SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING REFERENCE TO THE ABOVE-NAMED COMPANY AND ANY SUBSIDIARIES THEREOF.
SIGNATURE TITLE DATE (i) Principal Executive Officer: *E. LINN DRAPER, JR. Chairman of the Board, Chief Executive Officer and Director (II) PRINCIPAL FINANCIAL OFFICER: /S/ G. P. MALONEY Vice President March 25, 1996 (G. P. MALONEY) and Director (III) PRINCIPAL ACCOUNTING OFFICER: /S/ P. J. DEMARIA Vice President, ControllerMarch 25, 1996 (P. J. DEMARIA) Controller and Director (IV) A MAJORITY OF THE DIRECTORS: *HENRY FAYNE *WM. J. LHOTA *JAMES J. MARKOWSKY *J. H. VIPPERMAN *By: /S/ G. P. MALONEY March 25, 1996 (G. P. MALONEY, ATTORNEY-IN-FACT)
SIGNATURES PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED. THE SIGNATURE OF THE UNDERSIGNED COMPANY SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING REFERENCE TO SUCH COMPANY AND ANY SUBSIDIARIES THEREOF. INDIANA MICHIGAN POWER COMPANY BY: /S/ G. P. MALONEY (G. P. MALONEY, VICE PRESIDENT) Date: March 25, 1996 PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED. THE SIGNATURE OF EACH OF THE UNDERSIGNED SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING REFERENCE TO THE ABOVE-NAMED COMPANY AND ANY SUBSIDIARIES THEREOF.
SIGNATURE TITLE DATE (i) Principal Executive Officer: *E. LINN DRAPER, JR. Chairman of the Board, Chief Executive Officer and Director (II) PRINCIPAL FINANCIAL OFFICER: /S/ G. P. MALONEY Vice President March 25, 1996 (G. P. MALONEY) and Director (III) PRINCIPAL ACCOUNTING OFFICER: /S/ P. J. DEMARIA Vice President, March 25, 1996 (P. J. DEMARIA) Controller and Director (IV) A MAJORITY OF THE DIRECTORS: *C. R. BOYLE, III *G. A. CLARK *W. N. D'ONOFRIO *WM. J. LHOTA *JAMES J. MARKOWSKY *A. H. POTTER *D. B. SYNOWIEC *D. M. TRENARY *J. H. VIPPERMAN *W. E. WALTERS *By: /S/ G. P. MALONEY March 25, 1996 (G. P. MALONEY, ATTORNEY-IN-FACT)
SIGNATURES PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED. THE SIGNATURE OF THE UNDERSIGNED COMPANY SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING REFERENCE TO SUCH COMPANY AND ANY SUBSIDIARIES THEREOF. KENTUCKY POWER COMPANY BY: /S/ G. P. MALONEY (G. P. MALONEY, VICE PRESIDENT) Date: March 25, 1996 PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED. THE SIGNATURE OF EACH OF THE UNDERSIGNED SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING REFERENCE TO THE ABOVE-NAMED COMPANY AND ANY SUBSIDIARIES THEREOF.
SIGNATURE TITLE DATE (i) Principal Executive Officer: *E. LINN DRAPER, JR. Chairman of the Board, Chief Executive Officer and Director (II) PRINCIPAL FINANCIAL OFFICER: /S/ G. P. MALONEY Vice President March 25, 1996 (G. P. MALONEY) and Director (III) PRINCIPAL ACCOUNTING OFFICER: /S/ P. J. DEMARIA Vice President, March 25, 1996 (P. J. DEMARIA) Controller and Director (IV) A MAJORITY OF THE DIRECTORS: *WM. J. LHOTA *JAMES J. MARKOWSKY *J. H. VIPPERMAN *By: /S/ G. P. MALONEY March 25, 1996 (G. P. MALONEY, ATTORNEY-IN-FACT)
SIGNATURES PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED. THE SIGNATURE OF THE UNDERSIGNED COMPANY SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING REFERENCE TO SUCH COMPANY AND ANY SUBSIDIARIES THEREOF. OHIO POWER COMPANY BY: /S/ G. P. MALONEY (G. P. MALONEY, VICE PRESIDENT) Date: March 25, 1996 PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED. THE SIGNATURE OF EACH OF THE UNDERSIGNED SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING REFERENCE TO THE ABOVE-NAMED COMPANY AND ANY SUBSIDIARIES THEREOF.
SIGNATURE TITLE DATE (i) Principal Executive Officer: *E. LINN DRAPER, JR. Chairman of the Board, Chief Executive Officer and Director (II) PRINCIPAL FINANCIAL OFFICER: /S/ G. P. MALONEY Vice President March 25, 1996 (G. P. MALONEY) and Director (III) PRINCIPAL ACCOUNTING OFFICER: /S/ P. J. DEMARIA Vice President, March 25, 1996 (P. J. DEMARIA) Controller and Director (IV) A MAJORITY OF THE DIRECTORS: *HENRY FAYNE *WM. J. LHOTA *JAMES J. MARKOWSKY *J. H. VIPPERMAN *By: /S/ G. P. MALONEY March 25, 1996 (G. P. MALONEY, ATTORNEY-IN-FACT)
INDEX TO FINANCIAL STATEMENT SCHEDULES PAGE INDEPENDENT AUDITORS' REPORT S-2 The following financial statement schedules for the years ended December 31, 1995, 1994 and 1993 are included in this report on the pages indicated. AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Schedule II- Valuation and Qualifying Accounts and Reserves S-3 APPALACHIAN POWER COMPANY AND SUBSIDIARIES Schedule II- Valuation and Qualifying Accounts and Reserves S-3 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Schedule II- Valuation and Qualifying Accounts and Reserves S-3 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Schedule II- Valuation and Qualifying Accounts and Reserves S-4 KENTUCKY POWER COMPANY Schedule II- Valuation and Qualifying Accounts and Reserves S-4 OHIO POWER COMPANY AND SUBSIDIARIES Schedule II- Valuation and Qualifying Accounts and Reserves S-4 INDEPENDENT AUDITORS' REPORT AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARIES: We have audited the consolidated financial statements of American Electric Power Company, Inc. and its subsidiaries and the financial statements of certain of its subsidiaries, listed in Item 14 herein, as of December 31, 1995 and 1994, and for each of the three years in the period ended December 31, 1995, and have issued our reports thereon dated February 27, 1996; such financial statements and reports are included in your respective 1995 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 27, 1996
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, 1995 $4,056 $12,907 $ 5,927(a) $17,460(b) $5,430 Year Ended December 31, 1994 $4,048 $20,265 $(3,556)(a) $16,701(b) $4,056 Year Ended December 31, 1993 $7,287 $14,237 $ 4,163(a) $21,639(b) $4,048
(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, 1995 $ 830 $ 3,442 $ 963 (a) $ 2,982(b) $2,253 Year Ended December 31, 1994 $1,344 $ 2,297 $ 596 (a) $ 3,407(b) $ 830 Year Ended December 31, 1993 $ 724 $ 3,392 $ 627 (a) $ 3,399(b) $1,344
(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) Deducted from Assets: Accumulated Provision for Uncollectible Accounts: Year Ended December 31, 1995 $1,768 $ 4,873 $ 3,531(a) $ 9,111(b) $1,061 Year Ended December 31, 1994 $ 991 $ 6,181 $ 2,778(a) $ 8,182(b) $1,768 Year Ended December 31, 1993 $1,332 $ 4,167 $ 2,106(a) $ 6,614(b) $ 991
(a) Recoveries on accounts previously written off. (b) Uncollectible accounts written off. INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E ADDITIONS Balance 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, 1995 $ 121 $ 1,506 $ 632(a) $ 1,925(b) $ 334 Year Ended December 31, 1994 $ 504 $ 774 $ 707(a) $ 1,864(b) $ 121 Year Ended December 31, 1993 $ 562 $ 1,380 $ 624(a) $ 2,062(b) $ 504
(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, 1995 $ 260 $ 925 $ 234(a) $ 1,160(b) $ 259 Year Ended December 31, 1994 $ 208 $ 600 $ 84(a) $ 632(b) $ 260 Year Ended December 31, 1993 $ 248 $ 390 $ 179(a) $ 609(b) $ 208
(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, 1995 $1,019 $ 1,952 $ 472(a) $ 2,019(b) $1,424 Year Ended December 31, 1994 $ 960 $10,087 $(7,785)(a) $ 2,243(b) $1,019 Year Ended December 31, 1993 $4,353 $ 4,812 $ 549(a) $ 8,754(b) $960
(a) Recoveries on accounts previously written off. (b) Uncollectible accounts written off. EXHIBIT INDEX Certain of the following exhibits, designated with an asterisk(*), are filed herewith. The exhibits not so designated have heretofore been filed with the Commission and, pursuant to 17 C.F.R.
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 1995 Annual Report (for the fiscal year ended December 31, 1995) which are incorporated by reference in this filing. *24 - Power of Attorney. *27 - Financial Data Schedules. AEP 3(a) - Copy of Restated Certificate of Incorporation of AEP, dated April 26, 1978 [Registration Statement No. 2-62778, Exhibit 2(a)]. 3(b)(1) - Copy of Certificate of Amendment of the Restated Certificate of Incorporation of AEP, dated April 23, 1980 [Registration Statement No. 33-1052, Exhibit 4(b)]. 3(b)(2) - Copy of Certificate of Amendment of the Restated Certificate of Incorporation of AEP, dated April 28, 1982 [Registration Statement No. 33-1052, Exhibit 4(c)]. 3(b)(3) - Copy of Certificate of Amendment of the Restated Certificate of Incorporation of AEP, dated April 25, 1984 [Registration Statement No. 33-1052, Exhibit 4(d)]. 3(b)(4) - Copy of Certificate of Change of the Restated Certificate of Incorporation of AEP, dated July 5, 1984 [Registration Statement No. 33-1052, Exhibit 4(e)]. 3(b)(5) - Copy of Certificate of Amendment of the Restated Certificate of Incorporation of AEP, dated April 27, 1988 [Registration Statement No. 33-1052, Exhibit 4(f)]. 3(c) - Composite copy of the Restated Certificate of Incorporation of AEP, as amended [Registration Statement No. 33-1052, Exhibit 4(g)]. 3(d) - Copy of By-Laws of AEP, as amended through July 26, 1989 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1989, File No. 1-3525, Exhibit 3(d)]. 10(a) - Interconnection Agreement, dated July 6, 1951, among APCo, CSPCo, KEPCo, OPCo and I&M and with the Service Corporation, as amended [Registration Statement No. 2-52910, Exhibit 5(a); Registration Statement No. 2-61009, Exhibit 5(b); and Annual Report on Form 10- K of AEP for the fiscal year ended December 31, 1990, File No. 1- 3525, Exhibit 10(a)(3)]. 10(b) - Copy of Transmission Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KEPCo, OPCo and with the Service Corporation as agent, as amended [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(b); and Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1988, File No. 1-3525, Exhibit 10(b)(2)]. AEP (continued) EXHIBIT NUMBER DESCRIPTION 10(c)(1)-AEP Deferred Compensation Agreement for certain executive officers [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(e)]. 10(c)(2)-Amendment to AEP Deferred Compensation Agreement for certain executive officers [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1986, File No. 1-3525, Exhibit 10(d)(2)]. 10(d)-AEP Deferred Compensation Agreement for directors, as amended, effective October 24, 1984 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1984, File No. 1-3525, Exhibit 10(e)]. 10(e)-AEP Accident Coverage Insurance Plan for directors [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(g)]. 10(f)-AEP Retirement Plan for directors [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1986, File No. 1-3525, Exhibit 10(g)]. *10(g)(1)(A)-AEP Excess Benefit Plan, as amended through January 4, 1996. 10(g)(1)(B)-Guaranty by AEP of the Service Corporation Excess Benefits Plan [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1990, File No. 1-3525, Exhibit 10(h)(1)(B)]. 10(g)(2)-AEP System Supplemental Savings Plan (Non-Qualified) [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1993, File No. 1-3525, Exhibit 10(g)(2)]. 10(g)(3)-Service Corporation Umbrella Trust for Executives [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1993, File No. 1-3525, Exhibit 10(g)(3)]. 10(h)(1)-Employment Agreement between E. Linn Draper, Jr. and AEP and the Service Corporation [Annual Report on Form 10-K of AEGCo for the fiscal year ended December 31, 1991, File No. 0-18135, Exhibit 10(g)(3)]. *10(i)(1)-AEP Management Incentive Compensation Plan. 10(i)(2)-American Electric Power System Performance Share Incentive Plan, as Amended and Restated through October 1, 1995 [Quarterly Report on Form 10-Q of AEP for the quarterly period ended September 30, 1995, File No. 1-3525, Exhibit 10]. 10(j) - Copy of Lease Agreements, dated as of December 1, 1989, between AEGCo or I&M and Wilmington Trust Company, as amended [Registration Statement No. 33-32752, Exhibits 28(c)(1)(C), 28(c)(2)(C), 28(c)(3)(C), 28(c)(4)(C), 28(c)(5)(C) and 28(c)(6)(C); Registration Statement No. 33-32753, Exhibits 28(a)(1)(C), 28(a)(2)(C), 28(a)(3)(C), 28(a)(4)(C), 28(a)(5)(C) and 28(a)(6)(C); and Annual Report on Form 10-K of AEGCo for the fiscal year ended December 31, 1993, File No. 0-18135, Exhibits 10(c)(1)(B), 10(c)(2)(B), 10(c)(3)(B), 10(c)(4)(B), 10(c)(5)(B) and 10(c)(6)(B); Annual Report on Form 10-K of I&M for the fiscal year ended December 31, 1993, File No. 1-3570, Exhibits 10(e)(1)(B), 10(e)(2)(B), 10(e)(3)(B), 10(e)(4)(B), 10(e)(5)(B) and 10(e)(6)(B)]. 10(k)(1) - Copy of Agreement for Lease, dated as of September 17, 1992, between JMG Funding, Limited Partnership and OPCo [Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1992, File No. 1-6543, Exhibit 10(l)]. 10(k)(2) - Lease Agreement between Ohio Power Company and JMG Funding, Limited, dated January 20, 1995 [Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1994, File No. 1-6543, Exhibit 10(l)(2)]. 10(l) - 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 APCo for the fiscal year ended December 31, 1994, File No. 1-3457, Exhibit 10(d)]. *13 - Copy of those portions of the AEP 1995 Annual Report (for the fiscal year ended December 31, 1995) 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 EXHIBIT NUMBER DESCRIPTION 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) - Composite copy of the Restated Articles of Incorporation of APCo, as amended [Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1994, File No. 1-3457, Exhibit 3(c)]. *3(d) - Copy of By-Laws of APCo (amended as of January 1, 1996). 4(a) - Copy of Mortgage and Deed of Trust, dated as of December 1, 1940, between APCo and Bankers Trust Company and R. Gregory Page, as Trustees, as amended and supplemented [Registration Statement No. 2-7289, Exhibit 7(b); Registration Statement No. 2-19884, Exhibit 2(1); Registration Statement No. 2-24453, Exhibit 2(n); Registration Statement No. 2-60015, Exhibits 2(b)(2), 2(b)(3), 2(b)(4), 2(b)(5), 2(b)(6), 2(b)(7), 2(b)(8), 2(b)(9), 2(b)(10), 2(b)(12), 2(b)(14), 2(b)(15), 2(b)(16), 2(b)(17), 2(b)(18), 2(b)(19), 2(b)(20), 2(b)(21), 2(b)(22), 2(b)(23), 2(b)(24), 2(b)(25), 2(b)(26), 2(b)(27) and 2(b)(28); Registration Statement No. 2-64102, Exhibit 2(b)(29); Registration Statement No. 2-66457, Exhibits (2)(b)(30) and 2(b)(31); Registration Statement No. 2- 69217, Exhibit 2(b)(32); Registration Statement No. 2-86237, Exhibit 4(b); Registration Statement No. 33-11723, Exhibit 4(b); Registration Statement No. 33-17003, Exhibit 4(a)(ii), Registration Statement No. 33-30964, Exhibit 4(b); Registration Statement No. 33-40720, Exhibit 4(b); Registration Statement No. 33-45219, Exhibit 4(b); Registration Statement No. 33-46128, Exhibits 4(b) and 4(c); Registration Statement No. 33-53410, Exhibit 4(b); Registration Statement No. 33-59834, Exhibit 4(b); Registration Statement No. 33-50229, Exhibits 4(b) and 4(c); Registration Statement No. 33-58431, Exhibits 4(b), 4(c), 4(d) and 4(e); Registration Statement No. 333-01049, Exhibits 4(b) and 4(c); Form 8-K, dated March 18, 1996, File No. 1-3457, Exhibit 4]. 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 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 APCo for the fiscal year ended December 31, 1994, File No. 1-3457, Exhibit 10(d)]. 10(e)(1)-AEP Deferred Compensation Agreement for certain executive officers [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(e)]. 10(e)(2)-Amendment to AEP Deferred Compensation Agreement for certain executive officers [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1986, File No. 1-3525, Exhibit 10(d)(2)]. APCO (continued) EXHIBIT NUMBER DESCRIPTION 10(f)(1)-Management Incentive Compensation Plan [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1995, File No. 1-3525, Exhibit 10(i)(1)]. 10(f)(2)-American Electric Power System Performance Share Incentive Plan [Quarterly Report on Form 10-Q of APCo for the quarterly period ended September 30, 1995, File No. 1-3457, Exhibit 10]. 10(g)(1)-Excess Benefits Plan [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1995, File No. 1-3525, Exhibit 10(g)(1)(A)]. 10(g)(2)-AEP System Supplemental Savings Plan (Non-Qualified) [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1993, File No. 1-3525, Exhibit 10(g)(2)]. 10(g)(3)-Umbrella Trust for Executives [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1993, File No. 1-3525, Exhibit 10(g)(3)]. 10(h)(1)-Employment Agreement between E. Linn Draper, Jr. and AEP and the Service Corporation [Annual Report on Form 10-K of AEGCo for the fiscal year ended December 31, 1991, File No. 0-18135, Exhibit 10(g)(3)]. *12 - Statement re: Computation of Ratios. *13 - Copy of those portions of the APCo 1995 Annual Report (for the fiscal year ended December 31, 1995) 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, 1995, File No. 1-3525, Exhibit 21]. *23 - Consent of Deloitte & Touche LLP. *24 - Power of Attorney. *27 - Financial Data Schedules. CSPCO 3(a) - Copy of Amended Articles of Incorporation of CSPCo, as amended to March 6, 1992 [Registration Statement No. 33-53377, Exhibit 4(a)]. 3(b) - Copy of Certificate of Amendment to Amended Articles of Incorporation of CSPCo, dated May 19, 1994 [Annual Report on Form 10-K of CSPCo for the fiscal year ended December 31, 1994, File No. 1-2680, Exhibit 3(b)]. 3(c) - Composite copy of Amended Articles of Incorporation of CSPCo, as amended [Annual Report on Form 10-K of CSPCo for the fiscal year ended December 31, 1994, File No. 1-2680, Exhibit 3(c)]. 3(d) - Copy of Code of Regulations and By-Laws of CSPCo [Annual Report on Form 10-K of CSPCo for the fiscal year ended December 31, 1987, File No. 1-2680, Exhibit 3(d)]. 4(a) - Copy of Indenture of Mortgage and Deed of Trust, dated September 1, 1940, between CSPCo and City Bank Farmers Trust Company (now Citibank, N.A.), as trustee, as supplemented and amended [Registration Statement No. 2-59411, Exhibits 2(B) and 2(C); Registration Statement No. 2-80535, Exhibit 4(b); Registration Statement No. 2-87091, Exhibit 4(b); Registration Statement No. 2- 93208, Exhibit 4(b); Registration Statement No. 2-97652, Exhibit 4(b); Registration Statement No. 33-7081, Exhibit 4(b); Registration Statement No. 33-12389, Exhibit 4(b); Registration Statement No. 33-19227, Exhibits 4(b), 4(e), 4(f), 4(g) and 4(h); Registration Statement No. 33-35651, Exhibit 4(b); Registration Statement No. 33-46859, Exhibits 4(b) and 4(c); Registration Statement No. 33-50316, Exhibits 4(b) and 4(c); Registration Statement No. 33-60336, Exhibits 4(b), 4(c) and 4(d); Registration Statement No. 33-50447, Exhibits 4(b) and 4(c); Annual Report on Form 10-K of CSPCo for the fiscal year ended December 31, 1993, File No. 1-2680, Exhibit 4(b)]. 10(a)(1) - Copy of Power Agreement, dated October 15, 1952, between OVEC and United States of America, acting by and through the United States Atomic Energy Commission, and, subsequent to January 18, 1975, the Administrator of the Energy Research and Development Administration, as amended [Registration Statement No. 2-60015, Exhibit 5(a); Registration Statement No. 2-63234, Exhibit 5(a)(1)(B); Registration Statement No. 2-66301, Exhibit 5(a)(1)(C); Registration Statement No. 2-67728, Exhibit 5(a)(1)(B); Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1989, File No. 1-3457, Exhibit 10(a)(1)(F); and Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1992, File No. 1-3457, Exhibit 10(a)(1)(B)]. 10(a)(2) - Copy of Inter-Company Power Agreement, dated July 10, 1953, among OVEC and the Sponsoring Companies, as amended [Registration Statement No. 2-60015, Exhibit 5(c); Registration Statement No. 2- 67728, Exhibit 5(a)(3)(B); and Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1992, File No. 1-3457, Exhibit 10(a)(2)(B)]. CSPCO (continued) EXHIBIT NUMBER DESCRIPTION 10(a)(3) - Copy of Power Agreement, dated July 10, 1953, between OVEC and Indiana-Kentucky Electric Corporation, as amended [Registration Statement No. 2-60015, Exhibit 5(e)]. 10(b) - Copy of Interconnection Agreement, dated July 6, 1951, among APCo, CSPCo, KEPCo, OPCo and I&M and the Service Corporation, as amended [Registration Statement No. 2-52910, Exhibit 5(a); Registration Statement No. 2-61009, Exhibit 5(b); and Annual Report on Form 10- K of AEP for the fiscal year ended December 31, 1990, File No. 1- 3525, Exhibit 10(a)(3)]. 10(c) - Copy of Transmission Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KEPCo, OPCo, and with the Service Corporation as agent, as amended [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(b); and Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1988, File No. 1-3525, Exhibit 10(b)(2)]. 10(d) - Copy of Interim Allowance Agreement [Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1994, File No. 1-3457, Exhibit 10(d)]. *12 - Statement re: Computation of Ratios. *13 - Copy of those portions of the CSPCo 1995 Annual Report (for the fiscal year ended December 31, 1995) 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) - Composite Copy of the Amended Articles of Acceptance of I&M, as amended [Annual Report on Form 10-K of I&M for fiscal year ended December 31, 1993, File No. 1-3570, Exhibit 3(b)]. *3(c) - Copy of the By-Laws of I&M (amended as of January 1, 1996). 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)]. 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)]. I&M (continued) EXHIBIT NUMBER DESCRIPTION 10(b) - Copy of Interconnection Agreement, dated July 6, 1951, between APCo, CSPCo, KEPCo, I&M, and OPCo and with the Service Corporation, as amended [Registration Statement No. 2-52910, Exhibit 5(a); Registration Statement No. 2-61009, Exhibit 5(b); and Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1990, File No. 1-3525, Exhibit 10(a)(3)]. 10(c) - Copy of Transmission Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KEPCo, OPCo and with the Service Corporation as agent, as amended [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(b); and Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1988, File No. 1-3525, Exhibit 10(b)(2)]. 10(d) - Copy of Interim Allowance Agreement [Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1994, File No. 1-3457, Exhibit 10(d)]. 10(e) - Copy of Nuclear Material Lease Agreement, dated as of December 1, 1990, between I&M and DCC Fuel Corporation [Annual Report on Form 10-K of I&M for the fiscal year ended December 31, 1993, File No. 1-3570, Exhibit 10(d)]. 10(f) - Copy of Lease Agreements, dated as of December 1, 1989, between I&M and Wilmington Trust Company, as amended [Registration Statement No. 33-32753, Exhibits 28(a)(1)(C), 28(a)(2)(C), 28(a)(3)(C), 28(a)(4)(C), 28(a)(5)(C) and 28(a)(6)(C); Annual Report on Form 10-K of I&M for the fiscal year ended December 31, 1993, File No. 1-3570, Exhibits 10(e)(1)(B), 10(e)(2)(B), 10(e)(3)(B), 10(e)(4)(B), 10(e)(5)(B) and 10(e)(6)(B)]. *12 - Statement re: Computation of Ratios *13 - Copy of those portions of the I&M 1995 Annual Report (for the fiscal year ended December 31, 1995) 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, 1995, 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). 4(a) - Copy of Mortgage and Deed of Trust, dated May 1, 1949, between KEPCo and Bankers Trust Company, as supplemented and amended [Registration Statement No. 2-65820, Exhibits 2(b)(1), 2(b)(2), 2(b)(3), 2(b)(4), 2(b)(5), and 2(b)(6); Registration Statement No. 33-39394, Exhibits 4(b) and 4(c); Registration Statement No. 33-53226, Exhibits 4(b) and 4(c); Registration Statement No. 33- 61808, Exhibits 4(b) and 4(c), Registration Statement No. 33- 53007, Exhibits 4(b), 4(c) and 4(d)]. 10(a) - Copy of Interconnection Agreement, dated July 6, 1951, among APCo, CSPCo, KEPCo, I&M and OPCo and with the Service Corporation, as amended [Registration Statement No. 2-52910, Exhibit 5(a); Registration Statement No. 2-61009, Exhibit 5(b); and Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1990, File No. 1-3525, Exhibit 10(a)(3)]. 10(b) - Copy of Transmission Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KEPCo, OPCo and with the Service Corporation as agent, as amended [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(b); and Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1988, File No. 1-3525, Exhibit 10(b)(2)]. 10(c) - Copy of Interim Allowance Agreement [Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1994, File No. 1-3457, Exhibit 10(d)]. *12 - Statement re: Computation of Ratios. *13 - Copy those portions of the KEPCo 1995 Annual Report (for the fiscal year ended December 31, 1995) which are incorporated by reference in this filing. *23 - Consent of Deloitte & Touche LLP. *24 - Power of Attorney. *27 - Financial Data Schedules. OPCO EXHIBIT NUMBER DESCRIPTION 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) - Composite copy of the Amended Articles of Incorporation of OPCo, as amended [Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1994, File No. 1-6543, Exhibit 3(c)]. 3(d) - Copy of Code of Regulations of OPCo [Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1990, File No. 1-6543, Exhibit 3(d)]. 4(a) - Copy of Mortgage and Deed of Trust, dated as of October 1, 1938, between OPCo and Manufacturers Hanover Trust Company (now Chemical Bank), as Trustee, as amended and supplemented [Registration Statement No. 2-3828, Exhibit B-4; Registration Statement No. 2- 60721, Exhibits 2(c)(2), 2(c)(3), 2(c)(4), 2(c)(5), 2(c)(6), 2(c)(7), 2(c)(8), 2(c)(9), 2(c)(10), 2(c)(11), 2(c)(12), 2(c)(13), 2(c)(14), 2(c)(15), 2(c)(16), 2(c)(17), 2(c)(18), 2(c)(19), 2(c)(20), 2(c)(21), 2(c)(22), 2(c)(23), 2(c)(24), 2(c)(25), 2(c)(26), 2(c)(27), 2(c)(28), 2(c)(29), 2(c)(30), and 2(c)(31); Registration Statement No. 2-83591, Exhibit 4(b); Registration Statement No. 33-21208, Exhibits 4(a)(ii), 4(a)(iii) and 4(a)(vi); Registration Statement No. 33-31069, Exhibit 4(a)(ii); Registration Statement No. 33-44995, Exhibit 4(a)(ii); Registration Statement No. 33-59006, Exhibits 4(a)(ii), 4(a)(iii) and 4(a)(iv); Registration Statement No. 33-50373, Exhibits 4(a)(ii), 4(a)(iii) and 4(a)(iv); Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1993, File No. 1-6543, Exhibit 4(b)]. 10(a)(1) - Copy of Power Agreement, dated October 15, 1952, between OVEC and United States of America, acting by and through the United States Atomic Energy Commission, and, subsequent to January 18, 1975, the Administrator of the Energy Research and Development Administration, as amended [Registration Statement No. 2-60015, Exhibit 5(a); Registration Statement No. 2-63234, Exhibit 5(a)(1)(B); Registration Statement No. 2-66301, Exhibit 5(a)(1)(C); Registration Statement No. 2-67728, Exhibit 5(a)(1)(D); Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1989, File No. 1-3457, Exhibit 10(a)(1)(F); Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1992, File No. 1-3457, Exhibit 10(a)(1)(B)]. 10(a)(2) - Copy of Inter-Company Power Agreement, dated July 10, 1953, among OVEC and the Sponsoring Companies, as amended [Registration Statement No. 2-60015, Exhibit 5(c); Registration Statement No. 2- 67728, Exhibit 5(a)(3)(B); Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1992, File No. 1-3457, Exhibit 10(a)(2)(B)]. 10(a)(3) - Copy of Power Agreement, dated July 10, 1953, between OVEC and Indiana-Kentucky Electric Corporation, as amended [Registration Statement No. 2-60015, Exhibit 5(e)]. 10(b) - Copy of Interconnection Agreement, dated July 6, 1951, between APCo, CSPCo, KEPCo, I&M and OPCo and with the Service Corporation, as amended [Registration Statement No. 2-52910, Exhibit 5(a); Registration Statement No. 2-61009, Exhibit 5(b); Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1990, File 1-3525, Exhibit 10(a)(3)]. 10(c) - Copy of Transmission Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KEPCo, OPCo and with the Service Corporation as agent [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(b); Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1988, File No. 1-3525, Exhibit 10(b)(2)]. 10(d) - Copy of Interim Allowance Agreement [Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1994, File No. 1-3457, Exhibit 10(d)]. 10(e) - Copy of Agreement, dated June 18, 1968, between OPCo and Kaiser Aluminum & Chemical Corporation (now known as Ravenswood Aluminum Corporation) and First Supplemental Agreement thereto [Registration Statement No. 2-31625, Exhibit 4(c); Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1986, File No. 1-6543, Exhibit 10(d)(2)]. 10(f) - Copy of Power Agreement, dated November 16, 1966, between OPCo and Ormet Generating Corporation and First Supplemental Agreement thereto [Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1993, File No. 1-6543, Exhibit 10(e)]. 10(g) - 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 OPCO (continued) EXHIBIT NUMBER DESCRIPTION on Form 10-K of OPCo for the fiscal year ended December 31, 1993, File No. 1-6543, Exhibit 10(f)]. 10(h)(1)-AEP Deferred Compensation Agreement for certain executive officers [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(e)]. 10(h)(2)-Amendment to AEP Deferred Compensation Agreement for certain executive officers [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1986, File No. 1-3525, Exhibit 10(d)(2)]. 10(i)(1)-Management Incentive Compensation Plan [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1995, File No. 1-3525, Exhibit 10(i)(1)]. 10(i)(2)-American Electric Power System Performance Share Incentive Plan, as Amended and Restated through January 1, 1995 [Quarterly Report on Form 10-Q of OPCo for the quarterly period ended September 30, 1995, File No. 1-6543]. 10(j)(1)-Excess Benefits Plan [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1995, File No. 1-3525, Exhibit 10(g)(1)(A)]. 10(j)(2)-AEP System Supplemental Savings Plan (Non-Qualified) [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1993, 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)(1)-Employment Agreement between E. Linn Draper, Jr. and AEP and the Service Corporation [Annual Report on Form 10-K of AEGCo for the fiscal year ended December 31, 1991, File No. 0-18135, Exhibit 10(g)(2)]. 10(l)(1) - Agreement for Lease dated as of September 17, 1992 between JMG Funding, Limited Partnership and OPCo [Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1992, File No. 1- 6543, Exhibit 10(l)]. 10(l)(2) - Lease Agreement dated January 20, 1995 between OPCo and JMG Funding, Limited Partnership, and amendment thereto (confidential treatment requested) [Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1994, File No. 1-6543, Exhibit 10(l)(2)]. *12 - Statement re: Computation of Ratios. *13 - Copy of those portions of the OPCo 1995 Annual Report (for the fiscal year ended December 31, 1995) 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, 1995, File No. 1-3525, Exhibit 21]. *23 - Consent of Deloitte & Touche LLP. *24 - Power of Attorney. *27 - Financial Data Schedules. Certain instruments defining the rights of holders of long-term debt of the registrants included in the financial statements of registrants filed herewith have been omitted because the total amount of securities authorized thereunder does not exceed 10% of the total assets of registrants. The registrants hereby agree to furnish a copy of any such omitted instrument to the SEC upon request. EX-10 2 AEPCO EXCESS BENEFIT PLAN - EX. 10(G)(1)(A) Exhibit 10(g)(1)(A) American Electric Power System Excess Benefit Plan As Amended through January 4, 1996 ARTICLE I Purposes and Effective Date Section 1.1 The American Electric Power System Excess Benefit Plan is established to provide benefits for certain employees in excess of the limitations on benefits imposed by provisions of the Internal Revenue Code of 1986, as amended from time to time. Section 1.2 The effective date of the Excess Plan is January 1, 1990. ARTICLE II Definitions Section 2.1 "Code" shall mean the Internal Revenue Code of 1986, as amended from time to time. Section 2.2 "Committee" shall mean the Employee Benefits Trust Committee established pursuant to a resolution adopted by the American Electric Power Service Corporation Board of Directors as in effect from time to time. Section 2.3 "Company" shall mean American Electric Power Service Corporation. Section 2.4 "ERISA" shall mean the Employee Retirement Income Security Act of 1974 as amended from time to time. Section 2.5 "Maximum Benefit" shall mean the monthly equivalent of the maximum benefit permitted by the Code to be paid to a Participant or the Participant's Surviving Spouse from the Retirement Plan. Section 2.6 "Participant" shall mean any exempt salaried employee of the Company, who is an active Participant in the Retirement Plan on or after the Effective Date, whose Unre- stricted Benefit exceeds the Maximum Benefit and who either is an officer of the Company or has been designated and confirmed by the Committee as eligible to participate in the Plan. Section 2.7 "Plan" shall mean the American Electric Power System Excess Benefit Plan, as from time to time amended or restated. Section 2.8 "QDRO" shall mean a qualified domestic relations order as defined in section 414(p) of the Code or section 206(d) of ERISA. Section 2.9 "Retirement Plan" shall mean the American Electric Power System Retirement Plan, as amended from time to time. Section 2.10 "Supplemental Retirement Benefit" shall mean any supplemental retirement benefit payable to a Partici- pant or a Participant's spouse pursuant to the terms of an employment agreement entered into between the Participant and the Company. The term Supplemental Retirement Benefit shall not include deferred compensation payable to a Participant pursuant to a Participant's participation in a deferred com- pensation arrangement entered into prior to January 1, 1987 or deferred compensation payable to the Participant pursuant to the terms and conditions of the Management Incentive Compensa- tion Program. Section 2.11 "Surviving Spouse" shall mean the spouse of a Participant who is legally married to the Participant and whose marriage to the Participant occurred at least one year prior to the earlier of the Participant's termination of employment or death. Section 2.12 "Unrestricted Benefit" shall mean either (a) the monthly Normal, Early, or Deferred Vested retirement benefit payable to the Participant, whichever is applicable, or (b) the pre-retirement or post-retirement surviving spouse's benefit payable to the Participant's Surviving Spouse, whichever is applicable, determined under the provi- sions of the Retirement Plan without regard to the limitations imposed by the Code and based upon Participant earnings that, for each plan year, are the total of: (1) the Participant's Retirement Plan Earnings, (2) the Participant's contributions to the American Electric Power System Supplemental Savings Plan, and (3) for Participants who terminate employment after December 31, 1995, Management Incentive Compensation Plan awards earned, but not necessarily paid, in the plan year, including MICP awards earned prior to January 1, 1996. ARTICLE III Benefits Section 3.1 Upon the Normal Retirement of a Participant, as provided under the Retirement Plan, the Participant shall be entitled to a monthly benefit equal in amount to the Parti- cipant's Unrestricted Benefit less the Maximum Benefit and less any Supplemental Retirement Benefit. Section 3.2 Upon the Early Retirement of a Participant, as provided under the Retirement Plan, the Participant shall be entitled to a monthly benefit equal to the Participant's Unrestricted Benefit less the Maximum Benefit and less any Supplemental Retirement Benefit. Section 3.3 If a Participant terminates employment with the Company and is entitled to a Deferred Vested Retirement Benefit provided under the Retirement Plan, the Participant shall be entitled to a monthly benefit equal to the Partici- pant's Unrestricted Benefit less the Maximum Benefit and less any Supplemental Retirement Benefit. Section 3.4 Supplemental Retirement Benefits accrued as of December 31, 1993 shall be vested as of December 31, 1993. Supplemental Retirement Benefits accrued after 1993 shall vest when the Participant terminates employment. ARTICLE IV Spousal Benefit Section 4.1 Upon the death of a Participant whose spouse is entitled to a pre-retirement or a post-retirement surviving spouse's benefit from the Retirement Plan, the Participant's Surviving Spouse shall be entitled to receive a monthly bene- fit equal in amount to the Surviving Spouse's pre-retirement or post-retirement Unrestricted Benefit less the Maximum Benefit and less any Supplemental Retirement Benefit. ARTICLE V Benefit Payments Section 5.1 Payment of retirement benefits under Article 3 or 4 shall commence at the same time Retirement Plan bene- fits are paid. Section 5.2 The Plan benefit payable to a Participant shall be paid in the same form in which the Retirement Plan benefit is payable to the Participant. The Participant's election under the Retirement Plan of an optional form of payment (with the valid consent of the Participant's Spouse where required under the Retirement Plan) shall be deemed to be the form of payment elected for the payment of benefits from this Plan. Retirement Plan benefit payments subject to an assignment pursuant to the terms of a QDRO shall not be treated as a form of benefit payment selected by the Partici- pant under the terms of the Retirement Plan. ARTICLE VI Administration Section 6.1 The Company shall be responsible for the general operation and administration of the Plan and for carrying out the provisions thereof. Section 6.2 All provisions set forth in the Retirement Plan with respect to the administrative powers and duties of the Company, expenses of administration and procedures for filing claims shall also be applicable with respect to the Plan. The Company shall be entitled to rely conclusively upon all tables, valuations, certificates, opinions and reports furnished by any actuary, accountant, controller, counsel or other person employed or engaged by the Company with respect to the Plan or with respect to any Supplemental Retirement Benefit. Section 6.3 The Company shall provide a retired Par- ticipant, at the time of retirement or as soon thereafter as practicable, with a copy of the Plan and a certificate stating that the retired Participant is entitled to benefits under the Plan and the amount thereof. ARTICLE VII Amendment or Termination Section 7.1 The Company intends the Plan to be permanent but reserves the right to amend or terminate the Plan when, in the sole opinion of the Company, such amendment or termination is advisable. Any such amendment or termination shall be made pursuant to a resolution of the Board and shall be effective as of the date of such resolution. Section 7.2 No amendment or termination of the Plan shall directly or indirectly deprive any current or former Participant or Surviving Spouse of all or any portion of any retirement benefit or surviving spouse benefit payment which commenced prior to the effective date of such amendment or termination or which would be payable if the Participant terminated employment for any reason, including death, on such effective date. ARTICLE VIII General Provisions Section 8.1 Except as otherwise expressly provided herein, all terms and conditions of the Retirement Plan appli- cable to a retirement benefit or a surviving spouse benefit shall also be applicable to a retirement benefit or a surviv- ing spouse benefit payable hereunder. Any Plan retirement benefit or surviving spouse benefit, or any other benefit payable under the Plan, shall be paid solely in accordance with the terms and conditions of the Retirement Plan and nothing in this Plan shall operate or be construed in any way to modify, amend or affect the terms and provisions of the Retirement Plan. Section 8.2 Nothing contained in the Plan shall consti- tute a guaranty by the Company or any other entity or person that the assets of the Company will be sufficient to pay any benefit hereunder. The benefits under this Plan shall not be funded, but shall constitute liabilities of the Company pay- able when due. Section 8.3 No Participant or Surviving Spouse shall have any right to a benefit under the Plan except in accor- dance with the terms of the Plan. Establishment of the Plan shall not be construed to give any Participant the right to be retained in the service of the Company. Section 8.4 No interest of any person or entity in, or right to receive a benefit under, the Plan shall be subject in any manner to sale, transfer, assignment, pledge, attachment, garnishment, or other alienation or encumbrance of any kind; nor may such interest or right to receive a benefit be taken, either voluntarily or involuntarily, for the satisfaction of the debts of, or other obligations or claims against, such person or entity, including claims for alimony, support, separate maintenance and claims in bankruptcy proceedings. Section 8.5 The Plan shall be construed and administered under the laws of the State of Ohio. Section 8.6 If the actuarial value of any retirement benefit or surviving spouse benefit is less than $3,500, the Company may pay the actuarial value of such Benefit to the Participant or Surviving Spouse in a single lump sum in lieu of any further benefit payments hereunder. Section 8.7 If any person entitled to a benefit payment under the Plan is deemed by the Company to be incapable of personally receiving and giving a valid receipt for such payment, then, unless and until claim therefor shall have been made by a duly appointed guardian or other legal representa- tive of such person, the Company may provide for such payment or any part thereof to be made to any other person or institu- tion then contributing toward or providing for the care and maintenance of such person. Any such payment shall be a payment for the account of such person and a complete dis- charge of any liability of the Company and the Plan therefor. Section 8.8 The Plan shall not be automatically termi- nated by a transfer or sale of assets of the Company or by the merger or consolidation of the Company into or with any other corporation or other entity, but the Plan shall be continued after such sale, merger or consolidation only if and to the extent that the transferee, purchaser or successor entity agrees to continue the Plan. In the event that the Excess Plan is not continued by the transferee, purchaser or succes- sor entity, then the Plan shall terminate subject to the provisions of Section 7.2. Section 8.9 Each Participant shall keep the Company informed of his current address and the current address of his spouse. The Company shall not be obligated to search for the whereabouts of any person. If the location of a Participant is not made known to the Company within three (3) years after the date on which payment of the Participant's retirement benefit may first be made, payment may be made as though the Participant had died at the end of the three-year period. If, within one additional year after such three-year period has elapsed, or, within three years after the actual death of a Participant, the Company is unable to locate any Surviving Spouse of the Participant, then the Company shall have no further obligation to pay any benefit hereunder to such Par- ticipant or Surviving Spouse or any other person and such benefit shall be irrevocably forfeited. Section 8.10 Notwithstanding any of the preceding provi- sions of the Plan, neither the Company nor any individual acting as an employee or agent of the Company shall be liable to any Participant, former Participant, Surviving Spouse or any other person for any claim, loss, liability or expense incurred in connection with the Plan. Section 8.11 An assignment of part or all of a Partici- pant's Maximum Benefit pursuant to the terms of a QDRO shall not reduce the Participant's Maximum Benefit for the purpose of determining the benefit, if any, to be paid pursuant to the provisions of this Plan. Section 8.12 The benefits paid by this Plan shall not duplicate benefits being paid or to be paid by the Retirement Plan or any Supplemental Retirement Benefit the Participant or Participant's spouse is receiving or may be entitled to re- ceive. Section 8.13 In the event a Participant's claim for Plan benefits is denied or in the event the Participant disputes the computation of the benefit amount, the Participant shall be entitled to the same claims appeal procedure that is avail- able to the Participant under the terms of the Retirement Plan. EX-10 3 AEPCO MGMT INCENTIVE COMP PLAN - EX. 10(I)(1) EXHIBIT 10(i)(1) CONFIDENTIAL AMERICAN ELECTRIC POWER SYSTEM MANAGEMENT INCENTIVE COMPENSATION PLAN 1995 TABLE OF CONTENTS PAGE INTRODUCTION iv 1.0 OVERVIEW 1 1.1 Participation in MICP 1 1.2 MICP Award Limitation 2 2.0 TARGET AWARD ALLOCATIONS 3 3.0 AEP CORPORATE PERFORMANCE CRITERIA 5 3.1 Average Annual ROE 5 3.2 Total Investor Return 6 3.3 Realization Ratio 7 4.0 OPERATING COMPANY/DIVISION PERFORMANCE CRITERIA 8 4.1 Marketing Performance 8 4.2 Safety Performance 9 4.3 O&M Expense vs. Budget 11 4.4 Customer Service Reliability Index 12 5.0 POWER PLANT MANAGERS 13 6.0 CENTRALIZED PLANT MAINTENANCE MANAGERS 13 7.0 CENTRAL MACHINE SHOP MANAGER 13 8.0 TIDD PLANT MANAGER 13 9.0 FUEL SUPPLY PERFORMANCE CRITERIA 14 9.1 Adjusted Cost of Coal Produced from Affiliated Mines 14 9.2 PUCO Cap Performance 15 9.3 Safety Performance 15 9.4 Senior Vice President and Senior Staff - Fuel Supply - Delivered Fuel Prices 16 9.5 Vice President - Fuel Procurement Measures 16 9.6 General Mine Managers/General Superintendent Measures 17 9.7 Manager - River Transportation Measures 18 9.8 Manager - Cook Coal Terminal Measures 18 9.9 Managing Director - Transportation Measures 19 10.0 DEPARTMENT OBJECTIVES 20 11.0 THE MICP IN ACTION 21 12.0 PAYMENT RIGHTS AT TERMINATION OF ACTIVE EMPLOYMENT 24 12.1 Termination After Completion of Plan Year 24 ii 12.2 Termination Due to Death, Retirement, or Disability 24 12.3 Involuntary Termination During Plan Year 25 13.0 CHANGES IN SALARY/POSITION/PARTICIPATION 26 14.0 PLAN ADMINISTRATION 27 ADDENDUM PAGE 15.0 MICP AWARD DISTRIBUTIONS A-1 16.0 POSSIBLE ADJUSTMENTS TO CORPORATE PERFORMANCE DATA A-3 17.0 FUEL SUPPLY PAYMENT SCHEDULES A-4 17.1 Senior Vice President - Fuel Supply A-4 17.2 Delivered Fuel Prices A-4 17.3 Vice President - Fuel Procurement A-4 17.4 Delivered Fuel Prices A-4 17.5 Sum Total of PV Benefits/Special Contract Renegotiations A-5 17.6 General Mine Managers/General Superintendent (Meigs) A-6 17.7 Southern Ohio Coal Company - Meigs A-6 17.8 Central Ohio Coal Company A-6 17.9 Windsor Coal Company A-7 17.10 All Coal Mines - Safety Incidence Rate A-7 17.11 Manager - River Transportation A-8 17.12 River Transportation Operating Cost Per Ton Mile A-8 17.13 River Transportation Safety Incidence Rate A-8 17.14 Manager - Cook Coal Terminal A-9 17.15 Cook Coal Terminal Adjusted Expenses A-9 17.16 Cook Coal Terminal Safety Incidence Rate A-9 17.17 Managing Director - Transportation A-10 17.18 Cook Coal Terminal Adjusted Expenses A-10 17.19 River Transportation Operating Cost Per Ton Mile A-10 17.20 Delivered Fuel Prices A-11 17.21 River Transportation and Cook Coal Terminal Safety Incidence Rate A-11 iii INTRODUCTION The American Electric Power System will continue the Management Incentive Compensation Plan (MICP) during 1995, with revisions from the 1994 Plan. The Plan's purpose is to bring together the interests of key managers with those of the AEP System's customers and shareholders by providing performance incentives to serve customers' needs and meet shareholders' financial expectations at the highest possible levels. Through the MICP, a key manager can receive an annual monetary award in addition to base salary, if certain performance levels are met. The Plan is designed to help motivate a consistent level of superior Company performance by rewarding those principally accountable for achieving it. This Plan provides an element of compensation which will vary directly with Company performance. It will ensure that key managers are compensated competitively and consistent with the AEP System's financial and operating performance. Any questions about the Plan should be directed to the Assistant Vice President-Compensation and Benefits through the respective Operating Company President, Senior Vice President-Fuel Supply, or AEPSC Department head. iv 1.0 OVERVIEW OF THE MANAGEMENT INCENTIVE COMPENSATION PLAN A participant in the MICP is assigned an annual target award expressed as a percentage of annual base earnings. Actual awards can vary from 0% to 150% of the target award, based on performance. Performance criteria are established each year for the following organization units: - AEP Corporate - Each Operating Company (including Fuel Supply) - Individual Units Each participant in the MICP is assigned a target award percentage and advised how that target award is allocated by organizational unit. After the end of a year, actual awards are determined based on how well the participant and/or the organizational units meet their performance criteria. During the first part of the year following each performance year a participant will receive 80% of any actual award in cash unless a deferral election had been made in accordance with Section 15.2. The remaining 20% is deferred in the form of AEP common stock units payable 3 years later (see Addendum page A-1) unless a deferral election had been made in accordance with Section 15.2. The Plan will pay out 75% and defer 25% of the award to those employees participating in the MICP and an all-employee variable pay plan. 1.1 PARTICIPATION IN MICP Participation in MICP is limited each year to a select group of key managers and executives whose performance most significantly affects the Company's success. Positions eligible and individual executives were approved for participation by the Chief Executive Officer at the inception of the Plan. The following procedures apply to the addition of any other positions or executives: A. OPERATING COMPANIES Participation is generally automatic for employees promoted or transferred to a position that has been previously approved as eligible for participation in the Plan, effective on the promotion or transfer date. However, if an employee is demoted to a position normally covered by the MICP, approval of the Chief Executive Officer is required for the demoted employee to be eligible to continue as a participant. Requests for such approval should be submitted to the Executive Vice President. B. AEPSC AND FUEL SUPPLY DEPARTMENT Prior to becoming a participant in the Plan, specific approval of the Chief Executive Officer is required for all employees or positions not previously eligible to participate in the Plan. Requests for approval by the Chief Executive Officer should be submitted through the AVP-Compensation & Benefits. An executive who is not currently a Plan participant and who is entering an eligible position for the first time, will generally be eligible to participate in that year's Plan if the promotion/transfer date is prior to October 1. If it is after this date, the executive will be eligible to participate in the following year's Plan. 1.2 MICP AWARD LIMITATION No award is payable unless AEP's dividends remain at prevailing levels and net income is greater than dividend payments in the current year. 2.0 TARGET AWARD ALLOCATIONS Target awards of MICP participants are allocated to AEP Corporate and other organization units, as follows:
Target Award* as Percent of Percent of Awards Allocated Participant Base Salary to Organizational Units Office of the Chairman 30 100 Corporate Performance AEPSC Treasurer, VPs, and SVPs 25 75 Corporate Performance 25 Department Performance or 100 Corporate Performance Senior VP - Fuel Supply 25 25 Corporate Performance 50 Fuel Supply Performance 25 Delivered Fuel Prices Operating Company Presidents 25 50 Corporate Performance 50 Operating Company Performance AEPSC Senior Division Managers 20 75 Corporate Performance and Others as Designated 25 Department Performance or 100 Corporate Performance Operating Company VPs 20 50 Corporate Performance 50 Operating Company Performance Operating Company G.O. Department 20 25 Corporate Performance Heads and Executive Assistants 50 Operating Company Performance 25 Department Performance or 25 Corporate Performance 75 Operating Company Performance Operating Company Division/Region 20 25 Corporate Performance Managers 25 Operating Company Performance 50 Division/Region Performance Power Plant Managers (including 20 25 Corporate Performance Cook & Tidd) 75 Plant Incentive Plan Centralized Plant Maintenance 20 25 Corporate Performance Managers 75 Central Plant Maintenance Performance Central Machine Shop Manager 20 25 Corporate Performance 75 Central Machine Shop Performance Fuel Supply Lancaster Senior Staff 20 25 Corporate Performance 50 Fuel Supply Performance 25 Delivered Fuel Prices Vice President - Fuel Procurement 20 25 Corporate Performance 25 Fuel Supply Performance 50 Department Performance Managing Director - Transportation 20 25 Corporate Performance 25 Fuel Supply Performance 50 Department Performance Fuel Supply General Mine Managers/ 20 25 Corporate Performance General Superintendent (Meigs) 25 Fuel Supply Performance 50 Division/Mine Performance Manager - Cook Coal Terminal 20 25 Corporate Performance 75 Cook Coal Terminal Performance Manager - River Transportation 20 25 Corporate Performance 75 River Transportation Performance *Target awards are proportionately reduced for those participants in other all- employee variable pay plans.
3.0 AEP CORPORATE PERFORMANCE CRITERIA There are three AEP Corporate performance criteria which are weighted to determine a single Corporate performance factor. The three are as follows: - A two-component measure of Annual Return on Average Stockholder Equity (ROE) for the current year - weighted at 25%; - A component measuring the Three-year Average Total Investor Return (TIR) - weighted at 25%; and - A component comparing the Realization Ratio (Average Price of Power Sold to Retail Customers vs. Other Utilities) for the current year - weighted at 50%. The following describes each in greater detail. 3.1 RETURN ON EQUITY (ROE) is corporate annual after-tax income as a percentage of average annual stockholder equity. It is an indication of how profitably AEP manages its investors' capital. For purposes of the MICP, ROE is measured in the following two ways, each of which is weighted 12.5%: - In terms of absolute performance; and - Relative to the ranking of the AEP ROE among the 20 other electric utilities that together with AEP make up the Standard & Poor's Utility Index. The results of these two measures are averaged to determine performance on this component. The following chart indicates both of these ROE measurements and the performance factors for each.
Average Annual ROE Absolute Performance S&P Utility Performance ROE Factor* ROE Ranking** Factor 16 or more 1.50 1 - 6 1.50 15 1.25 7 1.40 14 1.00 8 1.30 13 .80 9 1.20 12 .60 10 1.10 11 .40 11 1.00 10 or less 0 12 .80 13 .60 14 .40 15 .20 16 or more 0
*Interpolate at intermediate performance. **Highest ROE is ranked first. Example: If AEP's annual ROE is 14%, and AEP achieves an S&P Utility Index rank of seventh out of 21, the average performance factor will be calculated this way: (1.00 + 1.40) 2 = 1.20. 3.2 TOTAL INVESTOR RETURN (TIR) is an indicator of the increase in value of AEP shareholders' investment. It measures the annual percentage increase in stock price as well as dividends paid over a three-year period (the current and two prior years). AEP System results are then compared with the other 20 companies in the Standard & Poor's Utility Index and are ranked for each of the three years. Performance factors are determined based on the average of the TIR rankings for the three years, as follows:
Three-Year Average Total Investor Return AEP TIR Ranking* Performance Factor 6 or higher 1.50 7 1.40 8 1.30 9 1.20 10 1.10 11 1.00 12 .80 13 .60 14 .40 15 .20 16 0
*Highest TIR is ranked first. Example: If the three-year average rank of AEP is 12 out of 21, the performance factor is .80. 3.3 REALIZATION RATIO is a measure of relative cost efficiency and productivity -- from AEP customers' perspective. It compares the AEP System's average price of power sold to ultimate customers with other utilities' corresponding average price. The realization ratio is based on average realization for sales to ultimate customers by other investor-owned utilities in the seven states in which AEP operates, weighted by the respective proportions of AEP's corresponding sales in those states. (Because Kingsport Power is the only investor-owned electric utility in Tennessee, the realization ratio for that state is based on retail rates of TVA Tennessee distributors.) Performance factors are then derived, as follows:
AEP REALIZATION RATIO AEP Ratio Performance Factor* .75 or less 1.50 .80 1.25 .85 1.00 .90 .75 .95 .50 1.00 .25 above 1.00 0
*Interpolate at intermediate performance. Example: If AEP's average realization is 20% below the seven-state average, its ratio will be .80 and the performance factor will be 1.25. 4.0 OPERATING COMPANY/DIVISION PERFORMANCE CRITERIA There are four Operating Company and Division performance criteria, each of which is given equal weighting to determine a single performance factor for each Operating Company and each Division. The four are as follows: - Achievement of Annual Marketing Objectives - weighted at 25%; - Safety Performance - weighted at 25%; - O&M Expense Performance vs. Budget - weighted at 25%; and - Customer Service Reliability Index - weighted at 25%. The following describes each measure in more detail. 4.1 ACHIEVEMENT OF ANNUAL MARKETING OBJECTIVES is measured by comparing actual performance against marketing objectives for the current year. Performance factors relate to achievement, as follows: Operating Company and Division Target Award Payment Schedules Annual Marketing Results vs. Goal Results as Percent of Goal Performance Factor* Over 110% 1.50 105% 1.25 100% 1.00 95% .50 Below 95% 0 *Interpolate at intermediate performance. Example: If 105% of the marketing goal has been achieved, the performance factor is 1.25. If 108% had been obtained, the performance factor would be calculated as follows: (108%-105%/110%-105% x 25) + 1.25 = 1.40 4.2 SAFETY PERFORMANCE of each Operating Company and Division is measured by two indices, equally weighted at 50%: - RECORDABLE CASE INCIDENCE RATE - Number of recordable cases per 200,000 work hours. - LOST AND RESTRICTED WORKDAY (SEVERITY) RATE - Number of days away from work AND restricted activity days per 200,000 work hours. The rate for the appropriate group will be compared to the most recently published EEI rate calculated for each measure. The related performance factors are determined from the following schedule and averaged to yield a single performance factor for safety performance. Operating Company and Division/Region Target Award Payment Schedule Ratio to the Latest EEI Rate Operating Company or Division/Region Safety Performance Ratio to EEI Performance Performance Factor* 0.700 1.50 0.850 1.00 0.925 0.50 1.000 or more 0 *Interpolate at intermediate performance. Example: If a Division achieves a ratio of .9250 to the EEI recordable case incidence rate and a ratio of .6500 to the EEI lost and restricted workday (severity) rate, the respective performance factors are .5000 and 1.50. Averaging the two yields a single performance factor of 1.000. For the purposes of these safety measures, Wheeling Power and Kingsport Power are considered Divisions. The performance factor shall be zero for any Division whose recordable injuries include a fatality or a permanent total disability case. SOURCE OF DATA - EEI Rate and AEP Data The EEI rates will be taken from the latest EEI Safety Statistical Survey Report at the time the awards are calculated. The data for the companies and divisions is taken from the year-end AEP System Report of Employee Injuries and Illnesses. This information is compiled by the Safety & Health Section of System Human Resources. The following data for the December cumulative year-to-date report is to be compiled by each Operating Company and forwarded to the AEPSC Safety & Health Division on or before January 15 of the following year: - Company/Division - Total Hours Worked - Lost Workdays (LWD Case - days away from work) - Restricted Activity Days - Lost and Restricted Workday (Severity) Rate - Recordable Cases - Recordable Case Incidence Rate DATA AVAILABILITY, CALCULATIONS AND AWARD DETERMINATIONS The AEPSC Safety & Health Section will calculate the performance factors for each Company and Division. The calculations will be completed by January 30 and approved by the SVP-Human Resources. 4.3 O&M EXPENSE PERFORMANCE VS. BUDGET is measured by comparing controllable operating and maintenance expenses against budget for the current year. Performance factors are designed to provide increased awards for expense performance which is below budget. However, because some O&M budgets are developed based primarily upon historical expenses and not upon need to complete specific projects, close monitoring of expenses is required. Each Operating Company president is responsible for monitoring expenses in each operation to ensure that projects that should have been accomplished are not delayed or omitted in order to achieve a higher performance factor score. If this is judged to occur, the approved budget will be commensurately reduced by an amount equal to the estimated cost of the project, and a revised performance factor determined. Operating Company and Division/Region Target Award Payment Schedule Controllable O & M Expenses vs. Budget Expenses as Percent of Budget* Performance Factor Less than 91% 1.50 91% but less than 96% 1.25 96% but less than 101% 1.00 101% but less than 103% .50 103% but less than 105% .25 105% or higher 0 *All numbers to be rounded to nearest whole numbers. Example: If an Operating Company's actual result is 93% of budget, the company has placed between the 91% and 96% bracket, achieving a performance factor of 1.25. 4.4 CUSTOMER SERVICE RELIABILITY INDEX is measured by comparing the current year annual service interruption frequency index and the interruption duration index against prior five-year average indices. The reliability index is determined by the following formula: [(Cur.Interpt.Freq.Index) + (Cur.Inerpt.Dur.Index)] _______________________________________________________ X 100 / 2 [(5-yr.Avg.Intm.Freq.Index) (5-yr.Avg.Intm.Dur.Index)] Resulting performance factors are determined as follows: Operating Company and Division/Region Target Award Payment Schedule Customer Service Reliability Index vs. Prior Five-Year Average
Service Reliability Index Performance Factor* 85% or lower 1.50 92.5% 1.25 100% 1.00 105% .50 110% or higher 0 *Interpolate at intermediate performance. Example: If an Operating Company's current reliability index is 97%, 3% better than its five-year average of 100%, the performance factor is: (100%-97%) _________ x.25)+1=1.10 (100%-92.5%)
SPECIAL ADJUSTMENTS MAY BE CONSIDERED FOR CATASTROPHIC SITUATIONS. (SEE PAGE 2 OF THE ADMINISTRATION MANUAL.) 5.0 POWER PLANT MANAGERS INCENTIVE AWARDS FOR POWER PLANT MANAGERS ARE FROM TWO SOURCES: --AEP CORPORATE PERFORMANCE - WEIGHTED 25%; AND --PERFORMANCE AS DETERMINED BY POWER PLANT INCENTIVE COMPENSATION PLAN - WEIGHTED 75%. 6.0 CENTRALIZED PLANT MAINTENANCE MANAGERS INCENTIVE AWARDS FOR THE MANAGERS OF APPALACHIAN POWER'S AND OHIO POWER'S CENTRALIZED PLANT MAINTENANCE DIVISIONS ARE FROM TWO SOURCES: --AEP CORPORATE PERFORMANCE - WEIGHTED 25%; AND --PERFORMANCE AS DETERMINED BY THE CENTRALIZED PLANT MAINTENANCE DIVISION'S INCENTIVE COMPENSATION PLAN - WEIGHTED 75%. 7.0 CENTRAL MACHINE SHOP MANAGER INCENTIVE AWARDS FOR THE CENTRAL MACHINE SHOP MANAGER ARE FROM TWO SOURCES: --AEP CORPORATE PERFORMANCE - WEIGHTED 25%; AND --PERFORMANCE AS DETERMINED BY THE CENTRAL MACHINE SHOP INCENTIVE COMPENSATION PLAN - WEIGHTED 75%. 8.0 TIDD PLANT MANAGER INCENTIVE AWARDS FOR THE TIDD PLANT MANAGER ARE FROM TWO SOURCES: --AEP CORPORATE PERFORMANCE - WEIGHTED 25%; AND --PERFORMANCE AS DETERMINED BY THE TIDD PFBC INCENTIVE COMPENSATION PLAN - WEIGHTED 75%. 9.0 FUEL SUPPLY PERFORMANCE CRITERIA THERE ARE THREE OVERALL FUEL SUPPLY PERFORMANCE MEASURES, WHICH ARE WEIGHTED TO DETERMINE A SINGLE FUEL SUPPLY PERFORMANCE FACTOR. THESE ARE AS FOLLOWS: --ADJUSTED COST OF COAL PRODUCED FROM AFFILIATED MINES, MEASURED BY CENTS PER MILLION BTU (/MM BTU) FOR THE CURRENT YEAR AS REDUCED TO REFLECT EXTRAORDINARY COSTS DUE TO DOWNSIZING AND/OR OTHER SPECIAL EXPENSES AND A VOLUME ADJUSTMENT OF 50/MM BTU FOR VARIANCE FROM BUDGETED TONS - WEIGHTED AT 50%; AND --PERFORMANCE RELATIVE TO THE PUCO NEGOTIATED EFC CAP - WEIGHTED AT 25%; AND --SAFETY INCIDENCE RATE AS A PERCENT OF THE INDUSTRY INCIDENCE RATE FOR THE CURRENT YEAR - WEIGHTED AT 25%. THE FOLLOWING DESCRIBES EACH IN GREATER DETAIL. 9.1 ADJUSTED COST OF COAL PRODUCED FROM AFFILIATED MINES The adjusted cost of coal produced as measured by /MM BTU is a measure of how efficiently affiliated mines produce clean coal for use in the System's power plants. Performance factors relate to achievement as follows: Fuel Supply Target Award Payment Schedule Affiliated Mine Costs
/MM BTU Performance Factor* 178.2 or lower 1.50 180.2 1.25 182.2 1.00 184.2 .75 186.2 .50 188.2 .25 190.2 or higher 0 *Interpolate at intermediate performance.
9.2 PUCO CAP PERFORMANCE The PUCO cap performance measures the amount of operating loss as defined in the Settlement Agreement dated February 28, 1995. Fuel Supply Target Award Payment Schedule PUCO CAP PERFORMANCE
CAP PERFORMANCE Performance Factor* $ 0 1.50 $ 5 million 1.25 $ 10 million 1.00 $ 15 million .75 $ 20 million .50 More than $ 20 million 0
*Interpolate at intermediate Performance Example: If the average cap performance was $8.0 million, the performance factor would be: ( 10-8) (______ x.25)+1.00=1.10 ( 10-5) 9.3 SAFETY PERFORMANCE Achievement of the safety objective is measured by comparing the incidence rate for the current year with the comparable coal industry incidence rate (including Fuel Supply). Performance factors relate to achievement as follows: Fuel Supply Target Award Payment Schedule Safety - Incidence Rate vs. Coal Industry
Incidence Rate - Percent Performance Factor* Industry Rate 55 or lower 1.50 65 1.25 75 1.00 85 .75 90 .50 95 .25 higher than 95 0 *Interpolate at intermediate performance. Example: If Fuel Supply's incidence rate were 92% of the coal industry rate, the performance factor is: (95%-92%) (_______x.25)+.25=.40 (95%-90%)
9.4 SENIOR VICE PRESIDENT AND SENIOR STAFF-FUEL SUPPLY - DELIVERED FUEL PRICES In addition to the awards allocated to Corporate performance and Fuel Supply performance, the Senior Vice President and Senior Staff-Fuel Supply are assigned a 25% award allocated to delivered fuel prices, (spot/contract) composited change as a percent of the GDP price index (fixed weight). (See Page A-4 for the target award payment schedule.) 9.5 VICE PRESIDENT - FUEL PROCUREMENT MEASURES In addition to the Corporate performance measures weighted 25% and the overall Fuel Supply performance measure weighted 25%, the Vice President - Fuel Procurement has two Department performance measures which are weighted to determine a single Department performance weighting of 50%. These are as follows: --Delivered fuel prices (spot/contract) composited change as a percent of the GDP price index (fixed weight), a national index which measures inflation of price for the current year - weighted 75%; and --Sum total of present value benefits from renegotiation of existing contracts for coal and transportation outside of existing contract price adjustment provisions - weighted at 25%. Tables showing the performance factors and how they relate to achievement begin on page A-4 of the Addendum. 9.6 GENERAL MINE MANAGERS/GENERAL SUPERINTENDENT (MEIGS) MEASURES In addition to the Corporate performance measures weighted 25% and the overall Fuel Supply performance measures weighted 25%, the Fuel Supply General Mine Managers and General Superintendent (Meigs) have two Division/Mine performance measures which are weighted to determine a single Division/Mine performance award weighting of 50% for the mines for which they are responsible. These are as follows: --Adjusted cost of coal produced from affiliated mines, measured by cents per million BTU (/MM BTU) for the current year as reduced to reflect extraordinary costs due to downsizing and/or other special expenses and a volume adjustment of 50/MM BTU for variance from budgeted tons - weighted at 75%; and --Safety incidence rate for the current year as a percent of the comparable industry incidence rate for either underground or surface mines (whichever is applicable) - weighted at 25%. Tables showing the performance factors and how they relate to achievement begin on page A-6 of the Addendum. The performance factor shall be zero for any mine whose lost workdays charged for any single occurrence total 6,000 days or higher. 9.7 MANAGER - RIVER TRANSPORTATION MEASURES The Manager-River Transportation has, in addition to the overall Corporate performance measures weighted 25%, two Department performance measures which are weighted to determine a single Department performance weighting of 75% for River Transportation. These are: --Operating costs measured by adjusted mils per ton mile (mils/ton mile-$0.00x) for the current year, excluding cost for fuel, associated taxes and other fixed and special expenses, as approved by the SVP-Fuel Supply, with a volume adjustment of 1.5 mils/ton mile for variance from budgeted mils per ton mile - weighted 75%; and --Safety incidence rate for the current year as a percent of the most recently published incidence rate for the water transportation industry - weighted 25%. The performance factor shall be zero for any operation whose lost workdays charged for any single occurrence total 6,000 days or higher. Tables showing the performance factors and how they relate to achievement are on page A-8 of the Addendum. 9.8 MANAGER - COOK COAL TERMINAL MEASURES The Manager-Cook Coal Terminal has, in addition to the overall Corporate performance measures weighted 25%, two Department performance measures which are weighted to determine a single Department performance weighting of 75% for Cook Coal Terminal. These are: --Adjusted expenses measured by total costs incurred less rental expenses, other fixed and special expenses (e.g., harbor dredging), as approved by SVP-Fuel Supply, adjustment volumes times 25/ton - weighted 75%; and --Safety incidence rate at CCT for the current year as a percent of the most recently published incidence rate for the coal preparation plants - weighted 25%. The performance factor shall be zero for any operation whose lost workdays charged for any single occurrence total 6,000 days or higher. Tables showing the performance factors and how they relate to achievement are on page A-9. 9.9 MANAGING DIRECTOR - TRANSPORTATION MEASURES In addition to the Corporate performance measures weighted 25% and the overall Fuel Supply performance measure weighted 25%, there are two overall transportation department performance criteria which are weighted to determine a single department performance factor. These are: --Transportation cost of fuel delivered comprised of performance at Cook Coal Terminal (adjusted expenses), River Transportation (adjusted cost per ton mile) and delivered fuel prices (spot/contract) - each weighted 25%; and --Safety incidence rate at River Transportation and Cook Coal for the current year as a percent of the most recently published comparable industry rate for each location (RTD vs water transportation industry; CCT vs coal preparation plants) - each weighted 12.5%. Tables showing the performance factors and how they relate to achievement are on page A-10. 10.0 DEPARTMENT OBJECTIVES Performance criteria, with appropriate weightings, may be established each year based on agreed objectives in each department in AEPSC, the Operating Companies, or Fuel Supply. The performance rating scale is similar to those used in other measures, with ratings from 0 to 1.5, and 1.0 as target performance. Managers who set department objectives which are subjective in nature will determine the degree of accomplishment in accordance with the 0 to 1.5 scale, taking into consideration such factors as timeliness, degree of accomplishment, acceptability of results, etc. In situations where a participant who has been assigned department objectives leaves the position during a Plan year, his successor will generally assume the same objectives and both participants will share the final performance factor score. 11.0 THE MICP IN ACTION Following is an illustration to demonstrate how the mechanics of the MICP work. For purposes of this example, assume that an Operating Company Division Manager with annual base salary earnings of $90,000 has a target award of 20%, or $18,000. This individual's target award is allocated among the following performance criteria: --AEP Corporate Performance: 25%, or $4,500 --Operating Company Performance: 25%, or $4,500 --Division Performance: 50%, or $9,000 11.1 In determining the AEP Corporate portion of the MICP award, results are measured for three separate Corporate performance criteria to arrive at a single Corporate performance factor. ROE is measured in two ways, averaged, and given a 25% weighting; Total Investor Return (TIR) is given a 25% weighting; and Realization Ratio is given a 50% weighting. ROE 14% actual ROE = 1.00 S&P ranking (7th) = 1.40 _______________________________ Average 1.20 x 25% = .30 TIR S&P ranking (12th) = .80 x 25% = .20 Realization Ratio AEP ratio (.80) = 1.25 x 50% = .625 ______ Corporate Performance Factor = 1.125 The AEP Corporate award, then, is 1.125 x $4,500, or $5,062.50. 11.2 IN DETERMINING THE OPERATING COMPANY PORTION OF THE MICP AWARD, RESULTS ARE MEASURED AGAINST FOUR OPERATING COMPANY PERFORMANCE CRITERIA TO ARRIVE AT THE OPERATING COMPANY PERFORMANCE FACTOR. ALL FOUR PERFORMANCE CRITERIA ARE WEIGHTED EQUALLY AT 25% EACH:
Marketing Performance Result = 105% = 1.25 x 25% = .3125 Safety Performance Result = 22.5% = .75 x 25% = .1875 O&M Expense Performance vs. Budget Result = 93% = 1.00 x 25% = .2500 Customer Service Reliability Index Result = 97% = 1.10 x 25% = .2750 ______ Operating Company Performance Factor = 1.025 The Operating Company Award, then, is 1.025 x $4,500, or $4,612.50
11.3 IN DETERMINING THE DIVISION PORTION OF THE MICP AWARD, WE MEASURE RESULTS AGAINST FOUR PERFORMANCE CRITERIA TO ARRIVE AT THE PERFORMANCE FACTOR--AGAIN GIVING EQUAL WEIGHTING TO ALL FOUR CRITERIA.
Marketing Performance Result = 107% = 1.35 x 25% = .3375 Safety Performance Result = 22.5% = 1.25 x 25% = .3125 O&M Expense Performance vs. Budget Result = 97% = 1.50 x 25% = .3750 Customer Service Reliability Index Result = 100% = 1.00 x 25% = .2500 ______ Performance Factor = 1.275 The Division award, then, is 1.275 x $9,000, or $11,475.00
11.4 THE OPERATING COMPANY DIVISION MANAGER IN OUR EXAMPLE EARNED A TOTAL AWARD OF $21,150.00, AS FOLLOWS: --AEP CORPORATE $ 5,062.50 --OPERATING COMPANY 4,612.50 --DIVISION 11,475.00 ___________ $ 21,150.00 Of that amount, 80%, or $16,920.00 is paid during the first part of the following year, assuming the participant has not elected to defer receipt of that payment under Section 15.2. The balance, $4,230.00, is deferred in AEP common stock units for three years. (No actual shares of stock are purchased--the amount deferred is merely treated as if shares had been purchased with these funds.) During that time dividends, which are credited on the deferred stock units, are used to "purchase" additional deferred stock units. After three years, the individual will receive a cash payment in the amount of the deferred units' value, which shall be equal to the average daily high and low market price of AEP common stock for the quarter preceding the payment date. (See page A-1 in the Addendum for further details.) 12.0 PAYMENT RIGHTS AT TERMINATION OF ACTIVE EMPLOYMENT 12.1 TERMINATION AFTER COMPLETION OF PLAN YEAR A participant who is actively employed on December 31 of the Plan year is entitled to receive the regular cash award (80%) for that year and, if applicable, the value of his deferred award that has met the three calendar year requirement. For example, an employee who is actively employed on 12/31/95, and subsequently terminates is entitled to the 80% cash award for Plan year 1995, and if applicable, the value of his 1992 Plan year deferred amount. Alternatively, a participant may elect to defer receipt of awards in accordance with Section 15.2. 12.2 TERMINATION DUE TO DEATH, RETIREMENT, OR DISABILITY If a participant should leave active employment during a Plan year because of death, retirement, or disability, the award will be pro- rated based on the time the participant was actively employed in positions covered by the Plan during that year. Full payment of 100% of the pro-rated award will be made as soon as practicable in the following year. The mandatory deferrals of the 20% portions of any awards are normally paid as soon as practicable after the participant's death, retirement, or disability. For purposes of the MICP, disability shall mean the employee meets the definition of permanent and total disability under the AEP System Retirement Plan. For purposes of this Section 12.2 and Section 12.4, "retirement" occurs on the date an employee who is at least age 55 and who has five or more years of vesting service, ceases active employment with the company. In situations where a participant retires, plan participation ends on the date that full control and responsibility for the function ceased. The manager who is on vacation prior to and extending immediately into retirement has effectively ended his responsibility for managing the unit. Upon the death of an active or terminated participant, all deferred awards are immediately payable to the participant's surviving spouse. If the participant's spouse is not living, the deferred awards are immediately payable to the participant's estate. 12.3 INVOLUNTARY TERMINATION DURING PLAN YEAR If a participant is involuntarily terminated from employment during a Plan year because of (1) the permanent closing of an office, plant or other facility, or (2) as a direct result of restructuring, consolidation, change in control of the corporation or downsizing, the award will be pro-rated based on the time the participant was actively employed in positions covered by the Plan during that year. Full payment of 100% of the pro-rated award will be made as soon as practicable in the following year. Deferred awards are payable as soon as practicable after the participant's involuntary termination. 12.4 Any potential award for the current Plan year, and all mandatory deferrals of the 20% portions of any awards that have not met the three calendar year requirement pursuant to Section 15.1, are forfeited when a participant terminates active employment during the Plan year for reasons other than (1) death, retirement, disability, or (2) involuntary termination as described in Section 12.3. 13.0 CHANGES IN SALARY / POSITION / PARTICIPATION Awards are paid as a percentage of the performance year's annual base earnings, including merit and promotional increases. In situations where participation changes as a result of job assignment, the employee will be entitled to a pro-rata share of any incentive award earned during the period he or she is employed in a position covered by the Plan. In the event an MICP participant is transferred from a position covered by the Plan to another such covered position within the AEP System, the participant will be entitled to a pro-rata share of any incentive award earned during the period he or she is employed in each of the positions. If the participant is subject to different target awards as a percent of base salary in the same performance year, each target award percentage will be applied to the base salary earned during the period employed in the related position. 14.0 PLAN ADMINISTRATION The MICP is administered by the Human Resources Committee of the American Electric Power Company, Inc. Board of Directors through the Executive Compensation Committee of AEPSC. Subject to the approval of the Chief Executive Officer, the Executive Compensation Committee's interpretation of the Plan's provisions are conclusive and binding on all participants. Participation in the MICP in any Plan year shall not be viewed as conferring any right to continued employment, or to continued participation in the MICP. Subject to the approval of the Chief Executive Officer, the Executive Compensation Committee of AEPSC may vary performance criteria, weightings, and/or performance factor schedules from time to time when appropriate, enlarge or diminish the number of participants, or make other adjustments or amendments to improve the workings of the Plan. The Board of Directors reserves a right to amend or terminate the MICP. Amendment or termination of the Plan will not adversely affect any funds deferred into stock unit accounts prior to the amendment or termination. For good and sufficient cause, on petition by an Operating Company president or by a senior officer of the Company, and with the approval of the Chief Executive Officer, any performance factor(s) for any participant(s) may be varied not more than plus or minus 25% to reflect exceptional circumstance. 15.0 MICP AWARD DISTRIBUTIONS AND DEFERRALS 15.1 WHEN ALL OF THE NECESSARY DATA ARE AVAILABLE AFTER THE END OF THE PLAN YEAR, PERFORMANCE RESULTS WILL BE CALCULATED AND AWARDS MADE AS SOON AS PRACTICABLE. UNLESS THE PARTICIPANT HAS MADE AN ELECTION TO DEFER RECEIPT OF AN ADDITIONAL PORTION OF THE ENTIRE AWARD IN ACCORDANCE WITH SECTION 15.2, EIGHTY PERCENT OF THE AWARD EARNED WILL BE PAID IN CASH, EXCEPT FOR VARIABLE PAY PLAN PARTICIPANTS AS NOTED IN SECTION 1.0. TWENTY PERCENT OF ANY AWARDS MADE UNDER THE MICP WILL BE DEFERRED. ALL DEFERRALS ARE INVESTED IN AEP STOCK UNIT ACCOUNTS. NO AEP STOCK IS ACTUALLY PURCHASED -- THE AMOUNT DEFERRED IS TREATED AS IF ACTUAL SHARES HAD BEEN PURCHASED. THE NUMBER OF STOCK UNITS IS DETERMINED BY DIVIDING THE AMOUNT DEFERRED BY THE AVERAGE OF THE DAILY HIGH AND LOW AEP COMMON STOCK PRICES DURING THE PLAN YEAR IN WHICH THE INCENTIVE AWARD WAS EARNED. AN AMOUNT EQUAL TO AEP COMMON STOCK DIVIDENDS IS CREDITED ON THE DATE PAYABLE EACH CALENDAR QUARTER COMMENCING WITH THE FIRST QUARTER OF THE YEAR FOLLOWING THE YEAR IN WHICH THE AWARD WAS EARNED. THOSE AMOUNTS ARE "REINVESTED" TO "PURCHASE" ADDITIONAL DEFERRED STOCK UNITS AT THE AVERAGE OF THE DAILY HIGH AND LOW MARKET PRICE FOR THE QUARTER IN WHICH THE STOCK DIVIDEND APPLIES. AMOUNTS DEFERRED IN STOCK UNITS ARE PAYABLE IN CASH TO PARTICIPANTS AFTER THE END OF THREE CALENDAR YEARS FOLLOWING THE END OF THE YEAR FOR WHICH THE 80% PORTION OF THE AWARD WAS SCHEDULED TO BE PAID. HOWEVER, A PARTICIPANT MAY ELECT TO DEFER RECEIPT AS OUTLINED IN SECTION 15.2. THE VALUE OF STOCK UNITS PAID IS BASED ON THE AVERAGE DAILY HIGH AND LOW MARKET PRICE OF AEP COMMON STOCK FOR THE QUARTER IMMEDIATELY PRECEDING THE DATE OF PAYMENT. BECAUSE AMOUNTS HELD IN DEFERRED STOCK UNIT ACCOUNTS DO NOT INVOLVE THE ACTUAL PURCHASE OF STOCK, PLAN PARTICIPANTS ARE NOT ENTITLED TO VOTING OR CERTAIN OTHER RIGHTS APPLICABLE TO AN ACTUAL SHAREHOLDER. AMOUNTS HELD IN DEFERRED STOCK UNIT ACCOUNTS MAY NOT BE ASSIGNED, TRANSFERRED, OR PLEDGED BY A PLAN PARTICIPANT NOR WILL THEY BE SUBJECT TO EXECUTION, ATTACHMENT OR OTHER SIMILAR PROCESS. IF THE EXECUTIVE COMPENSATION COMMITTEE DETERMINES THAT THE OCCURRENCE OF ANY MERGER, RECLASSIFICATION, CONSOLIDATION, RECAPITALIZATION, STOCK DIVIDEND OR STOCK SPLIT REQUIRES AN ADJUSTMENT IN ORDER TO PRESERVE THE BENEFITS INTENDED UNDER THE PLAN, THEN THE COMMITTEE MAY, IN ITS DISCRETION, MAKE EQUITABLE PROPORTIONATE ADJUSTMENTS IN THE NUMBER OF DEFERRED STOCK UNITS HELD BY PARTICIPANTS. 15.2 ELECTIONS TO DEFER RECEIPT OF A PORTION OF THE PLAN'S 80% CASH AWARD (UP TO THE FULL AMOUNT) OR ANY PREVIOUSLY DEFERRED 20% AWARDS MUST BE EXECUTED ONE YEAR PRIOR TO THE DATE EACH AWARD WOULD OTHERWISE BE PAYABLE. THE INITIAL ELECTIVE DEFERRAL PERIOD IS ONE 3-YEAR TERM FOR THE 80% CASH AWARD. SUBSEQUENT DEFERRALS, FOLLOWING THE INITIAL DEFERRAL PERIOD, SHALL APPLY TO THE AGGREGATE AMOUNTS INITIALLY DEFERRED AND SHALL BE FOR PERIODS OF NOT LESS THAN ONE YEAR; HOWEVER, IF THE PARTICIPANT'S ELECTIVE DEFERRAL PERIOD EXTENDS BEYOND THE PARTICIPANT'S EMPLOYMENT TERMINATION DATE AND THE PARTICIPANT'S TERMINATION OCCURRED UNDER CIRCUMSTANCES OTHER THAN THOSE DESCRIBED IN SECTION 12.3, PAYMENT WILL BE MADE NO LATER THAN FIVE YEARS AFTER THE PARTICIPANT'S TERMINATION OF EMPLOYMENT. ALL AMOUNTS DEFERRED IN ACCORDANCE WITH THE PRECEDING ARE REINVESTED IN AEP STOCK UNIT ACCOUNTS DESCRIBED IN SECTION 15.1. 16.0 POSSIBLE ADJUSTMENTS TO CORPORATE PERFORMANCE DATA IF ESTIMATED DATA ARE REQUIRED TO CALCULATE CORPORATE PERFORMANCE AWARDS, OR IF CORRECTIONS ARE MADE TO DATA PREVIOUSLY REPORTED AS FINAL, ADJUSTMENTS TO AWARDS MAY BE MADE WHEN FINAL DATA ARE AVAILABLE. 17.0 FUEL SUPPLY PAYMENT SCHEDULES 17.1 SENIOR VICE PRESIDENT - FUEL SUPPLY 17.2 Fuel Supply Target Award Payment Schedule Composited Change in Price of Purchased Coal as Percent of GDP Price Index (Fixed Weight)
Percent of GDP Price Index Performance Factor* 60 or lower 1.50 70 1.25 80 1.00 100 .50 110 .25 Higher than 110 0 *Interpolate at intermediate performance. Example: If the average percentage increase in the price of purchased coal is 85% of the GDP price index, the performance factor is .875.
17.3 VICE PRESIDENT - FUEL PROCUREMENT 17.4 Fuel Supply Target Award Payment Schedule Composited Change in Price of Purchased Coal as Percent of GDP Price Index (Fixed Weight)
Percent of GDP Price Index Performance Factor* 60 or lower 1.50 70 1.25 80 1.00 100 .50 110 .25 Higher than 110 0 *Interpolate at intermediate performance. Example: If the average percentage increase in the price of purchased coal is 85% of the GDP price index, the performance factor is .875.
17.5 Fuel Supply Target Award Payment Schedule Sum Total of PV Benefits Special Contract Renegotiations
PV Benefits Total Dollars Performance Factor* $64 million or higher 1.50 $32 million 1.25 $16 million 1.00 $8 million .75 $4 million .50 $2 million .25 0 0 *Interpolate at intermediate performance.
Example: If the sum total of PV benefits from special contract negotiations were $1.6 million, the performance factor would be 0.20. 17.6 GENERAL MINE MANAGERS/GENERAL SUPERINTENDENT (MEIGS) 17.7 Southern Ohio Coal Company - Meigs Adjusted Cost of Coal Produced
/MM BTU Performance Factor* 173.6 or lower 1.50 175.6 1.25 177.6 1.00 179.6 .75 181.6 .50 183.6 .25 185.6 or higher 0 *Interpolate at intermediate performance.
17.8 Central Ohio Coal Company Adjusted Cost of Coal Produced
/MM BTU Performance Factor* 207.8 or lower 1.50 209.8 1.25 211.8 1.00 213.8 .75 215.8 .50 217.8 .25 219.8 or higher 0 *Interpolate at intermediate performance.
17.9 Windsor Coal Company Adjusted Cost of Coal Produced
/MM BTU Performance Factor* 168.6 or lower 1.50 170.6 1.25 172.6 1.00 174.6 .75 176.6 .50 178.6 .25 180.6 or higher 0 *Interpolate at intermediate performance.
17.10 All Coal Mines Safety Incidence Rate
Incidence Rate - Percent Industry Rate Performance Factor* 55 or lower 1.50 65 1.25 75 1.00 85 .75 90 .50 95 .25 Higher than 95 0 *Interpolate at intermediate performance.
17.11 MANAGER - RIVER TRANSPORTATION 17.12 River Transportation Operating Cost Per Ton Mile
Mils/Ton Mile ($.00x) Performance Factor* 3.544 or lower 1.50 3.681 1.25 3.818 1.00 3.955 .75 4.092 .50 4.229 .25 4.366 or higher 0 *Interpolate at intermediate performance.
17.13 River Transportation Safety Incidence Rate
Incidence Rate - % Industry Rate Performance Factor* 55 or lower 1.50 65 1.25 75 1.00 85 .75 90 .50 95 .25 Higher than 95 0 *Interpolate at intermediate performance.
17.14 MANAGER - COOK COAL TERMINAL 17.15 Cook Coal Terminal Adjusted Expenses
Adjusted Expenses Performance Factor* $7.30 million or better 1.50 $7.50 1.25 $7.70 1.00 $7.90 .75 $8.10 .50 $8.30 .25 $8.50 million or higher 0 *Interpolate at intermediate performance.
17.16 Cook Coal Terminal Safety Incidence Rate
Incidence Rate - % Industry Rate Performance Factor* 55 or better 1.50 65 1.25 75 1.00 85 .75 90 .50 95 .25 Higher than 95 0 *Interpolate at intermediate performance.
17.17 MANAGING DIRECTOR - TRANSPORTATION 17.18 Cook Coal Terminal Adjusted Expenses
Adjusted Expenses Performance Factor* $7.30 million or better 1.50 $7.50 1.25 $7.70 1.00 $7.90 .75 $8.10 .50 $8.30 .25 $8.50 million or higher 0 *Interpolate at intermediate performance.
17.19 River Transportation Operating Cost Per Ton Mile
Mils/Ton Mile ($.00x) Performance Factor* 3.544 or lower 1.50 3.681 1.25 3.818 1.00 3.955 .75 4.092 .50 4.229 .25 4.366 or higher 0 *Interpolate at intermediate performance.
17.20 Composited Change in Purchased Coal As Percent of GDP Price Index (Fixed Weight)
PERCENT OF GDP PRICE INDEX (FIXED WEIGHT) PERFORMANCE FACTOR* 60 or lower 1.50 70 1.25 80 1.00 100 .50 110 .25 Higher than 110 0
*Interpolate at intermediate performance Example: If the average percentage increase in the price of purchased coal is 85% of the GDP Price Index, the performance factor is .875. 17.21 River Transportation and Cook Coal Terminal Safety Incidence Rate
INCIDENCE RATE - % INDUSTRY RATE PERFORMANCE FACTOR* 55 or lower 1.50 65 1.25 75 1.00 85 .75 90 .50 95 .25 Higher than 95 0
*Interpolate at intermediate performance EX-13 4 1995 ANNUAL REPORT AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES SELECTED CONSOLIDATED FINANCIAL DATA
Year Ended December 31, 1995 1994 1993 1992 1991 INCOME STATEMENTS DATA (in millions): Operating Revenues $5,670 $5,505 $5,269 $5,045 $5,047 Operating Income 965 932 929 883 918 Net Income 530 500 354 468 498 December 31, 1995 1994 1993 1992 1991 BALANCE SHEETS DATA (in millions): Electric Utility Plant $18,496 $18,175 $17,712 $17,509 $17,148 Accumulated Depreciation and Amortization 7,111 6,827 6,612 6,281 5,952 Net Electric Utility Plant $11,385 $11,348 $11,100 $11,228 $11,196 Total Assets $15,902 $15,739 $15,362 $14,217 $13,824 Common Shareholders' Equity 4,340 4,229 4,151 4,245 4,221 Cumulative Preferred Stocks of Subsidiaries: Not Subject to Mandatory Redemption 148 233 268 535 535 Subject to Mandatory Redemption* 523 590 501 234 141 Long-term Debt* 5,057 4,980 4,995 5,311 5,029 Obligations Under Capital Leases* 405 400 284 300 273 *Including portion due within one year
Year Ended December 31, 1995 1994 1993 1992 1991 COMMON STOCK DATA: Earnings per Share $2.85 $2.71 $1.92 $2.54 $2.70 Average Number of Shares Outstanding (in thousands) 185,847 184,666 184,535 184,535 184,535 Market Price Range: High $40-5/8 $37-3/8 $40-3/8 $35-1/4 $34-1/4 Low 31-1/4 27-1/4 32 30-3/8 26-5/8 Year-end Market Price 40-1/2 32-7/8 37-1/8 33-1/8 34-1/4 Cash Dividends Paid $2.40 $2.40 $2.40 $2.40 $2.40 Dividend Payout Ratio 84.1% 88.6% 125.2% 94.6% 88.9% Book Value per Share $23.25 $22.83 $22.50 $23.01 $22.88
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES MANAGEMENT S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Business Conditions The prospect for market driven rates is powering a movement to introduce direct competition to the generation function of the electric utility industry. As a result we expect that competition will be a factor influencing AEP s future results of operations. Other important factors that could affect future results of operations are environmental laws, affiliated coal mining costs, nuclear fuel storage and disposal costs and nuclear decommissioning costs. Management will be working to prepare for a transition to greater competition and to manage the other major factors that could impact future results of operations. Competition at the Wholesale Level The Energy Policy Act of 1992 (Energy Act) was designed, among other things, to foster competition in the wholesale market through amendments to (a) the Public Utility Holding Company Act, facilitating the ownership and operation of generating facilities by independent power producers including non-electric utilities and (b) the Federal Power Act, authorizing the Federal Energy Regulatory Commission (FERC) under certain conditions to order utilities which own transmission facilities to provide wholesale transmission services to other utilities and entities generating electric power. While the Energy Act gave the FERC broad authority to mandate transmission access in the wholesale market, it prohibited the FERC from ordering retail transmission access. Customer Choice The demand for customer choice of electric supplier is mainly coming from large industrial energy users. Transmission access in the retail marketplace will allow an electric customer within a particular utility s service territory to buy power directly from another source using the power lines of the local electric utility for delivery. Financial Implications of Competition A significant expansion of competition in the generation of electricity would require the resolution of many complex issues, including the obligation to serve and the recovery of stranded costs which, if not properly addressed, could adversely impact future results of operations and possibly the financial condition of electric utilities. Stranded costs occur when a customer switches to a new supplier for its electric energy needs creating the issue of who pays for plant investment, purchased power or fuel contracts both non-affiliated and affiliated, inventories, construction work in progress, nuclear decommissioning costs, and other investments and commitments that are no longer needed, economic or recoverable in a competitive market. The amount of any losses the Company may experience from stranded costs depends on the extent to which direct competition is introduced to its business and the market price of energy. Cost-based regulation traditionally results in the recognition of revenues and expenses in accordance with rate commission orders which can result in revenue and expense recognition in different time periods than for enterprises that are not regulated. As a result, regulatory assets have been recorded by regulated utility companies representing the deferral of costs for recovery in future periods. The Company has approximately $2 billion in regulatory assets. In order to maintain regulatory assets, the Company s rates must be cost- based regulated. Management has reviewed the evidence currently available and concluded that AEP continues to meet the requirements to apply rate-regulated accounting standards. In the event a portion of the Company s business no longer met these requirements, regulatory assets would have to be written off for that portion of the business. Whether future results of operations are adversely affected by losses or write-offs also will depend on whether and how equitable recovery is provided for by the applicable regulators. We intend to seek appropriate recovery of any stranded costs and regulatory assets. AEP s Response to Competitive Pressures AEP has the financial strength, geographic reach,location and cost structure to be an able competitor. However, no assurance can be given that AEP can maintain this position in the future. In 1995 AEP took steps to prepare for competition by realigning into functional business units, expanding our marketing and customer service efforts and proposing a plan for an orderly transition to retail competition. Previously, AEP had proposed open access transmission rates. In order to better position AEP for increasing competition among electricity suppliers, we realigned from separate operating company organizations to distinct Power Generation, Nuclear Generation, Energy Delivery and Corporate Development operating units. We are realigning into separate functional units in order (a) to facilitate the unbundling of electric services to the extent required or permitted by the evolving regulatory structure and (b) to operate more efficiently and effectively to meet customers needs. The legal, financial, rate and regulatory relationships of the subsidiary operating companies will not change. To facilitate reliable, safe and efficient access for customers, AEP supports the creation of an Independent System Operator (ISO) to operate a multi-state transmission grid. Under AEP s proposal each electric company, while retaining ownership, would place its portion of the transmission grid under the management of the ISO who would be responsive to the needs of all parties using the transmission grid. AEP also supports the evolution of a Regional Power Exchange, which would establish a competitive marketplace for generation. Generators and resellers of electricity would be permitted to sell power into a spot market operated by the Regional Power Exchange. The Regional Power Exchange would accept offers to buy and sell power and would settle transactions based on the price at which supply and demand are balanced. State regulators would continue to determine the terms, standards and prices for the delivery service. Under our proposed plan regulators would be authorized to establish distribution service charges which would provide, as appropriate, for the recovery of stranded costs and regulatory assets. These charges would be collected by electric companies from all new and existing distribution services customers within a company s service territory. AEP has also offered access to its transmission grid at 142 interconnections under the same costs and terms available to AEP itself. The unbundled transmission service for wholesale customers will provide AEP with greater opportunities for transmission service revenues. Also, AEP has responded to its retail customers by introducing new rate designs (interruptible buy-through and real-time pricing) to provide lower cost-based rates, to meet specific customers needs, and to offer customer choice. AEP's proposals to pave the way for retail competition were issued to enable the Company to participate in a meaningful way in the debate with other interested parties so that we can build consensus and form coalitions to shape the form of the future playing field. We plan to enhance shareholder value by making AEP the supplier of choice. Our success will depend on our ability to obtain a level playing field, improve and expand on our energy sales and services and maintain and improve our relatively low cost structure. New Business Opportunities We continue to seek and consider new business opportunities, particularly those which permit the use of our expertise and core competencies. In the non-rate-regulated environment, AEP offers consulting services both domestically and internationally and contracts with other public utilities and government agencies for the licensing of intellectual property and the delivery of energy services. In addition, AEP is pursuing investments in power generation, transmission and distribution projects. In 1995 AEP announced a strategic alliance with Cogentrix Energy and Zurn Industries to pursue industrial power projects in the United States and Canada. Cogentrix is one of the largest independent power producers in the U.S., while Zurn is the largest turnkey engineer and constructor of both biomass power plants and mid-sized gas turbine combined cycle plants in the U.S. AEP has been pursuing several other possible power generation, transmission and distribution investment projects overseas. These investment opportunities offer the potential for earning returns which exceed those of the domestic rate-regulated operations. However, they also involve a higher degree of risk which must be carefully considered and assessed. AEP may make investments in these and other new business opportunities after management carefully assesses the risks involved versus the potential for enhanced shareholder value. Appropriate new business investments are part of AEP s strategic plan for enhancing shareholder value and will be the full time responsibility of our newly formed corporate development operating unit. Affiliated Coal Cost Fuel is 80% of the production cost of electricity. Although our fuel costs have declined by one half in constant dollars since 1986, we must continue to manage our coal costs to effectively compete. As long-term contracts expire we are negotiating with suppliers to lower purchased coal costs. We will continue to supplement our affiliated and long-term coal supplies with spot market coal as favorable market conditions permit. Approximately 13% of the coal we burn is supplied by affiliated mines; the remainder is acquired under long-term contracts and in the spot market. Efforts continue to reduce the cost of affiliated coal. In recent years Ohio Power Company (OPCo) has been limited in its recovery of the cost of coal produced by its affiliated mines in its Ohio jurisdiction. Under the terms of a 1992 stipulation agreement a predetermined price of $1.575 per million Btu s for coal burned at the Gavin Plant was established effective December 1, 1994 for a 15-year period subject to adjustment for inflation. A subsequent Settlement Agreement sets an overall predetermined electric fuel component rate for OPCo at 1.465 cents per kwh for the period June 1, 1995 through November 30, 1998. The Gavin Plant predetermined price remains effective as escalated from the original $1.575 per million Btu s. After November 2009 the price that OPCo can recover for coal from its affiliated Meigs mine, which supplies the Gavin Plant, will be limited to the lower of cost or the then-current market price. The predetermined prices provide OPCo with an opportunity to accelerate recovery of its Ohio jurisdictional investment in and liabilities and closing costs of the Company s Meigs, Muskingum and Windsor mining operations to the extent the actual cost of coal burned at the Gavin Plant is less than the predetermined prices. Based on the estimated future cost of coal at Gavin Plant, we believe that OPCo should be able to recover under the terms of the 1992 stipulation agreement and in conjunction with the Settlement Agreement, the Ohio jurisdictional portion of the cost of the affiliated mining operations including mine closure costs. Management intends to seek from 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 $195 million after tax at December 31, 1995. The affiliated Muskingum and Windsor mines may have to close by January 2000 as part of compliance with Phase II requirements of the Clean Air Act Amendments of 1990. Should it become apparent that the costs of the affiliated mines including future mine closure costs will not be recoverable, the mines could be closed and results of operations adversely affected. Nuclear Cost The Company s only nuclear plant, the Donald C. Cook Nuclear Plant, has recently achieved a superior rating from the Institute of Nuclear Power Operations, a nuclear industry oversight group, and received improved Nuclear Regulatory Commission (NRC) performance ratings. Refueling outage costs have been reduced by $20 million compared to 1992 outage expense levels. In an effort to continue to reduce costs and enhance organizational efficiency, we announced in November that during the summer of 1996 we will consolidate our Columbus-based nuclear management and support staff with the plant staff at or near the Cook Nuclear Plant in Bridgman, Michigan. The cost to operate and maintain the two-unit Cook Nuclear Plant is impacted by federal laws and NRC requirements. The Nuclear Waste Policy Act of 1982 established federal responsibility for the permanent off-site disposal of spent nuclear fuel and high-level radioactive waste. By law we participate in the Department of Energy s (DOE s) Spent Nuclear Fuel (SNF) disposal program which is described in Note 4 of the Notes to Consolidated Financial Statements. Since 1983 our consumers of nuclear generated electricity have paid $237 million for the disposal of spent nuclear fuel consumed at the Cook Nuclear Plant. Under the provisions of the Nuclear Waste Policy Act, collections from customers are to provide the DOE with money to build a permanent repository for spent fuel. The federal government has not made sufficient progress towards a permanent repository and as long as there is a delay in the permanent storage repository for spent nuclear fuel, the cost of a temporary or permanent repository will continue to increase. The cost to decommission the Cook Plant is affected by NRC regulations and the DOE s SNF disposal program. Studies completed in 1994 estimate the cost to decommission the plant and dispose of low-level nuclear waste accumulation to range from $634 million to $988 million in 1993 dollars. The decommissioning estimate could escalate due to uncertainty in the DOE s SNF disposal program and the length of time that SNF may need to be stored at the plant site delaying decommissioning. Presently we are recovering the estimated cost of decommissioning the Cook Plant over its remaining life. However, AEP s future results of operations and possibly its financial condition could be adversely affected if the cost of spent nuclear fuel disposal and decommissioning continues to increase and if for some reason such costs cannot be recovered. Environmental Concerns Clean Air Act To comply with the Clean Air Act Amendments of 1990 (CAAA) which requires substantial reductions in sulfur dioxide and nitrogen oxides emitted from electric generating plants, an AEP System wide least-cost compliance plan was developed reflecting various methods of compliance. The corner stone of the compliance strategy is the installation of flue gas desulfurization systems (scrubbers) on the two-unit Gavin Plant which has been responsible for about 25% of the System s total sulfur dioxide emissions. By selecting scrubbers, the compliance plan allows the use of Ohio high-sulfur coal at the Gavin Plant. The scrubbers for the Gavin units are completed and operational. The PUCO approved the compliance plan as the least cost compliance strategy and approved recovery of the compliance costs under the terms of the Settlement Agreement. Through the CAAA emission allowance program in which utilities are authorized to emit a designated quantity of sulfur dioxide, measured in tons per year, AEP, on a system wide or aggregate basis, will bank a substantial number of Phase I allowances due to over compliance. To meet the stricter standards of Phase II of the CAAA, AEP has the option to use banked Phase I allowances, buy low sulfur com-pliance coal, purchase additional allowances and/or build additional scrubbers. We also have the option to sell Phase I allowances saved due to the installation of the scrubbers and the acquisition of low sulfur coal. Hazardous Material By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and spent nuclear fuel. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically disposed of or treated in captive disposal facilities or are beneficially utilized. In addition, the AEP generating plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls (PCBs) and other hazardous and non-hazardous materials. The AEP System is currently incurring costs to safely dispose of such substances, and additional costs could be incurred to comply with new laws and regulations if enacted. The Comprehensive Environmental Response, Compensation and Liability Act (CERCLA or Superfund legislation) addresses clean-up of hazardous substances at disposal sites and authorizes the United States Environmental Protection Agency (Federal EPA) to administer the clean-up programs. As of year-end 1995, AEP companies are currently involved in litigation with respect to five sites being overseen by the Federal EPA and have been named by the Federal EPA as Potentially Responsible Parties (PRPs) for five other sites. There are 11 additional sites for which AEP companies have received information requests which could lead to PRP designation. Also, AEP companies have received information requests with respect to four sites administered by state authorities. AEP companies liability has been resolved for a number of sites with no significant effect on results of operations. In those instances where an AEP company has been named a PRP or defendant, the disposal or recycling activity of the AEP company was in accordance with applicable laws and regulations. CERCLA does not recognize compliance as a defense, but imposes strict liability on parties who fall within its broad statutory categories. While the potential liability for each Superfund site must be evaluated separately, several general statements can be made regarding such potential liability. The disposal at a particular site by the AEP companies is often unsubstantiated; the quantity of material the AEP companies disposed of at a site was generally small; and the nature of the material AEP generally disposed of was non-hazardous. Typically, an AEP subsidiary is one of many parties named as PRPs for a site and, although liability is joint and several, generally some of the other parties are financially sound enterprises. Therefore, AEP s present estimates do not anticipate material cleanup costs for identified sites for which AEP subsidiaries have been declared PRPs. However, if for reasons not currently identified significant costs are incurred for cleanup, future results of operations and possibly financial condition would be adversely affected unless the costs can be recovered. Results of Operations Earnings Increase The 6% increase in net income to $530 million or $2.85 per share for 1995 from $500 million or $2.71 per share in 1994 was primarily due to increased energy sales. Total sales of energy were 120.7 billion kilowatthours in 1995 compared with 116.7 billion kilowatthours in 1994 reflecting increased usage and additional customers. Unseasonably warm weather in the summer of 1995 and colder weather in the fourth quarter of 1995, compared with milder weather in the prior year s fourth quarter, were the primary factors causing the increased usage. The positive earnings impact of the increased sales was partly offset by the unfavorable effect of $27 million in after-tax expenses related to severance pay charges. In 1994 earnings increased 41% to $500 million or $2.71 per share from $354 million or $1.92 per share in 1993. The increase was due to the effect of a $145 million after-tax loss recorded in 1993 as a result of a disallowance of a portion of the Company's Zimmer Plant investment. Without the disallowance, 1993 earnings and earnings per share would have been $498 million and $2.70, respectively. Excluding the disallowance, 1994 earnings increased slightly as compared to 1993 earnings predominately due to the favorable effect of rate increases in several jurisdictions which were heavily offset by the related amortization of Zimmer Plant deferrals and increased operating expenses largely as a result of significant storm damage. Revenues And Sales Increase Operating revenues increased 3% in 1995 and more than 4% in 1994 reflecting increased energy usage by retail customers, growth in the number of retail customers and the effects of rate increases. The change in revenues is analyzed as follows:
Increase (Decrease) From Previous Year (Revenues in Millions) 1995 1994 Amount % Amount % Retail: Price Variance $ 46.5 $ 90.7 Volume Variance 173.0 53.8 Fuel Cost Recoveries (22.9) 40.5 196.6 4.2 185.0 4.1 Wholesale: Price Variance (39.3) 68.6 Volume Variance 10.8 (49.7) Fuel Cost Recoveries (4.6) 8.1 (33.1)(4.6) 27.0 3.9 Other Operating Revenues 2.2 23.8 Total $165.7 3.0 $235.8 4.5
The increase in 1995 operating revenues resulted from a 4% increase in energy sales to retail customers primarily due to increased usage and continued growth in the number of customers in all retail customer classes. Energy sales to residential customers, which is the most weather-sensitive customer class, rose over 6% in 1995 mainly as a result of increased weather related usage in the last half of the year. Sales to commercial and industrial customers rose 5% and 2%, respectively, reflecting additional customers, the effects of weather and the expanding economy. Although revenues from wholesale customers declined in 1995, wholesale energy sales increased by more than 1% largely due to increased sales made on an hourly basis to unaffiliated utilities. This type of short-term sale is typically made when the unaffiliated utility can purchase energy at a lower cost than the cost at which that utility can generate the energy. Such sales usually take place as a result of increased weather-related demand. The increase in 1995 wholesale energy sales occurred during the last six months of the year when the summer weather was unseasonably warm and fall temperatures were colder compared with the prior year. While wholesale energy sales increased, wholesale revenues declined in 1995 reflecting increasing competition. Although demand and generation increased, fuel cost revenues declined in 1995 due to operation of the fuel clause mechanisms. Operating revenues increased in 1994 primarily due to increased revenues from retail customers reflecting retail rate increases in several jurisdictions and an increase in retail energy sales and fuel cost recoveries. A 2% increase in retail energy sales in 1994 was offset by a 7% decline in wholesale sales resulting in a slight decline in net energy sales. The 2% increase in retail energy sales in 1994 resulted from growth in the number of residential, commercial and industrial customers served and increased usage by industrial and commercial customers. Energy sales to residential customers remained constant in 1994 due to mild weather during most of the year. Wholesale revenues increased 4% in 1994, on a 7% decrease in sales, reflecting an increase in take-or-pay capacity charges to unaffiliated utilities. Capacity charges are to reserve a specified quantity of AEP System generating capacity and must be paid even when the energy is not taken. The increase in capacity charges resulted from increased capacity reserved under a long-term contract and short-term contracts with unaffiliated utilities in the summer of 1994 because of a forced generating unit outage. The increase in capacity reservation did not lead to a corresponding increase in energy sold in 1994 due to mild weather throughout most of 1994. The mild weather in 1994, combined with increased competition in the wholesale market, reduced short-term wholesale sales for 1994. Fuel cost recoveries increased in 1994 in both the retail and wholesale jurisdictions resulting from increased fuel costs. Future levels of short-term wholesale sales will be affected by the competitive nature of the short-term energy market and other factors, such as unaffiliated generating plant availability, the weather and the economy, all of which are not generally within management's control. The Company's future results of operations will be affected by its ability to make cost-effective wholesale sales or, if such sales are reduced, the ability to raise retail rates to reflect the loss of wholesale sales credits. Future results of operations also will depend in part on the weather since sales to residential and commercial customers are weather-sensitive. Operating Expenses Increase Changes in the components of operating expenses are shown in the table.
Increase (Decrease) From Previous Year (Dollars in Millions) 1995 1994 Amount % Amount % Fuel and Purchased Power $(119.7) (6.9) $ 97.7 5.9 Other Operation 181.3 18.1 31.9 3.3 Maintenance (2.4) (0.5) 21.2 4.1 Depreciation and Amortization 20.8 3.6 41.5 7.8 Taxes Other Than Federal Income Taxes (5.0) (1.0) 25.9 5.5 Federal Income Taxes 58.6 27.5 13.8 6.8 Total $ 133.6 2.9 $232.0 5.3
Although generation increased 3% in 1995, fuel and purchased power expense declined as a result of a decrease in the average cost of fossil fuel resulting from reduced coal prices reflecting the renegotiation of certain long-term coal contracts and other lower priced purchases under existing and new contracts. Other factors which reduced fuel and purchased power expense were increased utilization of low-cost nuclear generation in 1995; operation of fuel clause mechanisms; and decreased energy purchases due to the mild weather during the first half of 1995. Changes in fuel expense are generally deferred pending recovery in various fuel recovery mechanisms, and as such they generally do not affect earnings. The increase in fuel and purchased power expense in 1994 was mainly the result of increased utilization of coal-fired generation while the Cook Plant nuclear units were unavailable during refueling and maintenance outages in 1994, and increased purchases of energy from unaffiliated utilities for pass- through sales to other unaffiliated utilities. The significant increase in other operation expense during 1995 was primarily due to rent and other operating costs of the Gavin Plant scrubbers which went into service in December 1994 and the first quarter of 1995; a $41 million ($27 million after-tax) provision for severance pay recorded in 1995 related mainly to a functional realignment of operations; and costs related to the development of a new activity based budgeting system. Other operation expense increased in 1994 as a result of regulatory-approved increases in accruals and amortization, concurrent with rate recovery, of nuclear plant decommissioning expense and certain low-income residential customers' payment programs. Maintenance expense increased in 1994 due to significant storm damage caused by snow and ice storms during the first three months of 1994. The increase in depreciation and amortization expense in 1994 was primarily due to the court-ordered discontinuance of the Zimmer Plant phase- in plan deferrals effective in February 1994 and the subsequent monthly amortization of such costs as they were recovered in rates. Taxes other than federal income tax expense rose in 1994 mainly due to an increase in revenue-based gross receipts taxes of several states reflecting the increase in 1994 revenues and an increase in generation-based West Virginia taxes reflecting an increase in generation at West Virginia power plants in 1994. Effective June 1995, the West Virginia tax is based on generating capacity in West Virginia rather than on generation in West Virginia which will result in a less volatile level of West Virginia taxes. The increase in 1995 federal income tax expense attributable to operations was primarily due to an increase in pre-tax operating income; changes in certain book/tax differences accounted for on a flow-through basis and the effects of accrual adjustments for prior year tax returns. The 1994 increase was mainly due to an increase in pre-tax operating income. Deferred Carrying Charges and Nonoperating Income The decrease in deferred Zimmer Plant carrying charges in 1995 and 1994 resulted from the cessation of deferrals commensurate with inclusion of the full plant investment in rate base effective February 1, 1994 and the monthly reduction in the deferred balance on which a return is earned. The deferred balance declined due to its amortization to depreciation and amortization expense commensurate with recovery through a rate surcharge. The increase in other nonoperating income in 1995 and the decrease in 1994 was mainly due to the 1994 recordation of a provision for loss of $8.2 million after-tax on an investment. Also contributing to the 1994 decrease was the effect of interest income recorded in March 1993 on tax refunds from the Internal Revenue Service (IRS) in connection with the settlement of audits of prior years' tax returns. Interest Charges Increase Interest charges increased in 1995 mainly due to an increase in interest on short-term debt resulting from a higher average interest rate in 1995 on larger levels of outstanding short-term debt during the year. Refinancing programs of several subsidiaries during the early part of 1994 and 1993 reduced the average interest rate on outstanding long-term debt in 1994 as well as the levels of long-term debt causing the decline in interest expense in 1994. Common Dividend Remains Constant, Payout Ratio Decreases The Company paid a quarterly dividend in 1995 of 60 cents a share maintaining the annual dividend rate at $2.40 per share. The payout ratio improved to 84% in 1995 from 89% in 1994. In 1993 the payout ratio was also 89% before the Zimmer disallowance. Construction Spending Declining Construction expenditures have been declining in recent years. Management estimates cumulative construction expenditures for utility operation to be $2 billion over the next three years with no major new plant construction planned. Approximately 80% of the construction expenditures for the next three years will be financed internally. Liquidity and Capital Resources 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 preferred stock and with additional capital contributions by the parent company. In 1995 short-term borrowing increased by $48 million. At December 31, 1995, American Electric Power and its subsidiaries had unused short-term lines of credit of $372 million. The sources of funds available to the parent company are dividends from its subsidiaries, short-term and long-term borrowings and, when necessary, proceeds from the issuance of common stock. American Electric Power issued 1,400,000 shares of common stock in 1995 and 700,000 in 1994 through a Dividend Reinvestment Program raising $49 million and $22 million, respectively. As a result of the common stock issuance in 1995 and 1994 and a reduction in long-term debt over the past several years, the common equity to capitalization ratio has steadily improved. At December 31,1995 the ratio increased to 43.1% from 42.1% at year end 1994 and has improved from 41.1% in 1992. At December 31, 1995 the subsidiaries had outstanding $5.06 billion of long-term debt and $671 million of preferred stock. The subsidiaries have regulatory approval to issue up to $1.2 billion of long-term debt. Management expects to use the proceeds of future long-term financing to retire short-term debt, refinance maturing and other long-term debt, refund cumulative preferred stock and fund construction expenditures. Principal Operating Subsidiaries Debt & Preferred Stock Coverage
Mortgage Preferred December 31, 1995 Debt Stock Appalachian Power Co. 3.47 1.78 Columbus Southern Power Co. 3.90 N/A Indiana Michigan Power Co. 6.25 2.63 Kentucky Power Co. 2.86 N/A Ohio Power Co. 6.17 3.04 N/A - Not Applicable
Unless the subsidiaries meet certain earnings or coverage tests, they cannot issue additional mortgage bonds or preferred stock. In order to issue mortgage bonds (without refunding existing debt), each subsidiary must have pre-tax earnings equal to at least two times the annual interest charges on mortgage bonds after giving effect to the issuance of the new debt. Generally, issuance of additional preferred stock requires an after-tax gross income at least equal to one and one-half times annual interest and preferred stock dividend requirements after giving effect to the issuance of the new preferred stock. The subsidiaries presently exceed these minimum coverage requirements. Litigation AEP is involved in a number of legal proceedings and claims. While we are unable to predict the outcome of such litigation, it is not expected that the ultimate resolution of these matters will have a material adverse effect on the results of operations and/or financial condition. Effects of Inflation Inflation affects AEP s cost of replacing utility plant and the cost of operating and maintaining its plant. The rate-making process limits our recovery to the historical cost of assets resulting in economic losses when the effects of inflation are not recovered from customers on a timely basis. However, economic gains that results from the repayment of long-term debt with inflated dollars partly offset such losses. New Accounting Rules The Financial Accounting Standards Board (FASB) issued a new accounting standard, SFAS 121 Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of, in 1995 effective for 1996 accounting periods. The initial implementation of this new standard is not expected to have a significant impact on the Company. In 1996 the FASB issued an exposure draft Accounting for Certain Liabilities Related to Closure or Removal of Long-Lived Assets. This document proposes that the present value of any decommissioning or other closure or removal obligation be recorded as a liability when the obligation is incurred. A corresponding asset would be recorded in the plant investment account and recovered through depreciation charges over the asset s life. A proposed transition rule would require that an entity report in income the cumulative effect of initially applying the new standard. The Company is currently studying the impact of the proposed rules and evaluating its potential impact. AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF INCOME (in thousands - except per share amounts)
Year Ended December 31, 1995 1994 1993 OPERATING REVENUES $5,670,330 $5,504,670 $5,268,842 OPERATING EXPENSES: Fuel and Purchased Power 1,625,531 1,745,245 1,647,573 Other Operation 1,184,158 1,002,822 970,916 Maintenance 541,825 544,312 523,062 Depreciation and Amortization 593,019 572,189 530,731 Taxes Other Than Federal Income Taxes 489,223 494,210 468,296 Federal Income Taxes 272,027 213,399 199,621 TOTAL OPERATING EXPENSES 4,705,783 4,572,177 4,340,199 OPERATING INCOME 964,547 932,493 928,643 NONOPERATING INCOME: Deferred Zimmer Plant Carrying Charges (net of tax) 3,089 5,604 25,343 Other Nonoperating Income 17,115 5,881 21,229 TOTAL NONOPERATING INCOME 20,204 11,485 46,572 LOSS FROM ZIMMER PLANT DISALLOWANCE: Disallowed Cost - - 159,067 Related Income Taxes - - (14,534) NET ZIMMER LOSS - - 144,533 INCOME BEFORE INTEREST CHARGES AND PREFERRED DIVIDENDS 984,751 943,978 830,682 INTEREST CHARGES (net) 400,077 389,240 418,064 PREFERRED STOCK DIVIDEND REQUIREMENTS OF SUBSIDIARIES 54,771 54,726 58,849 NET INCOME $ 529,903 $ 500,012 $ 353,769 AVERAGE NUMBER OF SHARES OUTSTANDING 185,847 184,666 184,535 EARNINGS PER SHARE $2.85 $2.71 $1.92 CASH DIVIDENDS PAID PER SHARE $2.40 $2.40 $2.40
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (in thousands)
Year Ended December 31, 1995 1994 1993 RETAINED EARNINGS JANUARY 1 $1,325,581 $1,269,283 $1,358,800 NET INCOME 529,903 500,012 353,769 DEDUCTIONS: Cash Dividends Declared 445,831 443,101 442,891 Other 8 613 395 RETAINED EARNINGS DECEMBER 31 $1,409,645 $1,325,581 $1,269,283 See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF CASH FLOWS (in thousands)
Year Ended December 31, 1995 1994 1993 OPERATING ACTIVITIES: Net Income $ 529,903 $ 500,012 $ 353,769 Adjustments for Noncash Items: Depreciation and Amortization 578,003 561,188 555,436 Deferred Federal Income Taxes 11,916 (16,033) (62,186) Deferred Investment Tax Credits (25,819) (31,275) (28,222) Amortization of Operating Expenses and Carrying Charges (net) 53,479 16,022 2,997 Loss from Zimmer Plant Disallowance - - 159,067 Changes in Certain Current Assets and Liabilities: Accounts Receivable (net) (71,804) 34,302 (15,641) Fuel, Materials and Supplies 457 (1,627) 156,464 Accrued Utility Revenues (40,433) 2,419 18,994 Accounts Payable (31,044) (7,959) 47,018 Taxes Accrued 37,515 (26,521) 56,502 Other (net) 14,437 (52,803) 22,469 Net Cash Flows From Operating Activities 1,056,610 977,725 1,266,667 INVESTING ACTIVITIES: Construction Expenditures (605,974) (643,457) (592,199) Proceeds from Sale of Property and Other 20,567 49,802 26,669 Net Cash Flows Used For Investing Activities (585,407) (593,655) (565,530) FINANCING ACTIVITIES: Issuance of Common Stock 48,707 22,256 - Issuance of Cumulative Preferred Stock - 88,787 321,168 Issuance of Long-term Debt 523,476 411,869 1,339,227 Retirement of Cumulative Preferred Stock (158,839) (35,949) (333,992) Retirement of Long-term Debt (469,767) (445,636) (1,696,806) Change in Short-term Debt (net) 48,140 38,009 25,822 Dividends Paid on Common Stock (445,831) (443,101) (442,891) Net Cash Flows Used For Financing Activities (454,114) (363,765) (787,472) Net Increase (Decrease) in Cash and Cash Equivalents 17,089 20,305 (86,335) Cash and Cash Equivalents January 1 62,866 42,561 128,896 Cash and Cash Equivalents December 31 $ 79,955 $ 62,866 $ 42,561 See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED BALANCE SHEETS (In Thousands - Except Share Data)
December 31, 1995 1994 ASSETS ELECTRIC UTILITY PLANT: Production $ 9,238,843 $ 9,172,766 Transmission 3,316,664 3,247,280 Distribution 4,184,251 3,966,442 General (including mining assets and nuclear fuel) 1,442,086 1,529,436 Construction Work in Progress 314,118 258,700 Total Electric Utility Plant 18,495,962 18,174,624 Accumulated Depreciation and Amortization 7,111,123 6,826,514 NET ELECTRIC UTILITY PLANT 11,384,839 11,348,110 OTHER PROPERTY AND INVESTMENTS 825,781 747,422 CURRENT ASSETS: Cash and Cash Equivalents 79,955 62,866 Accounts Receivable: Customers (less allowance for uncollectible accounts of $5,430 in 1995 and $4,056 in 1994) 417,854 346,462 Miscellaneous 74,429 74,017 Fuel - at average cost 271,933 306,700 Materials and Supplies - at average cost 251,051 216,741 Accrued Utility Revenues 207,919 167,486 Prepayments and Other 98,717 94,786 TOTAL CURRENT ASSETS 1,401,858 1,269,058 REGULATORY ASSETS 1,979,446 2,040,997 DEFERRED CHARGES 310,377 333,169 TOTAL $15,902,301 $15,738,756 See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED BALANCE SHEETS
December 31, 1995 1994 CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock-Par Value $6.50: 1995 1994 Shares Authorized. .300,000,000 300,000,000 Shares Issued. . . .195,634,992 194,234,992 (8,999,992 shares were held in treasury) $ 1,271,627 $ 1,262,527 Paid-in Capital 1,658,524 1,640,661 Retained Earnings 1,409,645 1,325,581 Total Common Shareholders' Equity 4,339,796 4,228,769 Cumulative Preferred Stocks of Subsidiaries:* Not Subject to Mandatory Redemption 148,240 233,240 Subject to Mandatory Redemption 515,085 590,300 Long-term Debt* 4,920,329 4,686,648 TOTAL CAPITALIZATION 9,923,450 9,738,957 OTHER NONCURRENT LIABILITIES 884,707 794,478 CURRENT LIABILITIES: Preferred Stock and Long-term Debt Due Within One Year* 144,597 293,756 Short-term Debt 365,125 316,985 Accounts Payable 220,142 251,186 Taxes Accrued 420,192 382,677 Interest Accrued 80,848 88,916 Obligations Under Capital Leases 89,692 93,252 Other 304,466 281,124 TOTAL CURRENT LIABILITIES 1,625,062 1,707,896 DEFERRED INCOME TAXES 2,656,651 2,657,062 DEFERRED INVESTMENT TAX CREDITS 430,041 456,043 DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2 249,875 259,152 DEFERRED CREDITS 132,515 125,168 CONTINGENCIES (Note 4) TOTAL $15,902,301 $15,738,756 *See Accompanying Schedules on pages 34 - 35.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. Significant Accounting Policies: The American Electric Power System (AEP, AEP System or the Company) is a public utility engaged in the generation, purchase, transmission and distribution of electric power to over 2.9 million retail customers in its seven state service territory which covers portions of Ohio, Michigan, Indiana, Kentucky, West Virginia, Virginia and Tennessee. Electric power is also supplied at wholesale to neighboring utility systems. The organization of the AEP System consists of American Electric Power Company, Inc., the parent holding company; seven electric utility operating companies (utility subsidiaries); a generating subsidiary, AEP Generating Company (AEPGEN); a service company, American Electric Power Service Corporation (AEPSC); and three active coal-mining companies. The five largest utility subsidiaries, which pool their generating and transmission facilities and operate them as an integrated system, are: - - Appalachian Power Company (APCo) - - Columbus Southern Power Company (CSPCo) - - Indiana Michigan Power Company (I&M) - - Kentucky Power Company (KEPCo) - - Ohio Power Company (OPCo) The remaining two utility subsidiaries, Kingsport Power Company and Wheeling Power Company, are distribution companies that purchase power from APCo and OPCo, respectively. AEPSC provides management and professional services to the AEP System. The active coal-mining companies are wholly- owned by OPCo and sell substantially all of their production to OPCo. AEPGEN has a 50% interest in the Rockport Plant which is comprised of two of the AEP System's six 1,300 megawatt (mw) generating units. Effective January 1, 1996, AEPSC and the seven utility subsidiaries began operating as American Electric Power. There has been no change to the legal names of these companies. The AEP System s operations are divided into four major business units which are managed centrally by AEPSC. The four business units are Power Generation, Nuclear Generation, Energy Delivery and Corporate Development. Rate Regulation - The AEP System is subject to regulation by the Securities and Exchange Commission (SEC) under the Public Utility Holding Company Act of 1935 (1935 Act). The rates charged by the utility subsidiaries are approved by the Federal Energy Regulatory Commission (FERC) or one of the state utility commissions as applicable. The FERC regulates wholesale rates and the state commissions regulate retail rates. Principles of Consolidation - The consolidated financial statements include American Electric Power Company, Inc. (AEPCo., Inc.) and its wholly-owned subsidiaries consolidated with their wholly-owned subsidiaries. Significant intercompany items are eliminated in consolidation. Basis of Accounting - As the owner of cost-based rate-regulated electric public utility companies, AEPCo., Inc.'s consolidated financial statements reflect the actions of regulators that result in the recognition of revenues and expenses in different time periods than enterprises that are not rate regulated. In accordance with Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation, regulatory assets and liabilities are recorded to reflect the economic effects of regulation. Use of Estimates - The preparation of these financial statements in conformity with generally accepted accounting principles requires in certain instances the use of management s estimates. Actual results could differ from those estimates. Utility Plant - Electric utility plant is stated at original cost and is generally subject to first mortgage liens. Additions, major replacements and betterments are added to the plant accounts. Retirements from the plant accounts and associated removal costs, net of salvage, are deducted from accumulated depreciation. The costs of labor, materials and overheads incurred to operate and maintain utility plant are included in operating expenses. Allowance for Funds Used During Construction (AFUDC) - AFUDC is a noncash nonoperating income item that is recovered over the service life of utility plant through depreciation and represents the estimated cost of borrowed and equity funds used to finance construction projects. The average rates used to accrue AFUDC were 6.91%, 6.59%, and 5.84% in 1995, 1994 and 1993, respectively. Depreciation, Depletion and Amortization - Depreciation is provided on a straight-line basis over the estimated useful lives of property other than coal-mining property and is calculated largely through the use of composite rates by functional class as follows: Functional Class Composite of Property Annual Rates Production: Steam-Nuclear 3.4% Steam-Fossil-Fired 3.2% to 4.4% Hydroelectric-Conventional and Pumped Storage 2.5% to 3.2% Transmission 1.7% to 2.7% Distribution 3.4% to 4.2% General 2.0% to 3.8% The utility subsidiaries presently recover amounts to be used for demolition of non-nuclear plant through depreciation charges included in rates. Depreciation, depletion and amortization of coal-mining assets is provided over each asset's estimated useful life, ranging up to 30 years, and is calculated using the straight-line method for mining structures and equipment. The units-of-production method is used for coal rights and mine development costs based on estimated recoverable tonnages at a current average rate of $1.07 per ton. These costs are included in the cost of coal charged to fuel expense. Cash and Cash Equivalents - Cash and cash equivalents include temporary cash investments with original maturities of three months or less. Sale of Receivables - Under an agreement that expires in 2000, CSPCo can sell up to $50 million of undivided interests in designated pools of accounts receivable and accrued utility revenues with limited recourse. As collections reduce previously sold pools, interests in new pools are sold. At December 31, 1995, 1994 and 1993, $50 million remained to be collected and remitted to the buyer. Operating Revenues - Revenues include the accrual of electricity consumed but unbilled at month-end as well as billed revenues. Fuel Costs - Fuel costs are matched with revenues in accordance with rate commission orders. Generally in the retail jurisdictions, changes in fuel costs are deferred or revenues accrued until approved by the regulatory commission for billing to customers in later months. Wholesale jurisdictional fuel cost changes are expensed and billed as incurred. Levelization of Nuclear Refueling Outage Costs - Incremental operation and maintenance costs associated with refueling outages at the Company s Donald C. Cook Nuclear Plant (Cook Plant) are deferred for amortization over the period (generally eighteen months) beginning with the commencement of an outage until the beginning of the next outage. Income Taxes - The Company follows the liability method of accounting for income taxes as prescribed by SFAS 109, Accounting for Income Taxes. Under the liability method, deferred income taxes are provided for all temporary differences between book cost and tax basis of assets and liabilities which will result in a future tax consequence. Where the flow-through method of accounting for temporary differences is reflected in rates, regulatory assets and liabilities are recorded in accordance with SFAS 71. Investment Tax Credits - Investment tax credits have been accounted for under the flow-through method except where regulatory commissions have reflected investment tax credits in the rate-making process on a deferral basis. Deferred investment tax credits are being amortized over the life of the related plant investment. Debt and Preferred Stock - Gains and losses on reacquired debt are deferred and amortized over the remaining term of the reacquired debt in accordance with rate-making treatment. If the debt is refinanced the reacquisition costs are deferred and amortized over the term of the replacement debt commensurate with their recovery in rates. Debt discount or premium and debt issuance expenses are amortized over the term of the related debt, with the amortization included in interest charges. Redemption premiums paid to reacquire preferred stock are deferred, debited to paid-in capital and amortized to retained earnings in accordance with rate-making treatment. The excess of par value over costs of preferred stock reacquired to meet sinking fund requirements is credited to paid-in capital. Other Property and Investments - Securities held in trust funds for decommissioning nuclear facilities and for the disposal of spent nuclear fuel are recorded at market value in accordance with SFAS No. 115, Accounting for Certain Investments in Debt and Equity Securities. Securities in the trust funds have been classified as available-for-sale due to their long-term purpose. Due to the rate-making process, adjustments for unrealized gains and losses are not reported in equity but result in adjustments to regulatory assets and liabilities. Excluding the decommissioning and spent nuclear fuel disposal trust funds, other property and investments are stated at cost. Reclassifications - Certain prior-period amounts were reclassified to conform with current-period presentation. 2. Rate Matters: Base Rate Activity - In March 1995 a Settlement Agreement was approved by the Public Utilities Commission of Ohio (PUCO) that resolved a July 1994 base rate case and a pending electric fuel component (EFC) proceeding. Under the terms of the Settlement Agreement, base rates increased by $66 million annually in March 1995 which includes recovery of the cost of the flue gas desulfurization systems (scrubbers) installed at the Gavin Plant; the EFC rate is fixed at 1.465 cents per kwh from June 1995 through November 1998; OPCo is provided with the opportunity to recover its Ohio jurisdictional share of its investment in and the liabilities and the future shut-down costs of its affiliated mines as well as any fuel costs incurred above the fixed rate; and OPCo may proceed with its Clean Air Act Amendments of 1990 (CAAA) compliance plan as filed with the PUCO. The Settlement Agreement allows the Company to continue to operate the affiliated Muskingum and Windsor mines. 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. (As discussed above the Settlement Agreement fixes the EFC factor at 1.465 cents per kwh for the period June 1, 1995 through November 30, 1998.) After November 2009 the price that OPCo can recover for coal from its affiliated Meigs mine which supplies the Gavin Plant will be limited to the lower of cost or the then-current market price. The stipulation agreement, in conjunction with the above-referenced Settlement Agreement, provides OPCo with an opportunity to accelerate recovery of its investment in and the liabilities and closing costs and any operating losses incurred under the fixed EFC period of 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 will be recovered under the terms of the predetermined price agreement. Management intends to seek from 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 $195 million after tax at December 31, 1995. The affiliated Muskingum and Windsor mines may have to close by January 2000 as part of compliance with Phase II requirements of the CAAA. The Muskingum and/or Windsor mines could close prior to January 2000 depending on the economics of continued operation under the terms of the above Settlement Agreement. Unless future shutdown costs and/or the cost of affiliated coal production of the Meigs, Muskingum and Windsor mines can be recovered, results of operations would be adversely affected. 3. Effects of Regulation and Phase-In Plans: The consolidated financial statements include assets and liabilities recorded in accordance with regulatory actions to match expenses and revenues in cost- based rates. The assets are expected to be recovered in future periods through the rate-making process and the liabilities are expected to reduce future cost recoveries. The Company has reviewed all the evidence currently available and concluded that it continues to meet the requirements to apply SFAS 71. In the event a portion of the Company s business no longer met these requirements regulatory assets would have to be written off for that portion of the business. Regulatory assets and liabilities are comprised of the following:
December 31, 1995 1994 (In Thousands) Regulatory Assets: Amounts Due From Customers For Future Income Taxes $1,446,485 $1,458,807 Rate Phase-in Plan Deferrals 74,402 118,553 Unamortized Loss on Reacquired Debt 109,551 108,777 Other 349,008 354,860 Total Regulatory Assets $1,979,446 $2,040,997 Regulatory Liabilities: Deferred Investment Tax Credits $430,041 $456,043 Other Regulatory Liabilities* 86,347 76,468 Total Regulatory Liabilities $516,388 $532,511 * Included in Deferred Credits on Consolidated Balance Sheets
The rate phase-in plan deferrals are applicable to the Zimmer Plant Unit and the Rockport Plant Unit 1. The Zimmer Plant is a 1,300 mw coal- fired plant which commenced commercial operation in 1991. CSPCo owns 25.4% of the plant with the remainder owned by two unaffiliated companies. In May 1992 the PUCO issued an order providing for a phased in rate increase of $123 million to be implemented in three steps over a two-year period and disallowed $165 million of Zimmer Plant investment. CSPCo appealed the PUCO ordered Zimmer disallowance and phase-in plan to the Ohio Supreme Court. In November 1993 the Supreme Court issued a decision on CSPCo's appeal affirming the disallowance and finding that the PUCO did not have statutory authority to order phased-in rates. The Court instructed the PUCO to fix rates to provide gross annual revenues in accordance with the law and to provide a mechanism to recover the amounts deferred under the phase-in order. As a result of the ruling, 1993 net income was reduced by $144.5 million after tax to reflect the disallowance and in January 1994, the PUCO approved a 7.11% rate increase effective February 1, 1994. The increase is comprised of a 3.72% base rate increase to complete the rate increase phase- in and a temporary 3.39% surcharge, which will be in effect until the deferrals are recovered, estimated to be 1998. In 1995 and 1994 $28.5 million and $18.5 million, respectively, of net phase-in deferrals were collected through the surcharge which reduced the deferrals from $93.9 million at December 31, 1993 to $75.4 million at December 31, 1994 and $46.9 million at December 31, 1995. In 1993 and 1992, $47.9 million and $46 million, respectively, were deferred under the phase-in plan. The recovery of amounts deferred under the phase-in plan and the increase in rates to the full rate level did not affect net income. From the in-service date of March 1991 until rates went into effect in May 1992 deferred carrying charges of $43 million were recorded on the Zimmer Plant investment. Recovery of the deferred carrying charges will be sought in the next PUCO base rate proceeding in accordance with the PUCO accounting order that authorized the deferral. The Rockport Plant consists of two 1,300 mw coal-fired units. I&M and AEPGEN each own 50% of one unit (Rockport 1) and lease a 50% interest in the other unit (Rockport 2) from unaffiliated lessors under an operating lease. The gain on the sale and leaseback of Rockport 2 was deferred and is being amortized, with related taxes, over the initial lease term which expires in 2022. Rate phase-in plans in I&M's Indiana and FERC jurisdictions for its share of Rockport 1 provide for the recovery and straight-line amortization through 1997 of prior-year deferrals. Unamortized deferred amounts under the phase-in plans were $27.5 million and $43.2 million at December 31, 1995 and 1994, respectively. Amortization was $16 million in 1995, 1994 and 1993. 4. Commitments and Contingencies: Construction and Other Commitments - The AEP System has made substantial construction commitments for utility operations. Such commitments do not presently include any expenditures for new generating capacity. The aggregate construction program expenditures for 1996-1998 are estimated to be $2 billion. Long-term fuel supply contracts contain clauses for periodic adjustments, and most jurisdictions have fuel clause mechanisms that provide for recovery of changes in the cost of fuel with the regulators' review and approval. The contracts are for various terms, the longest of which extend to the year 2014, and contain various clauses that would release the Company from its obligation under certain force majeure conditions. The AEP System has contracted to sell up to 1,300 mw of capacity to unaffiliated utilities. The Company has an obligation to deliver energy under certain unit power agreements regardless of whether the unit capacity is available. The power sales contracts expire from 1997 to 2010. Nuclear Plant - I&M owns and operates the two-unit 2,110 mw Cook Plant under licenses granted by a regulatory authority. The operation of a nuclear facility involves special risks, potential liabilities, and specific regulatory and safety requirements. Should a nuclear incident occur at any nuclear power plant facility in the United States, the resultant liability could be substantial. By agreement I&M is partially liable together with all other electric utility companies that own nuclear generating units for a nuclear power plant incident. In the event nuclear losses or liabilities are underinsured or exceed accumulated funds and recovery is not possible, results of operations and financial condition could be negatively affected. Nuclear Incident Liability - Public liability is limited by law to $8.9 billion should an incident occur at any licensed reactor in the United States. Commercially available insurance provides $200 million of coverage. In the event of a nuclear incident at any nuclear plant in the United States the remainder of the liability would be provided by a deferred premium assessment of $79.3 million on each licensed reactor payable in annual installments of $10 million. As a result, I&M could be assessed $158.6 million per nuclear incident payable in annual installments of $20 million. The number of incidents for which payments could be required is not limited. Nuclear insurance pools and other insurance policies provide $3.6 billion of property damage, decommissioning and decontamination coverage for the Cook Plant. Additional insurance provides coverage for extra costs resulting from a prolonged accidental Cook Plant outage. Some of the policies have deferred premium provisions which could be triggered by losses in excess of the insurer's resources. The losses could result from claims at the Cook Plant or certain other non-affiliated nuclear units. I&M could be assessed up to $40.9 million under these policies. Spent Nuclear Fuel Disposal - Federal law provides for government responsibility for permanent spent nuclear fuel disposal and assesses nuclear plant owners fees for spent fuel disposal. A fee of one mill per kilowatthour for fuel consumed after April 6, 1983 is being collected from customers and remitted to the U.S. Treasury. Fees and related interest of $163 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 various factors including continued delays and uncertainties related to the federal disposal program. At December 31, 1995, funds collected from customers to eventually pay the pre-April 1983 fee and related earnings including accrued interest approximated the liability. Decommissioning and Low Level Waste Accumulation Disposal - Decommissioning costs are accrued over the service life of the Cook Plant. The licenses to operate the two nuclear units expire in 2014 and 2017. After expiration of the licenses the plant is expected to be decommissioned through dismantlement. The Company s latest estimate for decommissioning and low level radioactive waste accumulation disposal costs range from $634 million to $988 million in 1993 nondiscounted dollars. The wide range is caused by variables in assumptions including the estimated length of time spent nuclear fuel must be stored at the plant subsequent to ceasing operations. This in turn depends on future developments in the federal government's spent nuclear fuel disposal program. Continued delays in the federal fuel disposal program can result in increased decommissioning costs. I&M is recovering estimated decommissioning costs in its three rate-making jurisdictions based on at least the lower end of the range in the most recent decommissioning study at the time of the last rate proceeding. I&M records decommissioning costs in other operation expense and records a noncurrent liability equal to the decommissioning cost recovered in rates; such amount was $30 million in 1995, $26 million in 1994 and $13 million in 1993. Decommissioning amounts recovered from customers are deposited in external trusts. Trust fund earnings increase the fund assets and the recorded liability and decrease the amount to be recovered from ratepayers. At December 31, 1995 I&M has recognized a decommissioning liability of $269 million. Litigation - The Company is involved in a number of legal proceedings and claims. While management is unable to predict the ultimate outcome of litigation, it is not expected that the resolution of these matters will have a material adverse effect on the results of operations or financial condition. 5. Dividend Restrictions: Mortgage indentures, debentures, charter provisions and orders of regulatory authorities place various restrictions on the use of the subsidiaries' retained earnings for the payment of cash dividends on their common stocks. At December 31, 1995, $230 million of retained earnings were restricted. To pay dividends out of paid-in capital the subsidiaries need regulatory approval. 6. Lines of Credit and Commitment Fees: At December 31, 1995 and 1994 unused short-term bank lines of credit were available in the amounts of $372 million and $558 million, respectively. Commitment fees of approximately 1/8 of 1% of the unused short-term lines of credit are paid each year to the banks to maintain the lines of credit. Outstanding short-term debt consisted of: December 31, (Dollars In Thousands) 1995 1994 Balance Outstanding: Notes Payable $128,425 $ 42,535 Commercial Paper 236,700 274,450 Total $365,125 $316,985 Year-End Weighted Average Interest Rate: Notes Payable 6.1% 6.2% Commercial Paper 6.1% 6.3% Total 6.1% 6.3% 7. Benefit Plans: AEP System Pension Plan - The AEP pension plan is a trusteed, noncontributory defined benefit plan covering all employees meeting eligibility requirements, except participants in the United Mine Workers of America (UMWA) pension plans. Benefits are based on service years and compensation levels. The funding policy is to make annual trust fund contributions equal to the net periodic pension cost up to the maximum amount deductible for federal income taxes, but not less than the minimum required contribution in accordance with the Employee Retirement Income Security Act of 1974. Net AEP pension plan costs were computed as follows:
Year Ended December 31, 1995 1994 1993 (In Thousands) Service Cost-Benefits Earned During the Year $ 30,400 $ 40,000 $ 37,100 Interest Cost on Projected Benefit Obligation 116,700 114,500 112,600 Actual Return on Assets (416,800) (6,700) (150,000) Net Amortization and Deferral 281,800 (123,300) 24,700 Net AEP Pension Plan Costs $ 12,100 $ 24,500 $ 24,400
AEP pension plan assets and actuarially computed benefit obligations are:
December 31, 1995 1994 (In Thousands) AEP Pension Plan Assets at Fair Value (a) $1,805,300 $1,480,600 Actuarial Present Value of Benefit Obligation: Vested 1,321,600 1,130,000 Nonvested 147,400 120,700 Accumulated Benefit Obligation 1,469,000 1,250,700 Effects of Salary Progression 181,000 132,600 Projected Benefit Obligation 1,650,000 1,383,300 Funded Status - AEP Pension Plan Assets in Excess of Projected Benefit Obligation 155,300 97,300 Unrecognized Prior Service Cost 147,000 160,800 Unrecognized Net Gain (295,200) (229,000) Unrecognized Net Transition Assets (Being Amortized Over 17 Years) (78,700) (88,600) Accrued Net AEP Pension Plan Liability $ (71,600) $ (59,500)
(a) AEP pension plan assets primarily consist of common stocks, bonds and cash equivalents and are included in a separate entity Trust Fund. Assumptions used to determine AEP pension plan's funded status were:
December 31, 1995 1994 1993 Discount Rate 7.25% 8.5% 7.0% Average Rate of Increase in Compensation Levels 3.2% 3.2% 3.2% Expected Long-Term Rate of Return on Plan Assets 9.0% 8.5% 9.0%
AEP System Savings Plan - An employee savings plan is offered to non-UMWA employees which allows participants to contribute up to 17% of their salaries into various investment alternatives, including AEP common stock. An employer matching contribution, equaling one-half of the employees' contribution to the plan up to a maximum of 3% of the employees' base salary, is invested in AEP common stock. The employer's annual contributions totaled $18.8 million in 1995, $18.6 million in 1994 and $17.6 million in 1993. UMWA Pension Plans - The coal-mining subsidiaries of OPCo provide UMWA pension benefits for UMWA employees meeting eligibility requirements. Benefits are based on age at retirement and years of service. As of June 30, 1995, the UMWA actuary estimates the OPCo coal-mining subsidiaries' share of the UMWA pension plans unfunded vested liabilities was approximately $35 million. In the event the OPCo coal-mining subsidiaries cease or significantly reduce mining operations or contributions to the UMWA pension plans, a withdrawal obligation may be triggered for all or a portion of their share of the unfunded vested liability. Contributions are based on the number of hours worked, are expensed when paid and totaled $1.4 million in 1995 and $1.6 million in both 1994 and 1993. Postretirement Benefits Other Than Pensions (OPEB) - The AEP System provides certain other benefits for retired employees. Substantially all non-UMWA employees are eligible for postretirement health care and life insurance if they have at least 10 service years and are age 55 at retirement. Postretirement medical benefits for OPCo's UMWA employees who have or will retire after January 1, 1976 are the liability of the OPCo coal-mining subsidiaries. They are eligible for postretirement medical and life insurance benefits if they have at least 10 service years and are age 55 at retirement. Non-active UMWA employees become eligible at age 55 if they have had 20 service years. Management has taken several measures to reduce its OPEB costs. First, a Voluntary Employees Beneficiary Association (VEBA) trust fund for OPEB benefits for all non-UMWA employees was established. In addition, to help fund and reduce the future costs of OPEB benefits, a corporate owned life insurance (COLI) program was implemented, except where restricted by state law. The insurance policies have a substantial cash surrender value which is recorded, net of equally substantial policy loans, in other property and investments. Legislation was passed by Congress which would have significantly reduced the tax benefits of a COLI program for the future. The legislation containing this provision was vetoed by the President. At this time it is uncertain if legislation repealing certain tax benefits from COLI programs will be enacted. If enacted this legislation would negatively impact the effectiveness of the COLI program as a funding and cost reduction mechanism. For jurisdictions where OPEB costs are reflected in cost of service, the funding policy is to make VEBA trust fund contributions equal to the increase in OPEB costs resulting from the January 1993 implementation of SFAS 106, "Employers Accounting for Postretirement Benefits Other Than Pensions." These contributions include amounts collected from ratepayers and the net earnings from the COLI program. For jurisdictions where recovery has not been approved and rates are insufficient to absorb these additional costs, the funding policy is to contribute cash generated by the COLI program. Contribution to the VEBA trust fund, including amounts funded by the COLI program, were $53 million in 1995, $29.5 million in 1994 and $21.5 million in 1993. The utility subsidiaries received approval in several jurisdictions to recover their increased OPEB costs resulting from the implementation of SFAS 106. For those jurisdictions where recovery has not been approved and rates are insufficient to absorb these additional costs, the utility subsidiaries received regulatory authority to defer the increased OPEB costs which are not being currently recovered in rates. Future recovery of the deferrals and the annual ongoing OPEB costs will be sought by the utility subsidiaries in their next base rate filings. At December 31, 1995 and 1994, $24.6 million and $28.5 million, respectively, of incremental OPEB costs were deferred. Aggregate OPEB costs were computed as follows: Year Ended December 31, 1995 1994 1993 (In Thousands) Service Cost $ 13,500 $16,500 $15,700 Interest Cost on Projected Benefit Obligation 54,900 47,300 45,300 Net Amortization of Transition Obligation 32,000 31,100 28,200 Return on Plan Assets (25,400) 900 (1,000) Net Amortization and Deferral 16,800 (6,800) - Net OPEB Costs $ 91,800 $89,000 $88,200 OPEB assets and actuarially computed benefit obligations are: December 31, 1995 1994 (In Thousands) Fair Market Value of Plan Assets (a) $ 165,600 $ 87,200 Accumulated Postretirement Benefit Obligation: Active Employees Fully Eligible for Benefits 59,200 41,200 Current Retirees 398,400 361,500 Other Active Employees 282,400 245,800 Total Benefit Obligation 740,000 648,500 Unfunded Benefit Obligation (574,400) (561,300) Unrecognized Net Loss 48,500 8,900 Unrecognized Net Transition Obligation Being Amortized Over 20 Years 485,600 517,700 Accrued Net OPEB Liability $ (40,300) $ (34,700) (a) Plan assets consist of cash surrender value of life insurance contracts on certain employees owned by the trust and short-term tax exempt municipal bonds. Assumptions used to determine OPEB's funded status were: December 31, 1995 1994 1993 Discount Rate 7.25% 8.5 % 7.0 % Expected Long-Term Rate of Return on Plan Assets 8.75% 8.25% 8.75% Initial Medical Cost Trend Rate 8.0 % 8.0 % 8.0 % Ultimate Medical Cost Trend Rate 4.5 % 5.25% 4.25% Medical Cost Trend Rate Decreases to Ultimate Rate in Year 2005 2005 2005 Assuming a one percent increase in the medical cost trend rate, the 1995 OPEB cost for all employees, both non-UMWA and UMWA, would increase by $9 million and the accumulated benefit obligations would increase by $78 million. Several UMWA health plans pay the postretirement medical benefits for the Company's UMWA retirees who retired before January 2, 1976 and their survivors plus retirees and others whose last employer is no longer a signatory to the UMWA contract or is no longer in business. The UMWA health plans are funded by payments from current and former UMWA wage agreement signatories, the 1950 UMWA Pension Plan surplus and the Abandoned Mine Land Reclamation Fund Surplus. Required annual payments to the UMWA health funds made by AEP's active and inactive coal-mining subsidiaries were recognized as expense when paid and totaled $2.8 million in 1995, $3.1 million in 1994 and $3.8 million in 1993. By law excess Black Lung Trust funds may be used to pay certain postretirement medical benefits under one of the UMWA health plans. Excess AEP Black Lung Trust funds used to reimburse the coal companies totaled $7.9 million in 1995, $6.9 million in 1994 and $10 million in 1993. The Black Lung Trust had excess funds at December 31, 1995, 1994 and 1993 of $13 million, $16 million and $18 million, respectively. 8. Fair Value of Financial Instruments: Nuclear Trust Funds Recorded at Market Value - The trust investments, reported in other property and investments, are recorded at market value in accordance with SFAS 115 and consist primarily of long-term tax-exempt municipal bonds. At December 31, 1995 and 1994 the fair values of the trust investments were $434 million and $353 million, respectively. Accumulated gross unrealized holding gains and losses were $19.1 million and $1.0 million, respectively, at December 31, 1995. The change in market value was a $24.9 million net holding gain in 1995 and a $27.1 million net holding loss in 1994. The trust investments' cost basis by security type were:
December 31, 1995 1994 (In Thousands) Treasury Bonds $ 14,963 $ 997 Tax-Exempt Bonds 336,073 332,098 Equity Securities 24,101 1,665 Cash, Cash Equivalents and Interest Accrued 40,356 25,304 Total $415,493 $360,064
Proceeds from sales and maturities of securities of $78.2 million during 1995 resulted in $1.4 million of realized gains and $0.3 million of realized losses. Proceeds from sales and maturities of securities of $20.1 million during 1994 resulted in $52,000 of realized gains and $155,000 of realized losses. The cost of securities for determining realized gains and losses is original acquisition cost including amortized premiums and discounts. At December 31, 1995, the year of maturity of trust fund investments other than equity securities, was: (In Thousands) 1996 $ 55,748 1997 - 2000 96,882 2001 - 2005 162,563 After 2005 76,199 Total $391,392 Other Financial Instruments Recorded at Historical Cost - The carrying amounts of cash and cash equivalents, accounts receivable, short-term debt, and accounts payable approximate fair value because of the short-term maturity of these instruments. Fair values for preferred stock subject to mandatory redemption were $544 million and $537 million and for long-term debt were $5.3 billion and $4.7 billion at December 31, 1995 and 1994, respectively. The carrying amounts for preferred stock subject to mandatory redemption were $523 million and $590 million and for long-term debt were $5.1 billion and $5.0 billion at December 31, 1995 and 1994, respectively. Fair values are based on quoted market prices for the same or similar issues and the current dividend or interest rates offered for instruments of the same remaining maturities. The carrying amount of the pre-April 1983 spent nuclear fuel disposal liability approximates the Company's best estimate of its fair value. 9. Federal Income Taxes: The details of federal income taxes as reported are as follows:
Year Ended December 31, 1995 1994 1993 (In Thousands) Charged (Credited) to Operating Expenses (net): Current $265,313 $240,655 $270,318 Deferred 22,990 (10,177) (53,462) Deferred Investment Tax Credits (16,276) (17,079) (17,235) Total 272,027 213,399 199,621 Charged (Credited) to Nonoperating Income (net): Current 11,325 (2,907) 8,727 Deferred (11,074) (5,856) 4,603 Deferred Investment Tax Credits (9,543) (14,196) (9,780) Total (9,292) (22,959) 3,550 Credited to Loss from Zimmer Plant Disallowance (net): Deferred - - (13,327) Deferred Investment Tax Credits - - (1,207) Total - - (14,534) Total Federal Income Tax as Reported $262,735 $190,440 $188,637
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, 1995 1994 1993 (In Thousands) Income Before Preferred Stock Dividend Requirements of Subsidiaries $584,674 $554,738 $412,618 Federal Income Taxes 262,735 190,440 188,637 Pre-Tax Book Income $847,409 $745,178 $601,255 Federal Income Tax on Pre-Tax Book Income at Statutory Rate (35%) $296,593 $260,812 $210,439 Increase (Decrease) in Federal Income Tax Resulting from the Following Items: Depreciation 46,453 31,212 27,554 Removal Costs (14,640) (13,818) (17,730) Corporate Owned Life Insurance (25,506) (22,970) (27,310) Investment Tax Credits (net) (26,179) (31,273) (28,218) Zimmer Plant Disallowance - - 42,346 Federal Income Tax Accrual Adjustments - (16,100) (6,500) Other (13,986) (17,423) (11,944) Total Federal Income Taxes as Reported $262,735 $190,440 $188,637 Effective Federal Income Tax Rate 31.0% 25.6% 31.4%
The following tables show the elements of the net deferred tax liability and the significant temporary differences:
December 31, 1995 1994 (In Thousands) Deferred Tax Assets $ 723,196 $ 657,298 Deferred Tax Liabilities (3,379,847) (3,314,360) Net Deferred Tax Liabilities $(2,656,651) $(2,657,062) Property Related Temporary Differences $(2,139,387) $(2,098,304) Amounts Due From Customers For Future Federal Income Taxes (442,311) (444,305) Deferred State Income Taxes (183,981) (183,987) All Other (net) 109,028 69,534 Total Net Deferred Tax Liabilities $(2,656,651) $(2,657,062)
The Company has settled with the Internal Revenue Service (IRS) all issues from the audits of the consolidated federal income tax returns for the years prior to 1991. Returns for the years 1991 through 1993 are presently being audited by the IRS. In the opinion of management, the final settlement of open years will not have a material effect on results of operations. 10. Leases: Leases of property, plant and equipment are for periods up to 35 years and require payments of related property taxes, maintenance and operating costs. The majority of the leases have purchase or renewal options and will be renewed or replaced by other leases. Lease rentals are primarily charged to operating expenses in accordance with rate-making treatment. The components of rentals are as follows:
Year Ended December 31, 1995 1994 1993 (In Thousands) Operating Leases $259,877 $233,805 $243,190 Amortization of Capital Leases 101,068 79,116 84,226 Interest on Capital Leases 27,542 23,280 23,839 Total Rental Payments $388,487 $336,201 $351,255
Properties under capital leases and related obligations on the Consolidated Balance Sheets are as follows:
December 31, 1995 1994 (In Thousands) ELECTRIC UTILITY PLANT: Production $ 44,849 $ 44,683 Transmission 7 38 Distribution 14,753 14,717 General: Nuclear Fuel (net of amortization) 69,442 89,478 Mining Plant and Other 424,952 403,038 Total Electric Utility Plant 554,003 551,954 Accumulated Amortization 179,952 173,641 Net Electric Utility Plant 374,051 378,313 OTHER PROPERTY 34,536 24,724 Accumulated Amortization 3,994 2,838 Net Other Property 30,542 21,886 Net Property under Capital Leases $404,593 $400,199 Obligations under Capital Leases $404,593 $400,199 Less Portion Due Within One Year 89,692 93,252 Noncurrent Capital Lease Liability $314,901 $306,947
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, 1995:
Noncancelable Capital Operating Leases Leases (In Thousands) 1996 $ 86,495 $ 244,228 1997 72,576 239,800 1998 56,165 231,449 1999 47,531 229,296 2000 39,547 227,506 Later Years 156,895 4,092,193 Total Future Minimum Lease Rentals 459,209(a) $5,264,472 Less Estimated Interest Element 124,058 Estimated Present Value of Future Minimum Lease Rentals 335,151 Unamortized Nuclear Fuel 69,442 Total $404,593
(a) Minimum lease rentals do not include nuclear fuel rentals. The rentals are paid in proportion to heat produced and carrying charges on the unamortized nuclear fuel balance. There are no minimum lease payment requirements for leased nuclear fuel. 11. SUPPLEMENTARY INFORMATION:
Year Ended December 31, 1995 1994 1993 (In Thousands) Purchased Power - Ohio Valley Electric Corp. (44.2% owned by AEP) $10,546 $5,755 $19,253 Cash was paid for: Interest (net of capitalized amounts) $395,169 $379,361 $421,060 Income Taxes $273,671 $312,233 $245,350 Noncash Acquisitions under Capital Leases were $106,256 $227,055 $80,220
12. CAPITAL STOCKS AND PAID-IN CAPITAL: Changes in capital stocks and paid-in capital during the period January 1, 1993 through December 31, 1995 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, 1993 193,534,992 10,761,675 $1,257,977 $1,628,394 $ 534,978 $233,509 Issues - 3,250,000 - - - 325,000 Retirements and Other - (6,323,907) - (4,218) (266,738) (57,972) December 31, 1993 193,534,992 7,687,768 1,257,977 1,624,176 268,240 500,537 Issues 700,000 900,000 4,550 17,706 - 90,000 Retirements and Other - (351,517) - (1,221) (35,000) (152) December 31, 1994 194,234,992 8,236,251 1,262,527 1,640,661 233,240 590,385 Issues 1,400,000 - 9,100 39,607 - - Retirements and Other - (1,526,500) - (21,744) (85,000) (67,650) December 31, 1995 195,634,992 6,709,751 $1,271,627 $1,658,524 $ 148,240 $522,735 (a) Includes 8,999,992 shares of treasury stock. (b) Including portion due within one year.
13. Unaudited Quarterly Financial Information:
Quarterly Periods Ended 1995 March 31 June 30 Sept. 30 Dec. 31 (In Thousands - Except Per Share Amounts) Operating Revenues $1,416,169 $1,305,342 $1,523,390 $1,425,429 Operating Income 257,556 211,284 262,548 233,159 Net Income 147,850 96,478 154,156 131,419 Earnings per Share 0.80 0.52 0.83 0.70
Quarterly Periods Ended 1994 March 31 June 30 Sept. 30 Dec. 31 (In Thousands - Except Per Share Amounts) Operating Revenues $1,488,185 $1,348,563 $1,385,278 $1,282,644 Operating Income 257,517 219,496 247,015 208,465 Net Income 152,954 103,793 139,826 103,439 Earnings per Share 0.83 0.56 0.76 0.56 Fourth quarter 1994 net income includes favorable federal income tax accrual adjustments of $16.1 million related to the resolution of various issues with the IRS.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES SCHEDULE OF CONSOLIDATED CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES
December 31, 1995 Call Price per Shares Shares Amount (in Share (a) Authorized(b) Outstanding thousands) Not Subject to Mandatory Redemption: 4.08% - 4.56% $102-$110 932,403 932,403 $ 93,240 7.08% - 7.40% $101.85-$102.11 550,000 550,000 55,000 Total Not Subject to Mandatory Redemption $148,240 Subject to Mandatory Redemption (c): 4.50% $102 19,625 2,348 $ 235 5.90% - 5.92% (d) 1,950,000 1,950,000 195,000 6.02% - 6-7/8% (e) 1,950,000 1,950,000 195,000 7% - 7-7/8% $107.80-$107.88(f) 1,250,000 1,250,000 125,000 9.50% (g) 750,000 75,000 7,500 Total Subject to Mandatory Redemption (h) 522,735 Less Portion Due Within One Year 7,650 Long-term Portion $515,085
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December 31, 1994 Call Price per Shares Shares Amount (in Share (a) Authorized Outstanding thousands) Not Subject to Mandatory Redemption: 4.08% - 4.56% $102-$110 932,403 932,403 $ 93,240 7.08% - 7.76% $101.85-$102.26 1,250,000 1,250,000 125,000 8.04% $102.58 150,000 150,000 15,000 Total Not Subject to Mandatory Redemption $233,240 Subject to Mandatory Redemption (c): 4.50% $102 19,625 3,848 $ 385 5.90% - 5.92% (d) 1,950,000 1,950,000 195,000 6.02% - 6-7/8% (e) 1,950,000 1,950,000 195,000 7% - 7-7/8% $107.80-$107.88(f) 1,250,000 1,250,000 125,000 9.50% (g) 750,000 750,000 75,000 Total Subject to Mandatory Redemption (h) 590,385 Less Portion Due Within One Year 85 Long-term Portion $590,300 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 (December 31, 1995 price is shown) plus accrued dividends. The involuntary liquidation preference is $100 per share for all outstanding shares.(b) As of December 31, 1995 the subsidiaries had 4,255,000, 22,200,000 and 5,547,652 shares of $100, $25 and no par value preferred stock, respectively, that were authorized but unissued. (c) With sinking fund. Shares outstanding and related amounts are stated net of applicable retirements through sinking funds (generally at par) and reacquisitions of shares in anticipation of future requirements. (d) Redemption is prohibited prior to 2003; after that the call price is $100 per share. (e) Redemption is prohibited prior to 2000; after that the call price is $100 per share. (f) Redemption is restricted prior to 1997. (g) On February 1, 1996 the outstanding balance of 75,000 shares was redeemed at $100 per share. (h) The sinking fund provisions of the series subject to mandatory redemption aggregate $7,650,000, $84,800, $5,000,000, $5,000,000 and $16,000,000 in 1996, 1997, 1998, 1999 and 2000, respectively.
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, 1995 1995 1994 1995 1994 (in thousands) FIRST MORTGAGE BONDS 1995-1999 7.05% 5%-9.15% 5%-9.15% $ 496,866 $ 526,866 2001-2005 7.28% 6%-9.31% 6%-9.31% 1,530,020 1,450,020 2019-2025 8.26% 7.10%-9-7/8% 7.10%-9-7/8% 1,473,127 1,540,661 INSTALLMENT PURCHASE CONTRACTS(a) 1995-2002 5.65% 5%-7-1/4% 6%-7-1/4% 209,500 174,500 2007-2025 6.45% 5.45%-7-7/8% 5.45%-9-3/8% 756,745 811,745 NOTES PAYABLE(b) 1995-2008 7.87% 5.29%-10.78% 5.29%-10.78% 221,000 313,000 DEBENTURES 1996 - 1999(c) 6.40% 5-1/8%-7-7/8% 5-1/8%-7-7/8% 30,759 30,759 2025 8.35% 8.16%-8.72% - 200,000 - OTHER LONG-TERM DEBT(d) 172,403 163,896 Unamortized Discount (net) (33,144) (31,128) Total Long-term Debt Outstanding (e) 5,057,276 4,980,319 Less Portion Due Within One Year 136,947 293,671 Long-term Portion $4,920,329 $4,686,648 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 the demand of the owners at periodic interest-adjustment dates. Letters of credit from banks and standby bond purchase agreements support certain series. (b) Notes payable represent outstanding promissory notes issued under term loan agreements with a number of banks and other financial institutions. At expiration all notes then issued and outstanding are due and payable. Interest rates are both fixed and variable. Variable rates generally relate to specified short-term interest rates. (c) All sinking fund debentures will be reacquired by March 1, 1996. (d) Other long-term debt consist primarily of a liability along with accrued interest for disposal of spent nuclear fuel (see Note 4 of the Notes to Consolidated Financial Statements). (e) Long-term debt outstanding at December 31, 1995 is payable as follows: Principal Amount (in thousands) 1996 $ 136,947 1997 86,933 1998 269,266 1999 185,673 2000 168,648 Later Years 4,242,953 Total $5,090,420
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, 1995 and 1994, and the related consolidated statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 1995. 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, 1995 and 1994, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1995 in conformity with generally accepted accounting principles. Deloitte & Touche LLP Columbus, Ohio February 27, 1996 EX-21 5 AEPCO EX. 21 - LIST OF SUBSIDIARIES EXHIBIT 21 Subsidiaries of American Electric Power Company, Inc. As of January 1, 1996
Percentage of Voting Securities Location of Owned By Name of Company Incorporation Immediate Parent American Electric Power Service Corporation New York 100.0 AEP Energy Services, Inc. Ohio 100.0 AEP Generating Company Ohio 100.0 AEP Investments, Inc. Ohio 100.0 AEP Resources, Inc. Ohio 100.0 AEP Resources International, Ltd. Cayman Islands 100.0 Appalachian Power Company Virginia 96.1 (a) Cedar Coal Co. West Virginia 100.0 Central Appalachian Coal Company West Virginia 100.0 Central Coal Company West Virginia 50.0 (b) Central Operating Company West Virginia 50.0 (b) Southern Appalachian Coal Company West Virginia 100.0 West Virginia Power Company West Virginia 100.0 Columbus Southern Power Company Ohio 100.0 Colomet, Inc. Ohio 100.0 Conesville Coal Preparation Company Ohio 100.0 Simco Inc. Ohio 100.0 Franklin Real Estate Company Pennsylvania 100.0 Indiana Franklin Realty, Inc. Indiana 100.0 Indiana Michigan Power Company Indiana 100.0 Blackhawk Coal Company Utah 100.0 Price River Coal Company Indiana 100.0 Integrated Communications Systems, Inc. Georgia 20.5 (c) Kentucky Power Company Kentucky 100.0 Kingsport Power Company Virginia 100.0 Ohio Power Company Ohio 97.0 (d) Cardinal Operating Company Ohio 50.0 (e) Central Coal Company West Virginia 50.0 (b) Central Ohio Coal Company Ohio 100.0 Central Operating Company West Virginia 50.0 (b) Southern Ohio Coal Company West Virginia 100.0 Windsor Coal Company West Virginia 100.0 Ohio Valley Electric Corporation Ohio 44.2 (f) Indiana-Kentucky Electric Corporation Indiana 100.0 Wheeling Power Company West Virginia 100.0 (a) 13,499,500 shares of Common Stock, all owned by parent, have one vote each and 552,348 shares of Preferred Stock, all owned by public, have one vote each. (b) Owned 50% by Appalachian Power Company and 50% by Ohio Power Company. (c) American Electric Power Company, Inc. owns 20.5% of the stock and the remaining 79.5% is owned by unaffiliated companies. (d) 27,952,473 shares of Common Stock, all owned by parent, have one vote each and 862,403 shares of Preferred Stock, all owned by public, have one vote each. (e) Ohio Power Company owns 50% of the stock; the other 50% is owned by a corporation not affiliated with American Electric Power Company, Inc. (f) 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 6 AEPCO EX. 23 - 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. 1 to Registration Statement No. 33-01734 of American Electric Power Company, Inc. on Form S-3 of our reports dated February 27, 1996, 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, 1995. Deloitte & Touche LLP Columbus, Ohio March 27, 1996 EX-24 7 AEPCO EX. 24 - POWER OF ATTORNEY Exhibit 24 POWER OF ATTORNEY AMERICAN ELECTRIC POWER COMPANY, INC. ANNUAL REPORT ON FORM 1O-K FOR THE FISCAL YEAR ENDED __________________DECEMBER_31,_1995_________________ The undersigned directors of AMERICAN ELECTRIC POWER COMPANY, INC., a New York corporation (the "Company"), do hereby constitute and appoint E. LINN DRAPER, JR., G. P. MALONEY and P. J. DeMARIA, and each of them, their attorneys-in-fact and agents, to execute for them, and in their names, and in any and all of their capacities, the Annual Report of the Company on Form lO-K, pursuant to Section 13 of the Securities Exchange Act of 1934, for the fiscal year ended December 31, 1995, 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 28th day of February, 1996. _/s/_P._J._DeMaria____________ _/s/_Angus_E._Peyton__________ P. J. DeMaria Angus E. Peyton _/s/_E._Linn_Draper,_Jr.______ _/s/_Toy_F._Reid______________ E. Linn Draper, Jr. Toy F. Reid _/s/_Robert_M._Duncan_________ _/s/_Donald_G._Smith__________ Robert M. Duncan Donald G. Smith _/s/_Robert_W._Fri____________ _/s/_Linda_Gillespie_Stuntz___ Robert W. Fri Linda Gillespie Stuntz _/s/_Arthur_G._Hansen_________ _/s/_Morris_Tanenbaum_________ Arthur G. Hansen Morris Tanenbaum _/s/_Lester_A._Hudson,_Jr.____ _/s/_Ann_Haymond_Zwinger______ Lester A. Hudson, Jr. Ann Haymond Zwinger _/s/_G._P._Maloney____________ G. P. Maloney [ANNUAL\103.96C] EX-27 8 AEPCO EX. 27 - FINANCIAL DATA SCHEDULE
UT 0000004904 AMERICAN ELECTRIC POWER COMPANY, INC. 1,000 12-MOS DEC-31-1995 DEC-31-1995 PER-BOOK 11,384,839 825,781 1,401,858 310,377 1,979,446 15,902,301 1,271,627 1,658,524 1,409,645 4,339,796 515,085 148,240 4,920,329 128,425 0 236,700 136,947 7,650 314,901 89,692 5,064,536 15,902,301 5,670,330 289,432 4,416,351 4,705,783 964,547 20,204 984,751 400,077 529,903 54,771 529,903 445,831 271,924 1,056,610 $2.85 $2.85 Represents preferred stock dividend requirements of subsidiaries; deducted before computation of net income.
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