10-K405 1 AEPCO 1994 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, 1994 [_] 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 ___________ --------------
I.R.S. EMPLOYER COMMISSION REGISTRANT; STATE OF INCORPORATION; IDENTIFICATION FILE NUMBER ADDRESS; AND TELEPHONE NUMBER 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 (703) 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 (216) 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 X . No X . --- --- 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, $6.50 par value ..... New York Stock Inc. Exchange Appalachian Power Cumulative Preferred Stock, Company Voting, no par value: 4-1/2% ............ Philadelphia Stock Exchange 4.50% ............. Philadelphia Stock Exchange 7.40% ............. New York Stock Exchange Columbus Southern None Power Company Indiana Michigan Cumulative Preferred Stock, Power Company Non-Voting, $100 par value: 4-1/8% ............ Chicago Stock Exchange 7.08% ............. New York Stock Exchange Kentucky Power None Company Ohio Power Cumulative Preferred Stock, Company Voting, $100 par value: 7.60% ............. New York Stock Exchange 7-6/10% ........... New York Stock Exchange 8.04% ............. New York Stock Exchange
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K ((S)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 or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. X ---- 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 3, 1995 FEBRUARY 3, 1995 ---------------------- ------------------ AEP Generating None 1,000 Company ($1,000 par value) American Electric $6,621,000,000 185,235,000 Power Company, Inc. ($6.50 par value) Appalachian Power $38,000,000 13,499,500 Company (no par value) Columbus Southern None 16,410,426 Power Company (no par value) Indiana Michigan None 1,400,000 Power Company (no par value) Kentucky Power None 1,009,000 Company ($50 par value) Ohio Power Company $129,000,000 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 553,848 shares of Cumulative Preferred Stock, no par value; and (ii) Ohio Power Company consists of 1,712,403 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 3, 1995 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, 1994: 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, 1995, for Annual Meeting of Shareholders Part III Portions of Information Statements of the following companies for 1995 Annual Meeting of Shareholders, to be filed within 120 days after December 31, 1994: 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 .......................... 35 Executive Officers of the Registrants ................. 35 Part II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters ................. 38 Item 6. Selected Financial Data ...................... 38 Item 7. Management's Discussion and Analysis of Results of Operations and Financial Condition 38 Item 8. Financial Statements and Supplementary Data .. 39 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure ..... 39 Part III Item 10. Directors and Executive Officers of the Registrants ................................ 40 Item 11. Executive Compensation ....................... 41 Item 12. Security Ownership of Certain Beneficial Owners and Management ..................... 45 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 /TABLE 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. PFBC ..................... Pressurized fluidized-bed combustion, a process in which sulfur is removed during coal combustion and nitrogen oxide formation is minimized. 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. 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. /TABLE 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 operating electric utility 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. At December 31, 1994, the subsidiaries of AEP had a total of 19,660 employees. AEP, as such, has no employees. The principal 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 848,000 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, 1994, APCo and its wholly owned subsidiaries had 4,637 employees. A generating subsidiary of APCo, Kanawha Valley Power Company, which owns and operates under Federal license three hydroelectric generating stations located on Government lands adjacent to Government-owned navigation dams on the Kanawha River in West Virginia, sells its net output to APCo. Kanawha Valley Power Company has requested regulatory approval to merge into APCo. Among the principal industries served by APCo are coal mining, primary metals, chemicals, textiles, paper, stone, clay, glass, 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 588,000 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, 1994, CSPCo had 2,323 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 531,000 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, 1994, I&M had 3,817 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 163,000 customers in an area in eastern Kentucky, and in supplying electric power at wholesale to other utilities and municipalities in Kentucky. At December 31, 1994, KEPCo had 823 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 41,000 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, 1994, Kingsport Power Company had 104 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 662,000 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, 1994, OPCo and its wholly owned subsidiaries had 5,404 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, 1994, Wheeling Power Company had 141 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, computer, engineering, financial, legal and other services at cost to the AEP System companies. The executive officers of AEP 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 November 8, 1994, the SEC issued a release in which it discussed the need to modernize PUHCA, particularly in light of increasing competition in the electric utility industry (see Competition). It also requested comments on a broad range of issues, including whether PUHCA should be repealed or some of its restrictions eliminated. AEP filed comments indicating its belief that PUHCA is unnecessary and should be repealed. If PUHCA is repealed or amended to remove some restrictions, 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. On December 28, 1994, the SEC also proposed revisions to its rules governing transactions between associated companies in a registered holding company system. PUHCA and the rules and orders of the SEC currently require that these transactions 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. These proposed revisions to the rules would price transactions governed by SEC rules at a market-based price if it is lower than cost. Because prices charged in most AEP intra-system transactions are governed by SEC orders relating specifically to such transactions, not general SEC rules, the proposed revisions would not apply to them. However, the SEC could modify or amend the orders governing AEP intra-system transactions. 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 recent 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, 1994 are as follows:
AEP AEGCo APCo CSPCo I&M KEPCo OPCo System (a) (in thousands) Retail Residential Without Electric Heating . . $ -- $ 233,540 $ 305,189 $ 227,358 $ 42,613 $ 251,382 $1,079,865 With Electric Heating . . . . -- 312,508 109,086 107,523 58,047 132,799 755,577 Total Residential . . . . . -- 546,048 414,275 334,881 100,660 384,181 1,835,442 Commercial . . . . . . . . . . . -- 275,262 361,947 247,938 55,899 241,566 1,217,921 Industrial . . . . . . . . . . . -- 367,130 144,722 291,527 92,993 619,055 1,578,579 Miscellaneous . . . . . . . . . . -- 30,821 15,433 6,316 832 8,079 64,668 Total Retail . . . . . . . . -- 1,219,261 936,377 880,662 250,384 1,252,881 4,696,610 Wholesale (sales for resale) . . . 235,974 291,412 78,820 352,889 53,785 452,146 714,076 Total from KWH Sales . . . . 235,974 1,510,673 1,015,197 1,233,551 304,169 1,705,027 5,410,686 Provision for Revenue Refunds . . . -- 5,560 -- -- -- -- 5,560 Total Net of Provision for Revenue Refunds . . . . . . 235,974 1,516,233 1,015,197 1,233,551 304,169 1,705,027 5,416,246 Other Operating Revenues . . . . . 67 19,267 15,954 17,758 3,274 33,699 88,424 Total Electric Operating Revenues . . . . . $236,041 $1,535,500 $1,031,151 $1,251,309 $307,443 $1,738,726 $5,504,670 _______________ (a) Includes revenues of other subsidiaries not shown and elimination of intercompany transactions.
AEP SYSTEM POWER POOL AND OFF-SYSTEM POWER SALES AEP's electric utility subsidiaries operate their generating plants and transmission lines as a single interconnected and coordinated electric utility system. 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. The following table shows the net credits or (charges) allocated among the parties under the Interconnection Agreement during the years ended December 31, 1992, 1993 and 1994:
1992 1993 1994 ---------- ---------- ---------- (IN THOUSANDS) APCo ........................ $(243,000) $(260,000) $(254,000) CSPCo ....................... (118,000) (141,000) (105,000) I&M ......................... 71,000 183,000 107,000 KEPCo ....................... 26,000 1,000 12,000 OPCo ........................ 264,000 217,000 240,000
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 emission allowances. The IAA provides for and governs the terms of the following allowance transactions among the parties beginning January 1, 1995: (1) an annual reallocation of certain allowances initially allocated by the Federal EPA to OPCo's Gavin Plant; (2) transfer of allowances associated with energy transactions among the members of the AEP Power Pool; (3) a monthly cash settlement for allowances consumed in connection with power sales to non-affiliated electric utilities; and (4) transfers of 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 allowances to or from non-affiliated companies. The IAA was accepted by the FERC on December 30, 1994. AEGCo, APCo, CSPCo, I&M, KEPCo and OPCo also sell electric power on a wholesale basis to non-affiliated electric utilities. 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, 1992, 1993 and 1994:
1992(A) 1993(A) 1994(A) -------- -------- -------- (IN THOUSANDS) AEGCo (b) ................ $ 33,000 $ 32,500 $ 30,800 APCo (c) ................. 18,100 23,600 25,000 CSPCo (c) ................ 9,100 12,000 11,700 I&M (c)(d) ............... 31,300 35,300 34,600 KEPCo (c) ................ 3,700 4,900 4,800 OPCo (c) ................. 15,700 20,700 20,000 -------- -------- -------- Total System .......... $110,900 $129,000 $126,900 ======== ======== ========
--------------- (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 1992, 1993 and 1994 were made on a short-term basis, except that $11,500,000, $16,800,000 and $21,800,000, 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 1992, 1993 and 1994 amounts for I&M include $20,800,000, $21,600,000 and $21,600,000 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 will be supplying 205 megawatts of electric power to an unaffiliated utility for 15 years. The AEP System continues to seek appropriate long-term wholesale power agreements and will sell available power on a short-term basis. The future results of operations of AEP and its operating companies will be affected by their ability to make cost- effective wholesale sales or, if such sales are reduced, their ability to timely raise retail rates. In addition to System sales, APCo, CSPCo, I&M, KEPCo and OPCo serve wholesale customers that are full/partial requirement customers. The aggregate maximum demand for these customers in 1994 was 485, 83, 420, 17 and 125 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 June 1993, certain municipal customers of APCo filed an application with the FERC for transmission service in order to reduce by 50 megawatts the power these customers purchase under existing 10-year Electric Service Agreements (ESAs) and 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 December 1, 1993, the administrative law judge issued an initial decision 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 February 10, 1994, the FERC issued an order affirming, in part, the administrative law judge's initial decision. 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. On August 1, 1994, AEP System companies filed petitions for rehearing of these FERC orders. Effective August 1, 1994, these municipal customers reduced their purchases by 40 megawatts. Certain of these customers also have notified APCo that they intend to reduce their purchases by an additional 21 megawatts effective February 1996. AEP SYSTEM TRANSMISSION POOL AND OFF-SYSTEM TRANSMISSION 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 AEP System Power Pool and Off-System Power Sales. The following table shows the net credits or (charges) allocated among the parties to the Transmission Agreement during the years ended December 31, 1992, 1993 and 1994:
1992 1993 1994 -------- -------- -------- (IN THOUSANDS) APCo ..................... $ (8,000) $ (3,200) $(10,200) CSPCo .................... (29,900) (31,200) (30,100) I&M ...................... 48,200 47,400 50,300 KEPCo .................... 4,200 3,800 4,300 OPCo ..................... (14,500) (16,800) (14,300)
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, 1992, 1993 and 1994:
1992 1993 1994 -------- -------- -------- (IN THOUSANDS) APCo ..................... $ 3,000 $ 2,900 $ 4,100 CSPCo .................... 2,500 2,500 3,100 I&M ...................... 6,500 7,700 6,700 KEPCo .................... 600 600 800 OPCo ..................... 10,000 9,900 15,700 ------- ------- ------- Total System ............. $22,600 $23,600 $30,400 ======= ======= =======
The Energy Policy Act of 1992 amended the Federal Power Act to authorize 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. Effective August 1, 1994 and under a FERC order, the AEP System began to provide transmission services for 40 megawatts of power delivered to certain municipal customers of APCo as discussed above under AEP System Power Pool and Off- System Power Sales. FERC Transmission Access Filing: 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 any "eligible utility." The tariff covers the terms and conditions of the service, as well as the price which "eligible utilities" pay to wheel power on the AEP transmission system, 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 August 26, 1994, AEP System companies submitted to the FERC their comparability filing supplementing the April 12 filing, following the guidelines stated in the May 11 FERC ruling. They indicated their willingness to offer network transmission service under terms and conditions comparable to those enjoyed by members of the AEP System. Network users could import and export power through the network, with power deliveries occurring without separate arrangements for each transmission delivery point. Network users would participate in transmission planning and share transmission costs proportionately. In addition, the supplemental filing would expand the availability of point-to- point transmission service, including permitting such services to be offered at a discounted rate on an hourly, nondiscriminatory basis. A FERC hearing began in February 1995 and was recessed until April 24, 1995 for settlement discussions. 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 1,878,000 kilowatts and is scheduled to remain at about that level through the remaining term of the contract. The proceeds from the sale of power by OVEC, aggregating $308,000,000 in 1994, 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 1994. 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 299 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 880,000 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, AEGCo's business has consisted of the ownership and financing of its 50% interest in the Rockport Plant and, more recently, 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 36% of AEGCo's operating revenue in 1994 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, revise the rules and responsibilities under which new generating capacity is supplied and open access to an electric utility's transmission system; 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 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 alternative sources of energy, 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 capacity 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 alternative 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 have considered or are considering "retail wheeling" which, in general terms, means the transmission by an electric utility of energy produced by another entity 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 any other electric utility or independent power producer. The MPSC began a proceeding on September 11, 1992 to investigate a proposal by certain industrial companies for an experiment in retail wheeling in certain service territories in Michigan, not including those of I&M. On April 11, 1994, the MPSC approved an experimental five-year retail wheeling program and ordered Consumers Power Company and Detroit Edison Company, unaffiliated utilities, to make transmission services available to a group of industrial customers, to be limited to 60 megawatts and 90 megawatts, respectively, of retail delivery capacity. The MPSC remanded to the administrative law judge the issue of determining appropriate rates and charges for retail delivery service. 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 August 1994, Detroit Edison filed a declaratory judgment complaint in the U.S. District Court, Western District of Michigan, challenging the jurisdiction of the MPSC to order retail wheeling. On April 15, 1994, the Ohio Energy Strategy Task Force released its final report. The report contains seven broad implementation strategies along with 53 specific initiatives to be undertaken by government and the private sector. One strategy recommends 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. In addition, a retail wheeling bill was introduced in the Ohio House of Representatives in February 1994. Because adoption of retail wheeling would require resolution of complex issues, such as who would pay for the unused generating plant of the utility wheeling such power, it is not clear what effects will flow from its adoption in any state. However, if retail wheeling is adopted, the public utility subsidiaries of AEP believe that they have a favorable competitive position because of their relatively low costs. 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. 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. Upon resolution of the issues regarding the transmission access filing before the FERC (discussed under AEP System Transmission Pool and Off-System Transmission), the public utility subsidiaries of AEP expect to be able to satisfy FERC criteria to obtain approval to sell wholesale power at market rates. On June 29, 1994, the FERC issued a proposed rulemaking to provide the regulatory framework for dealing with utility assets that are stranded as a result of the transition to a competitive electric industry. Stranded costs are those costs incurred by a utility when a customer stops buying power from the utility and, instead, purchases transmission services from that utility to obtain power purchased from another supplier. If stranded costs are not recovered from customers, the AEP System, like all electric utilities, will be required by existing accounting standards to recognize stranded investment losses. The write-off of such stranded investment, which could include regulatory assets, would materially adversely affect results of operations and financial condition. New Generation When the AEP System needs new generation, the public utility subsidiaries of AEP which wish to provide it may have 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. AEP and its subsidiaries believe that they can be competitive as to both of these factors. However, no additional generating capacity is expected to be needed by the AEP System until about the year 2000. See Construction and Financing Program. Indiana: In August 1994, the IURC reissued a notice of proposed rulemaking for integrated resource planning guidelines, including consideration of resource bidding and independent power producers, and for demand-side management. 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 Clean Air Act emission 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 emission allowances, because existing federal laws address such concerns. Virginia: The Virginia SCC 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. 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 wholesale and retail 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, is involved in preliminary development of some projects, has submitted jointly with a non- affiliate a bid to provide power through an exempt wholesale generator, and has entered into a letter of intent which may result in the development of two 1,300-megawatt generating stations in China. In addition, AEP and Resources have received approval from the SEC under PUHCA to finance up to $300,000,000 for investment in exempt wholesale generators and foreign utility companies. AEPES offers consulting services using AEP System expertise both domestically and internationally. AEPES contracts with other public utilities, commercial concerns and government agencies for the rendition of services and the licensing of intellectual property. 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 AND FINANCING PROGRAM 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 growing demands for electric service. At the present time, there are no specific commitments for new capacity additions 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, AEP's current resource plan indicates no need for new generation until about 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 2005. The size of any new coal-fired generation will most likely be significantly smaller than the 1,300-megawatt units recently added to the AEP System, to better match projected load growth. 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. 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. The extent and timing of construction expenditures and the nature of future financing activities may be dependent on, among other things, the timing and amount of additional rate relief received. See Competition -- New Generation and Rates. PFBC Projects Tidd Plant: In November 1990, OPCo began operating a 70,000- kilowatt PFBC demonstration plant at the deactivated Tidd Plant on the Ohio River at Brilliant, Ohio. The Tidd Plant was built and operated to demonstrate that the combined-cycle PFBC technology is a cost-effective, reliable, and environmentally superior alternative to conventional coal-fired electric power generation with a flue-gas desulfurization system. Through December 31, 1994, the Tidd Plant achieved 10,297 hours of coal- fired operation while demonstrating the viability of the PFBC process in the reduction of targeted sulfur dioxide and nitrogen oxide emissions. See Environmental and Other Matters for information regarding restrictions on sulfur dioxide and nitrogen oxide emissions from coal-fired power plants in the AEP System. The Tidd Plant operated for a four-year period, which is expected to conclude not later than March 31, 1995. The plant is planned to be deactivated at the conclusion of the test program. Total Tidd Plant construction costs (including PFBC development costs) and total Tidd operating costs incurred through December 31, 1994 were $182,489,000 and $36,497,000, respectively. At such date, OPCo had received funding from DOE and the State of Ohio in the aggregate amounts of $65,232,000 and $11,336,000, respectively, and had recovered $125,543,000 from its retail customers. PFBC Utility Demonstration Project: DOE is cost sharing with APCo development of a 340,000-kilowatt commercial-size PFBC plant adjacent to APCo's Mountaineer Plant in New Haven, West Virginia. DOE has agreed to continue funding the design of the plant through at least January 1996; however, the program can be terminated sooner with mutual consent of the parties. The present four-year effort to refine the PFBC design extends through January 1996. The ultimate decision to proceed with the construction of the commercial PFBC plant will hinge on the confirmation of the need for new coal-fired baseload capacity, the readiness of PFBC technology, and other applicable market conditions. 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 1992, 1993 and 1994 and their current estimate of 1995 construction expenditures, in each case including AFUDC but excluding nuclear fuel and other assets acquired under leases. The construction expenditures for the years 1992-1994 were applied, and it is anticipated that the estimated construction expenditures for 1995 will be applied, approximately as follows to construction of the following classes of assets:
1992 1993 1994 1995 Actual Actual Actual Estimate -------- -------- -------- -------- (in thousands) AEGCO Generating plant and facilities .. $ 3,600 $ 3,100 $ 3,900 $ 4,600 -------- -------- -------- -------- TOTAL ......................... $ 3,600 $ 3,100 $ 3,900 $ 4,600 ======== ======== ======== ======== APCO Generating plant and facilities (a) ................ $ 34,400 $ 51,200 $ 65,600 $ 58,600 Transmission lines and facilities 54,200 36,700 38,700 38,300 Distribution lines and facilities 91,600 98,200 116,500 103,100 General plant and other facilities 11,500 4,800 9,500 14,600 -------- -------- -------- -------- TOTAL ......................... $191,700 $190,900 $230,300 $214,600 ======== ======== ======== ======== CSPCO Generating plant and facilities .. $ 21,900 $ 33,300 $ 24,800 $ 38,700 Transmission lines and facilities 11,600 10,100 3,600 9,000 Distribution lines and facilities 40,800 40,700 50,800 50,000 General plant and other facilities 1,100 2,200 2,300 10,200 -------- -------- -------- -------- TOTAL ......................... $ 75,400 $ 86,300 $ 81,500 $107,900 ======== ======== ======== ======== I&M Generating plant and facilities .. $ 66,400 $ 50,200 $ 49,700 $ 59,000 Transmission lines and facilities 17,300 10,100 20,300 30,300 Distribution lines and facilities 39,200 41,300 42,300 44,900 General plant and other facilities 3,500 6,700 2,200 7,300 -------- -------- -------- -------- TOTAL ......................... $126,400 $108,300 $114,500 $141,500 ======== ======== ======== ======== KEPCO Generating plant and facilities .. $ 4,100 $ 8,100 $ 22,600 $ 8,600 Transmission lines and facilities 8,700 6,700 6,400 8,500 Distribution lines and facilities 17,500 20,300 23,700 22,200 General plant and other facilities 1,500 0 500 4,300 -------- -------- -------- -------- TOTAL ......................... $ 31,800 $ 35,100 $ 53,200 $ 43,600 ======== ======== ======== ======== OPCO Generating plant and facilities (b)(c) ............. $124,900 $112,700 $ 83,800 $ 35,900 Transmission lines and facilities 18,900 28,600 15,300 28,300 Distribution lines and facilities 42,800 46,000 45,200 48,000 General plant and other facilities 5,900 10,500 4,700 14,700 -------- -------- -------- -------- TOTAL ......................... $192,500 $197,800 $149,000 $126,900 ======== ======== ======== ======== AEP SYSTEM (d) Generating plant and facilities (a)(b)(c) .......... $255,300 $258,600 $250,400 $205,400 Transmission lines and facilities 111,900 92,800 85,400 120,700 Distribution lines and facilities 237,700 252,300 286,900 276,100 General plant and other facilities 23,700 24,400 19,400 52,000 -------- -------- -------- -------- TOTAL ......................... $628,600 $628,100 $642,100 $654,200 ======== ======== ======== ========
---------- (a) Excludes expenditures for PFBC Utility Demonstration Project. See PFBC Projects. (b) Includes expenditures for Tidd Plant. See PFBC Projects. (c) 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 1992, 1993 and 1994 and the current estimate for 1995 are $93,653,000, $256,673,000, $176,220,000 and $129,771,000, respectively. See Environmental and Other Matters -- CAAA-AEP System Compliance Plan. (d) 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. If the System receives adequate rate relief in future periods, and is able to finance additional construction expenditures, and if the loads which are served by the System increase above the levels currently projected, additional expenditures may be incurred in subsequent years in amounts which would be substantial but which cannot be accurately predicted at this time. 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. Proposed Transmission Facilities: 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 energy between the two companies and relieve present constraints on the transmission of electric energy 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. A decision by the Virginia SCC is pending. 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 1995 or early 1996, with a decision expected in 1996. 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 October 1995 and the final EIS in 1996. Environmental Expenditures: Expenditures related to compliance with air and water quality standards, included in the gross additions to plant of the System, during 1992, 1993 and 1994 and the current estimate for 1995 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 may have been or may be adopted.
1992 1993 1994 1995 Actual Actual Actual Estimate ------ ------ ------ -------- (in thousands) AEGCo ............... $ 0 $ 0 $ 0 $ 0 APCo (a) ............ 11,200 16,800 32,000 15,000 CSPCo ............... 6,500 15,800 13,700 12,100 I&M ................. 0 0 0 1,800 KEPCo ............... 100 1,000 9,500 3,300 OPCo (b)(c) ......... 61,600 31,600 8,000 300 ------- ------- ------- ------- AEP System (a)(b)(c) $79,400 $65,200 $63,200 $32,500 ======= ======= ======= =======
--------------- (a) Excludes expenditures for PFBC Utility Demonstration Project. See PFBC Projects. (b) Includes expenditures for Tidd Plant which have been or are expected to be funded through Federal/state grants and the fuel clause mechanism. See PFBC Projects. (c) 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 1992, 1993 and 1994 and the current estimate for 1995 are $93,653,000, $256,673,000, $176,220,000 and $129,771,000, respectively. See Environmental and Other Matters -- CAAA-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 to the subsidiaries. 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 1994, AEP issued 700,000 shares of Common Stock pursuant to its Dividend Reinvestment and Stock Purchase Plan. Although prevailing interest costs of short-term bank debt and commercial paper generally have been lower than prevailing interest costs of long-term debt securities, whenever interest costs of short-term debt exceed costs of long-term debt, the companies might be adversely affected by reliance on the use of short-term debt to finance their construction and other capital requirements. During the period 1992-1994, external funds from financings and capital contributions by AEP amounted, with respect to APCo, CSPCo and KEPCo to approximately 37%, 1.6% and 37%, 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, 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, 1995, 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 $40 $213 $163 $130 $100 $218 $1,080 ==== === ==== ==== ==== ==== ==== ====== Amount outstanding: Notes payable ... $ -- $ 7 $ -- $ -- $ -- $ 21 $ -- $ 43 Commercial paper 52 -- 120 -- 51 34 17 274 ---- --- ---- ---- ---- ---- ---- ------ $ 52 $ 7 $120 $ -- $ 51 $ 55 $ 17 $ 317 ==== === ==== ==== ==== ==== ==== ======
(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 long-term debt 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, debenture indentures and charters. The most restrictive of these provisions in each instance generally requires (1) for the issuance of additional long-term debt by APCo, I&M and OPCo, for purposes other than the refunding of outstanding long-term debt securities, a minimum, before income tax, earnings coverage of twice the pro forma annual interest charges on long-term debt, (2) for the issuance of first mortgage bonds by CSPCo and KEPCo 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 (3) 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 long-term debt and preferred stock coverages of APCo, CSPCo, I&M, KEPCo and OPCo under their respective debenture indenture, 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, ---------------------- 1992 1993 1994 ---- ---- ---- APCo Debt coverage .............. 3.50 3.62 3.10 Preferred stock coverage ... 1.99 2.04 1.65 CSPCo Mortgage coverage .......... 2.16 2.91 3.64 I&M Debt coverage .............. 3.55 4.59 5.08 Preferred stock coverage ... 2.06 2.48 2.74 KEPCo Mortgage coverage .......... 3.34 2.19 2.60 OPCo Debt coverage .............. 3.36 4.65 4.55 Preferred stock coverage ... 2.22 2.88 2.58
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 respective construction programs 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. CONSERVATION AND LOAD MANAGEMENT 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 electricity as opposed to electricity 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. Recovery of demand-side program expenditures through rates is being reviewed by AEP's respective regulatory commissions. RATES General In recent years the operating subsidiaries of AEP have filed a series of rate increase applications with their respective state commissions and the FERC and expect that they will continue to do so as competitive conditions permit, whenever necessary, as increases in operating, construction and capital costs exceed increases in revenues resulting from previously granted rate increases and increased customer demand. 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. A hearing has been scheduled to begin in July 1995. 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, estimated to be 1998. In 1994, $18,500,000 of net phase-in deferrals were collected through the surcharge which reduced the deferrals from $93,900,000 at December 31, 1993 to $75,400,000 at December 31, 1994. 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. Other Ohio Regulatory Matters: Reference is made to Environmental and Other Matters -- Clean Air Act Amendments of 1990 for a discussion of emission allowances. On March 25, 1993, the PUCO issued its final guidelines concerning emission allowances. The final guidelines state that the PUCO expects that Ohio utilities will take advantage of the allowance trading market, and encourages all trades that can be economically justified. The final guidelines include the proposed guideline that gains or losses on transactions involving emission allowances created by rate base assets should generally flow through to ratepayers. The final guidelines also provide that allowance plans, procedures, practices, trading activity, and associated costs should be reviewed annually in the electric fuel component since the cost of these allowances are part of the acquisition and delivery costs of fuel. Reference is made to the caption Environmental and Other Matters -- Clean Air Amendments of 1990 -- AEP System Compliance Plan for information regarding AEP's compliance plan which has been filed with the PUCO. On September 3, 1992, the PUCO began an investigation into incentive based ratemaking under Ohio's existing ratemaking statutes. Joint comments were filed in November 1992 by CSPCo and OPCo. I&M FERC: In October 1987, a wholesale customer filed a complaint with the FERC for a refund based on the reasonableness of coal costs pursuant to a seven-year contract, beginning in 1986, from an unaffiliated supplier who has leased a Utah mining operation from I&M. In February 1993, the FERC dismissed the complaint. The wholesale customer has appealed the FERC order to the U.S. Court of Appeals for the District of Columbia Circuit. KEPCo FERC: On October 28, 1993, KEPCo filed an application to begin serving the City of Vanceburg as a full requirements customer, effective January 1, 1994, which will yield annual revenues of $1,448,000. On June 9, 1994, the FERC issued a letter order accepting for filing KEPCo's application. On July 24, 1992, the KPSC began an investigation into the feasibility of implementing demand-side management cost recovery and incentive mechanisms. A Kentucky law enacted in April 1994 provides the KPSC with authority to establish cost recovery mechanisms outside of base rate cases. On July 14, 1994, the KPSC issued an order stating that Kentucky utilities should pursue cost-effective DSM. OPCo Reference is made to Rates -- CSPCo regarding generic proceedings by the PUCO relating to emission allowance trading and incentive-based ratemaking. In April 1991, the municipal wholesale customers of OPCo filed a complaint with the FERC seeking refunds back to 1982 for alleged overcharges for certain affiliated fuel costs. The complaint contends that the price of coal from two of OPCo's affiliated mines violated the FERC's market price requirement for affiliate coal pricing. In February 1993, the FERC issued an order dismissing the complaint and, in January 1995, the U.S. Court of Appeals for the Sixth Circuit affirmed the FERC's order, ending the matter. 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 -- Clean Air Act Amendments of 1990 -- AEP System Compliance Plan). 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:
1990 1991 1992 1993 1994 ---- ---- ---- ---- ---- Coal ...................... 90% 86% 93% 86% 91% Nuclear ................... 9% 13% 6% 13% 8% Hydroelectric and other ... 1% 1% 1% 1% 1%
Variations in the generation of nuclear power are primarily related to refueling outages and, in 1992, a forced outage at Cook Plant Unit 2. See Cook Nuclear Plant. Coal The Clean Air Act Amendments of 1990 provide for the issuance of annual allowance allocations covering sulfur dioxide emissions at levels below historic emission levels for many coal-fired generating units of the AEP System. Phase I of this program began in 1995 and Phase II begins in 2000, with both phases requiring significant changes in coal supplies and suppliers. The full extent of such changes, particularly in regard to Phase II, however, has not been determined. See Environmental and Other Matters -- Air Pollution Control -- CAAA-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 energy 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 3,763 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:
1990 1991 1992 1993 1994 ------ ------ ------ ------ ------ Total coal delivered to AEP operated plants (thousands of tons) ...... 52,087 45,232 44,738 40,561 49,024 Sources (percentage): Subsidiaries ............. 25% 28% 25% 20% 15% Long-term contracts ...... 58% 62% 65% 66% 65% Spot or short-term purchases ............. 17% 10% 10% 14% 20% Average price per ton of spot-purchased coal ...... $26.75 $25.40 $23.88 $23.55 $23.00
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:
1990 1991 1992 1993 1994 ------ ------ ------ ------ ------ Dollars per ton AEP System Companies ....... $35.23 $35.16 $34.31 $33.57 $33.95 AEGCo ...................... 21.05 20.65 20.11 17.74 18.59 APCo ....................... 39.77 41.99 43.00 42.65 39.89 CSPCo ...................... 37.01 35.18 33.87 33.87 32.80 I&M ........................ 27.18 25.57 24.23 23.80 22.85 KEPCo ...................... 30.71 31.38 30.24 27.08 26.83 OPCo ....................... 40.13 40.18 38.36 38.12 41.10 Cents per Million Btu's AEP System Companies ....... 158.10 158.88 154.41 150.89 152.41 AEGCo ...................... 126.21 123.33 120.90 107.71 112.06 APCo ....................... 160.94 169.48 173.05 173.32 161.37 CSPCo ...................... 159.83 152.55 143.94 143.66 140.45 I&M ........................ 143.43 139.16 135.11 129.39 123.62 KEPCo ...................... 129.72 132.25 126.92 113.90 113.40 OPCo ....................... 171.10 171.65 163.89 161.25 173.51
The coal supplies at AEP System plants vary from time to time depending on various factors, including customers' usage of electric energy, space limitations, the rate of consumption at particular plants, labor unrest and weather conditions which may interrupt deliveries. At December 31, 1994, the System's coal inventory was approximately 65 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 1994 of the coal-fired generating units of AEP's principal operating subsidiaries, coal requirements of these units over the remainder of their useful lives and the average sulfur content of coal delivered in 1994 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 TOTAL REQUIREMENTS AVERAGE SULFUR CONTENT CONSUMPTION FOR REMAINDER OF DELIVERED COAL DURING 1994 OF USEFUL LIVES ---------------------------- (IN THOUSANDS (IN MILLIONS POUNDS OF SO/2/ OF TONS) OF TONS)(A) BY WEIGHT PER MILLION BTU'S ------------- --------------- --------- ----------------- AEGCo (b) ..... 5,377 258 0.3% 0.7 APCo .......... 9,455 406 0.7% 1.2 CSPCo (c) ..... 6,137 253 3.2% 5.5 I&M (d) ....... 6,865 295 0.6% 1.3 KEPCo ......... 2,315 89 1.3% 2.1 OPCo .......... 17,613 627 2.5% 4.1
--------------- (a) Preliminary estimates of the effects of the Clean Air Act Amendments of 1990 are included. (b) Reflects AEGCo's 50% interest in the Rockport Plant. (c) Includes coal requirements for CSPCo's interest in Beckjord, Stuart and Zimmer Plants. (d) 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: APCo, or its subsidiaries formerly engaged in coal mining, control coal reserves in the State of West Virginia which contain approximately 42,000,000 tons of clean recoverable coal, ranging in sulfur content between 1.0% and 3.5% sulfur by weight (weighted average, 2.6% sulfur by weight). Substantially all of the coal consumed at APCo's generating plants is obtained from unaffiliated suppliers under long-term contracts or on a spot purchase basis. The average sulfur content by weight of the coal received by APCo at its generating stations approximated 0.7% during 1994, 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 owns an undivided one-half interest in 24,000,000 tons of clean recoverable deep-mineable coal in the State of Ohio which is located in the vicinity of its decommissioned Poston Plant and has an average sulfur content of 2.4% by weight. Peabody Coal Company (Peabody), which owns the remaining one-half interest, has the right to mine and sell all of the jointly owned coal to any party on terms negotiated by Peabody. CSPCo has an option and right of first refusal (exercisable within a specified period after tender by Peabody) which will permit it to purchase this coal on the same terms as those of any contract which Peabody may negotiate with a third party. In the event that CSPCo does not exercise such right, it is entitled to receive a royalty on the coal from this reserve which Peabody sells to others. However, in such a case, this coal will not be available for CSPCo's use. CSPCo also owns coal reserves in eastern and southeastern Ohio which contain approximately 46,000,000 tons of clean recoverable coal with a sulfur content of approximately 4.5% sulfur by weight and reserves that contain approximately 10,000,000 tons of clean recoverable coal with a sulfur content of approximately 2.4% sulfur by weight. CSPCo has a coal supply agreement with an unaffiliated supplier for the delivery of 1,272,000 tons of coal per year through March 1999. Such coal contains approximately 4% sulfur by weight and 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 acquired surface ownership interest in lands in Wyoming which, it is estimated, are underlaid by approximately 730,000,000 tons of clean recoverable coal with an average sulfur content by weight of approximately 0.5%. Federal and state coal leases which would provide the rights and authorization to extract this coal have not been obtained. I&M is attempting to sell its interest in these lands. I&M has entered into 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. A contract with remaining deliveries of 72,500,000 tons expires on December 31, 2014 and a contract with remaining deliveries of 60,000,000 tons expires on December 31, 2004. I&M or its subsidiaries own or control coal reserves in Carbon County, Utah, which are estimated to contain 227,000,000 tons of clean recoverable coal with an average sulfur content by weight of approximately 0.5% sulfur. In 1986, I&M and its two subsidiaries signed agreements under which certain of such coal rights, land, and related mining and preparation equipment and facilities were leased or subleased on a long-term basis to unaffiliated interests. In 1993, the remainder of those land and coal rights containing approximately 108,000,000 tons of clean recoverable coal were leased on a long-term basis to unaffiliated interests. Mining operations in Carbon County formerly conducted by I&M were suspended in 1984. KEPCo: Substantially all of the coal consumed at KEPCo's Big Sandy Plant is obtained from unaffiliated suppliers under long- term contracts or on a spot purchase basis. KEPCo has entered into coal supply agreements with unaffiliated suppliers pursuant to which KEPCo will receive approximately 2,718,000 tons of coal in 1995. 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: OPCo and certain of its coal-mining subsidiaries own or control coal reserves in the State of Ohio which contain approximately 218,000,000 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 107,000,000 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 30,000,000 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 market until it decides that deliveries under 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 1998 --- Unit 2 .... --- --- 2000 1998 ---
--------------- 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. I&M also has a contract with Cogema, Inc. for the supply of enrichment services through 1995, depending on market conditions. 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 $82,013,000 at December 31, 1994. This amount has been recorded as long-term debt with an offsetting regulatory asset. The regulatory asset at December 31, 1994 of $8,400,000 is being amortized as rate recovery occurs. 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 this fee. At December 31, 1994, funds collected from customers to dispose of spent nuclear fuel and related earnings totaled $145,600,000. 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. Studies completed in 1994 estimate decommissioning and low- level radioactive waste disposal costs to range from $634,000,000 to $988,000,000 in 1993 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. 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 and Michigan rate cases 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 $26,000,000 in 1994, $13,000,000 in 1993 and $12,000,000 in 1992. At December 31, 1994, I&M had recognized a decommissioning liability of $212,000,000. 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 radiological decommissioning may be materially different from the amounts derived from the estimates contained in the site-specific study 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) limited experience to date 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 1994, the Financial Accounting Standards Board (FASB) added Accounting for Nuclear Decommissioning Liabilities to its agenda. Among the topics to be studied by the FASB is the question of when future decommissioning liabilities should be recognized. I&M and the electric utility industry accrue such costs over the service life of their nuclear facilities as recovered in rates. A new requirement from the FASB could cause the annual provisions for decommissioning to increase should the estimate of the remaining unaccrued decommissioning costs be greater than the regulators' allowed recovery level. Management believes that the industry's life of the plant accrual accounting method is appropriate and should be accepted by the FASB. Until the FASB completes its study and reaches a conclusion, the impact, if any, on results of operations and financial condition cannot be determined. 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 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 1990, Nevada, South Carolina and Washington, the three states with operating disposal sites, determined that Michigan was out of compliance with milestones established by the LLWPA which were designed to force development of new disposal sites by the end of 1992. Failure of a state or compact region to have met a milestone could result in denial of access to operating sites for waste generators within the state. Since November 1990, the Cook Plant has been denied access to these operating sites. The Cook Plant's low-level radioactive waste is currently 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. 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. 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 $48,598,000, subject to inflation adjustments, and is payable in annual assessments over the next 12 years. I&M recorded a regulatory asset concurrent with the recording of the liability. The payments are being recorded and recovered as fuel expense. 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 operating subsidiaries and that, in the long term, AEP's operating 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 for which management is seeking recovery 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 and Financing Program -- Construction Expenditures. 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. A utility or utility system will be deemed to operate in compliance with the legislation if its aggregate annual emissions do not exceed the total number of allowances that are allocated to the utility or utility system by the federal government and net acquisitions through purchases. Effective January 1, 2000, the legislation establishes a maximum national aggregate ceiling on allowances allocated to fossil fuel-fired units larger than 25 megawatts. The allowance cap is set at 8.95 million tons. 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 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 and Picway Unit 5; and OPCo's Gavin Units 1- 2, Muskingum River Units 1-5, Cardinal Unit 1, Mitchell Units 1-2 and Kammer Units 1-3. The CAAA contemplate four general methods of compliance: (i) fuel switching; (ii) technological methods of control such as scrubbers; (iii) capacity utilization adjustments; and (iv) acquisition of allowances to cover anticipated emissions levels. The AEP System permit application and compliance plan filings reflect, to some extent, each method of compliance. On January 11, 1993, Federal EPA published final regulations in the Federal Register which cover the Acid Rain Permit Program, Allowance System, Continuous Emission Monitoring, Excess Emissions Penalties and Offset Plans and Appeal Procedures. These regulations included allocation of allowances for Phase I sources. On March 12, 1993, several environmental groups, the State of New York and a number of utilities (including APCo, CSPCo, I&M, KEPCo and OPCo) filed petitions in the U.S. Court of Appeals for the District of Columbia Circuit seeking a review of the regulations. The parties have settled a number of issues, including those relating to Substitution Unit, Compensation Unit and Reduced Utilization plans. Oral argument has not been scheduled for the remaining issues. Phase I permits have been issued for all Phase I-affected units in the AEP System. All fossil fuel-fired 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 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. These regulations 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. On December 16, 1994, OPCo and CSPCo filed appeals seeking the suspension of NOx limits contained in acid rain permits for Conesville, Picway and Mitchell plants pending the reissuance of NOx regulations. On February 7, 1995, Federal EPA published a notice in the Federal Register advising that the NOx limitations contained in the permits for these plants were suspended pending the remanded rulemaking. For wet bottom wall-fired boilers, cyclone boilers, units applying cell burner technology and all other types of boilers, emission limitations comparable in cost to the controls applicable to tangentially fired boilers and non-cell burner dry bottom wall-fired boilers are to be adopted no later than January 1, 1997. The 1997 nitrogen oxides emission limitations are required to be met by Phase II-affected sources as of January 1, 2000. 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 nonattainment of ambient air quality standards, establishes a tiered system for classifying degrees of nonattainment with air quality standards for ozone and mandates that Federal EPA in cooperation with the states issue, within 240 days of enactment, ozone "attainment" or "nonattainment" designations for airsheds throughout the country. Depending upon the severity of nonattainment within a given nonattainment 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. The deadlines for submission of new state plans and the accomplishment of mandated emission reductions, as well as the nature of stationary source nitrogen oxides control requirements, also depend upon the severity of a given airshed's nonattainment. While ozone nonattainment is largely restricted to urban areas, several 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 NOx emissions from the midwest must be reduced in order to achieve the National Ambient Air Quality Standard for ozone in the northeast. Plants currently located in areas being evaluated for imposition of additional emission controls include Zimmer and Beckjord Unit 6 (both partially owned by CSPCo), I&M's Tanners Creek Plant, KEPCo's Big Sandy Plant, OPCo's Gavin Plant and APCo's Amos, Sporn, Kanawha River and Mountaineer plants. 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. 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 has received a court order to complete the study and submit it by November 1995. 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 by November 1995 to prevent serious adverse effects to public health and serious or widespread environmental effects. It is possible that emissions from electric utility 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 citizens 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. CAAA-AEP System Compliance Plan: In 1992, the PUCO approved a systemwide Phase I CAAA 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 has emitted 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 are being 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. Fuel switching is planned for Muskingum River Units 1-4 in 2000 and Cardinal Unit 1 in 2001 for Phase II 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. Central Ohio Coal Company reduced its operating level by approximately 50% in 1994. Windsor Coal Company has also reduced its operating level to comply with the CAAA. 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. Management currently expects that the cost of the leased scrubbers will be approximately $675,000,000. See Construction and Financing Program -- Construction Expenditures. 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. The lease term is for 34 years, subject to certain termination provisions. OPCo may purchase the scrubbers during the last 19 years of the lease term and may renew the lease for an additional 20 years. Rent will be payable quarterly and will reflect, among other factors, amortization of the final cost of the scrubbers and the costs of JMG's equity and debt capital. OPCo's rental obligation under the lease has been pledged by JMG as security for the debt portion of its financing. Recovery of compliance costs is being 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. 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. 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. The proponents of the theory of global climate change maintain that the increasing concentrations of man-made greenhouse gases will cause some of the sun's energy that is normally radiated back into space to be trapped in the atmosphere and that, as a result, the global temperature will increase. 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 before new restrictions are imposed. Management is concerned that new laws may be passed or new regulations promulgated without sufficient scientific study and support. At the Earth Summit in Rio de Janeiro, Brazil in June 1992, over 150 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 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 voluntary partnerships between the Federal government and U.S. industry. One such collaboration is between the electric utility industry and DOE. Known as the Utility Climate Challenge, this initiative is intended to identify voluntary, 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 is intended to lead to reductions in future greenhouse gas emissions through cost-effective actions. On February 3, 1995, the AEP System entered into the Climate Challenge Participation Accord with DOE. The Accord contains a wide diversity 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. 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 severe command-and- control limitations on carbon dioxide emissions if the compliance costs incurred are not fully recovered from ratepayers. In addition, any such severe program to stabilize or reduce carbon dioxide emissions could impose substantial costs on industry and society and seriously erode the economic base that AEP's operations serve. Ohio: On July 29, 1988, Federal EPA issued a notice of violation alleging that OPCo's Muskingum River Plant operated in violation of Ohio EPA's regulation governing visible emissions during 1987. At a November 1988 enforcement conference pursuant to Clean Air Act Section 113, OPCo representatives presented evidence to Federal EPA indicating that the notice of violation was not supported by factual evidence nor by law. Federal EPA has yet to take further action. West Virginia: The West Virginia Air Pollution Control Commission 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. The West Virginia Air Pollution Control Commission 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 also 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 and 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 September 1, 1995. The outcome of this initiative cannot be predicted at this time. Stack Height Regulations: On June 27, 1985, Federal EPA issued stack height regulations pursuant to an order of the United States Court of Appeals for the District of Columbia Circuit. These regulations were appealed by a number of states, environmental groups and investor-owned electric utilities (including APCo, CSPCo, I&M, KEPCo and OPCo), along with three electric utility trade associations. OPCo also filed a separate petition for review to raise issues unique to its Kammer Plant. Various petitions for reconsideration filed with and denied by Federal EPA were also appealed. This litigation was consolidated into a single case. On January 22, 1988, the U.S. Court of Appeals 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 is in the process of initiating administrative proceedings under the 1985 stack height rules 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 substantially 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 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 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. 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 Resource 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. 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 1995. 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. Recently renewed thermal variances for Conesville and Muskingum River plants were more stringent in their controls, but the cost impacts are not expected to be significant. 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. 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 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. The Comprehensive Environmental Response, Compensation, and Liability Act 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 this Act 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 as parties responsible for clean-up at eight federal sites, including I&M at four sites, KEPCo at one site, OPCo at two sites and Wheeling Power Company at one site. I&M also has been named as a party responsible for clean-up at one state site. The companies' share of clean-up costs, however, is not expected to be significant. AEP System companies, including I&M and OPCo, also have been named as defendants in contribution lawsuits for two additional sites. 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 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 three epidemiological studies of EMF and utility workers published from 1993 through early 1995 -- each with results that contradicted the others. One reported a weak association between EMF and a type of adult leukemia, but not brain cancer; while another reported a weak association with brain cancer, but not leukemia. However, the third found no evidence of increased deaths from cancer, including leukemia and brain cancer. A conclusion cannot be drawn from these three studies. The researchers are collaborating to reexamine their data collection techniques, exposure assessments, and statistical analyses to possibly reconcile their conflicting findings by looking at the three studies together. In addition, the research 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 operation and financial condition of AEP and its operating subsidiaries could be materially adversely affected unless these costs can be recovered from rate payers. 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. See Construction and Financing Program -- PFBC Projects. AEP System operating companies have elected to join 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 will be phased in from 1994 through 1996. AEP's operating companies are seeking recovery of these dues through rates, which recovery is anticipated to closely relate to each company's membership date. Total research and development expenditures by AEP and its subsidiaries were approximately $7,700,000 for the year ended December 31, 1994, $13,800,000 for the year ended December 31, 1993 and $14,200,000 for the year ended December 31, 1992, including $2,200,000, $10,900,000 and $12,000,000, respectively, for Tidd Plant and related PFBC costs. 1994 expenditures also included $3,200,000 for EPRI dues. Item 2. PROPERTIES ----------------------------------------------------------------- At December 31, 1994, 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 Niagara Roanoke, Virginia 3,000 Reusens Lynchburg, Virginia 12,000 Hydroelectric -- Pumped Storage: Smith Mountain Penhook, Virginia 565,000 ---------- 5,807,000 ---------- 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 ---------- Kanawha Valley Power Company: Hydroelectric -- Conventional: London Montgomery, West Virginia 16,000(e) Marmet Marmet, West Virginia 16,000(e) Winfield Winfield, West Virginia 19,000(e) ---------- 51,000 ---------- 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(f) 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) Kanawha Valley Power Company has requested regulatory approval to merge into APCo. (f) The scrubber facilities at the Gavin Plant are leased. The lease terminates in 2029 unless extended or terminated earlier. 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) ...... 124,251(b) 2,022 APCo ................ 48,532 641 CSPCo (a) ........... 14,050 --- I&M ................. 20,688 614 KEPCo ............... 9,854 258 OPCo ................ 28,082 509
--------------- (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 119 high-voltage transmission interconnections with 29 neighboring electric utility systems. The all-time and 1994 one-hour peak System demand was 25,940,000 kilowatts (which included 7,314,000 kilowatts 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. The net dependable capacity to serve the System load on such date, including power available under contractual obligations, was 23,457,000 kilowatts. The all-time and 1994 one-hour internal peak demand was 19,236,000 kilowatts and occurred on January 19, 1994. The net dependable capacity to serve the System load on such date, including power dedicated under contractual arrangements, was 23,995,000 kilowatts. The all-time one-hour integrated and internal net system peak demands and 1994 peak demands for AEP's generating subsidiaries are shown in the following tabulation:
ALL-TIME ONE-HOUR INTEGRATED 1994 ONE-HOUR INTEGRATED NET SYSTEM PEAK DEMAND NET SYSTEM PEAK DEMAND ---------------------------- -------------------------- (IN THOUSANDS) NUMBER OF NUMBER OF KILOWATTS DATE KILOWATTS DATE --------- ---------------- --------- ---------------- APCo .......... 8,203 January 19, 1994 8,203 January 19, 1994 CSPCo ......... 4,172 June 17, 1994 4,172 June 17, 1994 I&M ........... 5,027 June 17, 1994 5,027 June 17, 1994 KEPCo ......... 1,575 January 19, 1994 1,575 January 19, 1994 OPCo .......... 7,291 June 17, 1994 7,291 June 17, 1994 ALL-TIME ONE-HOUR INTEGRATED 1994 ONE-HOUR INTEGRATED NET INTERNAL PEAK DEMAND NET INTERNAL PEAK DEMAND ---------------------------- --------------------------- (IN THOUSANDS) NUMBER OF NUMBER OF KILOWATTS DATE KILOWATTS DATE --------- ---------------- --------- ---------------- APCo .......... 6,887 January 19, 1994 6,887 January 19, 1994 CSPCo ......... 3,179 June 20, 1994 3,179 June 20, 1994 I&M ........... 3,605 June 16, 1994 3,605 June 16, 1994 KEPCo ......... 1,363 February 9, 1995 1,309 January 19, 1994 OPCo .......... 5,436 January 21, 1994 5,436 January 21, 1994
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. 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 71.0% during 1994 and 100% during 1993. 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 54.3% during 1994 and 96.6% during 1993. The availability of Units 1 and 2 was affected in 1994 by outages to refuel. 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 have continued to increase and become less predictable, 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 $34,000,000. 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 operation and the financial condition of AEP, I&M and other AEP System companies. Item 3. LEGAL PROCEEDINGS ----------------------------------------------------------------- In February 1990, the Supreme Court of Indiana overturned an order of the IURC, affirmed by the Indiana Court of Appeals, which had awarded I&M the right to serve a General Motors Corporation light truck manufacturing facility located in Fort Wayne. In August 1990, the IURC issued an order transferring the right to serve the GM facility to an unaffiliated local distribution utility. In October 1990, the local distribution utility sued I&M in Indiana under a provision of Indiana law that allows the local distribution utility to seek damages equal to the gross revenues received by a utility that renders retail service in the designated service territory of another utility. On November 30, 1992, the DeKalb Circuit Court granted I&M's motion for summary judgment to dismiss the local distribution utility's complaint. The local distribution utility has appealed the decision to the Indiana Court of Appeals. I&M received revenues of approximately $29,000,000 from serving the GM facility. It is not clear whether the plaintiffs claim will be upheld on appeal because the service was rendered in accordance with an IURC order I&M believed in good faith to be valid. 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 has appealed to the Mine Safety and Health Review Commission the July 20, 1993 and April 20, 1994 administrative law judge decisions. All remaining cases, including the citations involving OPCo's mines, have been stayed. On October 4, 1993, I&M was served with a complaint issued by Region V, Federal EPA which alleged violations by Breed Plant of the Clean Water Act and proposed a penalty of $70,000, which demand was subsequently reduced to $40,000. 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 Contracts. Pursuant to the Clean Air Act Amendments of 1990, OPCo received sulfur dioxide emission allowances for its Kammer Plant. See Environmental and Other Matters. Ormet's complaint seeks a declaration that it is the owner of approximately 89% of the Phase I and Phase II allowances issued for use by the Kammer Plant. On May 2, 1994, AEP, OPCo and AEP Service Corporation and its two employee defendants filed a motion seeking to dismiss the complaint filed by Ormet Corporation. On May 2, 1994, the Federal EPA defendants also filed a motion to dismiss. OPCo believes that since it is the owner and operator of Kammer Plant and Ormet is a contract power customer, Ormet is not entitled to any of the allowances attributable to the Kammer Plant. 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. On July 27, 1994, West Virginia filed an answer to SOCCo's complaint disputing SOCCo's entitlement to a declaratory judgement and asserting a counterclaim seeking an award of $2,550,000 in civil penalties, reimbursement of monitoring costs and compensation for unspecified natural resources damage. On October 27, 1994, SOCCo filed a motion for summary judgement or alternatively to dismiss West Virginia's counterclaim. SOCCo is currently negotiating a resolution of federal and West Virginia claims. The resolution of these legal actions is not expected to have a material adverse impact on results of operations. 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 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 for the Northern District of West Virginia. At that time, a consent decree entered into by Federal EPA and OPCo specifying compliance by the Kammer Plant with the federally enforceable sulfur dioxide emission limit by September 1, 1995 was lodged with the court. On January 23, 1995, the consent decree was entered by the court. The portion of the NOV relating to penalties will be addressed independently. At this time, management is unable to estimate the amount of any civil penalties that may be imposed by Federal EPA. 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, 1995.
NAME AGE OFFICE (A) ------ --- ------------ E. Linn Draper, Jr. ... 53 Chairman of the Board, President and Chief Executive Officer of AEP and of the Service Corporation Peter J. DeMaria ...... 60 Treasurer of AEP; Executive Vice President- Administration and Chief Accounting Officer of the Service Corporation William J. Lhota ...... 55 Executive Vice President of the Service Corporation Charles A. Ebetino, Jr. 42 Senior Vice President-Fuel Supply of the Service Corporation Gerald P. Maloney ..... 62 Vice President and Secretary of AEP; Executive Vice President-Chief Financial Officer of the Service Corporation James J. Markowsky .... 50 Executive Vice President-Engineering & Construction 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, 1995, 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. ... 53 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 Joseph H. Vipperman ... 54 Director 1985-Present President and Chief Operating Officer 1990-Present Executive Vice President 1989-1990 Peter J. DeMaria ...... 60 Director 1988-Present Vice President 1991-Present Treasurer 1978-Present Treasurer of AEP 1978-Present Executive Vice President- Administration and Chief Accounting Officer of the Service Corporation 1984-Present Treasurer of the Service Corporation 1989-1990 William J. Lhota 55 Director 1990-Present Vice President 1989-Present Executive Vice President of the Service Corporation 1993-Present Executive Vice President- Operations of the Service Corporation 1989-1993 Gerald P. Maloney ..... 62 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 .... 50 Director 1993-Present Executive Vice President- Engineering and Construction of the Service Corporation 1993-Present Senior Vice President and Chief Engineer of the Service Corporation 1988-1993 Charles A. Ebetino, Jr. 42 Senior Vice President-Fuel Supply of the Service Corporation 1993-Present Vice President-Fuel Procurement and Transportation of the Service Corporation 1990-1993 Managing Director-Coal Procurement of the Service Corporation 1986-1990
--------------- (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, 1995, 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. ... 53 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 Carl A. Erikson ....... 44 Director, President and Chief Operating Officer 1993-Present Vice President 1990-1992 President and Chief Operating Officer of CSPCo 1993-Present Vice President of the Service Corporation and Executive Assistant to E. Linn Draper, Jr. 1992-1994 Assistant to Executive Vice President-Operations of the Service Corporation 1989-1990 Peter J. DeMaria ...... 60 Director and Treasurer 1978-Present Vice President 1991-Present Treasurer of AEP 1978-Present Executive Vice President- Administration and Chief Accounting Officer of the Service Corporation 1984-Present Treasurer of the Service Corporation 1989-1990 William J. Lhota ...... 55 Director and Vice President 1989-Present Executive Vice President of the Service Corporation 1993-Present Executive Vice President- Operations of the Service Corporation 1989-1993 Gerald P. Maloney ..... 62 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 .... 50 Director 1989-Present Executive Vice President- Engineering and Construction of the Service Corporation 1993-Present Senior Vice President and Chief Engineer of the Service Corporation 1988-1993 Charles A. Ebetino, Jr. 42 Senior Vice President-Fuel Supply of the Service Corporation 1993-Present Vice President-Fuel Procurement and Transportation of the Service Corporation 1990-1993 Managing Director-Coal Procurement of the Service Corporation 1986-1990
--------------- (a) Positions are with OPCo unless otherwise indicated. PART II --------------------------------------------------------- Item 5. MARKET FOR REGISTRANTS' COMMON EQUITY AND RELATED STOCKHOLDER MATTERS ----------------------------------------------------------------- AEP. AEP Common Stock is traded principally on the New York Stock Exchange. The following table sets forth for the calendar periods indicated the high and low sales prices for the Common Stock as reported on the New York Stock Exchange Composite Tape and the amount of cash dividends paid per share of Common Stock.
PER SHARE ----------------- MARKET PRICE ----------------- QUARTER ENDED HIGH LOW DIVIDEND(1) ------------- -------- ------- ----------- March 1993 ............ $37 $32 $.60 June 1993 ............. 38-1/2 33-3/8 .60 September 1993 ........ 40-3/8 37-1/4 .60 December 1993 ......... 39-5/8 34-5/8 .60 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 30-1/8 .60
--------------- (1) See Note 5 of the Notes to the Consolidated Financial Statements of AEP for information regarding restrictions on payment of dividends. At December 31, 1994, AEP had approximately 183,000 shareholders of record. AEGCO, APCO, CSPCO, I&M, KEPCO AND OPCO. The information required by this item is not applicable as the common stock of all these companies is held solely by AEP. Item 6. SELECTED FINANCIAL DATA ----------------------------------------------------------------- AEGCO. Omitted pursuant to Instruction 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 1994 Annual Report (for the fiscal year ended December 31, 1994). APCO. The information required by this item is incorporated herein by reference to the material under Selected Consolidated Financial Data in the APCo 1994 Annual Report (for the fiscal year ended December 31, 1994). 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 1994 Annual Report (for the fiscal year ended December 31, 1994). 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 1994 Annual Report (for the fiscal year ended December 31, 1994). 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 1994 Annual Report (for the fiscal year ended December 31, 1994). 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 1994 Annual Report (for the fiscal year ended December 31, 1994). 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 1994 Annual Report (for the fiscal year ended December 31, 1994). 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 1994 Annual Report (for the fiscal year ended December 31, 1994). 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 1994 Annual Report (for the fiscal year ended December 31, 1994). 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 1994 Annual Report (for the fiscal year ended December 31, 1994). 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 1994 Annual Report (for the fiscal year ended December 31, 1994). 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, 1995, for the 1995 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 1995 annual meeting of stockholders, to be filed within 120 days after December 31, 1994. 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, 1995, 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. ... 53 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 Richard C. Menge ...... 59 Director 1976-Present President and Chief Operating Officer 1989-Present Mark A. Bailey ........ 42 Director and Vice President 1989-Present Peter J. DeMaria ...... 60 Director 1992-Present Vice President 1991-Present Treasurer 1978-Present Treasurer of AEP 1978-Present 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 .. 47 Director and Vice President 1984-Present William J. Lhota ...... 55 Director and Vice President 1989-Present Executive Vice President of the Service Corporation 1993-Present Executive Vice President- Operations of the Service Corporation 1989-1993 Gerald P. Maloney ..... 62 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 ... 50 Director 1995-Present Vice President 1993-Present Executive Vice President- Engineering & Construction of the Service Corporation 1993-Present Senior Vice President and Chief Engineer of the Service Corporation 1988-1993 A. H. Potter .......... 47 Director 1994-Present Transmission and Distribution Director 1987-Present D. M. Trenary ......... 58 Director 1994-Present Indiana Region Manager 1994-Present Division Manager 1989-1994 W. E. Walters ......... 47 Director 1991-Present Michiana Region Manager 1994-Present Executive Assistant to President 1987-1994 Charles A. Ebetino, Jr. 42 Senior Vice President-Fuel Supply of the Service Corporation 1993-Present Vice President-Fuel Procurement & Transportation of the Service Corporation 1990-1993 Managing Director-Coal Procurement of the Service Corporation 1986-1990
(a) Positions are with I&M unless otherwise indicated. (b) Dr. Draper is a director of VECTRA Technologies, Inc., Mr. Lhota is a director of Huntington Bancshares Incorporated and Mr. Menge is a director of Fort Wayne National Corporation. (c) Drs. Draper and Markowsky and Messrs. DeMaria, Lhota and Maloney are directors of AEGCo, APCo, CSPCo, KEPCo and OPCo. Dr. Draper and Messrs. DeMaria and Maloney are also directors of AEP. 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 1995 annual meeting of shareholders, to be filed within 120 days after December 31, 1994. 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, 1995, for the 1995 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 1995 annual meeting of stockholders, to be filed within 120 days after December 31, 1994. 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 1995 annual meeting of shareholders, to be filed within 120 days after December 31, 1994. 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 1994, 1993 and 1992 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, 1994. SUMMARY COMPENSATION TABLE
LONG-TERM ANNUAL COMPENSATION COMPENSATION ___________________ __________________ PAYOUTS ALL OTHER SALARY BONUS ------------------ COMPENSATION NAME AND PRINCIPAL POSITION YEAR ($) ($)(1) LTIP PAYOUTS($)(2) ($)(3) --------------------------- ---- ------- -------- ------------------ ------------ E. LINN DRAPER, JR. -- chairman of the board and 1994 620,000 209,436 137,362 29,385 and chief executive officer of I&M; chairman of 1993 538,333 148,742 18,180 the board, president and chief executive officer 1992 395,833 8,730 63,700 of AEP and the Service Corporation; chairman and chief executive officer of other AEP System subsidiaries PETER J. DEMARIA -- vice president, treasurer and 1994 305,000 103,029 59,032 18,750 director of I&M; treasurer and director of AEP; 1993 280,000 77,364 17,811 executive vice president -- administration and 1992 273,000 6,021 15,576 chief accounting officer and director of the Service Corporation; vice president, treasurer and director of other AEP System subsidiaries G. P. MALONEY -- vice president and director of 1994 300,000 101,340 58,094 19,745 I&M; vice president, secretary and director of 1993 269,000 74,325 18,000 AEP; executive vice president -- chief financial 1992 261,000 5,757 17,036 officer and director of the Service Corporation; vice president and director of other AEP System subsidiaries WILLIAM J. LHOTA -- vice president and director of 1994 280,000 94,584 54,409 19,185 I&M; executive vice president and director of the 1993 249,000 68,799 17,160 Service Corporation; vice president and director 1992 230,000 5,073 15,116 of other AEP System subsidiaries JAMES J. MARKOWSKY -- vice president and director 1994 267,000 90,193 51,930 14,755 of I&M; executive vice president -- engineering 1993 247,000 65,259 11,165 and construction and director of the Service 1992 219,000 4,497 7,020 Corporation; vice president and director of other AEP System subsidiaries
--------------- (1) Reflects payments under the Management Incentive Compensation Plan (MICP). Amounts for 1994 are estimates but should not change significantly. For 1994 and 1993, these amounts include both cash paid and a portion deferred in the form of restricted stock units. These units are paid out in cash after three years based on the price of AEP Common Stock at that time. Dividend equivalents are paid during the three-year period. At December 31, 1994, the deferred amounts (included in the above table) and accrued dividends for Dr. Draper, Messrs. DeMaria, Maloney and Lhota and Dr. Markowsky were equivalent to 2,204, 1,109, 1,080, 1,004 and 956 units having values of $72,456, $36,458, $35,505, $33,006 and $31,428, respectively, based upon a $32-7/8 per share closing price of AEP's Common Stock as reported on the New York Stock Exchange. For 1992, MICP payments were made entirely in cash. (2) Reflects payments under the Performance Share Incentive Plan (which became effective January 1, 1994) for the one-year transition performance period ending December 31, 1994. Dr. Draper, Messrs. DeMaria, Maloney and Lhota and Dr. Markowsky received 2,050, 881, 867, 812 and 775 shares of AEP Common Stock, respectively, representing one-half of their payments. See the discussion below for additional information. (3) For 1994, 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, $14,100; Mr. DeMaria, $4,650; Mr. Maloney, $4,500; Mr. Lhota, $3,900; and Dr. Markowsky, $3,510; and (iii) subsidiary companies director fees: Dr. Draper, $10,785; Mr. DeMaria, $9,600; Mr. Maloney, $10,745; Mr. Lhota, $10,785; and Dr. Markowsky, $6,745. Long-Term Incentive Plans -- Awards In 1994 Each of the awards set forth below constitutes a grant of performance share units, which represent units equivalent to shares of AEP Common Stock, pursuant to AEP'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 AEP Common Stock are not included in the table. The ability to earn performance share units is tied to achieving specified levels of total shareowner return (TSR) relative to the S&P Electric Utility Index. Notwithstanding AEP's TSR ranking, no performance share units are earned unless AEP shareowners 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. Payment of awards earned for the one-year transition performance period ending December 31, 1994 were made 50% in cash and 50% in AEP Common Stock. For subsequent performance periods, 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. 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 AEP Common Stock.
ESTIMATED FUTURE PAYOUTS OF PERFORMANCE SHARE UNITS UNDER PERFORMANCE NON-STOCK PRICE-BASED PLAN NUMBER OF PERIOD UNTIL ----------------------------- PERFORMANCE MATURATION THRESHOLD TARGET MAXIMUM NAME SHARE UNITS OR PAYOUT (#) (#) (#) ---------------------- ----------- ------------ --------- -------- --------- E. L. Draper, Jr. .... 2,235 1994 (1) (1) (1) 4,470 1994-1995 1,118 4,470 8,940 6,705 1994-1996 1,676 6,705 13,410 P. J. DeMaria ......... 960 1994 (1) (1) (1) 1,920 1994-1995 480 1,920 3,840 2,885 1994-1996 721 2,885 5,770 G. P. Maloney ......... 945 1994 (1) (1) (1) 1,890 1994-1995 473 1,890 3,780 2,840 1994-1996 710 2,840 5,680 W. J. Lhota ........... 885 1994 (1) (1) (1) 1,770 1994-1995 443 1,770 3,540 2,650 1994-1996 663 2,650 5,300 J. J. Markowsky ....... 845 1994 (1) (1) (1) 1,690 1994-1995 423 1,690 3,380 2,525 1994-1996 631 2,525 5,050
--------------- (1) For the 1994 transition performance period, the actual number of performance share units earned was: Dr. Draper 4,100; Mr. DeMaria 1,761; Mr. Maloney 1,734; Mr. Lhota 1,624; and Dr. Markowsky 1,550 (see Summary Compensation Table for the cash value of these payouts). 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 I&M. 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. The amounts shown in the table are the straight life annuities payable under the 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. Pension Plan Table
YEARS OF ACCREDITED SERVICE HIGHEST AVERAGE -------------------------------------------------------------- ANNUAL EARNINGS 15 20 25 30 35 40 --------------- -------- -------- -------- -------- -------- -------- $250,000 ...... $ 58,065 $ 77,420 $ 96,775 $116,130 $135,485 $152,110 350,000 ...... 82,065 109,420 136,775 164,130 191,485 214,760 450,000 ...... 106,065 141,720 176,775 212,130 247,485 277,410 600,000 ...... 142,065 189,420 236,775 284,130 331,485 371,385 750,000 ...... 178,065 237,420 296,775 356,130 415,485 465,360
Compensation upon which retirement benefits are based consists of the average of the 36 consecutive months of the employee's highest salary, as listed in the Summary Compensation Table, out of the employee's most recent 10 years of service. As of December 31, 1994, the number of full years of service credited under the Retirement Plan to each of the executive officers of the Company named in the Summary Compensation Table were as follows: Dr. Draper, two years; Mr. DeMaria, 35 years; Mr. Maloney, 39 years; Mr. Lhota, 30 years; and Dr. Markowsky, 23 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 entitlements from prior employers. AEP has determined to pay supplemental retirement benefits to 23 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 1995 of the executive officers named in the Summary Compensation Table, none would be eligible to receive supplemental benefits. AEP made available a voluntary deferred-compensation program in 1982 and 1986, which permitted certain executive employees of AEP System companies to defer receipt of a portion of their salaries. Under this program, an executive 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 executive 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 ANNUAL AMOUNT OF ANNUAL ANNUAL AMOUNT OF AMOUNT SUPPLEMENTAL AMOUNT SUPPLEMENTAL DEFERRED RETIREMENT DEFERRED RETIREMENT (4-YEAR PAYMENT (4-YEAR PAYMENT NAME PERIOD) (15-YEAR PERIOD) 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 AEP and the 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 AEP and the Service Corporation on March 1, 1992. AEP or the 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, the 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, 1995, for the 1995 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, 1994. 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 that were beneficially owned, directly or indirectly, as of December 31, 1994, 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 set forth opposite his name. Fractions of shares have been rounded to the nearest whole share.
AMOUNT AND NATURE OF BENEFICIAL OWNERSHIP (A) ------------------------ Mark A. Bailey ............ 1,050 Peter J. DeMaria .......... 6,105(b)(c) William N. D'Onofrio ...... 3,811(b) E. Linn Draper, Jr. ....... 1,492(b) William J. Lhota .......... 7,414(b)(c) Gerald P. Maloney ......... 4,249(b)(c) James J. Markowsky ........ 4,861(b) Richard C. Menge .......... 3,011(b) A. H. Potter .............. 2,795(b) D. M. Trenary ............. 206 W. E. Walters ............. 4,242 All directors and executive officers as a group (12 persons) ............ 127,621(c)(d)
--------------- (a) The amounts include shares held by the trustee of the AEP Employees Savings Plan, over which directors, nominees and executive officers have voting power, but the investment/disposition power is subject to the terms of such Plan, as follows: Mr. Bailey, 1,005 shares; Mr. DeMaria, 2,398 shares; Mr. D'Onofrio, 3,251 shares; Mr. Lhota, 5,986 shares; Mr. Maloney, 2,464 shares; Mr. Menge, 2,925 shares; Mr. Potter, 2,741 shares; Mr. Trenary, 165 shares; Mr. Walters, 4,197 shares; and all directors and executive officers as a group, 33,608 shares. Messrs. Bailey's, DeMaria's, D'Onofrio's, Lhota's, Maloney's, Menge's, Potter's, Trenary's and Walter's holdings include 44, 83, 59, 60, 85, 62, 41, 41 and 45 shares, respectively; and the holdings of all directors and executive officers as a group include 633 shares, each held by the trustee of the AEP Employee Stock Ownership Plan, over which shares such persons have sole voting power, but the investment/disposition power is subject to the terms of such Plan. (b) Includes shares with respect to which such directors, nominees and executive officers share voting and investment power as follows: Mr. DeMaria, 3,624 shares; Mr. D'Onofrio, 500 shares; Dr. Draper, 124 shares; Mr. Lhota, 1,368 shares; Mr. Maloney, 1,700 shares; Mr. Menge, 24 shares; and Mr. Potter, 13 shares; and all directors and executive officers as a group, 4,956 shares. Mr. DeMaria disclaims beneficial ownership of 2,392 shares. (c) 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 of such shares), are not included in their individual totals, but are included in the group total. (d) Represents less than 1 percent of the total number of shares outstanding on December 31, 1994. 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 1995 annual meeting of shareholders, to be filed within 120 days after December 31, 1994. 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, 1995, for the 1995 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: PAGE ---- The following financial statements have been incorporated herein by reference pursuant to Item 8. AEGCo: Independent Auditors' Report; Statements of Income for the years ended December 31, 1994, 1993 and 1992; Statements of Retained Earnings for the years ended December 31, 1994, 1993 and 1992; Statements of Cash Flows for the years ended December 31, 1994, 1993 and 1992; Balance Sheets as of December 31, 1994 and 1993; Notes to Financial Statements. AEP and its subsidiaries consolidated: Consolidated Statements of Income for the years ended December 31, 1994, 1993 and 1992; Consolidated Statements of Retained Earnings for the years ended December 31, 1994, 1993 and 1992; Consolidated Balance Sheets as of December 31, 1994 and 1993; Consolidated Statements of Cash Flows for the years ended December 31, 1994, 1993 and 1992; Notes to Consolidated Financial Statements; Schedule of Consolidated Cumulative Preferred Stocks of Subsidiaries at December 31, 1994 and 1993; Schedule of Consolidated Long-term Debt of Subsidiaries at December 31, 1994 and 1993; Independent Auditors' Report. APCo: Independent Auditors' Report; Consolidated Statements of Income for the years ended December 31, 1994, 1994 and 1993; Consolidated Balance Sheets as of December 31, 1994 and 1993; Consolidated Statements of Cash Flows for the years ended December 31, 1994, 1993 and 1992; Consolidated Statements of Retained Earnings for the years ended December 31, 1994, 1993 and 1992; Notes to Consolidated Financial Statements. CSPCo: Independent Auditors' Report; Consolidated Statements of Income for the years ended December 31, 1994, 1993 and 1992; Consolidated Balance Sheets as of December 31, 1994 and 1993; Consolidated Statements of Cash Flows for the years ended December 31, 1994, 1993 and 1992; Consolidated Statements of Retained Earnings for the years ended December 31, 1994, 1993 and 1992; Notes to Consolidated Financial Statements. I&M: Independent Auditors' Report; Consolidated Statements of Income for the years ended December 31, 1994, 1993 and 1992; Consolidated Balance Sheets as of December 31, 1994 and 1993; Consolidated Statements of Cash Flows for the years ended December 31, 1994, 1993 and 1992; Consolidated Statements of Retained Earnings for the years ended December 31, 1994, 1993 and 1992; Notes to Consolidated Financial Statements. KEPCo: Independent Auditors' Report; Statements of Income for the years ended December 31, 1994, 1993 and 1992; Statements of Retained Earnings for the years ended December 31, 1994, 1993 and 1992; Balance Sheets as of December 31, 1994 and 1993; Statements of Cash Flows for the years ended December 31, 1994, 1993 and 1992; Notes to Financial Statements. OPCo: Consolidated Statements of Income for the years ended December 31, 1994, 1993 and 1992; Consolidated Balance Sheets as of December 31, 1994 and 1993; Consolidated Statements of Cash Flows for the years ended December 31, 1994, 1993 and 1992; Consolidated Statements of Retained Earnings for the years ended December 31, 1994, 1993 and 1992; Notes to Consolidated Financial Statements; Independent Auditors' Report. 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, 1994. 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 23, 1995 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 23, 1995 ----------------------- and Director (G. P. MALONEY) (III) PRINCIPAL ACCOUNTING OFFICER: /s/ P. J. DeMaria Vice President, March 23, 1995 ----------------------- Treasurer and (P. J. DEMARIA) 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 23, 1995 ----------------------- (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 23, 1995 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 23, 1995 ----------------------- Secretary and (G. P. MALONEY) Director (III) PRINCIPAL ACCOUNTING OFFICER: /s/ P. J. DeMaria Treasurer and March 23, 1995 ----------------------- Director (P. J. DEMARIA) (IV) A MAJORITY OF THE DIRECTORS: *Robert M. Duncan *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 23, 1995 ----------------------- (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 23, 1995 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 23, 1995 ----------------------- and Director (G. P. MALONEY) (III) PRINCIPAL ACCOUNTING OFFICER: /s/ P. J. DeMaria Vice President, March 23, 1995 ----------------------- Treasurer and (P. J. DEMARIA) Director (IV) A MAJORITY OF THE DIRECTORS: *Henry Fayne *Luke M. Feck *Wm. J. Lhota *James J. Markowsky *J. H. Vipperman *By: /s/ G. P. Maloney March 23, 1995 ----------------------- (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 23, 1995 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 23, 1995 ----------------------- and Director (G. P. MALONEY) (III) PRINCIPAL ACCOUNTING OFFICER: /s/ P. J. DeMaria Vice President, March 23, 1995 ----------------------- Treasurer and (P. J. DEMARIA) Director (IV) A MAJORITY OF THE DIRECTORS: *C. A. Erikson *Henry Fayne *Wm. J. Lhota *James J. Markowsky *By: /s/ G. P. Maloney March 23, 1995 ----------------------- (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 23, 1995 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 23, 1995 ----------------------- and Director (G. P. MALONEY) (III) PRINCIPAL ACCOUNTING OFFICER: /s/ P. J. DeMaria Vice President, March 23, 1995 ----------------------- Treasurer and (P. J. DEMARIA) Director (IV) A MAJORITY OF THE DIRECTORS: *Mark A. Bailey *W. N. D'Onofrio *Wm. J. Lhota *James J. Markowsky *Richard C. Menge *A. H. Potter *D. M. Trenary *W. E. Walters *By: /s/ G. P. Maloney March 23, 1995 ----------------------- (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 23, 1995 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 23, 1995 ----------------------- and Director (G. P. MALONEY) (III) PRINCIPAL ACCOUNTING OFFICER: /s/ P. J. DeMaria Vice President, March 23, 1995 ----------------------- Treasurer and (P. J. DEMARIA) Director (IV) A MAJORITY OF THE DIRECTORS: *C. R. Boyle, III *Wm. J. Lhota *James J. Markowsky *Ronald A. Petti *By: /s/ G. P. Maloney March 23, 1995 ----------------------- (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 23, 1995 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 23, 1995 ----------------------- and Director (G. P. MALONEY) (III) PRINCIPAL ACCOUNTING OFFICER: /s/ P. J. DeMaria Vice President, March 23, 1995 ----------------------- Treasurer and (P. J. DEMARIA) Director (IV) A MAJORITY OF THE DIRECTORS: *C. A. Erikson *Henry Fayne *Wm. J. Lhota *James J. Markowsky *By: /s/ G. P. Maloney March 23, 1995 ----------------------- (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, 1994, 1993 and 1992 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, 1994 and 1993, and for each of the three years in the period ended December 31, 1994, and have issued our reports thereon dated February 21, 1995; such financial statements and reports are included in your respective 1994 Annual Report to Shareowners 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. /s/ Deloitte & Touche Deloitte & Touche LLP Columbus, Ohio February 21, 1995 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, 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 Year Ended December 31, 1992. . . . . . . . . . . . $ 9,599 $12,888 $ 4,096(a) $19,296(b) $ 7,287 (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, 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 Year Ended December 31, 1992. . . . . . . . . . . . . $ 987 $1,810 $ 672(a) $2,745(b) $ 724 (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, 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 Year Ended December 31, 1992. . . . . . . . . $1,134 $ 4,593 $1,981(a) $6,376(b) $1,332 (a) Recoveries on accounts previously written off. (b) Uncollectible accounts written off. /TABLE 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, 1994. . . . . . . . . . . . $ 504 $ 774 $ 707(a) $ 1,864(b) $ 121 Year Ended December 31, 1993. . . . . . . . . . . . $562 $1,380 $ 624(a) $ 2,062(b) $ 504 Year Ended December 31, 1992. . . . . . . . . . . . $629 $1,736 $ 650(a) $ 2,453(b) $ 562 (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, 1994. . . . . . . . . . . . . $ 208 $ 600 $ 84(a) $ 632(b) $ 260 Year Ended December 31, 1993. . . . . . . . . . . . . $ 248 $ 390 $ 179(a) $ 609(b) $ 208 Year Ended December 31, 1992. . . . . . . . . . . . . $ 352 $ 630 $ 106(a) $ 840(b) $ 248 (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, 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 Year Ended December 31, 1992. . . . . . . . . . . . $ 4,815 $ 4,084 $ 618(a) $ 5,164(b) $ 4,353 (a) Recoveries on accounts previously written off. (b) Uncollectible accounts written off. /TABLE EXHIBIT INDEX Certain of the following exhibits, designated with an asterisk(*), are filed herewith. The exhibits not so designated have heretofore been filed with the Commission and, pursuant to 17 C.F.R. Section 201.24 and Section 240.12b-32, are incorporated herein by reference to the documents indicated in brackets following the descriptions of such exhibits. Exhibits, designated with a dagger (+), are management contracts or compensatory plans or arrangements required to be filed as an exhibit to this form pursuant to Item 14(c) of this report. AEGCO
EXHIBIT NUMBER DESCRIPTION ------- ----------- 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 1994 Annual Report (for the fiscal year ended December 31, 1994) 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)]. +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) -- Excess Benefits Plan [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1993, File No. 1- 3525, Exhibit 10(g)(1)(A)]. +10(g)(1)(B) -- Guaranty by AEP of the Service Corporation Excess Benefits Plan [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1990, File No. 1-3525, Exhibit 10(h)(1)(B)]. +10(g)(2) -- AEP System Supplemental Savings Plan (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 January 1, 1995. 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 1994 Annual Report (for the fiscal year ended December 31, 1994) which are incorporated by reference in this filing. *21 -- List of subsidiaries of AEP. *23 -- Consent of Deloitte & Touche LLP. *24 -- Power of Attorney. *27 -- Financial Data Schedules. APCO++ 3(a) -- Copy of Restated Articles of Incorporation of APCo, and amendments thereto to November 4, 1993 [Registration Statement No. 33-50163, Exhibit 4(a); Registration Statement No. 33-53805, Exhibits 4(b) and 4(c)]. *3(b) -- Copy of Articles of Amendment to the Restated Articles of Incorporation of APCo, dated June 6, 1994. *3(c) -- Composite copy of the Restated Articles of Incorporation of APCo, as amended. 3(d) -- Copy of By-Laws of APCo [Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1990, File No. 1-3457 Exhibit 3(d)]. 4(a) -- Copy of Mortgage and Deed of Trust, dated as of December 1, 1940, between APCo and Bankers Trust Company and R. Gregory Page, as Trustees, as amended and supplemented [Registration Statement No. 2-7289, Exhibit 7(b); Registration Statement No. 2-19884, Exhibit 2(1); Registration Statement No. 2-24453, Exhibit 2(n); Registration Statement No. 2-60015, Exhibits 2(b)(2), 2(b)(3), 2(b)(4), 2(b)(5), 2(b)(6), 2(b)(7), 2(b)(8), 2(b)(9), 2(b)(10), 2(b)(12), 2(b)(14), 2(b)(15), 2(b)(16), 2(b)(17), 2(b)(18), 2(b)(19), 2(b)(20), 2(b)(21), 2(b)(22), 2(b)(23), 2(b)(24), 2(b)(25), 2(b)(26), 2(b)(27) and 2(b)(28); Registration Statement No. 2-64102, Exhibit 2(b)(29); Registration Statement No. 2-66457, Exhibits (2)(b)(30) and 2(b)(31); Registration Statement No. 2-69217, Exhibit 2(b)(32); Registration Statement No. 2-86237, Exhibit 4(b); Registration Statement No. 33-11723, Exhibit 4(b); Registration Statement No. 33-17003, Exhibit 4(a)(ii), Registration Statement No. 33-30964, Exhibit 4(b); Registration Statement No. 33-40720, Exhibit 4(b); Registration Statement No. 33-45219, Exhibit 4(b); Registration Statement No. 33-46128, Exhibits 4(b) and 4(c); Registration Statement No. 33-53410, Exhibit 4(b); Registration Statement No. 33-59834, Exhibit 4(b); Registration Statement No. 33-50229, Exhibits 4(b) and 4(c); Annual Report on Form 10-K of APCo for the fiscal year ending December 31, 1993, File No. 1-3457, Exhibit 4(b)]. *4(b) -- Copy of Indentures Supplemental, dated August 15, 1994, October 1, 1994 and March 1, 1995, to Mortgage and Deed of Trust. 10(a)(1) -- Copy of Power Agreement, dated October 15, 1952, between OVEC and United States of America, acting by and through the United States Atomic Energy Commission, and, subsequent to January 18, 1975, the Administrator of the Energy Research and Development Administration, as amended [Registration Statement No. 2-60015, Exhibit 5(a); Registration Statement No. 2-63234, Exhibit 5(a)(1)(B); Registration Statement No. 2-66301, Exhibit 5(a)(1)(C); Registration Statement No. 2-67728, Exhibit 5(a)(1)(D); Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1989, File No. 1-3457, Exhibit 10(a)(1)(F); and Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1992, File No. 1-3457, Exhibit 10(a)(1)(B)]. 10(a)(2) -- Copy of Inter-Company Power Agreement, dated as of July 10, 1953, among OVEC and the Sponsoring Companies, as amended [Registration Statement No. 2-60015, Exhibit 5(c); Registration Statement No. 2-67728, Exhibit 5(a)(3)(B); and Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1992, File No. 1- 3457, Exhibit 10(a)(2)(B)]. 10(a)(3) -- Copy of Power Agreement, dated July 10, 1953, between OVEC and Indiana-Kentucky Electric Corporation, as amended [Registration Statement No. 2-60015, Exhibit 5(e)]. 10(b) -- Copy of Interconnection Agreement, dated July 6, 1951, among APCo, CSPCo, KEPCo, OPCo and I&M and with the Service Corporation, as amended [Registration Statement No. 2-52910, Exhibit 5(a); Registration Statement No. 2- 61009, Exhibit 5(b); Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1990, File No. 1- 3525, Exhibit 10(a)(3)]. 10(c) -- Copy of Transmission Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KEPCo, OPCo and with the Service Corporation as agent, as amended [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(b); Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1988, File No. 1-3525, Exhibit 10(b)(2)]. *10(d) -- Copy of AEP System Interim Allowance Agreement, dated July 28, 1994, among APCo, CSPCo, I&M, KEPCo, OPCo and the Service Corporation. +10(e)(1) -- AEP Deferred Compensation Agreement for certain executive officers [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1985, File No. 1- 3525, Exhibit 10(e)]. +10(e)(2) -- Amendment to AEP Deferred Compensation Agreement for certain executive officers [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1986, File No. 1-3525, Exhibit 10(d)(2)]. +10(f)(1) -- Management Incentive Compensation Plan [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1994, File No. 1-3525, Exhibit 10(i)(1)]. +10(f)(2) -- American Electric Power System Performance Share Incentive Plan [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1994, File No. 1- 3525, Exhibit 10(i)(2)]. +10(g)(1) -- Excess Benefits Plan [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1993, 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 1994 Annual Report (for the fiscal year ended December 31, 1994) 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, 1994, 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. *3(c) -- Composite copy of Amended Articles of Incorporation of CSPCo, as amended. 3(d) -- Copy of Code of Regulations and By-Laws of CSPCo [Annual Report on Form 10-K of CSPCo for the fiscal year ended December 31, 1987, File No. 1-2680, Exhibit 3(d)]. 4(a) -- Copy of Indenture of Mortgage and Deed of Trust, dated September 1, 1940, between CSPCo and City Bank Farmers Trust Company (now Citibank, N.A.), as trustee, as supplemented and amended [Registration Statement No. 2- 59411, Exhibits 2(B) and 2(C); Registration Statement No. 2-80535, Exhibit 4(b); Registration Statement No. 2- 87091, Exhibit 4(b); Registration Statement No. 2-93208, Exhibit 4(b); Registration Statement No. 2-97652, Exhibit 4(b); Registration Statement No. 33-7081, Exhibit 4(b); Registration Statement No. 33-12389, Exhibit 4(b); Registration Statement No. 33-19227, Exhibits 4(b), 4(e), 4(f), 4(g) and 4(h); Registration Statement No. 33-35651, Exhibit 4(b); Registration Statement No. 33-46859, Exhibits 4(b) and 4(c); Registration Statement No. 33-50316, Exhibits 4(b) and 4(c); Registration Statement No. 33-60336, Exhibits 4(b), 4(c) and 4(d); Registration Statement No. 33- 50447, Exhibits 4(b) and 4(c); Annual Report on Form 10- K of CSPCo for the fiscal year ended December 31, 1993, File No. 1-2680, Exhibit 4(b)]. 10(a)(1) -- Copy of Power Agreement, dated October 15, 1952, between OVEC and United States of America, acting by and through the United States Atomic Energy Commission, and, subsequent to January 18, 1975, the Administrator of the Energy Research and Development Administration, as amended [Registration Statement No. 2-60015, Exhibit 5(a); Registration Statement No. 2-63234, Exhibit 5(a)(1)(B); Registration Statement No. 2-66301, Exhibit 5(a)(1)(C); Registration Statement No. 2-67728, Exhibit 5(a)(1)(B); Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1989, File No. 1-3457, Exhibit 10(a)(1)(F); and Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1992, File No. 1-3457, Exhibit 10(a)(1)(B)]. 10(a)(2) -- Copy of Inter-Company Power Agreement, dated July 10, 1953, among OVEC and the Sponsoring Companies, as amended [Registration Statement No. 2-60015, Exhibit 5(c); Registration Statement No. 2-67728, Exhibit 5(a)(3)(B); and Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1992, File No. 1- 3457, Exhibit 10(a)(2)(B)]. 10(a)(3) -- Copy of Power Agreement, dated July 10, 1953, between OVEC and Indiana-Kentucky Electric Corporation, as amended [Registration Statement No. 2-60015, Exhibit 5(e)]. 10(b) -- Copy of Interconnection Agreement, dated July 6, 1951, among APCo, CSPCo, KEPCo, OPCo and I&M and the Service Corporation, as amended [Registration Statement No. 2- 52910, Exhibit 5(a); Registration Statement No. 2-61009, Exhibit 5(b); and Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1990, File No. 1- 3525, Exhibit 10(a)(3)]. 10(c) -- Copy of Transmission Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KEPCo, OPCo, and with the Service Corporation as agent, as amended [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(b); and Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1988, File No. 1-3525, Exhibit 10(b)(2)]. 10(d) -- Copy of 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 1994 Annual Report (for the fiscal year ended December 31, 1994) which are incorporated by reference in this filing. 21 -- List of subsidiaries of CSPCo [Annual Report on Form 10- K of AEP for the fiscal year ended December 31, 1994, File No. 1-3525, Exhibit 21]. *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 [Annual Report on Form 10-K of I&M for the fiscal year ended December 31, 1990, File No 1-3570, Exhibit 3(d)]. 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)]. *4(b) -- Copy of Indenture Supplemental dated May 1, 1994 to Mortgage and Deed of Trust. 10(a)(1) -- Copy of Power Agreement, dated October 15, 1952, between OVEC and United States of America, acting by and through the United States Atomic Energy Commission, and, subsequent to January 18, 1975, the Administrator of the Energy Research and Development Administration, as amended [Registration Statement No. 2-60015, Exhibit 5(a); Registration Statement No. 2-63234, Exhibit 5(a)(1)(B); Registration Statement No. 2-66301, Exhibit 5(a)(1)(C); Registration Statement No. 2-67728, Exhibit 5(a)(1)(D); Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1989, File No. 1-3457, Exhibit 10(a)(1)(F); and Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1992, File No. 1-3457, Exhibit 10(a)(1)(B)]. 10(a)(2) -- Copy of Inter-Company Power Agreement, dated as of July 10, 1953, among OVEC and the Sponsoring Companies, as amended [Registration Statement No. 2-60015, Exhibit 5(c); Registration Statement No. 2-67728, Exhibit 5(a)(3)(B); Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1992, File No. 1-3457, Exhibit 10(a)(2)(B)]. 10(a)(3) -- Copy of Power Agreement, dated July 10, 1953, between OVEC and Indiana-Kentucky Electric Corporation, as amended [Registration Statement No. 2-60015, Exhibit 5(e)]. 10(b) -- Copy of Interconnection Agreement, dated July 6, 1951, between APCo, CSPCo, KEPCo, I&M, and OPCo and with the Service Corporation, as amended [Registration Statement No. 2-52910, Exhibit 5(a); Registration Statement No. 2- 61009, Exhibit 5(b); and Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1990, File No. 1-3525, Exhibit 10(a)(3)]. 10(c) -- Copy of Transmission Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KEPCo, OPCo and with the Service Corporation as agent, as amended [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(b); and Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1988, File No. 1-3525, Exhibit 10(b)(2)]. 10(d) -- Copy of 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 1994 Annual Report (for the fiscal year ended December 31, 1994) 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, 1994, 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. 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 1994 Annual Report (for the fiscal year ended December 31, 1994) which are incorporated by reference in this filing. *23 -- Consent of Deloitte & Touche LLP. *24 -- Power of Attorney. *27 -- Financial Data Schedules. OPCO++ 3(a) -- Copy of Amended Articles of Incorporation of OPCo, and amendments thereto to December 31, 1993 [Registration Statement No. 33-50139, Exhibit 4(a); Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1993, File No. 1-6543, Exhibit 3(b)]. *3(b) -- Certificate of Amendment to Amended Articles of Incorporation of OPCo, dated May 3, 1994. *3(c) -- Composite copy of the Amended Articles of Incorporation of OPCo, as amended. 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 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, 1994, 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 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1994, File No. 1-3525, Exhibit 10(i)(2)]. +10(j)(1) -- Excess Benefits Plan [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1993, 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). *12 -- Statement re: Computation of Ratios. *13 -- Copy of those portions of the OPCo 1994 Annual Report (for the fiscal year ended December 31, 1994) 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, 1994, 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 10-K EX. 10(I)(1) MGMT INCENTIVE COMP PLAN Exhibit 10(i)(1) CONFIDENTIAL AMERICAN ELECTRIC POWER SYSTEM MANAGEMENT INCENTIVE COMPENSATION PLAN TABLE OF CONTENTS Page INTRODUCTION . . . . . . . . . . . . . . . . . . . . . . . . v 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 Annual Marketing Objectives . . . . . . . . . 8 4.2 Safety Performance . . . . . . . . . . . . . 9 4.3 O&M Expense vs. Budget . . . . . . . . . . . 10 4.4 Customer Service Reliability Index . . . . . 11 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 Affiliated Mine Costs . . . . . . . . . . . . 14 9.2 Safety Performance . . . . . . . . . . . . . 14 9.3 Vice President - Fuel Procurement and Transportation Measures . . . . . . . . . . . 15 9.4 General Mine Manager/General Superintendent Measures . . . . . . . . . . . . . . . . . . 15 9.5 Manager - River Transportation Measures . . . 16 9.6 Manager - Cook Coal Terminal Measures . . . . 17 9.7 Director - Coal Procurement Measures . . . . 17 10.0 DEPARTMENT OBJECTIVES . . . . . . . . . . . . . . . 18 11.0 THE MICP IN ACTION . . . . . . . . . . . . . . . . 19 12.0 PAYMENT RIGHTS AT TERMINATION OF ACTIVE EMPLOYMENT 22 12.1 Termination After Completion of Plan Year . . 22 12.2 Termination Due to Death, Retirement, or Disability . . . . . . . . . . . . . . . . 22 12.3 Involuntary Termination During Plan Year . . 22 13.0 CHANGES IN SALARY / POSITION / PARTICIPATION . . . 24 14.0 PLAN ADMINISTRATION . . . . . . . . . . . . . . . . 25 ADDENDUM 15.0 MICP AWARD PAYMENTS/DEFERRED AWARDS . . . . . . . . A-1 16.0 POSSIBLE ADJUSTMENTS TO CORPORATE PERFORMANCE . . . A-2 17.0 FUEL SUPPLY PAYMENT SCHEDULES . . . . . . . . . . . A-3 17.1 Vice President-Fuel Procurement & Transportation . . . . . . . . . . . . . . A-3 17.2 Price of Purchased Coal . . . . . . . . . . . A-3 17.3 River Transportation Safety . . . . . . . . . A-3 17.4 General Mine Managers . . . . . . . . . . . . A-4 17.5 Southern Ohio Coal Company - Meigs Division . A-4 17.6 Central Ohio Coal . . . . . . . . . . . . . . A-4 17.7 Windsor Coal . . . . . . . . . . . . . . . . A-5 17.8 Safety - All Mines . . . . . . . . . . . . . A-5 17.9 Manager - River Transportation . . . . . . . A-6 17.10 River Transportation Operating Cost Per Ton Mile . . . . . . . . . . . . . . . . A-6 17.11 River Transportation Safety . . . . . . . . . A-6 17.12 Manager-Cook Coal Terminal . . . . . . . . . A-7 17.13 Cook Coal Terminal Adjusted Expenses . . . . A-7 17.14 Cook Coal Terminal Safety . . . . . . . . . . A-7 17.15 Director - Coal Procurement . . . . . . . . . A-8 17.16 Delivered Fuel Prices (Spot/Contract) . . . . A-8 17.17 Sum Total of Present Value Benefits/ Special Contract Negotiations . . . . . . . . A-8 INTRODUCTION The American Electric Power System will continue the Management Incentive Compensation Plan (MICP) during 1993, with revisions from the 1992 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. 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. The remaining 20% is deferred in the form of AEP common stock units payable 3 years later (see Addendum page A-1). 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 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 EVP- Operations. 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 Percent of Awards Allocated to Participant Award as Organizational Units Percent of Base Salary 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 50 Corporate Performance 50 Fuel Supply Performance 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. 20 25 Corporate Performance Department Heads and Executive 50 Operating Company Assistants 25 Performance Department Performance 25 or 75 Corporate Performance Operating Company Performance Operating Company Division 20 25 Corporate Performance Managers 25 Operating Company 50 Performance Division 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
2.0 TARGET AWARD ALLOCATIONS (Continued)
Target Percent of Awards Allocated Participant Award as to Organizational Units Percent of Base Salary Central Machine Shop Manager 20 25 Corporate Performance 75 Central Machine Shop Performance Fuel Supply Lancaster Senior 20 25 Corporate Performance Staff 50 Fuel Supply Performance 25 Department Performance or 25 Corporate Performance 75 Fuel Supply Performance Vice President - Fuel 20 25 Corporate Performance Procurement & Transportation 25 Fuel Supply Performance 50 Department Performance Fuel Supply General Mine 20 25 Corporate Performance Managers / General 25 Fuel Supply Performance Superintendents 50 Division / Mine Performance Manager - Cook Coal Terminal 20 25 Corporate Performance 75 Cook Coal Terminal Performance or 25 Corporate Performance 25 Fuel Supply Performance 50 Cook Coal Terminal Performance Manager - River Transportation 20 25 Corporate Performance 75 River Transportation Performance or 25 Corporate Performance 25 Fuel Supply Performance 50 River Transportation Performance Director - Coal Procurement 20 25 Corporate Performance 25 Fuel Supply Performance 50 Department Performance
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 ROE Performance ROE Factor* 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 interim 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) divided by 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 aver- age 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: The sum of (i) 1.25 and (ii) .25 times [(108% minus 105%) divided by (110% minus 105%)], which equals 1.40 4.2 Safety Performance of each Operating Company and Division is measured by improvement in three indices, each weighted from 25% to 50% as indicated. The three are as follows: Lost Workday Case Incidence Rate (weighted 25%) - Number of lost workday cases per 200,000 work hours. A three-year average incidence rate is calculated for all of the Operating Companies combined. Target is set for a 15% improvement over the three-year combined Company average. The same calculations are made for each Division and all of the Divisions in the System combined. The Division target is a 15% improvement over the three-year combined Division average. Recordable Case Incidence Rate (weighted 50%) - Number of recordable cases per 200,000 work hours. A three- year average incidence rate is calculated for all of the Operating Companies combined. Target is set for a 15% improvement over the three-year combined Company average. The same calculations are made for each Division and all of the Divisions in the System combined. The Division target is set for a 15% improvement over the three-year combined Division average. Lost Workday Rate (weighted 25%) - Number of days away from work and restricted activity days per 200,000 work hours. A three-year average lost workday rate is calculated for all of the Operating Companies combined. Target is set for a 15% improvement over the three-year combined Company average. The same calculations are made for each Division and all of the Divisions in the System combined. The Division target is set for a 15% improvement over the three-year combined Division average. The percent improvement over the three-year combined average is calculated for each measure and the related performance factor averaged to yield a single performance factor for safety performance. For the purposes of these measures, Wheeling Power and Kingsport Power are considered Divisions.
Operating Company and Division Target Award Payment Schedules Improvement Over Three-Year Average Operating Company or Division Safety Performance Percent Improvement Over Performance Three-Year Average Factor* 30 or better 1.50 22.50 1.25 15.00 1.00 11.25 .75 7.50 .50 3.75 .25 0 or worse 0
*Interpolate at intermediate performance. Example: If a Division achieves a 15% improvement in lost workday case incidence rate, a 30% improvement in recordable case incidence rate, and a 7.5% improvement in lost workday rate, the respective performance factors are 1.00, 1.50 and .50. Multiply the performance factor by the assigned weight percentage and the total yields a single performance factor of 1.125. The performance factor shall be zero for any Division whose recordable injuries include a fatality or a permanent total disability case. When a Division or Operating Company works less than 500,000 hours in a calendar year the maximum performance factor for both the lost workday case incidence rate and the lost workday rate, will each be 1.00. Such performance factor(s) may be increased up to 1.50 on recommendation of the Operating Company President and EVP-Operations, based on the attainment of specific objectives in safety and health management, or the affected manager's specific contributions to the safety records of the operation. 4.3 O&M Expense Performance vs. Budget is measured by comparing controllable operating and maintenance expenses against budget for the current year. Perperformance 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 Target Award Payment Schedules 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: (i) 100 times the sum of [Cur. Interpt. Freq. Index divided by (5 minus the Yr. Avg. Intm. Freq. Index)] and [Cur. Interpt. Dur. Index divided by (5 minus Yr. Avg. Intm. Dur. Index)] divided by (ii) 2 Resulting performance factors are determined as follows: Operating Company and Division Target Award Payment Schedules
Customer Service Reliability Index vs. Prior Five-Year Average Service Reliability Performance Factor* Index 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 1.10, which equals the sum of (i) 1 and (ii) .25 times [(100% minus 97%) divided by (100% minus 92.5%)} Special adjustments may be considered for catastrophic situations. (See page 3 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 two overall Fuel Supply performance measures, which are weighted to determine a single Fuel Supply performance factor. These are as follows: Average cost of coal produced from affiliated mines, measured by cents per million BTU (cents/MM BTU) for the current year - weighted at 75%; 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 Affiliated Mine Costs The cost of coal produced as measured by cents/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 Schedules Affiliated Mine Costs cents/MM BTU Performance Factor* 153 or lower 1.50 158 1.25 163 1.00 Higher than 163 0
*Interpolate at intermediate performance. Example: If the average cost of coal produced were 160 cents/MM BTU, the performance factor would be 1.15, which equals the sum of (i) 1 and (ii) .25 times [(163 minus 160) divided by (163 minus 158)] 9.2 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 Schedules 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 .40, which equals the sum of (i) .25 and (ii) .25 times [(95% minus 92%) divided by (95% minus 90%)]. 9.3 Vice President - Fuel Procurement and Transportation Measures In addition to the Corporate performance measures weighted 25% and the overall Fuel Supply performance measures which is weighted 25%, the Vice President - Fuel Procurement and Transportation has two Department performance measures which are weighted to determine a single Department performance weighting of 50%. These are as follows: Cost of coal purchased against the GDP Price Index (fixed weight), a national index which measures inflation of price for the current year - weighted 75%; and Safety at River Transportation and Cook Coal Terminal measured by percent improvement in incidence rate for the current year over the prior three year average incidence rate - weighted 25%. Tables showing the performance factors and how they relate to achievement are on page A-3 of the Addendum. 9.4 General Mine Managers/General Superintendents Measures In addition to the Corporate performance measures weighted 25% and the overall Fuel Supply performance measure weighted 25%, the Fuel Supply General Mine Managers and General Superintendents have two Division/Mine performance measures which are weighted to determine a single Division/Mine performance weighting of 50% for the mines for which they are responsible. These are as follows: General Mine Managers - Cost of coal produced measured in the current year by cents per million BTU (cents/MM BTU) - weighted at 75%; General Superintendents - Production cost of coal produced measured in the current year by cents per million BTU (cents/MM BTU) - 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-4 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. 9.5 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 mils per ton mile (mils/ton mile-$0.00x) for the current year, excluding cost for fuel - weighted 75%; and Safety performance measured by the percent improvement in incidence rate for the current year over the prior three year average incidence rate for River Transportation - weighted 25%. Tables showing the performance factors and how they relate to achievement are on page A-7 of the Addendum. 9.6 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 cents/ton - weighted 75%; and Safety performance measured by the percent improvement in incidence rate for the current year over the prior three- year average incidence rate for Cook Coal Terminal - weighted 25%. Tables showing the performance factors and how they relate to achievement are on page A-7. 9.7 Director - Coal Procurement Measures The Director - Coal Procurement has, in addition to the overall Corporate performance measures weighted 25% and the overall Fuel Supply performance measure weighted 25%, two Department performance measures which are weighted to determine a single Department performance weighting of 50% for Coal Procurement. These are: Delivered fuel prices (spot/contract) composited change as a percent of the GDP price index (fixed weight) - 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 25%. Tables showing the performance factors and how they relate to achievement are on page A-8. 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 $70,000 has a target award of 20%, or $14,000. This individual's target award is allocated among the following performance criteria: AEP Corporate Performance: 25%, or $3,500 Operating Company Performance: 25%, or $3,500 Division Performance: 50%, or $7,000 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 = 1.40 (7th) Average 1.20 x 25% = .30 TIR S&P ranking = .80 x 25% = .20 (12th) Realization AEP ratio (.80) = 1.25 x 50% = .625 Ratio Corporate Performance Factor = 1.125 The AEP Corporate award, then, is 1.125 x $3,500, or $3,937.50.
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: Achievement of Result = 105% = 1.25 x 25% = .3125 Annual Marketing Objectives Safety Performance Result = 22.5% = .75 x 25% = .1875 O&M Expense Result = 93% = 1.00 x 25% = .2500 Performance vs. Budget Customer Service Result = 97% = 1.10 x 25% = .2750 Reliability Index Operating Company Performance Factor = 1.025 The Operating Company Award, then, is 1.025 x $3,500, or $3,587.50
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. Achievement of Result = 107% = 1.35 x 25% = .3375 Annual Marketing Objectives Safety Result = 22.5% = 1.25 x 25% = .3125 Performance O&M Expense Result = 97% = 1.50 x 25% = .3750 Performance vs. Budget Customer Service Result = 100% = 1.00 x 25% = .2500 Reliability Index Performance Factor = 1.275 The Division award, then, is 1.275 x $7,000, or $8,925.00
11.4 Assuming the earnings per share for the year permitted a 100% payout, the Operating Company Division Manager in our example earned a total award of $16,450.00, as follows: AEP Corporate $ 3,937.50 Operating Company 3,587.50 Division 8,925.00 $16,450.00 Of that amount, 80%, or $13,160.00 is paid during the first part of the following year. The balance, $3,290.00, 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.) However, if earnings per share were $2.60 for the year, the payout would be reduced to 75% of total award (see item 1.2 on page two for an explanation of how MICP awards are affected by earnings per share). The Division Manager in this situation would have a total award of $12,337.50 instead of $16,450.00, i.e., $16,450.00 x .75 = $12,337.50. The total 75% award of $12,337.50 would be paid out as 80% cash and 20% deferred as explained above. 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 12/31/93, and subsequently terminates is entitled to the 80% cash award for Plan year 1993, and if applicable, the value of his 1990 Plan year deferred amount. 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. Deferred awards are payable 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. 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. 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 and/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 deferred amounts that have not met the three calendar year requirement, 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 Compen- sation 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 PAYMENTS/DEFERRED AWARDS When all of the necessary data is available after the end of the Plan year, performance results will be calculated and awards made as soon as practicable. Eighty percent of the award earned will be paid in cash. Twenty percent of any awards made under the MICP will automatically be deferred in AEP stock unit accounts. No company 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 paid 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 paid. 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 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. 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 Vice President - Fuel Procurement and Transportation 17.2 Fuel Supply Target Award Payment Schedules
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 /TABLE *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 Fuel Supply Target Award Payment Schedules
River Transportation and Cook Coal Terminal Safety Percent Improvement Over Performance Factor* Three-Year Average Incidence Rate 30 or better 1.50 22.50 1.25 15.00 1.00 11.25 .75 7.50 .50 3.75 .25 0 or worse 0
*Interpolate at intermediate performance. 17.4 General Mine Managers 17.5 Southern Ohio Coal Company - Meigs Division
Cost of Coal Produced cents/MM BTU Performance Factor* 157 or lower 1.50 162 1.25 167 1.00 Higher than 167 0
*Interpolate at intermediate performance. 17.6 Central Ohio Coal Company
Cost of Coal Produced cents/MM BTU Performance Factor* 156 or lower 1.50 161 1.25 165 1.00 Higher than 165 0
*Interpolate at intermediate performance. 17.7 Windsor Coal Company
Cost of Coal Produced cents/MM BTU Performance Factor* 133 or lower 1.50 138 1.25 143 1.00 Higher than 143 0
*Interpolate at intermediate performance. 17.8 All Coal Mines
Safety - Incidence Rate vs. Coal Industry 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. 17.9 Manager - River Transportation 17.10 River Transportation
Operating Cost Per Ton Mile Mils/Ton Mile ($.00x) Performance Factor* 5.00 or better 1.50 5.20 1.25 5.40 1.00 5.60 .75 5.80 .50 6.00 .25 Higher than 6.20 0
*Interpolate at intermediate performance. 17.11 River Transportation Safety
Percent Improvement Over Three-Year Base Average Percent Improvement Over Three-Year Average Performance Factor* Incidence Rate 30 or better 1.50 22.50 1.25 15.00 1.00 11.25 .75 7.50 .50 3.75 .25 0 or worse 0
*Interpolate at intermediate performance. 17.12 Manager - Cook Coal Terminal 17.13 Cook Coal Terminal
Adjusted Expenses Adjusted Expenses Performance Factor* $6.90 million or better 1.50 $7.10 1.25 $7.30 1.00 $7.50 .75 $7.70 .50 $7.90 .25 $8.10 million or higher 0
*Interpolate at intermediate performance. 17.14 Cook Coal Terminal Safety
Percent Improvement Over Three - Year Average Percent Improvement Over Three-Year Average Performance Factor* Incidence Rate 30 or better 1.50 22.50 1.25 15.00 1.00 11.25 .75 7.50 .50 3.75 .25 0 or worse 0
*Interpolate at intermediate performance. 17.15 Director - Coal Procurement 17.16 Delivered Fuel Prices (Spot/Contract)
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. 17.17 Sum Total of Present Value Benefits/ Special Contract Negotiations
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. /PAGE EX-10 3 AEPCO 10-K EX.10(I)(2) PERF. SHARE INCENTIVE PLAN Exhibit 10(i)(2) American Electric Power System Performance Share Incentive Plan as Amended and Restated through January 1, 1995 Article 1. Establishment and Purpose 1.1 Establishment of the Plan. The Company hereby establishes an incentive compensation plan to be known as the "American Electric Power System Performance Share Incentive Plan" (the "Plan"), as set forth in this document. 1.2 Purposes. The Purposes of the Plan are to provide competitive, longer-term, performance driven, incentive compensation opportunities to Participants, which are directly related to and dependent upon the competitiveness of the longer-term returns realized by the Company's shareholders; and to facilitate ownership of Restricted Stock Units by Participants so as to equate further their long- term financial interests with those of the shareholders. Article 2. Effective Date and Term of Plan The Plan was approved by the Company's shareholders and the Securities and Exchange Commission effective January 1, 1994. While the Board may suspend or terminate the Plan at any time, no such suspension or termination shall adversely affect any outstanding Performance Share Units without the Participant's written consent as specified in Section 12.2. No Performance Share Units shall be granted for Performance Periods commencing after December 31, 2003. Article 3. Definitions Whenever used in the Plan, the following terms shall have the meanings set forth below and, when the meaning is intended, the initial letter of the word is capitalized: (a) "Award Certificate" means a certificate setting forth the terms and provisions applicable to each grant of Performance Share Units, which shall include, but shall not be limited to, the number of Performance Share Units granted to the Participant, the Performance Measure, the levels of Performance Share Unit payment opportunities based on the Performance Measure, the method of determining earned Performance Share Units pursuant to Section 8.1 and the length of the Performance Period. (b) "Board" means the Board of Directors of the Company. (c) "Committee" shall mean the Human Resources Committee of the Board. (d) "Common Stock" shall mean the common stock of the Company. (e) "Company" means American Electric Power Company, Inc., a New York corporation, and any successor thereto. (f) "Director" means an individual who is a member of the Board. (g) "Disability" shall have the definition set forth in the American Electric Power System Retirement Plan. (h) "Equivalent Stock Ownership Target" means a stock ownership target for each Participant established by the Board which is a combination of Common Stock and Common Stock equivalents held by a Participant. (i) "Fair Market Value" means the closing sale price of the Common Stock, as published in The Wall Street Journal report of New York Stock Exchange Composite Transactions on the date in question or, if the Common Stock shall not have been traded on such date or if the New York Stock Exchange is closed on such date, then the first day prior thereto on which the Common Stock was so traded. (j) "Participant" means any full-time, nonunion employee of any Subsidiary, who has been selected to participate in the Plan for a stipulated Performance Period by the Committee. (k) "Performance Measure" means, for a period of at least three years, the financial objective to be applied to the Performance Period in which Performance Share Units held by a Participant for a Performance Period are earned, based on the relative ranking of the Com- pany's TSR compared to the TSR's of the companies comprising the S&P Electric Utility Index. (l) "Performance Period" means the period established by the Committee, during which the number of Performance Share Units earned by Participants shall be determined. (m) "Performance Share Unit" means a measure of participation, expressed as a share of Common Stock, received as a grant under Section 7.1 or as a dividend under Section 7.2. (n) "Restricted Stock Unit" means a measure of value, expressed as a share of Common Stock, allocated to a Participant under Section 8.1. No certificates shall be issued with respect to such Restricted Stock Units, but the Company shall maintain a bookkeeping account in the name of the Participant to which the Restricted Stock Units shall relate. (o) "Retirement" means termination of employment with any Subsidiary other than for cause after attaining age 55 and at least five (5) years of service. (p) "Rule 16b-3" means Rule 16b-3 promulgated under the Securities Exchange Act of 1934, as amended (or any successor provision at the time in effect). (q) "Section 162(m)" means Section 162(m) of the Internal Revenue Code of 1986, as amended and applicable interpretive authority thereunder. (r) "Subsidiary" shall mean any corporation in which the Company owns directly or indirectly through its Subsidiaries, at least fifty percent (50%) of the total combined voting power of all classes of stock, or any other entity (including, but not limited to, partnerships and joint ventures) in which the Company owns at least fifty percent (50%) of the combined equity thereof. (s) "Transition Performance Period" means the one (1) and two (2) year Performance Periods that may be made available on a one-time basis to Participants receiving Performance Share Units at the commencement of the Plan and Participants receiving their first grant of Performance Share Units for a Performance Period at any time during the term of the Plan. (t) "TSR" means total shareholder return and is the compound product of the annual TSR amounts obtained by dividing: (1) the sum of: (i) the annual amount of dividends for each year of the Performance Period, assuming dividend reinvestment, and (ii) the difference between the share price at the end and the beginning of each year of the Performance Period; by (2) the share price at the beginning of each year of the Performance Period. Article 4. Administration 4.1 The Committee. The Plan shall be administered by the Committee consisting of not less than three (3) Directors. Each member of the Committee shall at all times while serving be a "disinterested person" within the meaning of Rule 16b-3 and an "outside director" within the meaning of Section 162(m). 4.2 Authority of the Committee. Subject to the provisions herein and to the approval of the Board, the Committee shall have full power for the following: (a) Selecting Participants to whom Performance Share Units are granted. (b) Determining the size and frequency of grants (which need not be the same for each Participant), except as limited by Article 5. (c) Construing and interpreting the Plan and any agreement or instrument entered into under the Plan. (d) Establishing, amending, rescinding or waiving rules and regulations for the Plan's administration. (e) Amending, modifying, and/or terminating the Plan, subject to the provisions of Article 12 herein. Further, the Committee shall have the full power to make all other determinations which may be necessary or advisable for the administration of the Plan, to the extent consistent with the provisions of the Plan, and subject to the approval of the Board. As permitted by law, the Committee may delegate its authority as identified hereunder; provided, however, that the Committee may not delegate certain of its responsibilities hereunder if such delegation may jeopardize compliance with the "disinterested administration" requirement of Rule 16b-3 and the "outside directors" provision of Section 162(m). 4.3 Decisions Binding. All determinations and decisions made by the Committee pursuant to the provisions of the Plan, and all related orders or resolutions of the Board shall be final, conclusive, and binding on all persons, including the Company, its shareholders, Participants and their estates, and beneficiaries. Article 5. Maximum Awards and Adjustments 5.1 Maximum Amount Available for Awards. The maximum number of Performance Share Units which may be earned during the term of the Plan on an aggregate basis is 1,000,000 and, for one Performance Period, the maximum number of Performance Share Units which may be earned by a Participant is 25,000. Not more than 1,000,000 shares of Common Stock will be available for delivery upon payment for Performance Share Units earned under the Plan. The shares to be delivered under the Plan will be made available from shares reacquired by the Company. The limitations in this Section 5.1 on the maximum amount of Performance Share Units and shares of Common Stock available under the Plan are subject to adjustment as provided in Section 5.2. 5.2 Adjustments. If the Committee determines that the occurrence of any merger, reclassification, consolidation, recapitalization, stock dividend or stock split requires an adjustment in order to preserve the benefits intended under the Plan, then the Committee may, in its discretion, make equitable proportionate adjustments in the maximum number of Performance Share Units which may be earned on an aggregate basis or by a Participant, the maximum number of shares of Common Stock which may be delivered, as specified in Section 5.1, and the number of Restricted Stock Units held by a Participant. Article 6. Eligibility and Participation 6.1 Eligibility. Eligibility for participation in the Plan shall be limited to senior officers of the Company and/or its Subsidiaries who, in the opinion of the Committee, have the capacity for contributing in a substantial measure to the successful performance of the Company. 6.2 Actual Participation. Participation in the Plan shall begin on the first day of each Performance Period. At the beginning of each Performance Period, the Committee will identify which, if any, Participants shall receive a grant of Performance Share Units for that Performance Period. As soon as practicable following selection, a Participant shall receive an Award Certificate. Article 7. Grants of Performance Share Units 7.1 Grant Timing, Frequency and Number. Performance Share Units may be granted to Participants as of the first day of each Performance Period on an annual basis. It is intended that Performance Periods will overlap. However, grants do not necessarily have to be on an annual basis. The number of Performance Share Units to be granted to each Participant shall be determined by the Committee in its sole discretion. 7.2 Dividends. During the Performance Period, Participants will be credited with dividends, equivalent in value to those declared and paid on shares of the Common Stock, on all Performance Share Units granted to them. These dividends will be regarded as having been reinvested in Performance Share Units on the date of the Common Stock dividend payments based on the then Fair Market Value of the Common Stock, thereby increasing the number of Performance Share Units held by a Participant. Participants will be credited with dividend equivalents, equal in value to those declared and paid on shares of Common Stock, on all Restricted Stock Units allocated to the Participants. Dividend equivalents on Restricted Stock Units required to be held pursuant to Section 8.2 or deferred pursuant to Section 8.4 will be regarded as having been reinvested in Restricted Stock Units on the date of the Common Stock dividend payments based on the then Fair Market Value of the Common Stock, thereby increasing the number of Restricted Stock Units held by a Participant. However, once a Participant attains the desired Equivalent Stock Ownership Target, dividend equivalents on Restricted Stock Units held pursuant to Section 8.2 shall be paid to the Participant in cash on the same date Common Stock dividends are paid. 7.3 Performance Periods. Subject to the next sentence, the Committee shall establish Performance Periods in its discretion. Performance Periods shall, in all cases, be at least three (3) years in length, except for the Transition Performance Periods. The first Performance Periods shall be the one (1) and two (2) year Transition Performance Periods ending December 31, 1994 and December 31, 1995, respectively, and the three-year period beginning January 1, 1994 and ending December 31, 1996. Performance Share Units granted as part of the initial grant of Performance Share Units for such Performance Periods shall be deemed to be granted as of the first day of such Performance Periods. Article 8. Determination and Payment 8.1 Determination. The number of Performance Share Units earned by a Participant for a Performance Period shall be determined by multiplying the number of Performance Share Units held by the Participant at the end of the Performance Period by a factor based upon the Performance Measure. No Performance Share Units shall be earned by any Participant if, at the end of the Performance Period, shareholders do not realize a positive TSR under the Performance Measure. In any event, the Committee may, at its discretion, reduce the number of Performance Share Units earned by any Participant for a Performance Period. Earned Performance Share Units shall be converted to Restricted Stock Units if the Participant has not met the Equivalent Stock Ownership Target. A Participant shall receive one Restricted Stock Unit for each earned Performance Share Unit. Once a Participant has attained the Equivalent Stock Ownership Target, earned Performance Share Units shall be paid to the Participant at the end of the Performance Period as provided in Section 8.3 or may be deferred by the Participant as provided in Section 8.4. 8.2 Holding of Restricted Stock Units. Restricted Stock Units required to meet the Equivalent Stock Ownership Target will be held until the Participant terminates employment at which time the Participant shall receive payment for the Restricted Stock Units. 8.3 Payment of Restricted Stock Units and Earned Performance Share Units. The payment of Restricted Stock Units that were required to be held pursuant to Section 8.2 shall be made in cash or shares of Common Stock, or a combination of both, as then elected by the Participant and as approved by the Committee. Any cash payments of Restricted Stock Units shall be calculated on the basis of the average of the Fair Market Value of the Common Stock for the last 20 trading days prior to the date the Participant terminates employment. Payment in Common Stock shall be at the rate of one share of Common Stock for each Restricted Stock Unit. The payment of earned Performance Share Units not required to be converted to Restricted Stock Units pursuant to Section 8.1 shall be made in cash or shares of Common Stock, or a combination of both, as then elected by the Participant and as approved by the Committee. Any cash payment of earned Performance Share Units shall be calculated on the basis of the average of the Fair Market Value of the Common Stock for the last 20 trading days of the Performance Period for which the Performance Share Units were earned. Payment in Common Stock shall be at the rate of one share of Common Stock for each earned Performance Share Unit. 8.4 Deferrals. Once the Participant attains the Equivalent Stock Ownership Target, the Participant may make annual elections to defer the payment of subsequent earned Performance Share Units for at least one year but in no event any later than the Participant's termination of employment. The deferral election must be made at least one year prior to the end of the Performance Period for which the Participant has received an allocation with regard to a Performance Period and each earned Performance Share Unit shall be converted into a Restricted Stock Unit. Payment of the elective deferrals will be made at the end of the deferral period in cash or shares of Common Stock, or a combination of both as then elected by the Participant and as approved by the Committee. Cash payments of Restricted Stock Units shall be calculated on the basis of the average of the Fair Market Value of the Common Stock for the last 20 trading days of the deferral period. Payment in Common Stock shall be at the rate of one share of Common Stock for each Restricted Stock Unit. 8.5 Performance Share Units Granted in 1994. Performance Share Units granted in 1994 for the two Transition Performance Periods ending December 31, 1994 and December 31, 1995 and for the Performance Period ending December 31, 1996 shall be paid 50% in cash and 50% in Common Stock unless the Participant consents to have the Performance Share Units earned for the Transition Performance Period ending December 31, 1995 and the Performance Share Units earned for the Performance Period ending December 31, 1996 paid in accordance with the provisions of Sections 8.1 through 8.4. The payment in cash and Common Stock shall be as provided in the second paragraph of Section 8.3. 8.6 Limitations on Sales of Common Stock. A Participant shall not be permitted to sell the shares of Common Stock distributed to such Participant pursuant to Section 8.5 which are required to meet the Equivalent Stock Ownership Target until the Participant terminates employment with the Subsidiaries. In order to enforce the limitations imposed upon the shares of Common Stock distributed pursuant to Section 8.5, the Committee may (i) direct the delivery of stock certificates to Participants to be withheld until the shares of Common Stock covered by such certificates may be sold by the Participant, (ii) cause a legend or legends to be placed on any such certificates, and/or (iii) issue "stop transfer" instructions as it deems necessary or appropriate. Holders of shares of Common Stock limited as to sale under this Section 8.6 shall have rights as a shareholder with respect to such shares to receive dividends in cash or other property or other distribution or rights in respect of such shares and to vote such shares as the record owner thereof. Article 9. Termination of Employment 9.1 Termination of Employment Due to Death, Disability, Retirement or Involuntary Termination Other Than for Cause. In the event of a Participant's termination of employment with the Subsidiaries, prior to the end of a Performance Period but after the first six months of such Performance Period, by reason of the Participant's death, Disability, Retirement or involuntary termination other than for cause, the Participant will be eligible to earn prorated Performance Share Units for each such Performance Period which has not yet ended, determined pursuant to Section 8.1 for such period and the number of days of participation during such Performance Period. In the case of the Transition Performance Periods, the Performance Share Units earned would not be subject to proration if the employment period and termination conditions specified in this Section 9.1 were met. 9.2 Termination for Reasons Other Than Death, Disability, Retirement or Involuntary Termination Other Than for Cause. In the event a Participant's employment is terminated for reasons other than death, Disability, Retirement or involuntary termination other than for cause, all rights to any unearned Performance Share Units under the Plan shall be forfeited. Article 10. Beneficiary Designation 10.1 Designation of Beneficiary. Each Participant shall be entitled to designate a beneficiary or beneficiaries who, following the Participant's death, will be entitled to receive any amounts that otherwise would have been paid to the Participant under the Plan. All designations shall be signed by the Participant, and shall be in such form as prescribed by the Committee. Each designation shall be effective as of the date delivered to the Company by the Participant. The Participant may change his or her designation of beneficiary on such form as prescribed by the Committee. The payment of any amounts owing to a Participant pursuant to such Participant's outstanding Performance Share Units or Restricted Stock Units held under the Plan shall be in accordance with the last unrevoked written designation of beneficiary that has been signed by the Participant and delivered by the Participant to the Company prior to the Participant's death. 10.2 Death of Beneficiary. In the event that all of the beneficiaries named by a Participant pursuant to Section 10.1 herein predecease the Participant, any amounts that would have been paid to the Participant or the Participant's beneficiaries under the Plan shall be paid to the Participant's estate. Article 11. Rights of Participants 11.1 Employment. Nothing in the Plan shall interfere with or limit in any way the right of the Company or any Subsidiary to terminate any Participant's employment at any time, nor confer upon any Participant any right to continue in the employ of the Company or Subsidiary. 11.2 Participation. No Participant shall at any time have a right to be selected for participation in the Plan for any Performance Period, despite having been selected for participation in a previous Performance Period. 11.3 Nontransferability. No Performance Share Units held by a Participant or Restricted Stock Units held pursuant to Sections 8.2 or 8.4 may be sold, transferred, pledged, assigned, or otherwise alienated or hypothecated, other than by will or by the laws of descent and distribution. 11.4 Rights to Common Stock. Performance Share Units or Restricted Stock Units do not give a Participant any rights whatsoever with respect to shares of Common Stock until such time and to such extent that payment of earned Performance Share Units or Restricted Stock Units is made in shares of Common Stock as requested by the Participant. Article 12. Amendment, Modification and Termination 12.1 Amendment, Modification and Termination. The Committee may amend or modify the Plan at any time, with the approval of the Board. However, without the approval of the shareholders of the Company, no such amendment or modification may: (a) Materially modify the eligibility requirements of the Plan. (b) Materially increase the benefits accruing to Participants under the Plan. (c) Materially increase the number of Performance Share Units which may be earned on an aggregate basis or by a Participant (except as provided in Section 5.2). (d) Materially increase the maximum number of shares of Common Stock available for payment under the Plan (except as provided in Section 5.2). (e) Modify the Performance Measure and the method of determining Performance Share Units earned pursuant to Section 8.1, except as may be permitted by Section 162(m). 12.2 Performance Share Units Previously Granted. No termination, amendment or modification of the Plan shall in any manner adversely affect any outstanding Performance Share Units or Restricted Stock Units under the Plan, without the written consent of the Participant holding such Performance Share Units or Restricted Stock Units. Article 13. Miscellaneous Provisions 13.1 Costs of the Plan. The costs of the Plan awards shall be paid directly by the Subsidiary that pays each Participant's base salary during the Performance Period. Although not prohibited from doing so, the Subsidiary is not required in any way to segregate assets in any manner or to specifically fund the benefits provided under the Plan. 13.2 Relationship to Other Benefits. No payment under the Plan shall be taken into account in determining any benefits under any pension, retirement, group insurance, or other benefit plan of the Company and/or its Subsidiaries. 13.3 Governing Law. To the extent not preempted by Federal law, the Plan, and all agreements hereunder, shall be construed in accordance with and governed by the laws of the State of New York. Article 14. Rule 16b-3 Compliance The Company intends that the Plan meet the requirements of Rule 16b-3. In all cases, the terms, provisions, conditions and limitations of the Plan shall be construed and interpreted consistent with the Company's intent as stated in this Article 14. In the event the Plan does not include a provision required by Rule 16b-3 to be stated therein, such provision shall be deemed to be incorporated by reference into the Plan as it relates to eligible Participants subject to Section 16 of the Securities Exchange Act of 1934, with such incorporation to be deemed effective as of the effective date of such Rule 16b-3 provision. EX-13 4 AEPCO 10-K EX. 13 1994 ANNUAL REPORT AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES SELECTED CONSOLIDATED FINANCIAL DATA
Year Ended December 31, 1994 1993 1992 1991 1990 INCOME STATEMENTS DATA (in millions): Operating Revenues $5,505 $5,269 $5,045 $5,047 $5,178 Operating Income 932 928 883 918 861 Net Income 500 354 468 498 496 December 31, 1994 1993 1992 1991 1990 BALANCE SHEETS DATA (in millions): Electric Utility Plant $18,175 $17,712 $17,509 $17,148 $16,652 Accumulated Depreciation and Amortization 6,827 6,612 6,281 5,952 5,588 Net Electric Utility Plant $11,348 $11,100 $11,228 $11,196 $11,064 Total Assets $15,713 $15,341 $14,277 $13,886 $13,596 Common Shareholders' Equity 4,230 4,152 4,246 4,222 4,167 Cumulative Preferred Stocks of Subsidiaries: Not Subject to Mandatory Redemption 233 268 535 535 535 Subject to Mandatory Redemption* 590 501 234 141 145 Long-term Debt* 4,980 4,995 5,311 5,029 4,927 Obligations Under Capital Leases* 400 284 300 273 290 *Including portion due within one year Year Ended December 31, 1994 1993 1992 1991 1990 COMMON STOCK DATA: Earnings per Share $2.71 $1.92 $2.54 $2.70 $2.65 Average Number of Shares Outstanding (in thousands) 184,666 184,535 184,535 184,535 187,064 Market Price Range: High $37-3/8 $40-3/8 $35-1/4 $34-1/4 $33-1/8 Low 27-1/4 32 30-3/8 26-5/8 26 Year-end Market Price 32-7/8 37-1/8 33-1/8 34-1/4 28 Cash Dividends Paid $2.40 $2.40 $2.40 $2.40 $2.40 Dividend Payout Ratio 88.6% 125.2% 94.6% 88.9% 90.3% Book Value per Share $22.83 $22.50 $23.01 $22.88 $22.58
Management's Discussion and Analysis of Results of Operations and Financial Condition Earnings Increase Earnings for 1994 were $500 million or $2.71 per share, up 41.3% 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 resulting from a disallowance by the Public Utilities Commission of Ohio (PUCO) of a portion of the Company's Zimmer Plant investment. Exclusive of the disallowance, 1993 earnings and earnings per share would have been $498 million and $2.70, respectively, and 1994 earnings would have increased slightly as the effect of rate increases in several jurisdictions was offset by the related amortization of Zimmer Plant deferrals and increased operating expenses due mainly to significant storm damage and increased fuel expenses. In 1993 earnings declined 24.4% from $468 million or $2.54 per share in 1992 reflecting the adverse impact in 1993 of the Zimmer disallowance. Without the Zimmer disallowance, earnings in 1993 would have increased 6.4% due predominantly to improved sales reflecting a return to normal weather, continued improvement in industrial sales, rate increases in several jurisdictions and decreased interest expense and preferred stock dividends due to refinancings. _________________________________________________________________________ [The following data was presented in graphical form in the printed report.] 1990 1991 1992 1993 1994 Earnings per share $2.65 $2.70 $2.54 $1.92* $2.71 * Without the Zimmer disallowance 1993 would be $2.70 _________________________________________________________________________ Revenues Increase Operating revenues increased more than 4% in 1994 and 1993 reflecting the effects of rate increases, growth in the number of customers and the weather. The change in revenues can be analyzed as follows: Increase (Decrease) From Previous Year (Dollars in Millions) 1994 1993 Amount % Amount % Retail: Price Variance $ 90.7 $ 53.1 Volume Variance 53.8 173.4 Fuel Cost Recoveries 40.5 (49.7) 185.0 4.1 176.8 4.1 Wholesale: Price Variance 68.6 (3.4) Volume Variance (49.7) 59.1 Fuel Cost Recoveries 8.1 (15.9) 27.0 3.9 39.8 6.1 Other Operating Revenues 23.8 7.5 Total $235.8 4.5 $224.1 4.4 The increase in 1994 operating revenues was 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. The increase in retail energy sales of 2% 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 as mild weather during most of the year offset the effect of the severe weather in January and the unseasonably hot weather in June. Although wholesale energy sales declined by 7% in 1994, wholesale revenues increased 4% 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 an increase in 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 due to mild weather throughout most of 1994. While severe winter weather in January 1994 and extremely hot June weather increased short-term wholesale sales, the mild weather throughout the remainder of 1994, combined with increased competition in the wholesale market, reduced short-term sales for the year. Fuel cost recoveries increased in both the retail and wholesale jurisdictions in 1994 with the retail jurisdiction increase reflecting the effect of the operation of the fuel clause mechanism in Indiana and the wholesale jurisdiction increase resulting from increased fuel costs. The increase in 1993 operating revenues was also primarily due to increased revenues from retail customers reflecting a significant increase in retail energy sales and retail rate increases offset in part by a reduction in fuel cost recoveries. In 1993 energy sales rose 5% with retail energy sales increasing 4% and wholesale sales rising 9%. The increase in retail energy sales in 1993 was due to a return to normal weather, improved industrial sales and growth in the number of retail customers. The 9% upturn in wholesale sales in 1993 was mainly the result of an increase in short-term sales due to decreased availability of unaffiliated generating units combined with increased demand resulting from hot summer weather in 1993. The decline in fuel cost recoveries in 1993 reflects the effects of decreases in fuel costs. Efforts to improve short-term wholesale sales are affected by the highly 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 the extent applicable. Also, since the Company's residential and commercial sales are weather- sensitive, future results of operations will depend on the weather. _________________________________________________________________________ [The following data was presented in graphical form in the printed report.] 1990 1991 1992 1993 1994 (in billions of kilowatthours) Sales of Energy: Residential 25 27 27 29 29 Commercial 19 20 20 21 21 Industrial 39 40 41 42 44 Wholesale & All Other 37 26 23 25 23 Total Energy Use 120 113 111 117 117 _________________________________________________________________________ Operating Expenses Increase Operating expenses increased 5% in 1994 and 4% in 1993. Changes in the components of operating expenses are shown in the table. Increase (Decrease) From Previous Year (Dollars in Millions) 1994 1993 Amount % Amount % Fuel and Purchased Power $ 97.7 5.9 $ 0.4 0.0 Other Operation 31.9 3.3 57.2 6.3 Maintenance 21.2 4.1 32.6 6.7 Depreciation and Amortization 41.5 7.8 24.4 4.8 Taxes Other Than Federal Income Taxes 25.9 5.5 26.4 5.9 Federal Income Taxes 13.8 6.8 37.2 22.4 Total $232.0 5.3 $178.2 4.3 The increased fuel and purchased power expense in 1994 was mainly the result of increased utilization of coal-fired generation as low-cost nuclear generation was reduced due to scheduled refueling and maintenance outages at both of the Company's nuclear generating units. Also contributing to the increase was increased purchases of energy from unaffiliated utilities for pass-through sales to other unaffiliated utilities. 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. The increase in other operation expense in 1993 was due to severance costs in connection with a reorganization of the Company's Ohio operations and a change in accounting method for postretirement benefits other than pensions due to the adoption of a new accounting standard. Significant storm damage caused by snow and ice storms during the first three months of 1994 increased maintenance expense. Storm damage expenditures totaled $46 million of which $23.9 million was deferred as a regulatory asset. The increase in maintenance expense in 1993 was due to an increase in scheduled power plant maintenance, unusual storm damage and the amortization of previously deferred incremental cost of nuclear maintenance expenditures incurred during refueling outages in 1992. With regulator approval the incremental cost of certain nuclear maintenance procedures, which are performed only when the nuclear unit is out of service for refueling, are levelized (deferred and amortized) over the period starting with the beginning of the outage and ending with the beginning of the next outage so that the cost of an average number of refuelings are reflected in each year's expenses. This procedure is necessary to levelize rates because the refueling outages occur approximately every 18 months. 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 amortization of such costs as they were recovered in rates. Depreciation and amortization expense increased in 1993 predominantly as a result of property additions including the Zimmer Plant. Although Zimmer went into service in 1991, regulator-approved deferrals of depreciation expense were recorded through May of 1992, when rate recovery commenced. Taxes other than federal income tax expense rose in 1994 mainly due to an increase in the generation-based West Virginia business and occupation tax reflecting an increase in generation at West Virginia power plants and an increase in the revenue-based gross receipts tax of several states reflecting the increase in revenues in 1994. In 1993 taxes other than federal income taxes rose reflecting increased taxable income and property tax assessments and the effect of regulator-approved deferral of Zimmer Plant property taxes in 1992. The increase in federal income tax expense attributable to operations in 1994 and 1993 was primarily due to an increase in pre-tax operating income. Deferred Carrying Charges and Nonoperating Income The decrease in deferred Zimmer Plant carrying charges in 1994 resulted from the cessation of deferrals commensurate with inclusion of the full plant investment in rate base effective February 1, 1994. The amortization of the deferrals is included in depreciation and amortization expense. Zimmer Plant carrying charges decreased in 1993 as the plant investment was phased into rate base commensurate with recovery from ratepayers under a PUCO-ordered rate phase-in plan. From the in-service date of March 1991 until phase-in rate relief was granted in May 1992, deferred carrying charges of $56 million were recorded on the full Zimmer Plant investment. Under the phase-in plan and subsequent to May 1992, a deferred return was recorded only on the portion of the allowed plant investment not yet reflected in rates. Recovery of the pre-rate relief deferral will be sought in the next PUCO base rate proceeding. The decrease in other nonoperating income in 1994 was mainly due to recording 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 received from the Internal Revenue Service (IRS) in connection with the settlement of audits of prior years' tax returns. From 1992 to 1993 other nonoperating income declined significantly mainly because of the effect of interest income recorded in 1992 on tax refunds received from the IRS in connection with the settlement of audits of prior years' tax returns and on receivables from customers for the collection of prior years' fuel costs resulting from the favorable resolution of litigation. _________________________________________________________________________ [The following data was presented in graphical form in the printed report.] 1990 1991 1992 1993 1994 (In Millions) Net Interest Charges $401 $431 $448 $418 $389 Preferred Dividend Requirements $53 $54 $59 $59 $55 _________________________________________________________________________ _________________________________________________________________________ [The following data was presented in graphical form in the printed report.] 1990 1991 1992 1993 1994 (In Percent) Dividend Payout Ratio 90.3% 88.9% 94.6% 125.2%* 88.6% Common Equity Ratio 42.6% 42.5% 41.1% 41.9% 42.2% * Without Zimmer disallowance 1993 would be 88.9% _________________________________________________________________________ Interest and Preferred Stock Dividends Decrease Refinancing programs of several subsidiaries during 1993 and the early part of 1994 reduced the average interest rate on outstanding long-term debt as well as the levels of long-term debt causing the decline in interest expense in 1994 and 1993. Over the past two years management refinanced and retired $2 billion of relatively high interest rate long-term debt to take advantage of low interest rates. Also management took advantage of the low market rates to refinance preferred stock at reduced dividend rates. Common Dividend and Payout Ratio Remain Constant The Company paid a quarterly dividend in 1994 of 60 cents a share maintaining the annual dividend rate at $2.40 per share. The payout ratio was 89% in both 1994 and 1993 before the Zimmer disallowance, down from 95% in 1992. The payout ratio is considered an indicator of a company's ability to increase or maintain its dividend in the future. It has become an important consideration for the electric utility industry as it faces the possibility of competition. Some electric utility companies have reduced the payout ratio by cutting their dividend in order to retain more earnings and be better equipped to meet competitive challenges. Management's objective is to reduce the payout ratio to a level between 75% and 80% by improving earnings. Construction Spending Construction expenditures have been declining in recent years. Management estimates cumulative construction expenditures for the next three years to be $2 billion including expenditures necessary to meet the requirements of the Clean Air Act Amendments of 1990. Approximately 86% of the construction expenditures for the next three years will be financed internally. These estimated construction expenditures do not include any major new plant construction. 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 1994 short-term borrowings increased by $38 million. At December 31, 1994, American Electric Power and its subsidiaries had outstanding unused short-term lines of credit of $558 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 700,000 shares of common stock in 1994 through a Dividend Reinvestment Program raising $22 million. As a result of the common stock issuance in 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, 1994 the ratio increased to 42.2% from 41.9% at year end 1993 and has improved from 41.1% in 1992. Management expects that small amounts of common stock will similarly be issued to meet a portion of the construction budget and to maintain or enhance common equity ratios over the next three years. At December 31, 1994 the subsidiaries have outstanding $4.98 billion of long-term debt and $823 million of preferred stock. The subsidiaries have regulatory approval to issue up to $714 million of long-term debt and $85 million of preferred stock. Management expects to use the proceeds of future long-term financings to retire short-term debt, refinance higher cost and maturing long-term debt, refund cumulative preferred stock and fund construction expenditures. Unless the subsidiaries meet certain earnings or coverage tests, they cannot issue additional long-term debt or preferred stock. In order to issue certain long-term debt (without refunding existing debt), each subsidiary must have pre-tax earnings equal to at least two times the annual interest charges on long-term debt 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. _________________________________________________________________ PRINCIPAL OPERATING SUBSIDIARIES DEBT & PREFERRED STOCK COVERAGE Long-term Preferred December 31, 1994 Debt Stock Appalachian Power Co. 3.10 1.65 Columbus Southern Power Co. 3.64 N/A Indiana Michigan Power Co. 5.08 2.74 Kentucky Power Co. 2.60 N/A Ohio Power Co. 4.55 2.58 N/A = Not applicable; no preferred stock restrictions _________________________________________________________________ Business Conditions Competition in Our Core Business All public electric utilities are confined with regard to retail service to providing electric generation, transmission and distribution services in a designated service territory. In exchange for this exclusive right to provide such services at a cost-based regulated price which provides the opportunity to earn a regulator-determined reasonable rate of return on shareholders' equity, electric utilities are obligated to serve all customers in their service territories. Although public electric utilities including AEP are regulated monopolies, we have historically competed with self- generation and with distributors of alternative sources of energy, such as natural gas, fuel oil and coal, within our service areas. In recent years regulated electric utilities have also competed with independent power producers for the right to build and operate new generating plant. The primary competitive factors have been price, reliability of service and the ability of customers to utilize sources of energy other than electric power. AEP has maintained a favorable competitive position on the basis of all of these factors. This is evidenced by the lack of independent power producers and significant self generation in our service territories. With respect to alternative energy sources, AEP believes that the convenience and versatility of electricity and reliability of our service coupled with the limited ability of customers to substitute other energy sources for electric power have placed us in a favorable competitive position. However, we continue to work to improve the competitiveness, effectiveness and reliability of our core product, electricity. AEP, for example, markets high-efficiency heat pumps and off-peak storage water heaters which make electricity competitive with natural gas for space and water heating. Competition in the wholesale market, that is, the sale of bulk power to other public and municipal utilities, is not new and has been increasing for a number of years. This is particularly true in the short-term wholesale market. The National Energy Policy Act of 1992 (the Energy Act) facilitated competition in the short and long-term wholesale market since, among other things, it authorized the Federal Energy Regulatory Commission (FERC) to order transmission access for wholesale transactions. The principal factors in competing for wholesale sales are price, including fuel costs, availability of capacity, transmission capability and cost, and reliability of service. Management believes that over the years AEP has generally maintained a favorable competitive position in these factors. However, due to the recent availability of additional capacity of other utilities and reduced fuel prices, price competition, especially in the short-term wholesale market, has been, and is expected to be, important in the future. AEP intends to continue competing for wholesale sales when it will enhance shareholder value. With the passage of the Energy Act, the potential for retail wheeling, i.e., competition for retail sales, is getting considerable attention. While the Energy Act gave the FERC broad authority to mandate transmission access in the wholesale market, it prohibits the FERC from ordering retail wheeling. A number of state legislatures and state regulatory agencies have begun to study retail wheeling with encouragement from major industrial customers. If it occurs, increased competition may require the resolution of some complex issues, such as stranded investment and the obligation to serve. When a customer leaves a utility system, there is an issue of who pays for plant investment, regulatory assets and commitments that are no longer needed. If a customer leaves its native electric supplier and later decides to return, the issue of whether the original local utility has an obligation to serve the returning customer must also be addressed. If not recovered directly from customers that choose another supplier and/or from the remaining regulated customers, the AEP System, like all electric utilities, will be required to address stranded investment losses that could result from any future loss of customers or reduced pricing from head-to-head competition. Management intends to seek recovery of any stranded investment, including regulatory assets, as an appropriate recovery of previously approved cost of service. Although management believes that it has a favorable competitive position due to AEP's relatively low cost of generation, it will be essential for management to better understand the nature of AEP's costs in order to develop new, innovative and competitive pricing structures and to manage profit margins especially if competition were to expand. It will be important to develop improved costing tools in order to maintain our position as a low-cost supplier. AEP is turning to activity-based budgeting and cost management techniques to enable management to cost logical work activities and services. By examining our operations by logical work units, the cost of all major activities can be better controlled, identified and evaluated to properly price our products and to eliminate unnecessary activities and their cost. The development of tools and training to enable management to better manage the costs of operations is only one of the options AEP is currently pursuing. In 1994 AEP's management team has been: - Reviewing and streamlining operations and staffing, - Reducing layers of supervision, - Expanding customer relations and service activities, - Expanding its ability to help customers adopt new electro-technologies to reduce their usage of electricity, - Expanding strategic planning and management training activities, and - Exploring participation in new and existing international power projects and other non-core but related business opportunities. Management is committed to maintaining and enhancing our core business. Although the AEP System with our relatively low cost of generation is competitive, management is moving in "new directions" to maintain and improve our competitive position. Whether competition expands or not, these efforts will serve to maintain our relatively low rates and improve sales through economic development in our service territory. Non-Core Business Prospects Although AEP has not yet developed any major non-core business, we continue to consider new business opportunities, particularly those which permit the use of our expertise and core competencies. These endeavors are conducted through AEP Energy Services, Inc. (AEPES) and AEP Resources, Inc. which are non-rate-regulated subsidiaries. AEPES offers consulting services both domestically and internationally and contracts with other public utilities, commercial entities and government agencies for the licensing of intellectual property and the delivery of services. Recently AEPES entered into agreements with several major engineering consulting firms to jointly market certain consulting services. AEPES is also engaged in efforts to research, develop and commercialize products that can be made out of the ash by-products of electricity generation from coal in an attempt to reduce disposal costs and improve shareholder value. AEP Resources is pursuing several possible investment projects. Its primary business focus will be international and domestic cogeneration, the independent power market and the privatization of generation and transmission facilities in the international market. Recently an agreement of intent was signed that may result in a joint venture to construct two 1,300 mw coal- fired generating units in China at an estimated cost of $2 billion. These two units, if constructed, would be the largest coal-fired generating units in Asia and would burn low-sulfur coal. It is currently proposed that AEPES will provide the engineering, design, construction management and training for operation of the two 1,300 mw units. It is anticipated that AEP may acquire an interest in the 49% share of equity expected to be available to foreign investors. Non-core investments offer the potential for earning returns which 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 investments in these and other new non-core businesses after management carefully assesses the risks involved vs. potential for enhanced shareholder value. Appropriate non-core business investments are part of AEP's strategic plan for enhancing shareholder value. Affiliated Coal For a number of years Ohio Power Company (OPCo) has been limited in its recovery of the cost of coal produced by its affiliated mines. Under a 1992 stipulation agreement a predetermined price of $1.64 per million Btu's was established for the cost of coal burned at four of OPCo's generating plants (the Gavin, Mitchell, Muskingum River and Cardinal plants), three of which burn affiliated coal from the Meigs, Muskingum and Windsor mines. The stipulation covered the three-year period ending November 30, 1994. Beginning December 1, 1994 an inflation adjusted 15-year predetermined price of $1.575 per million Btu's for coal burned at the Gavin Plant was established by the 1992 stipulation agreement. As discussed below under "Clean Air Act" a Settlement Agreement sets an overall predetermined electric fuel component rate 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 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, management believes that OPCo should be able to recover, under the terms of the 1992 stipulation agreement in conjunction with the Settlement Agreement, the Ohio jurisdictional portion of the cost of the affiliated mining operations including mine closure costs. As discussed below, compliance with the January 1, 2000 Phase II deadline of the Clean Air Act Amendments of 1990 may cause the affiliated Muskingum and Windsor mines to close. Shutdown costs for the Muskingum and Windsor mines include investments in the mines, leased asset buy-outs, reclamation costs and employee benefits and are estimated to be $150 million after tax (the non-Ohio jurisdiction portion is estimated to be $85 million after tax) at December 31, 1994. Management intends to seek from ratepayers adequate and timely recovery of the non-Ohio jurisdictional portion of the investment in and the liabilities and closing costs of the Muskingum and Windsor mining operations as well as for the Meigs mining operations. In the event those costs and/or the cost of such affiliated coal production in the interim cannot be recovered, results of operations would be adversely affected. Nuclear Cost The cost to operate and maintain the two-unit Cook Nuclear Plant is impacted by Nuclear Regulatory Commission (NRC) requirements and the normal aging of the plant (Unit 1 began commercial operation in 1975 and Unit 2 in 1978). In addition, the cost to decommission the plant is affected by NRC regulations and the Department of Energy's Spent Nuclear Fuel (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. By law I&M participates in the Department of Energy's SNF disposal program which is described in Note 4 of the Notes to Consolidated Financial Statements. Decommissioning costs and spent nuclear fuel disposal costs are being recovered from ratepayers. In 1993 the Indiana and the Michigan commissions approved higher levels of recovery so that the amount currently being recovered is at least at the lower end of the range in the prior decommissioning study. To date AEP has recovered and accrued $212 million in decommissioning cost. Management intends to seek recovery through the rate-making process of the last increase and any future increases in decommissioning costs over the remaining plant life. Nuclear operations are continually reviewed for ways to lessen the growth in operation, maintenance and decommissioning costs. In 1994 Cook Nuclear Plant achieved a superior rating from the Institute of Nuclear Power Operations, a nuclear industry oversight group, and received improved NRC performance ratings. Additionally, costs related to nuclear refueling outages at the Cook Nuclear Plant have been reduced by approximately $20 million in the last two years. In 1994 the Financial Accounting Standards Board (FASB) added Accounting for Nuclear Decommissioning Liabilities to its agenda. Among the topics to be studied by the FASB is the question of when future decommissioning liabilities should be recognized. The Company and the electric utility industry accrue such costs over the service life of their nuclear facilities as recovered in rates. A new requirement from the FASB could cause the annual provisions for decommissioning to increase should the estimate of the remaining unaccrued decommissioning costs be greater than the regulators' allowed recovery level. Management believes that the industry's life of the plant accrual accounting method is appropriate and should be accepted by the FASB. Until the FASB completes its study and reaches a conclusion, the impact, if any, on results of operations and financial condition cannot be determined. 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 Systemwide least-cost compliance plan was developed reflecting various methods of compliance. The cornerstone of the compliance strategy is the installation of flue gas desulfurization systems (scrubbers) on OPCo's 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 continued use of Ohio high-sulfur coal at the Gavin Plant. The scrubbers for Gavin Unit 1 were completed in December 1994 and the Unit 2 scrubbers are expected to be completed in March 1995. The cost of the leased scrubbers is estimated to be $675 million. Capital expenditures for all other AEP System CAAA- related environmental based protection facilities for the next three years are estimated to be $45 million. The PUCO approved the compliance plan for OPCo as a least-cost compliance strategy in November 1992, and under Ohio law the plan is deemed prudent for subsequent PUCO rate proceedings. Under the approved plan, fuel switching would be the compliance method at OPCo's Muskingum River Plant in 1995 and 2000 and at OPCo's Cardinal Plant Unit 1 in 2001 although the PUCO in a subsequent fuel cost recovery proceeding recommended that OPCo consider employing fuel switching as early as 1995 at the Cardinal Plant. The plants are currently supplied by OPCo's wholly-owned, high-sulfur coal-mining subsidiaries which operate the Muskingum and Windsor mines. Consequently, these affiliated mining operations could shut down resulting in substantial costs. Recovery of CAAA capital and operating compliance costs is being sought through the rate-making process. In 1994 OPCo filed with the PUCO for an annual revenue increase of $152.5 million with half of the requested rate increase to recover costs associated with the Gavin Plant's 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. Under the terms of the Settlement Agreement base rates would increase by $66 million annually in March 1995 which includes recovery of the annual cost of the scrubbers; the EFC rate would be fixed at 1.465 cents per kwh from June 1995 through November 1998; OPCo would be provided an opportunity under a 1992 predetermined price agreement for coal burned at the Gavin Plant (which is described above) to recover its Ohio jurisdictional portion of the investment in and the future shutdown costs of all affiliated mines; and OPCo may proceed with its CAAA compliance plan as filed with the PUCO. The Settlement Agreement allows the Company to continue to operate the Muskingum and Windsor mines through the end of Phase I, January 1, 2000. The Settlement Agreement is subject to PUCO approval. Efforts are continuing to obtain timely recovery of the compliance costs in jurisdictions other than OPCo's Ohio jurisdiction, although there can be no assurance that regulators will provide for recovery of all CAAA compliance costs on a timely basis. Compliance with the CAAA, including potential mine closure costs, will have an adverse effect on results of operations and possibly financial condition if not recovered from ratepayers or through asset dispositions. 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 substance disposal sites and authorizes the United States Environmental Protection Agency (Federal EPA) to administer the clean-up programs. AEP companies have been named by the Federal EPA as a "potentially responsible party" (PRP) for 12 sites as of December 31, 1994. Liability has been settled for five of these sites with no significant effect on results of operations. In addition, there are 11 sites for which AEP companies have received information requests or demand letters which could lead to PRP designation. In all 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. As a result, AEP has instituted a number of Systemwide policies that have raised the standard of care by going beyond regulatory requirements where appropriate. 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 unknown reasons significant costs are incurred for cleanup, results of operations and possibly financial condition would be adversely affected unless the costs can be recovered from insurance proceeds and/or, with regulatory approval, from ratepayers. Notice of Violation - Kammer Plant - In August 1994 the Federal EPA issued a Notice of Violation (NOV) to OPCo alleging that the Kammer Plant has been operating in violation of applicable federally enforceable air pollution control requirements since January 1, 1989. By law the Federal EPA may seek penalties of up to $25,000 per day for each day of violation. A Consent Decree was negotiated and filed on November 15, 1994, which resolves that portion of the NOV relating to compliance. The portion of the NOV relating to penalties will be addressed independently. At this time management is unable to estimate the amount of any civil penalties that the Federal EPA may impose. It is not anticipated that the ultimate resolution of this matter will have a material adverse impact on results of operations. Global Climate Change - Concern about global climate change, or "the greenhouse effect," has been the focus of intensive debate within the United States and around the world. Much of the uncertainty about what effects greenhouse gas concentrations will have on the global climate results from a myriad of factors that affect climate. Based on the terms of a 1992 United Nations treaty that pledged the United States to reduce greenhouse gas emissions, the Clinton Administration developed a voluntary plan to reduce greenhouse gas emissions to 1990 levels by the year 2000. As part of this plan, AEP is participating with the U.S. Department of Energy and other electric utility companies in the climate change program to limit future greenhouse gas emissions. AEP's climate challenge program applies a policy of proactive environmental stewardship, whereby actions are taken that make economic and environmental sense on their own merits, irrespective of the uncertain threat of global climate change. The plan includes energy conservation programs, improvements in fossil generation efficiency, increased use of nuclear capacity and forest management activities. However, should it be determined necessary to enact significant new measures to control the burning of coal, their cost, if not recovered from ratepayers could adversely impact results of operations and financial condition. EMF - The potential for electric and magnetic fields (EMF) from transmission and distribution facilities to adversely affect the public health is being extensively researched. AEP continues to support EMF research to help determine the extent, if any, to which EMF may adversely impact public health. Our concern is that new laws imposing EMF limits may be passed or new regulations promulgated without sufficient scientific study and evidence to support them. As long as there is uncertainty about EMF, AEP and other electric utilities will have difficulty finding acceptable sites for their facilities, which could hamper economic growth within AEP's seven-state operating territory. If the present energy delivery system must be changed because of EMF concerns, or if the courts conclude that EMF exposure harms individuals and that utilities are liable for damages, then AEP's results of operations and financial condition could be adversely affected, unless the costs can be recovered from ratepayers. Litigation The Company is involved in a number of legal proceedings and claims. While we are unable to predict the outcome of such litigation, it is not expected that the resolution of these matters will have a material adverse effect on financial condition. Information about these matters can be found in the footnotes to the financial statements. Proposed Revision of the Public Utility Holding Company Act The Public Utility Holding Company Act of 1935 (1935 Act) currently requires that service, sales and construction contracts (other than power sales) between companies in a registered holding company system, such as the AEP 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 their full costs under these provisions. The Securities and Exchange Commission is studying the 1935 Act to determine whether the rules to administer it should be updated or the 1935 Act should be amended or repealed. Proposals being considered to modernize the 1935 Act could eliminate the assurance that affiliated companies will recover their full cost of providing intra-system services. These proposals may price such transactions at a market-based price if it is lower than cost or generally eliminate the application of the 1935 Act to such transactions. The effect of the adoption of these proposals on AEP 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. The 1935 Act was premised upon the fact that utilities were vertically integrated and operated as monopolies in an assigned territory. With passage of the Energy Act and the possibility of increased competition in the electric utility industry, it is essential that the Company's ability to compete not be restricted by its status as a registered holding company under the 1935 Act. To be prepared for these possible changes in the nature of the industry, management has concluded that it supports the repeal of the 1935 Act. Effects of Inflation Inflation affects the AEP System's cost of replacing utility plant and the cost of operating and maintaining its plant. The rate-making process limits the Company to recovery of the historical cost of assets resulting in economic losses when the effects of inflation are not recovered from customers on a timely basis. However, economic gains that result from the repayment of long-term debt with inflated dollars partly offset such losses. AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF INCOME (in thousands - except per share amounts)
Year Ended December 31, 1994 1993 1992 OPERATING REVENUES $5,504,670 $5,268,842 $5,044,792 OPERATING EXPENSES: Fuel and Purchased Power 1,745,245 1,647,573 1,647,167 Other Operation 997,235 965,329 908,172 Maintenance 544,312 523,062 490,425 Depreciation and Amortization 572,189 530,731 506,304 Taxes Other Than Federal Income Taxes 496,260 470,346 443,963 Federal Income Taxes 217,209 203,431 166,219 TOTAL OPERATING EXPENSES 4,572,450 4,340,472 4,162,250 OPERATING INCOME 932,220 928,370 882,542 NONOPERATING INCOME: Deferred Zimmer Plant Carrying Charges (net of tax) 5,604 25,343 41,901 Other Nonoperating Income 5,881 21,229 51,163 TOTAL NONOPERATING INCOME 11,485 46,572 93,064 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 943,705 830,409 975,606 INTEREST CHARGES (net) 388,998 417,822 447,955 PREFERRED STOCK DIVIDEND REQUIREMENTS OF SUBSIDIARIES 54,695 58,818 59,348 NET INCOME $ 500,012 $ 353,769 $ 468,303 AVERAGE NUMBER OF SHARES OUTSTANDING 184,666 184,535 184,535 EARNINGS PER SHARE $2.71 $1.92 $2.54 CASH DIVIDENDS PAID PER SHARE $2.40 $2.40 $2.40
____________________________________________ CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Year Ended December 31, (in thousands) 1994 1993 1992 RETAINED EARNINGS JANUARY 1 $1,269,283 $1,358,800 $1,333,855 NET INCOME 500,012 353,769 468,303 DEDUCTIONS: Cash Dividends Declared 443,101 442,891 442,891 Other 613 395 467 RETAINED EARNINGS DECEMBER 31 $1,325,581 $1,269,283 $1,358,800 See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED BALANCE SHEETS
December 31, (in thousands) 1994 1993 ASSETS ELECTRIC UTILITY PLANT: Production $ 9,172,766 $ 9,079,130 Transmission 3,247,280 3,169,347 Distribution 3,966,442 3,743,047 General (including mining assets and nuclear fuel) 1,529,436 1,406,159 Construction Work in Progress 258,700 314,489 Total Electric Utility Plant 18,174,624 17,712,172 Accumulated Depreciation and Amortization 6,826,514 6,612,131 NET ELECTRIC UTILITY PLANT 11,348,110 11,100,041 OTHER PROPERTY AND INVESTMENTS 735,042 724,373 CURRENT ASSETS: Cash and Cash Equivalents 62,866 42,561 Accounts Receivable: Customers (Less Allowance for Uncollectible Accounts of $4,056 in 1994 and $4,048 in 1993) 346,462 373,251 Miscellaneous 86,397 90,514 Fuel - at average cost 306,700 314,441 Materials and Supplies - at average cost 216,741 207,373 Accrued Utility Revenues 167,486 169,905 Prepayments and Other 94,786 98,958 TOTAL CURRENT ASSETS 1,281,438 1,297,003 REGULATORY ASSETS 1,949,852 1,849,055 DEFERRED CHARGES 398,257 370,929 TOTAL $15,712,699 $15,341,401 See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED BALANCE SHEETS
December 31, (in thousands - except share data) 1994 1993 CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock-Par Value $6.50: 1994 1993 Shares Authorized. .300,000,000 300,000,000 Shares Issued. . . .194,234,992 193,534,992 (8,999,992 shares were held in treasury) $ 1,262,527 $ 1,257,977 Paid-in Capital 1,641,522 1,625,068 Retained Earnings 1,325,581 1,269,283 Total Common Shareholders' Equity 4,229,630 4,152,328 Cumulative Preferred Stocks of Subsidiaries:* Not Subject to Mandatory Redemption 233,240 268,240 Subject to Mandatory Redemption 590,300 500,450 Long-term Debt* 4,686,648 4,964,060 TOTAL CAPITALIZATION 9,739,818 9,885,078 OTHER NONCURRENT LIABILITIES 667,722 509,317 CURRENT LIABILITIES: Long-term Debt Due Within One Year* 293,671 31,141 Short-term Debt 316,985 278,976 Accounts Payable 251,186 259,145 Taxes Accrued 382,677 409,198 Interest Accrued 88,916 91,161 Obligations Under Capital Leases 93,252 62,215 Other 407,965 338,988 TOTAL CURRENT LIABILITIES 1,834,652 1,470,824 DEFERRED FEDERAL INCOME TAXES 2,473,539 2,468,015 DEFERRED INVESTMENT TAX CREDITS 456,043 487,501 DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2 415,226 430,091 DEFERRED CREDITS 125,699 90,575 CONTINGENCIES (Note 4) TOTAL $15,712,699 $15,341,401 See Notes to Consolidated Financial Statements. *See accompanying schedules.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31, (in thousands) 1994 1993 1992 OPERATING ACTIVITIES: Net Income $ 500,012 $ 353,769 $ 468,303 Adjustments for Noncash Items: Depreciation and Amortization 561,188 555,436 541,726 Deferred Federal Income Taxes (12,223) (58,376) 103,180 Deferred Investment Tax Credits (31,275) (28,222) (27,796) Deferred Operating Expenses and Carrying Charges (net of amortization) 16,022 2,997 (108,429) Loss from Zimmer Plant Disallowance - 159,067 - Changes in Certain Current Assets and Liabilities: Accounts Receivable (net) 30,906 (16,980) (72,055) Fuel, Materials and Supplies (1,627) 156,464 84,473 Accrued Utility Revenues 2,419 18,994 (48,935) Accounts Payable (7,959) 47,018 (12,550) Taxes Accrued (26,521) 56,502 26,304 Other (net) (53,217) 19,998 (119,234) Net Cash Flows From Operating Activities 977,725 1,266,667 834,987 INVESTING ACTIVITIES: Construction Expenditures (643,457) (592,199) (625,636) Proceeds from Sale of Property and Other 49,802 26,669 97,977 Net Cash Flows Used For Investing Activities (593,655) (565,530) (527,659) FINANCING ACTIVITIES: Issuance of Common Stock 22,256 - - Issuance of Cumulative Preferred Stock 88,787 321,168 98,851 Issuance of Long-term Debt 411,869 1,339,227 1,329,973 Retirement of Cumulative Preferred Stock (35,949) (333,992) (7,153) Retirement of Long-term Debt (445,636) (1,696,806) (1,086,875) Change in Short-term Debt (net) 38,009 25,822 (159,229) Dividends Paid on Common Stock (443,101) (442,891) (442,891) Net Cash Flows Used For Financing Activities (363,765) (787,472) (267,324) Net Increase (Decrease) in Cash and Cash Equivalents 20,305 (86,335) 40,004 Cash and Cash Equivalents January 1 42,561 128,896 88,892 Cash and Cash Equivalents December 31 $ 62,866 $ 42,561 $ 128,896 See Notes to Consolidated Financial Statements.
1. Significant Accounting Policies: Organization - The American Electric Power System (AEP, AEP System or the Company) is comprised 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; 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. American Electric Power Service Corporation (AEPSC) provides management and professional services to the AEP System. The active coal-mining companies are wholly-owned by OPCo and sell 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 1,300 megawatt (mw) generating units. 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 appropriate. 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 do 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 and represent regulator- approved deferred expenses and revenues, respectively, resulting from the rate-making process. 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 6.59%, 5.84% and 6.13% in 1994, 1993 and 1992, respectively, and the amounts of AFUDC accrued were $11 million in 1994 and $9 million in 1993 and 1992. 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 4.3% Hydroelectric-Conventional and Pumped Storage 1.7% to 3.0% Transmission 1.7% to 2.7% Distribution 3.4% to 4.2% General 1.7% 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 57 cents 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 1995, 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, 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. 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 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. The amounts deferred were $49.6 million in 1994, $1.4 million in 1993 and $71.8 million in 1992. Amortization of such deferrals was $30.8 million in 1994, $35.2 million in 1993 and $24.6 million in 1992. 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. 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 and amortized 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 - Investments held in trust funds for decommissioning nuclear facilities and for the disposal of spent nuclear fuel are recorded at market value. Adjustments for unrealized gains and losses to the carrying value of trust fund investments are not reflected in equity due to the rate-making process. 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: Rate Activity - On June 27, 1994 the Virginia State Corporation Commission (VA SCC) issued a final order granting APCo an increase in annual revenues of $17.9 million out of the requested amount of $31.4 million which required a revenue refund to customers in August 1994 of $15.8 million. Effective November 15, 1994 APCo implemented a net decrease in rates charged to its Virginia retail customers of $13.2 million, subject to final approval by the VA SCC. The net decrease reflects reduced fuel costs offset, in part, by amortization over three years of $23.9 million of the deferred cost of extensive repairs to facilities damaged by severe winter storms in 1994. An application was filed by OPCo on July 6, 1994 with the Public Utilities Commission of Ohio (PUCO) seeking a $152.5 million 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. Under the terms of the Settlement Agreement, base rates would increase by $66 million annually in March 1995 which includes recovery of the cost of the scrubbers; the EFC rate would be 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 the investment in and the liabilities and the future shut-down 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 (CAAA) compliance plan as filed with the PUCO. The Settlement Agreement allows the Company to continue to operate the Muskingum and Windsor mines. The Settlement Agreement is subject to PUCO approval. Recovery of Fuel Costs - 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 Btu's with quarterly escalation adjustments. As discussed above the Settlement Agreement fixes the EFC factor to 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 predetermined Gavin Plant 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. As discussed in Note 4 under "Clean Air Act" 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. Management believes that costs of compliance with the CAAA should be recovered from ratepayers and intends to seek adequate and timely recovery of the non-Ohio jurisdictional portion of the investment in and the liabilities and closing costs of the Muskingum and Windsor mining operations as well as for the Meigs mining operation. Unless those costs and/or the cost of affiliated coal production can be recovered from customers through regulated rates, results of operations would be adversely affected. Unaffiliated Coal and Affiliated Transportation Cost - In October 1993, the FERC denied a request by an I&M wholesale customer seeking rehearing of a February 1993 order. The order concerned the reasonableness of coal costs from an unaffiliated supplier who leases a Utah mining operation from I&M and affiliated coal transportation charges. The February order reversed an administrative law judge's decision and dismissed the complaint. The wholesale customer appealed the October order to the U.S. Court of Appeals. It is not anticipated that the ultimate resolution of this matter will have a material adverse impact on results of operations. 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. These regulatory assets and liabilities are comprised of the following: December 31, (In Thousands) 1994 1993 Regulatory Assets: Amounts Due From Customers For Future Federal Income Taxes $1,381,549 $1,363,802 Rate Phase-in Plan Deferrals 118,553 152,711 Unamortized Loss on Reacquired Debt 101,672 99,910 Other 348,078 232,632 Total Regulatory Assets $1,949,852 $1,849,055 Regulatory Liabilities: Deferred Investment Tax Credits $456,043 $487,501 Other Regulatory Liabilities* 76,468 45,259 Total Regulatory Liabilities $532,511 $532,760 * Included in Deferred Credits on Consolidated Balance Sheets 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 1994 $18.5 million 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. 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. 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 $43.2 million and $58.8 million at December 31, 1994 and 1993, respectively. Amortization was $16 million in 1994, 1993 and 1992. 4. Commitments and Contingencies: Construction and Other Commitments - The AEP System has made substantial construction commitments. Such commitments do not presently include any expenditures for new generating capacity. The aggregate construction program expenditures for 1995-1997 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 1,275 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 1996 to 2010. Clean Air Act - The Clean Air Act Amendments of 1990 (CAAA) requires significant reductions in sulfur dioxide and nitrogen oxide emissions from various AEP System generating plants. The first phase of reductions in sulfur dioxide emissions (Phase I) began in 1995 and the second, more restrictive phase (Phase II) begins in the year 2000. The law also established a permanent nationwide cap on sulfur dioxide emissions after 1999. In 1992 the PUCO approved a systemwide Phase I CAAA compliance plan. The AEP System's compliance plan centers around the compliance method selected for OPCo's two-unit 2,600 mw Gavin Plant which has emitted 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: installing leased flue gas desulfurization equipment (scrubbers) to burn Ohio high-sulfur coal at Gavin; 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; and switching from high-sulfur coal to an alternate fuel at other System units. Fuel switching may result in the shutdown of OPCo's affiliated Muskingum and Windsor coal-mining operations. To meet Phase I compliance, fuel switching is necessary at one of the Muskingum River generating units beginning in 1995. In order to comply with Phase II requirements on a least- cost basis, fuel switching is currently planned at all of the Muskingum River generating units in January 2000 and at the Cardinal generating unit in 2001. As a result of the aforementioned PUCO approval of the Company's least- cost compliance plan, OPCo entered into an agreement in 1992 for construction and lease of the Gavin Plant scrubbers with JMG Funding Partnership, an unaffiliated company. The lease will be accounted for as an operating lease. Management currently expects that the cost of the leased scrubbers will be approximately $675 million. The scrubbers on Gavin Plant Unit 1 commenced operation in December 1994 and the Unit 2 scrubbers are expected to commence operation in March 1995. Capital expenditures for AEP System CAAA-related environmental-based protection facilities for the next three years are estimated to be $45 million which excludes the Gavin scrubbers. Recovery of compliance costs is being sought and will be sought through the rate-making process. As detailed in Note 2 under Rate Activity, OPCo has filed an application with the PUCO seeking recovery of its cost of CAAA compliance and entered into a Settlement Agreement regarding this rate request. This Ohio 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 Muskingum and Windsor mining operations to the extent the actual cost of coal burned at the Gavin Plant is below a predetermined price. The Settlement Agreement requires PUCO approval. AEP intends to also seek timely recovery of all compliance costs, including mine shutdown costs, from its non-Ohio jurisdictional customers. There can be no assurance that regulators will provide for recovery of all CAAA compliance costs on a timely basis. Compliance with the CAAA, including potential mine closure costs, will have an adverse effect on results of operations and possibly financial condition unless the cost can be recovered from ratepayers and/or from asset dispositions. Other Environmental Matters - The AEP System is regulated by federal, state and local authorities with respect to air and water quality and other environmental matters. Local authorities also regulate zoning. The generation of electricity produces non-hazardous and hazardous by-products. Asbestos, polychlorinated biphenyls (PCBs) and other hazardous materials have been used in the generating plants and transmission/distribution facilities. Substantial costs to store and dispose of hazardous materials have been incurred. Significant additional costs could be incurred in the future to meet the requirements of new laws and regulations and to clean up disposal sites under existing legislation. Management has no knowledge of any material clean up costs related to AEP's past disposal of hazardous and non- hazardous materials. 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. Should nuclear losses or liabilities be underinsured or exceed accumulated funds, or should recovery through regulated rates be denied, results of operations and financial condition would be negatively affected. Specific information about nuclear risk management and potential liabilities is discussed below. 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 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 $41.9 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 $154 million for fuel consumed prior to April 7, 1983 have been recorded as long-term debt with an offsetting regulatory asset. The regulatory asset at December 31, 1994 of $8.4 million is being amortized as rate recovery occurs. 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, 1994, funds collected from customers and related earnings including accrued interest totaled $145.6 million. 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. Estimated decommissioning and low level radioactive waste accumulation disposal costs range from $634 million to $988 million in 1993 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 which depends on future developments in the federal government's spent nuclear fuel disposal program. 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 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 which was $26 million in 1994, $13 million in 1993 and $12 million in 1992. Decommissioning amounts recovered from customers are deposited in external trusts. Trust fund earnings increase the fund assets and the recorded liability. Trust fund earnings decrease the amount to be recovered from ratepayers. At December 31, 1994 I&M has recognized a decommissioning liability of $212 million. Kammer Plant - In August 1994 the United States Environmental Protection Agency (Federal EPA) issued a Notice of Violation (NOV) to OPCo alleging that the Kammer Plant has been operating in violation of applicable federally enforceable air pollution control requirements since January 1, 1989. By law, civil penalties of up to $25,000 per day may be imposed for each day of violation. A Consent Decree was negotiated and filed on November 15, 1994 which resolves that portion of the NOV relating to compliance. The portion of the NOV relating to penalties will be addressed independently. At this time management is unable to estimate the amount of any civil penalties that may be imposed by the Federal EPA. It is not anticipated that the ultimate resolution of this matter will have a material adverse impact on results of operations. Litigation - The Company is involved in a number of legal proceedings and claims. While management is unable to predict the outcome of litigation, it is not expected that the resolution of these matters will have a material adverse effect on 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, 1994, $234 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, 1994 and 1993 short-term bank lines of credit were available in the amounts of $558 million and $537 million, respectively. Commitment fees of approximately 3/16 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) 1994 1993 Balance Outstanding: Notes Payable $ 42,535 $ 65,526 Commercial Paper 274,450 213,450 Total $316,985 $278,976 Weighted Average Interest Rate: Notes Payable 6.2% 3.5% Commercial Paper 6.3% 3.7% Total 6.3% 3.6% 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, (In Thousands) 1994 1993 1992 Service Cost-Benefits Earned During the Year $ 40,000 $ 37,100 $ 36,600 Interest Cost on Projected Benefit Obligations 114,500 112,600 110,100 Actual Return on Assets (6,700) (150,000) (97,600) Net Amortization and Deferral (123,300) 24,700 (17,800) Net AEP Pension Plan Costs $ 24,500 $ 24,400 $ 31,300 AEP pension plan assets and actuarially computed benefit obligations are: December 31, (In Thousands) 1994 1993 AEP Pension Plan Assets at Fair Value (a) $1,480,600 $1,560,900 Actuarial Present Value of Benefit Obligations: Vested 1,130,000 1,315,200 Nonvested 120,700 144,700 Accumulated Benefit Obligation 1,250,700 1,459,900 Effects of Salary Progression 132,600 176,600 Projected Benefit Obligation 1,383,300 1,636,500 Funded Status - AEP Pension Plan Assets in Excess of or (Less Than) Projected Benefit Obligation 97,300 (75,600) Unrecognized Prior Service Cost 160,800 174,500 Unrecognized Net Gain (229,000) (35,500) Unrecognized Net Transition Assets (Being Amortized Over 17 Years) (88,600) (98,400) Accrued Net AEP Pension Plan Liability $ (59,500) $ (35,000) (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, 1994 1993 1992 Discount Rate 8.5% 7.0% 8.22% Average Rate of Increase in Compensation Levels 3.2% 3.2% 5.6 % Expected Long-term Rate of Return 8.5% 9.0% 9.25% 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 three 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 $18.6 million in 1994, $17.6 million in 1993 and $17.1 million in 1992. 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, 1994, the UMWA actuary estimates the OPCo coal-mining subsidiaries' share of the UMWA pension plans unfunded vested liabilities was approximately $46 million. In the event the OPCo coal-mining subsidiaries cease or significantly reduce mining operations or contributions to the UMWA pension plans, a withdrawal obligation may be triggered for all or a portion of their share of the unfunded vested liability. Contributions are based on the number of hours worked, are expensed when paid and totaled $1.6 million in both 1994 and 1993 and $2.1 million in 1992. Postretirement Benefits Other Than Pensions - 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. Prior to 1993, net costs of these benefits were recognized as an expense when paid and totaled $12.3 million in 1992. 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. The cost of health care benefits for this group was expensed when paid in 1992 and totaled $16.5 million. SFAS 106, Employers' Accounting for Postretirement Benefits Other Than Pensions, was adopted in January 1993 for the Company's aggregate liability for postretirement benefits other than pensions (OPEB). SFAS 106 requires the accrual of the present value liability for OPEB costs during the employee's service years. Costs for the accumulated postretirement benefits earned and not recognized at adoption are being recognized, in accordance with SFAS 106, as a transition obligation over 20 years. Management has taken several measures to reduce the impact of its postretirement benefits cost. 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, as other property and investments. 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 implementation of SFAS 106 which is comprised of 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 $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 regulator 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, 1994 and 1993, $28.5 million and $19.1 million, respectively, of incremental OPEB costs were deferred. Aggregate OPEB costs were computed as follows: December 31, (In Thousands) 1994 1993 Service Cost $16,500 $15,700 Interest Cost on Projected Benefit Obligation 47,300 45,300 Net Amortization of Transition Obligation 31,100 28,200 Return on Plan Assets 900 (1,000) Net Amortization and Deferral (6,800) - Net OPEB Costs $89,000 $88,200 OPEB assets and actuarially computed benefit obligations are: December 31, (In Thousands) 1994 1993 Fair Market Value of Plan Assets (a) $ 87,200 $ 58,600 Accumulated Postretirement Benefit Obligation: Active Employees Fully Eligible for Benefits 41,200 26,800 Current Retirees 361,500 357,000 Other Active Employees 245,800 278,200 Total Benefit Obligations 648,500 662,000 Unfunded Benefit Obligation (561,300) (603,400) Unrecognized Net Loss 8,900 48,000 Unrecognized Transition Obligation Being Amortized Over 20 Years 517,700 550,100 Accrued OPEB Liability $ (34,700) $ (5,300) (a) Plan assets represent cash surrender value of life insurance contracts on certain employees owned by the trust. Assumptions used to determined OPEB's funded status were: December 31, 1994 1993 1992 Discount Rate 8.5% 7.0% 8.22% Expected Long-Term Rate of Return on Plan Assets 8.25% 8.75% 9.0% Initial Medical Cost Trend Rate 8.0% 8.0% 9.0% Ultimate Medical Cost Trend Rate 5.25% 4.25% 5.25% Medical Cost Trend Rate Decreases to Ultimate Rate in Year 2005 2005 2005 Assuming a one percent increase in the medical cost trend rate, the 1994 OPEB cost for all employees, both non-UMWA and UMWA would increase by $8 million and the accumulated benefit obligations would increase by $71 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 $3.1 million in 1994, $3.8 million in 1993 and $10 million in 1992. 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 $6.9 million in 1994 and $10 million in 1993. The Black Lung Trust had excess funds at December 31, 1994 and 1993 of $16 million and $18 million, respectively. 8. Fair Value of Financial Instruments: Nuclear Trust Funds Recorded at Market Value - Effective January 1, 1994, the Company adopted SFAS 115, Accounting for Certain Investments in Debt and Equity Securities, which requires fair value accounting for investments in equity securities with readily determinable market values and investments in debt securities except those that the reporting enterprise has the positive intent and ability to hold to maturity. Debt securities not classified as held-to-maturity and qualifying equity securities, shall be classified as trading or available-for-sale. The Company's investments held in trust funds for decommissioning nuclear facilities and for the disposal of spent nuclear fuel have been classified as available-for-sale. SFAS 115 requires that unrealized gains and losses on investments classified as available-for-sale be reported as a separate component of shareholders' equity. However, due to the rate-making process, adjustments under SFAS 115 for unrealized gains and losses to the carrying value of investments held in the trusts result in corresponding adjustments to regulatory assets and liabilities. The cumulative effect of adopting SFAS 115 resulted in an increase in the decommissioning and spent nuclear fuel trust fund assets of $20.4 million comprised of an unrealized holding gain of $21.4 million and an unrealized holding loss of $1 million, with no effect on net income and/or shareholders' equity. The trust investments, reported in other property and investments, had a fair value of $321 million at January 1, 1994 and consist primarily of long-term tax-exempt municipal bonds. In accordance with SFAS 115, prior year amounts were not restated. At December 31, 1994 the fair value of the trust investments was $353 million. Accumulated gross unrealized holding gains and losses were $5.5 million and $12.2 million, respectively, at December 31, 1994. The change in market value during 1994 was a $27.1 million net holding loss. The trust investments' cost basis by security type at December 31, 1994, was: (In Thousands) Treasury Bonds $ 997 Tax-Exempt Bonds 332,098 Equity Securities 1,665 Cash and Cash Equivalents 25,304 Total $360,064 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, 1994, the year of maturity of trust fund investments other than equity securities, was: (In Thousands) 1995 $ 39,173 1996 - 1999 85,199 2000 - 2004 142,868 After 2004 91,159 Total $358,399 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 $537 million and $512 million and for long-term debt were $4.7 billion and $5.3 billion at December 31, 1994 and 1993, respectively. The carrying amounts for preferred stock subject to mandatory redemption were $590 million and $501 million and for long-term debt were $5.0 billion and $5.0 billion at December 31, 1994 and 1993, 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, (In Thousands) 1994 1993 1992 Charged (Credited) to Operating Expenses (net): Current $240,655 $270,318 $ 93,266 Deferred (6,367) (49,652) 91,188 Deferred Investment Tax Credits (17,079) (17,235) (18,235) Total 217,209 203,431 166,219 Charged (Credited) to Nonoperating Income (net): Current (2,907) 8,727 17,600 Deferred (5,856) 4,603 11,992 Deferred Investment Tax Credits (14,196) (9,780) (9,561) Total (22,959) 3,550 20,031 Credited to Loss from Zimmer Plant Disallowance (net): Deferred - (13,327) - Deferred Investment Tax Credits - (1,207) - Total - (14,534) - Total Federal Income Taxes as Reported $194,250 $192,447 $186,250 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, (In Thousands) 1994 1993 1992 Income Before Preferred Stock Dividend Requirements of Subsidiaries $554,707 $412,587 $527,651 Federal Income Taxes 194,250 192,447 186,250 Pre-Tax Book Income $748,957 $605,034 $713,901 Federal Income Tax on Pre-Tax Book Income at Statutory Rate (1994 and 1993-35%, 1992-34%) $262,135 $211,762 $242,726 Increase (Decrease) in Federal Income Tax Resulting from the Following Items: Depreciation 31,212 27,554 24,337 Removal Costs (13,818) (17,730) (15,124) Corporate Owned Life Insurance (22,970) (27,310) (25,490) Investment Tax Credits (net) (31,273) (28,218) (26,528) Zimmer Plant Disallowance - 42,346 - Federal Income Tax Accrual Adjustments (16,100) (6,500) - Other (14,936) (9,457) (13,671) Total Federal Income Taxes as Reported $194,250 $192,447 $186,250 Effective Federal Income Tax Rate 25.9% 31.8% 26.1% The following tables show the elements of the net deferred tax liability and the significant temporary differences: December 31, (In Thousands) 1994 1993 Deferred Tax Assets $ 712,048 $ 709,895 Deferred Tax Liabilities (3,185,587) (3,177,910) Net Deferred Tax Liabilities $(2,473,539) $(2,468,015) Property Related Temporary Differences $(2,098,304) $(2,074,684) Amounts Due From Customers For Future Federal Income Taxes (483,512) (477,331) Deferred Net Gain - Rockport Plant Unit 2 125,278 129,794 All Other (net) (17,001) (45,794) Total Net Deferred Tax Liabilities $(2,473,539) $(2,468,015) 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 1988. Returns for the years 1988 through 1990 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, (In Thousands) 1994 1993 1992 Operating Leases $233,805 $243,190 $268,810 Amortization of Capital Leases 79,116 84,226 59,971 Interest on Capital Leases 23,280 23,839 22,562 Total Rental Payments $336,201 $351,255 $351,343 Properties under capital leases and related obligations on the Consolidated Balance Sheets are as follows: December 31, (In Thousands) 1994 1993 ELECTRIC UTILITY PLANT: Production $ 44,683 $ 26,831 Transmission 38 364 Distribution 14,717 14,717 General: Nuclear Fuel (net of amortization) 89,478 45,660 Mining Plant and Other 403,038 332,099 Total Electric Utility Plant 551,954 419,671 Accumulated Amortization 173,641 164,820 Net Electric Utility Plant 378,313 254,851 OTHER PROPERTY 24,724 30,986 Accumulated Amortization 2,838 1,985 Net Other Property 21,886 29,001 Net Property under Capital Leases $400,199 $283,852 Obligations under Capital Leases $400,199 $283,852 Less Portion Due Within One Year 93,252 62,215 Noncurrent Capital Lease Liability $306,947 $221,637 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, 1994: Noncancelable Capital Operating (In Thousands) Leases Leases 1995 $ 80,308 $ 252,206 1996 66,203 250,427 1997 52,654 245,813 1998 39,650 237,146 1999 33,008 234,891 Later Years 141,781 4,378,882 Total Future Minimum Lease Rentals 413,604(a) $5,599,365 Less Estimated Interest Element 102,883 Estimated Present Value of Future Minimum Lease Rentals 310,721 Unamortized Nuclear Fuel 89,478 Total $400,199 (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, (In Thousands) 1994 1993 1992 Purchased Power - Ohio Valley Electric Corp. (44.2% owned by AEP) $5,755 $19,253 $15,599 Cash was paid for: Interest (net of capitalized amounts) $379,361 $421,060 $447,549 Income Taxes $312,233 $245,350 $128,200 Noncash Acquisitions under Capital Leases were $227,055 $80,220 $108,726 In connection with a 1992 sale of coal-mining properties, a coal-mining subsidiary is receiving cash payments of $77 million over a 13-1/2 year period which had a net present value of $44.6 million at the time of the sale. 12. CAPITAL STOCKS AND PAID-IN CAPITAL: Changes in capital stocks and paid-in capital during the period January 1, 1992 through December 31, 1994 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) January 1, 1992 193,534,992 9,953,201 $1,257,977 $1,630,466 $ 534,978 $140,662 Issues - 1,000,000 - - - 100,000 Retirements and Other - (191,526) - (1,149) - (7,153) December 31, 1992 193,534,992 10,761,675 1,257,977 1,629,317 534,978 233,509 Issues - 3,250,000 - - - 325,000 Retirements and Other - (6,323,907) - (4,249) (266,738) (57,972) December 31, 1993 193,534,992 7,687,768 1,257,977 1,625,068 268,240 500,537 Issues 700,000 900,000 4,550 17,706 - 90,000 Retirements and Other - (351,517) - (1,252) (35,000) (152) December 31, 1994 194,234,992 8,236,251 $1,262,527 $1,641,522 $ 233,240 $590,385 (a) Includes 8,999,992 shares of treasury stock. (b) Including portion due within one year.
13. Unaudited Quarterly Financial Information: Quarterly Periods Ended (In Thousands - Except 1994 Per Share Amounts) March 31 June 30 Sept. 30 Dec. 31 Operating Revenues $1,488,185 $1,348,563 $1,385,278 $1,282,644 Operating Income 257,448 219,427 246,946 208,399 Net Income 152,954 103,793 139,826 103,439 Earnings per Share 0.83 0.56 0.76 0.56 Quarterly Periods Ended (In Thousands - Except 1993 Per Share Amounts) March 31 June 30 Sept. 30 Dec. 31 Operating Revenues $1,321,450 $1,210,398 $1,406,311 $1,330,683 Operating Income 240,965 195,196 242,156 250,053 Net Income (Loss) 133,058 86,219 (10,139) 144,631 Earnings (Loss) per Share 0.72 0.47 (0.06) 0.79 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. The third quarter 1993 loss results from the Zimmer disallowance discussed in Note 3. American Electric Power Company, Inc. and Subsidiary Companies SCHEDULE OF CONSOLIDATED CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES
December 31, 1994 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% - 7.76% $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% $109.50(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 ___________________________________________________________________________________________________________ December 31, 1993 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 1,600,000 1,600,000 160,000 8.04% $102.58 150,000 150,000 15,000 Total Not Subject to Mandatory Redemption $268,240 Subject to Mandatory Redemption (c): 4.50% $102 19,625 5,365 $ 537 5.90% - 5.92% (d) 1,950,000 1,950,000 195,000 6.02% - 6-7/8% (e) 1,300,000 1,300,000 130,000 7% - 7-7/8% $107.80-$107.88(f) 1,000,000 1,000,000 100,000 9.50% $109.50(g) 750,000 750,000 75,000 Total Subject to Mandatory Redemption (h) 500,537 Less Portion Due Within One Year 87 Long-term Portion $500,450
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, 1994 price is shown) plus accrued dividends. The involuntary liquidation preference is $100 per share for all outstanding shares. (b) As of December 31, 1994 the subsidiaries had 2,730,000, 22,200,000 and 5,546,152 shares of $100, $25 and no par valve 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) Redemption is restricted prior to November 1995. (h) The sinking fund provisions of the series subject to mandatory redemption aggregate $85,000, $3,900,000, $3,835,000, $8,750,000 and $8,750,000 in 1995, 1996, 1997, 1998 and 1999, 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, 1994 1994 1993 1994 1993 (in thousands) FIRST MORTGAGE BONDS 1995-1999 7.16% 5%-9.15% 5%-9.15% $ 526,866 $ 596,566 2001-2004 7.26% 6%-9.31% 6%-9.31% 1,450,020 1,264,020 2017-2024 8.37% 7.10%-9-7/8% 7.10%-9-7/8% 1,540,661 1,677,186 INSTALLMENT PURCHASE CONTRACTS (a) 1995-1998 6.55% 6%-7-1/4% 3.65%-7-1/4% 174,500 174,500 2007-2022 6.82% 5.45%-9-3/8% 5.45%-9-3/8% 811,745 811,745 NOTES PAYABLE (b) 1994 - 2008 8.29% 5.29%-10.78% 3.725%-10.78% 313,000 318,000 SINKING FUND DEBENTURES (c) 1996 - 1999 6.40% 5-1/8%-7-7/8% 5-1/8%-7-7/8% 30,759 31,153 OTHER LONG-TERM DEBT (d) 163,896 154,386 Unamortized Discount (net) (31,128) (32,355) Total Long-term Debt Outstanding (e) 4,980,319 4,995,201 Less Portion Due Within One Year 293,671 31,141 Long-term Portion $4,686,648 $4,964,060
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 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) Prior to December 31, 1994 sufficient principal amounts of debentures had been reacquired in anticipation of all future sinking fund requirements. (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, 1994 is payable as follows: Principal Amount (in thousands) 1995 $ 293,671 1996 117,062 1997 90,513 1998 274,645 1999 139,905 Later Years 4,095,651 Total $5,011,447 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, 1994 and 1993, and the related consolidated statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 1994. 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, 1994 and 1993, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1994 in conformity with generally accepted accounting principles. DELOITTE & TOUCHE LLP Columbus, Ohio February 21, 1995 EX-21 5 AEPCO 10-K EX. 21 LIST OF AEP SUBSIDIARIES EXHIBIT 21 Subsidiaries of American Electric Power Company, Inc. As of January 1, 1995
Percentage of Voting Securities State 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) Kanawha Valley Power Company West Virginia 100.0 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 94.2 (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 553,848 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 1,712,403 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 10-K 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. 33-1052 of American Electric Power Company, Inc. on Form S-8 and Post-Effective Amendment No. 2 to Registration Statement No. 33-1734 of American Electric Power Company, Inc. on Form S-3 of our reports dated February 21, 1995, 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, 1994. /s/ Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio March 28, 1995 /PAGE EX-24 7 AEPCO 10-K EX. 24 POWER OF ATTORNEY Exhibit 24 POWER OF ATTORNEY AMERICAN ELECTRIC POWER COMPANY, INC. Annual Report on Form lO-K for the Fiscal Year Ended December 31, 1994 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, 1994, 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 22nd day of February, 1995. /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/ Arthur G. Hansen /s/ Linda Gillespie Stuntz Arthur G. Hansen Linda Gillespie Stuntz /s/ Lester A. Hudson, Jr. /s/ Morris Tanenbaum Lester A. Hudson, Jr. Morris Tanenbaum /s/ G. P. Maloney /s/ Ann Haymond Zwinger G. P. Maloney Ann Haymond Zwinger /PAGE EX-27 8 ARTICLE UT FIN. DATA SCH. FOR 10-K
UT 0000004904 AMERICAN ELECTRIC POWER COMPANY, INC. 1,000 12-MOS DEC-31-1994 DEC-31-1994 PER-BOOK 11,348,110 735,042 1,281,438 398,257 1,949,852 15,712,699 1,262,527 1,641,522 1,325,581 4,229,630 590,300 233,240 4,686,648 42,535 0 274,450 293,671 85 306,947 93,252 4,961,941 15,712,699 5,504,670 235,043 4,337,407 4,572,450 932,220 11,485 943,705 388,998 500,012 54,695 500,012 443,101 270,745 977,725 $2.71 $2.71 Represents preferred stock dividend requirements of subsidiaries; deducted before computation of net income.