-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, TObn/VHF0eooO6XtKbzGv7lLdLHnocB5NXPhPlXjW2kuRdWscSnvHTyLO0nr48m2 VQ8LFXRCxvsDwtllVXWunQ== 0000004904-98-000037.txt : 19980402 0000004904-98-000037.hdr.sgml : 19980402 ACCESSION NUMBER: 0000004904-98-000037 CONFORMED SUBMISSION TYPE: 10-K/A PUBLIC DOCUMENT COUNT: 1 CONFORMED PERIOD OF REPORT: 19971231 FILED AS OF DATE: 19980401 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: AMERICAN ELECTRIC POWER COMPANY INC CENTRAL INDEX KEY: 0000004904 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 134922640 STATE OF INCORPORATION: NY FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K/A SEC ACT: SEC FILE NUMBER: 001-03525 FILM NUMBER: 98585286 BUSINESS ADDRESS: STREET 1: 1 RIVERSIDE PLZ CITY: COLUMBUS STATE: OH ZIP: 43215 BUSINESS PHONE: 6142231000 FORMER COMPANY: FORMER CONFORMED NAME: KINGSPORT UTILITIES INC DATE OF NAME CHANGE: 19660906 10-K/A 1 AMENDMENT TO AEP 10-K FOR 1997 SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K/A AMENDMENT NO. 1 (Mark One) [x] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 1997 [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from __________ to __________ Commission Registrant; State of Incorporation; I.R.S. Employer File Number Address; and Telephone Number Identification No. 1-3525 American Electric Power Company, Inc. 13-4922640 (A New York Corporation) 1 Riverside Plaza Columbus, Ohio 43215 Telephone (614) 223-1000 0-18135 AEP Generating Company 31-1033833 (An Ohio Corporation) 1 Riverside Plaza Columbus, Ohio 43215 Telephone (614) 223-1000 1-3457 Appalachian Power Company 54-0124790 (A Virginia Corporation) 40 Franklin Road, S.W. Roanoke, Virginia 24011 Telephone (540) 985-2300 1-2680 Columbus Southern Power Company 31-4154203 (An Ohio Corporation) 215 North Front Street Columbus, Ohio 43215 Telephone (614) 464-7700 1-3570 Indiana Michigan Power Company 35-0410455 (An Indiana Corporation) One Summit Square P. O. Box 60 Fort Wayne, Indiana 46801 Telephone (219) 425-2111 1-6858 Kentucky Power Company 61-0247775 (A Kentucky Corporation) 1701 Central Avenue Ashland, Kentucky 41101 Telephone (800) 572-1141 1-6543 Ohio Power Company 31-4271000 (An Ohio Corporation) 301 Cleveland Avenue, S.W. Canton, Ohio 44702 Telephone (330) 456-8173 AEP Generating Company, Columbus Southern Power Company and Kentucky Power Company meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and are therefore filing this Form 10-K with the reduced disclosure format specified in General Instruction I(2) to such Form 10-K. Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes (check mark) No Securities registered pursuant to Section 12(b) of the Act: Name of each exchange Registrant Title of each class on which registered AEP Generating Company None American Electric Power Common Stock, Company, Inc. $6.50 par value New York Stock Exchange Appalachian Power Cumulative Preferred Stock, Company Voting, no par value: 4-1/2% Philadelphia Stock Exchange 8-1/4% Junior Subordinated Deferrable Interest Debentures, Series A, Due 2026 New York Stock Exchange 8% Junior Subordinated Deferrable Interest Debentures, Series B, Due 2027 New York Stock Exchange 7.20% Senior Notes, Series A, Due 2038 New York Stock Exchange Columbus Southern 8-3/8% Junior Subordinated Deferrable Power Company Interest Debentures, Series A, Due 2025 New York Stock Exchange 7.92% Junior Subordinated Deferrable Interest Debentures, Series B, Due 2027 New York Stock Exchange Indiana Michigan 8% Junior Subordinated Deferrable Power Company Interest Debentures, Series A, Due 2026 New York Stock Exchange Kentucky Power Company 8.72% Junior Subordinated Deferrable Interest Debentures, Series A, Due 2025 New York Stock Exchange Ohio Power Company 8.16% Junior Subordinated Deferrable Interest Debentures, Series A, Due 2025 New York Stock Exchange 7.92% Junior Subordinated Deferrable Interest Debentures, Series B, Due 2027 New York Stock Exchange Indicate by check mark if disclosure of delinquent filers with respect to American Electric Power Company, Inc. pursuant to Item 405 of Regulation S- K (Section 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in the definitive proxy statement of American Electric Power Company, Inc. incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ____ Indicate by check mark if disclosure of delinquent filers with respect to Appalachian Power Company, Indiana Michigan Power Company or Ohio Power Company pursuant to Item 405 of Regulation S-K (Section 229.405 of this chap- ter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in the definitive information statements of Appalachian Power Company or Ohio Power Company incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. (check mark) Securities registered pursuant to Section 12(g) of the Act: Registrant Title of each class AEP Generating Company None American Electric Power Company, Inc. None Appalachian Power Company None Columbus Southern Power Company None Indiana Michigan Power Company 4-1/8% Cumulative Preferred Stock, Non-Voting, $100 par value Kentucky Power Company None Ohio Power Company 4-1/2% Cumulative Preferred Stock, Voting, $100 par value Aggregate market value of voting and non-voting Number of shares common equity held of common stock by non-affiliates of outstanding of the registrants at the registrants at February 13, 1998 February 13, 1998 AEP Generating Company None 1,000 ($1,000 par value) American Electric Power Company, Inc. $9,333,250,000 189,989,989 ($6.50 par value) Appalachian Power Company None 13,499,500 (no par value) Columbus Southern Power Company None 16,410,426 (no par value) Indiana Michigan Power Company None 1,400,000 (no par value) Kentucky Power Company None 1,009,000 ($50 par value) Ohio Power Company None 27,952,473 (no par value) NOTE ON MARKET VALUE OF COMMON EQUITY HELD BY NON-AFFILIATES All of the common stock of AEP Generating Company, Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company and Ohio Power Company is owned by American Electric Power Company, Inc. (see Item 12 herein). DOCUMENTS INCORPORATED BY REFERENCE Part of Form 10-K Into Which Document Description Is Incorporated Portions of Annual Reports of the following companies for the fiscal year ended December 31, 1997: Part II AEP Generating Company American Electric Power Company, Inc. Appalachian Power Company Columbus Southern Power Company Indiana Michigan Power Company Kentucky Power Company Ohio Power Company Portions of Proxy Statement of American Electric Power Company, Inc. for 1998 Annual Meeting of Shareholders, to be filed within 120 days after December 31, 1997 Part III Portions of Information Statements of the following companies for 1998 Annual Meeting of Shareholders, to be filed within 120 days after December 31, 1997: Part III Appalachian Power Company Ohio Power Company This combined Form 10-K is separately filed by AEP Generating Company, American Electric Power Company, Inc., Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company and Ohio Power Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Except for American Electric Power Company, Inc., each registrant makes no representation as to information relating to the other registrants. EXPLANATORY NOTE This Amendment No. 1 to Form 10-K for the fiscal year ended December 31, 1997, is filed in order to revise certain amounts reported in Item 1 under the heading "Construction Expenditures--Environmental Expenditures". PART I Item 1. Business General AEP was incorporated under the laws of the State of New York in 1906 and reorganized in 1925. It is a public utility holding company which owns, directly or indirectly, all of the outstanding common stock of its domestic electric utility subsidiaries and varying percentages of other subsidiaries. Substantially all of the operating revenues of AEP and its subsidiaries are derived from the furnishing of electric service. In addition, in recent years AEP has been pursuing various unregulated business opportunities in the U.S. and worldwide as discussed in New Business Development. The service area of AEP's electric utility subsidiaries covers portions of the states of Indiana, Kentucky, Michigan, Ohio, Tennessee, Virginia and West Virginia. The generating and transmission facilities of AEP's subsidiar- ies are physically interconnected, and their operations are coordinated, as a single integrated electric utility system. Transmission networks are interconnected with extensive distribution facilities in the territories served. The electric utility subsidiaries of AEP have traditionally provided electric service, consisting of generation, transmission and distribution, on an integrated basis to their retail customers. As a result of the changing nature of the electric business (see Competition and Business Change), effective January 1, 1996, AEP's subsidiaries realigned into four functional business units: Power Generation; Nuclear Generation; Energy Delivery; and Corporate Development. In addition, the electric utility subsidiaries began to do business as "American Electric Power." The legal and financial structure of AEP and its subsidiaries, however, did not change. At December 31, 1997, the subsidiaries of AEP had a total of 17,844 employees. AEP, as such, has no employees. The operating subsidiaries of AEP are: APCo (organized in Virginia in 1926) is engaged in the generation, sale, purchase, transmission and distribution of electric power to approximately 877,000 retail customers in the southwestern portion of Virginia and southern West Virginia, and in supplying electric power at wholesale to other electric utility companies and municipalities in those states and in Tennessee. At December 31, 1997, APCo and its wholly owned subsidiaries had 3,877 employees. Among the principal industries served by APCo are coal mining, primary metals, chemicals and textile mill products. In addition to its AEP System interconnections, APCo also is interconnected with the following unaffiliated utility companies: Carolina Power & Light Company, Duke Energy Corporation and VEPCo. A comparatively small part of the properties and business of APCo is located in the northeastern end of the Tennessee Valley. APCo has several points of interconnection with TVA and has entered into agreements with TVA under which APCo and TVA interchange and transfer electric power over portions of their respective systems. CSPCo (organized in Ohio in 1937, the earliest direct predecessor company having been organized in 1883) is engaged in the generation, sale, purchase, transmission and distribution of electric power to approximately 621,000 customers in Ohio, and in supplying electric power at wholesale to other electric utilities and to municipally owned distribution systems within its service area. At December 31, 1997, CSPCo had 1,802 employees. CSPCo's service area is comprised of two areas in Ohio, which include portions of twenty-five counties. One area includes the City of Columbus and the other is a predominantly rural area in south central Ohio. Approximately 80% of CSPCo's retail revenues are derived from the Columbus area. Among the principal industries served are food processing, chemicals, primary metals, electronic machinery and paper products. In addition to its AEP System interconnections, CSPCo also is interconnected with the following unaffiliated utility companies: CG&E, DP&L and Ohio Edison Company. I&M (organized in Indiana in 1925) is engaged in the generation, sale, purchase, transmission and distribution of electric power to approximately 549,000 customers in northern and eastern Indiana and southwestern Michigan, and in supplying electric power at wholesale to other electric utility companies, rural electric cooperatives and municipalities. At December 31, 1997, I&M had 3,306 employees. Among the principal industries served are primary metals, transportation equipment, electrical and electronic machinery, fabricated metal products, rubber and miscellaneous plastic products and chemicals and allied products. Since 1975, I&M has leased and operated the assets of the municipal system of the City of Fort Wayne, Indiana. In addition to its AEP System interconnections, I&M also is interconnected with the following unaffiliated utility companies: Central Illinois Public Service Company, CG&E, Commonwealth Edison Company, Consumers Energy Company, Illinois Power Company, Indianapolis Power & Light Company, Louisville Gas and Electric Company, Northern Indiana Public Service Company, PSI Energy Inc. and Richmond Power & Light Company. KEPCo (organized in Kentucky in 1919) is engaged in the generation, sale, purchase, transmission and distribution of electric power to approximately 168,000 customers in an area in eastern Kentucky, and in supplying electric power at wholesale to other utilities and municipalities in Kentucky. At December 31, 1997, KEPCo had 731 employees. In addition to its AEP System interconnections, KEPCo also is interconnected with the following unaffiliated utility companies: Kentucky Utilities Company and East Kentucky Power Cooperative Inc. KEPCo is also interconnected with TVA. Kingsport Power Company (organized in Virginia in 1917) provides electric service to approximately 43,000 customers in Kingsport and eight neighboring communities in northeastern Tennessee. Kingsport Power Company has no generating facilities of its own. It purchases electric power distributed to its customers from APCo. At December 31, 1997, Kingsport Power Company had 85 employees. OPCo (organized in Ohio in 1907 and reincorporated in 1924) is engaged in the generation, sale, purchase, transmission and distribution of electric power to approximately 679,000 customers in the northwestern, east central, eastern and southern sections of Ohio, and in supplying electric power at wholesale to other electric utility companies and municipalities. At December 31, 1997, OPCo and its wholly owned subsidiaries had 4,376 employees. Among the principal industries served by OPCo are primary metals, rubber and plastic products, stone, clay, glass and concrete products, petroleum refining and chemicals. In addition to its AEP System interconnections, OPCo also is interconnected with the following unaffiliated utility companies: CG&E, The Cleveland Electric Illuminating Company, DP&L, Duquesne Light Company, Kentucky Utilities Company, Monongahela Power Company, Ohio Edison Company, The Toledo Edison Company and West Penn Power Company. Wheeling Power Company (organized in West Virginia in 1883 and reincorporated in 1911) provides electric service to approximately 43,000 customers in northern West Virginia. Wheeling Power Company has no generating facilities of its own. It purchases electric power distributed to its customers from OPCo. At December 31, 1997, Wheeling Power Company had 94 employees. Another principal electric utility subsidiary of AEP is AEGCo, which was organized in Ohio in 1982 as an electric generating company. AEGCo sells power at wholesale to I&M, KEPCo and VEPCo. AEGCo has no employees. See Item 2 for information concerning the properties of the subsidiaries of AEP. The Service Corporation provides accounting, administrative, information systems, engineering, financial, legal, maintenance and other services at cost to the AEP System companies. The executive officers of AEP and its public utility subsidiaries are all employees of the Service Corporation. Regulation General AEP and its subsidiaries are subject to the broad regulatory provisions of PUHCA administered by the SEC. The public utility subsidiaries' retail rates and certain other matters are subject to regulation by the public utility commissions of the states in which they operate. Such subsidiaries are also subject to regulation by the FERC under the Federal Power Act in respect of rates for interstate sale at wholesale and transmission of electric power, accounting and other matters and construction and operation of hydroelectric projects. I&M is subject to regulation by the NRC under the Atomic Energy Act of 1954, as amended, with respect to the operation of the Cook Plant. Possible Change to PUHCA The provisions of PUHCA, administered by the SEC, regulate all aspects of a registered holding company system, such as the AEP System. PUHCA requires that the operations of a registered holding company system be limited to a single integrated public utility system and such other businesses as are incidental or necessary to the operations of the system. In addition, PUHCA governs, among other things, financings, sales or acquisitions of assets and intra-system transactions. On June 20, 1995, the SEC released a report from its Division of Investment Management recommending a conditional repeal of PUHCA, including its limits on financing and on geographic and business diversification. Specific federal authority, however, would be preserved over access to the books and records of registered holding company systems, audit authority over registered holding companies and their subsidiaries and oversight over affili- ate transactions. This authority would be transferred to the FERC. Legislation was introduced in Congress in 1997 that would repeal PUHCA and transfer certain federal authority to the FERC as recommended in the SEC report as part of broader legislation regarding changes in the electric industry. It is expected that a number of bills contemplating the restructuring of the electric utility industry will be introduced in the cur- rent Congress. See Competition and Business Change. If PUHCA is repealed, registered holding company systems, including the AEP System, will be able to compete in the changing industry without the constraints of PUHCA. Management of AEP believes that removal of these constraints would be beneficial to the AEP System. PUHCA and the rules and orders of the SEC currently require that transactions between associated companies in a registered holding company system be performed at cost with limited exceptions. Over the years, the AEP System has developed numerous affiliated service, sales and construction relationships and, in some cases, invested significant capital and developed significant operations in reliance upon the ability to recover its full costs under these provisions. Legislation has been introduced in Congress to repeal PUHCA or modify its provisions governing intra-system transactions. The effect of repeal or amendment of PUHCA on AEP's intra-system transactions depends on whether the assurance of full cost recovery is eliminated immediately or phased-in and whether it is eliminated for all intra-system transactions or only some. If the cost recovery assurance is eliminated immediately for all intra-system transactions, it could have a material adverse effect on results of operations and financial condition of AEP and OPCo. Conflict of Regulation Public utility subsidiaries of AEP can be subject to regulation of the same subject matter by two or more jurisdictions. In such situations, it is possible that the decisions of such regulatory bodies may conflict or that the decision of one such body may affect the cost of providing service and so the rates in another jurisdiction. In a case involving OPCo, the U.S. Court of Appeals for the District of Columbia held that the determination of costs to be charged to associated companies by the SEC under PUHCA precluded the FERC from determining that such costs were unreasonable for ratemaking purposes. The U.S. Supreme Court also has held that a state commission may not conclude that a FERC approved wholesale power agreement is unreasonable for state ratemaking purposes. Certain actions that would overturn these decisions or otherwise affect the jurisdiction of the SEC and FERC are under consideration by the U.S. Congress and these regulatory bodies. Such conflicts of jurisdiction often result in litigation and, if resolved adversely to a public utility subsidiary of AEP, could have a material adverse effect on the results of operations or financial condition of such subsidiary or AEP. Classes of Service The principal classes of service from which the major electric utility subsidiaries of AEP derive revenues and the amount of such revenues (from kilowatt-hour sales) during the year ended December 31, 1997 are as follows:
AEP AEGCo APCo CSPCo I&M KEPCo OPCo System (a) (in thousands) Retail Residential Without Electric Heating . . . . $ 0 $ 227,457 $ 317,341 $ 237,475 $ 40,395 $ 274,680 $1,117,740 With Electric Heating . . . . . 0 336,395 110,385 110,547 65,522 147,503 806,095 Total Residential . . . . . . . 0 563,852 427,726 348,022 105,917 422,183 1,923,835 Commercial . . . . . . . . . . . 0 281,939 381,368 264,031 56,680 263,212 1,286,452 Industrial . . . . . . . . . . . 0 382,056 147,367 332,218 94,645 618,548 1,637,058 Miscellaneous . . . . . . . . . 0 32,271 16,170 6,465 863 8,109 67,387 Total Retail . . . . . . . . . 0 1,260,118 972,631 950,736 260,105 1,312,052 4,914,732 Wholesale (sales for resale) . . 227,803 410,813 141,769 415,077 89,337 597,133 1,080,190 Total from KWH Sales . . . . . 227,803 1,670,931 1,114,400 1,365,813 349,442 1,909,185 5,994,922 Provision for Revenue Refunds . . 0 (250) 0 0 0 0 (250) Total Net of Provision for Revenue Refunds . . . . . . . . . 227,803 1,670,681 1,114,400 1,365,813 349,442 1,909,185 5,994,672 65 49,329 25,204 26,104 10,101 56,633 166,696 $227,868 $1,720,010 $1,139,604 $1,391,917 $359,543 $1,965,818 $6,161,368
__________ (a) Includes revenues of other subsidiaries not shown and reflects elimination of intercompany transactions. Sale of Power AEP's electric utility subsidiaries own or lease generating stations with total generating capacity of 23,759 megawatts. See Item 2 for more information regarding the generating stations. They operate their generating plants as a single interconnected and coordinated electric utility system and share the costs and benefits in the AEP System Power Pool. Most of the electric power generated at these stations is sold, in combination with transmission and distribution services, to retail customers of AEP's utility subsidiaries in their service territories. These sales are made at rates that are established by the public utility commissions of the state in which they operate. See Rates and Regulation. Some of the electric power is sold at wholesale to non-affiliated companies. AEP System Power Pool APCo, CSPCo, I&M, KEPCo and OPCo are parties to the Interconnection Agreement, dated July 6, 1951, as amended (the Interconnection Agreement), defining how they share the costs and benefits associated with the System's generating plants. This sharing is based upon each company's "member-load- ratio," which is calculated monthly on the basis of each company's maximum peak demand in relation to the sum of the maximum peak demands of all five companies during the preceding 12 months. In addition, since 1995, APCo, CSPCo, I&M, KEPCo and OPCo have been parties to the AEP System Interim Allowance Agreement which provides, among other things, for the transfer of SO2 Allowances associated with transactions under the Interconnection Agreement. The following table shows the net credits or (charges) allocated among the parties under the Interconnection Agreement and Interim Allowance Agreement during the years ended December 31, 1995, 1996 and 1997:
1995 1996 1997(a) (in thousands) APCo . . . . . . $(252,000) $(258,000) $(237,000) CSPCo . . . . . . (143,000) (145,000) (138,000) I&M . . . . . . . 118,000 121,000 67,000 KEPCo . . . . . . 23,000 2,000 20,000 OPCo . . . . . . 254,000 280,000 288,000
__________ (a) Includes credits and charges from allowance transfers related to the transactions. Wholesale Sales of Power to Non-Affiliates AEGCo, APCo, CSPCo, I&M, KEPCo and OPCo also sell electric power on a wholesale basis to non-affiliated electric utilities and power marketers. Such sales are either made by the AEP System and then allocated among APCo, CSPCo, I&M, KEPCo and OPCo based on member-load-ratios or made by individual companies pursuant to various long-term power agreements. The following table shows the net realization (revenue less operating, maintenance, fuel and federal income tax expenses) of the various companies from such sales during the years ended December 31, 1995, 1996 and 1997:
1995(a) 1996(a) 1997(a) (in thousands) AEGCo(b) . . . . $ 29,200 $ 26,300 $ 26,200 APCo(c) . . . . . 24,100 36,800 37,500 CSPCo(c) . . . . 12,000 18,100 18,300 I&M(c)(d) . . . . 34,700 43,000 42,400 KEPCo(c) . . . . 5,000 7,600 7,700 OPCo(c) . . . . . 20,200 30,200 30,200 Total System . $125,200 $162,000 $162,300
__________ (a) Such sales do not include wholesale sales to full/partial requirement customers of AEP System companies. See the discussion below. (b) All amounts for AEGCo are from sales made pursuant to a long-term power agreement. See AEGCo - Unit Power Agreements. (c) All amounts, except for I&M, are from System sales which are allocated among APCo, CSPCo, I&M, KEPCo and OPCo based upon member-load-ratio. All System sales made in 1995, 1996 and 1997 were made on a short-term basis, except that $22,500,000, $33,300,000 and $25,900,000 respectively, of the contribution to operating income for the total System were from long-term System sales. (d) In addition to its allocation of System sales, the 1995, 1996 and 1997 amounts for I&M include $21,000,000, $20,900,000 and $21,100,000 from a long-term agreement to sell 250 megawatts of power scheduled to terminate in 2009. The AEP System has long-term system agreements to sell the following to unaffiliated utilities: (1) 205 megawatts of electric power through August 2010; and (2) 50 megawatts of electric power through August 2001. In addition to long-term and short-term sales, APCo, CSPCo, I&M, KEPCo and OPCo serve unaffiliated wholesale customers that are full/partial requirement customers. The aggregate maximum demand for these customers in 1997 was 611, 109, 451, 18 and 140 megawatts for APCo, CSPCo, I&M, KEPCo and OPCo, respectively. Although the terms of the contracts with these customers vary, they generally can be terminated by the customer upon one to four years' notice. Since 1995, customers have given notices of termination, effective in 1998 and 1999, for 405, 63 and 131 megawatts for APCo, I&M and OPCo, respectively. Several wholesale customers, some of whom had previously given notice of termination, have entered into long-term contracts, ranging from five to seven years, with the AEP System. The expected demand under these contracts aggregates approximately 450 megawatts. In June 1993, certain municipal customers of APCo, who have since given APCo notice to terminate their contracts in 1998, filed an application with the FERC for transmission service in order to reduce by 50 megawatts the power these customers then purchased under existing Electric Service Agreements (ESAs) and to purchase power from a third party. APCo maintains that its agreements with these customers are full-requirements contracts which preclude the customers from purchasing power from third parties. On February 10, 1994, the FERC issued an order finding that the ESAs are not full requirements contracts and that the ESAs give these municipal wholesale customers the option of substituting alternative sources of power for energy purchased from APCo. On May 24, 1994, APCo appealed the February 10, 1994 order of the FERC to the U.S. Court of Appeals for the District of Columbia Circuit. On July 1, 1994, the FERC ordered the requested transmission service and granted a complaint filed by the municipal customers directing certain modifications to the ESAs in order to accommodate their power purchases from the third party. Following FERC's denial of APCo's requests for rehearing, on December 20, 1995, APCo appealed the July 1, 1994 orders to the U.S. Court of Appeals for the District of Columbia. Effective August 1994, these municipal customers reduced their purchases by 40 megawatts. Certain of these customers further reduced their purchases by an additional 21 megawatts effective February 1996. On December 17, 1996, the U.S. Court of Appeals reversed the FERC's order directing APCo to provide transmission service and remanded the case to the FERC, where it remains pending. Transmission Services AEP's electric utility subsidiaries own and operate transmission and distribution lines and other facilities to deliver electric power. See Item 2 for more information regarding the transmission and distribution lines. AEP's electric utility subsidiaries operate their transmission lines as a single interconnected and coordinated system and share the cost and benefits in the AEP System Transmission Pool. Most of the transmission and distribution services is sold, in combination with electric power, to retail customers of AEP's utility subsidiaries in their service territories. These sales are made at rates that are established by the public utility commissions of the state in which they operate. See Rates and Regulations. Some transmission services also are separately sold to non-affiliated companies. AEP System Transmission Pool APCo, CSPCo, I&M, KEPCo and OPCo are parties to the Transmission Agreement, dated April 1, 1984, as amended (the Transmission Agreement), defining how they share the costs associated with their relative ownership of the extra-high-voltage transmission system (facilities rated 345 kv and above) and certain facilities operated at lower voltages (138 kv and above). Like the Interconnection Agreement, this sharing is based upon each company's "member-load-ratio." See Sale of Power. The following table shows the net credits or (charges) allocated among the parties to the Transmission Agreement during the years ended December 31, 1995, 1996 and 1997:
1995 1996 1997 (in thousands) APCo . . . . . . $( 5,400) $( 6,500) $( 8,400) CSPCo . . . . . . ( 31,100) ( 30,600) ( 29,900) I&M . . . . . . . 46,700 46,300 46,100 KEPCo . . . . . . 3,500 3,300 2,700 OPCo . . . . . . ( 13,700) ( 12,500) ( 10,500)
Transmission Services for Non-Affiliates APCo, CSPCo, I&M, KEPCo, OPCo and other System companies also provide transmission services for non-affiliated companies. The following table shows the revenues net of federal income tax expenses of the various companies from such services during the years ended December 31, 1995, 1996 and 1997:
1995 1996 1997 (in thousands) APCo . . . . . . $ 6,000 $ 13,800 $ 18,000 CSPCo . . . . . . 4,200 8,000 10,200 I&M . . . . . . . 4,800 7,700 10,500 KEPCo . . . . . . 1,200 2,800 3,900 OPCo . . . . . . 17,800 17,800 27,200 $ 34,000 $ 50,100 $ 69,800
The AEP System has contracts with non-affiliated companies for transmission of approximately 5,000 megawatts of electric power on an annual or longer basis. On April 24, 1996, the FERC issued orders 888 and 889. These orders require each public utility that owns or controls interstate transmission facilities to file an open access network and point-to-point transmission tariff that offers services comparable to the utility's own uses of its trans- mission system. The orders also require utilities to functionally unbundle their services, by requiring them to use their own tariffs in making off- system and third-party sales. As part of the orders, the FERC issued a pro- forma tariff which reflects the Commission's views on the minimum non-price terms and conditions for non-discriminatory transmission service. In addition, the orders require all transmitting utilities to establish an Open Access Same-time Information System ("OASIS") which electronically posts transmission information such as available capacity and prices, and require utilities to comply with Standards of Conduct which prohibit utilities' system operators from providing non-public transmission information to the utility's merchant employees. The orders also allow a utility to seek recovery of certain prudently-incurred stranded costs that result from unbundled transmis- sion service. On July 9, 1996, the AEP System companies filed a tariff conforming with the FERC's pro-forma transmission tariff, subject to the resolution of certain pricing issues, which are still pending before FERC. During 1996 and 1997 AEP engaged in discussions with several utilities regarding the creation of an independent system operator to operate the transmission system in the Midwestern region of the United States. On January 15, 1998, nine utilities or utility systems filed with the FERC a proposal to form the Midwest Independent Transmission System Operator, Inc. ("Midwest ISO"). AEP was not a participant in that filing, but supports the formation of voluntary ISOs, and is currently examining its options, which include, among others, participation in the Midwest ISO. See Competition and Business Change - AEP Position on Competition. OVEC AEP, CSPCo and several unaffiliated utility companies jointly own OVEC, which supplies the power requirements of a uranium enrichment plant near Portsmouth, Ohio owned by the DOE. The aggregate equity participation of AEP and CSPCo in OVEC is 44.2%. The DOE demand under OVEC's power agreement, which is subject to change from time to time, is 945,000 kilowatts. On March 1, 1998, it is scheduled to increase to approximately 1,900,000 kilowatts. The proceeds from the sale of power by OVEC are designed to be sufficient for OVEC to meet its operating expenses and fixed costs and to provide a return on its equity capital. APCo, CSPCo, I&M and OPCo, as sponsoring companies, are entitled to receive from OVEC, and are obligated to pay for, the power not required by DOE in proportion to their power participation ratios, which averaged 42.1% in 1997. The power agreement with DOE terminates on December 31, 2005, subject to early termination by DOE on not less than three years notice. The power agreement among OVEC and the sponsoring companies expires by its terms on March 12, 2006. Buckeye Contractual arrangements among OPCo, Buckeye and other investor-owned electric utility companies in Ohio provide for the transmission and delivery, over facilities of OPCo and of other investor-owned utility companies, of power generated by the two units at the Cardinal Station owned by Buckeye and back-up power to which Buckeye is entitled from OPCo under such contractual arrangements, to facilities owned by 27 of the rural electric cooperatives which operate in the State of Ohio at 306 delivery points. Buckeye is entitled under such arrangements to receive, and is obligated to pay for, the excess of its maximum one-hour coincident peak demand plus a 15% reserve margin over the 1,226,500 kilowatts of capacity of the generating units which Buckeye currently owns in the Cardinal Station. Such demand, which occurred on January 16, 1997, was recorded at 1,178,460 kilowatts. Certain Industrial Customers Century Aluminum of West Virginia, Inc. (formerly Ravenswood Aluminum Corporation), and Ormet Corporation operate major aluminum reduction plants in the Ohio River Valley at Ravenswood, West Virginia, and in the vicinity of Hannibal, Ohio, respectively. The power requirements of such plants presently are approximately 357,000 kilowatts for Century and 537,000 kilowatts for Ormet. On October 3, 1996, the PUCO approved, with some exceptions, a contract pursuant to which OPCo will continue to provide electric service to Ravenswood for the period July 1, 1996 through July 31, 2003. On February 6, 1997, the PUCO approved an amendment to the contract addressing these exceptions and the amended contract is now in effect. On November 14, 1996, the PUCO approved (1) an interim agreement pursuant to which OPCo will continue to provide electric service to Ormet for the period December 1, 1997 through December 31, 1999 and (2) a joint petition with an electric cooperative to transfer the right to serve Ormet to the electric cooperative after December 31, 1999. As part of the territorial transfer, OPCo and Ormet entered into an agreement which contains penalties and other provisions designed to avoid having OPCo provide involuntary back-up power to Ormet. See Legal Proceedings for a discussion of litigation involving Ormet. AEGCo Since its formation in 1982, AEGCo's business has consisted of the ownership and financing of its 50% interest in the Rockport Plant and, since 1989, leasing of its 50% interest in Unit 2 of the Rockport Plant. The operating revenues of AEGCo are derived from the sale of capacity and energy associated with its interest in the Rockport Plant to I&M, KEPCo and VEPCo, pursuant to unit power agreements. Pursuant to these unit power agreements, AEGCo is entitled to recover its full cost of service from the purchasers and will be entitled to recover future increases in such costs, including increases in fuel and capital costs. See Unit Power Agreements. Pursuant to a capital funds agreement, AEP has agreed to provide cash capital contributions, or in certain circumstances subordinated loans, to AEGCo, to the extent necessary to enable AEGCo, among other things, to provide its pro- portionate share of funds required to permit continuation of the commercial operation of the Rockport Plant and to perform all of its obligations, covenants and agreements under, among other things, all loan agreements, leases and related documents to which AEGCo is or becomes a party. See Capital Funds Agreement. Unit Power Agreements A unit power agreement between AEGCo and I&M (the I&M Power Agreement) provides for the sale by AEGCo to I&M of all the power (and the energy asso- ciated therewith) available to AEGCo at the Rockport Plant. I&M is obligated, whether or not power is available from AEGCo, to pay as a demand charge for the right to receive such power (and as an energy charge for any associated energy taken by I&M) such amounts, as when added to amounts received by AEGCo from any other sources, will be at least sufficient to enable AEGCo to pay all its operating and other expenses, including a rate of return on the common equity of AEGCo as approved by FERC, currently 12.16%. The I&M Power Agree- ment will continue in effect until the date that the last of the lease terms of Unit 2 of the Rockport Plant has expired unless extended in specified circumstances. Pursuant to an assignment between I&M and KEPCo, and a unit power agreement between KEPCo and AEGCo, AEGCo sells KEPCo 30% of the power (and the energy associated therewith) available to AEGCo from both units of the Rockport Plant. KEPCo has agreed to pay to AEGCo in consideration for the right to receive such power the same amounts which I&M would have paid AEGCo under the terms of the I&M Power Agreement for such entitlement. The KEPCo unit power agreement expires on December 31, 1999, unless extended to December 31, 2004. A unit power agreement among AEGCo, I&M, VEPCo, and APCo provides for, among other things, the sale of 70% of the power and energy available to AEGCo from Unit 1 of the Rockport Plant to VEPCo by AEGCo from January 1, 1987 through December 31, 1999. VEPCo has agreed to pay to AEGCo in consideration for the right to receive such power those amounts which I&M would have paid AEGCo under the terms of the I&M Power Agreement for such entitlement. Approximately 32% of AEGCo's operating revenue in 1997 was derived from its sales to VEPCo. Capital Funds Agreement AEGCo and AEP have entered into a capital funds agreement pursuant to which, among other things, AEP has unconditionally agreed to make cash capital contributions, or in certain circumstances subordinated loans, to AEGCo to the extent necessary to enable AEGCo to (i) maintain such an equity component of capitalization as required by governmental regulatory authorities, (ii) pro- vide its proportionate share of the funds required to permit commercial operation of the Rockport Plant, (iii) enable AEGCo to perform all of its obligations, covenants and agreements under, among other things, all loan agreements, leases and related documents to which AEGCo is or becomes a party (AEGCo Agreements), and (iv) pay all indebtedness, obligations and liabilities of AEGCo (AEGCo Obligations) under the AEGCo Agreements, other than indebtedness, obligations or liabilities owing to AEP. The Capital Funds Agreement will terminate after all AEGCo Obligations have been paid in full. Industry Problems The electric utility industry, including the operating subsidiaries of AEP, has encountered at various times in the last 15 years significant problems in a number of areas, including: delays in and limitations on the recovery of fuel costs from customers; proposed legislation, initiative measures and other actions designed to prohibit construction and operation of certain types of power plants under certain conditions and to eliminate or reduce the extent of the coverage of fuel adjustment clauses; inadequate rate increases and delays in obtaining rate increases; jurisdictional disputes with state public utilities commissions regarding the interstate operations of integrated electric systems; requirements for additional expenditures for pollution control facilities; increased capital and operating costs; construction delays due, among other factors, to pollution control and environmental considerations and to material, equipment and fuel shortages; the economic effects on net income (which when combined with other factors may be immediate and adverse) associated with placing large generating units and related facilities in commercial operation, including the commencement at that time of substantial charges for depreciation, taxes, maintenance and other operating expenses, and the cessation of AFUDC with respect to such units; uncertainties as to conservation efforts by customers and the effects of such efforts on load growth; depressed economic conditions in certain regions of the United States; increasingly competitive conditions in the wholesale and retail markets; proposals to deregulate certain portions of the industry and revise the rules and responsibilities under which new generating capacity is supplied; and substantial increases in construction costs and difficulties in financing due to high costs of capital, uncertain capital markets, charter and indenture limitations restricting conventional financing, and shortages of cash for construction and other purposes. Seasonality Sales of electricity by the AEP System tend to increase and decrease because of the use of electricity by residential and commercial customers for cooling and heating and relative changes in temperature. Franchises The operating companies of the AEP System hold franchises to provide electric service in various municipalities in their service areas. These franchises have varying provisions and expiration dates. In general, the operating companies consider their franchises to be adequate for the conduct of their business. Competition and Business Change General The public utility subsidiaries of AEP, like other electric utilities, have traditionally provided electric generation and energy delivery, consisting of transmission and distribution services, as a single product to their retail customers. FERC has required utilities to sell transmission services separately from their other services. Proposals are being made that would also require electric utilities to sell distribution services separately. These proposals generally allow competition in the generation and sale of electric power, but not in its transmission and distribution. Competition in the generation and sale of electric power will require resolution of complex issues, including who will pay for the unused generating plant of, and other stranded costs incurred by, the utility when a customer stops buying power from the utility; will all customers have access to the benefits of competition; how will the rules of competition be established; what will happen to conservation and other regulatory-imposed programs; how will the reliability of the transmission system be ensured; and how will the utility's obligation to serve be changed. As a result, it is not clear how or when competition in generation and sale of electric power will be instituted. However, if competition in generation and sale of electric power is instituted, the public utility subsidiaries of AEP believe that they have a favorable competitive position because of their relatively low costs. If stranded costs are not recovered from customers, however, the public utility subsidiaries of AEP, like all electric utilities, will be required by existing accounting standards to recognize stranded investment losses. Wholesale The public utility subsidiaries of AEP, like the electric industry generally, face increasing competition to sell available power on a wholesale basis, primarily to other public utilities and also to power marketers. The Energy Policy Act of 1992 was designed, among other things, to foster competition in the wholesale market (a) through amendments to PUHCA, facilitating the ownership and operation of generating facilities by "exempt wholesale generators" (which may include independent power producers as well as affiliates of electric utilities) and (b) through amendments to the Federal Power Act, authorizing the FERC under certain conditions to order utilities which own transmission facilities to provide wholesale transmission services for other utilities and entities generating electric power. The principal factors in competing for such sales are price (including fuel costs), availability of capacity and reliability of service. The public utility subsidiaries of AEP believe that they maintain a favorable competitive position on the basis of all of these factors. However, because of the availability of capacity of other utilities and the lower fuel prices in recent years, price competition has been, and is expected for the next few years to be, particularly important. FERC orders 888 and 889, issued in April 1996, provide that utilities must functionally unbundle their transmission services, by requiring them to use their own tariffs in making off-system and third-party sales. See Transmission Services. The public utility subsidiaries of AEP have functionally separated their wholesale power sales from their transmission functions, as required by orders 888 and 889. Retail The public utility subsidiaries of AEP generally have the exclusive right to sell electric power at retail within their service areas. However, they do compete with self-generation and with distributors of other energy sources, such as natural gas, fuel oil and coal, within their service areas. The primary factors in such competition are price, reliability of service and the capability of customers to utilize sources of energy other than electric power. With respect to self-generation, the public utility subsidiaries of AEP believe that they maintain a favorable competitive position on the basis of all of these factors. With respect to alternative sources of energy, the public utility subsidiaries of AEP believe that the reliability of their service and the limited ability of customers to substitute other cost- effective sources for electric power place them in a favorable competitive position, even though their prices may be higher than the costs of some other sources of energy. Significant changes in the global economy in recent years have led to increased price competition for industrial companies in the United States, including those served by the AEP System. Such industrial companies have requested price reductions from their suppliers, including their suppliers of electric power. In addition, industrial companies which are downsizing or reorganizing often close a facility based upon its costs, which may include, among other things, the cost of electric power. The public utility subsidiaries of AEP cooperate with such customers to meet their business needs through, for example, various off-peak or interruptible supply options and believe that, as low cost suppliers of electric power, they should be less likely to be materially adversely affected by this competition and may be benefitted by attracting new industrial customers to their service territories. The legislatures and/or the regulatory commissions in many states are considering or have adopted "retail customer choice" which, in general terms, means the transmission by an electric utility of electric power generated by an entity of the customer's choice over its transmission and distribution system to a retail customer in such utility's service territory. A require- ment to transmit directly to retail customers would have the result of permitting retail customers to purchase electric power, at the election of such customers, not only from the electric utility in whose service area they are located but from another electric utility, an independent power producer or an intermediary, such as a power marketer. Although AEP's power generation would have competitors under some of these proposals, its transmission and distribution would not. If competition develops in retail power generation, the public utility subsidiaries of AEP believe that they have a favorable competitive position because of their relatively low costs. Federal: Legislation to provide for retail competition among electric energy suppliers has been introduced in both the U.S. Senate and House of Representatives. Indiana: In January 1998, S.B. 431 was introduced in the Indiana Senate. The bill contained provisions allowing all customers the unrestricted right to choose their generator of electricity by July 1, 2004. Under the bill, customers could have chosen their power supplier after October 1, 1999, by paying an access charge, while transmission and distribution services would have continued to be regulated at the federal and state levels, respectively. Prior to the full vote on the bill, S.B. 431 was amended on the Senate floor to remove these restructuring provisions. Michigan: In June 1995, the MPSC issued an order approving an experimental five-year retail wheeling program and ordered Consumers Energy Company (Consumers) and Detroit Edison Company (Detroit Edison), unaffiliated utilities, to make retail delivery services available to a group of industrial customers, in the amount of 60 megawatts and 90 megawatts, respectively. The experiment, which commences when each utility needs new capacity, seeks to determine whether a retail wheeling program best serves the public interest. During the experiment, the MPSC will collect information regarding the effects of retail wheeling. Consumers, Detroit Edison and other parties have appealed the MPSC's order to the Michigan Supreme Court. In January 1996, the Governor of Michigan endorsed a proposal of the Michigan Jobs Commission to promote competition and customer choice in energy and requested that the MPSC review the existing statutory and regulatory framework governing Michigan utilities in light of increasing competition in the utility industry. In December 1996, the MPSC staff issued a report on electric industry restructuring which recommended a phase-in program from 1997 through 2004 of direct access to electricity suppliers applicable to all customers. On June 5, 1997, the MPSC entered an order requiring electric utilities (including I&M) to phase in retail open access for customers, with full customer choice by 2002 (MPSC Order). Under the MPSC Order, customer choice is phased in from 1997 through 2001, at the rate of 2.5% of each utility's customer load per year, with all customers becoming eligible to choose their electric supplier effective January 1, 2002. The MPSC Order essentially adopted the December 1996 MPSC staff report that recommended full recovery of stranded costs of utilities, including nuclear generating investment, through the use of a transition charge applicable to customers exercising choice. While concluding that securitization of stranded costs would be feasible, the MPSC Order stated that legislative guidance is required prior to the implementation of any securitization program. As required by the MPSC Order, in July 1997, I&M filed a proposed open access distribution tariff phasing-in customer choice for all customer classes. The MPSC has not yet acted on I&M's filing. The MPSC has approved, by orders dated January 14, 1998 and February 11, 1998, after contested proceedings and with modifications, filings made by Consumers and Detroit Edison. Detroit Edison, the Michigan Attorney General and other parties have appealed the MPSC's orders to the Michigan Court of Appeals. Ohio: On April 15, 1994, the Ohio Energy Strategy Task Force released its final report. The report contained seven broad implementation strategies along with 53 specific initiatives to be undertaken by government and the private sector. One strategy recommended continuing to encourage competition in the electric utility industry in a manner which maximizes benefits and efficiencies for all customers. An initiative under this strategy recommends facilitating informal roundtable discussions on issues concerning competition in the electric utility industry and promoting increased competitive options for Ohio businesses that do not unduly harm the interests of utility company shareholders or ratepayers. The PUCO has begun such discussions. As a result, on February 15, 1996, the PUCO adopted guidelines for interruptible electric service, including a buy-through provision that will enable customers to avoid being interrupted during utility capacity deficiencies by having the utility purchase off-system replacement power for the customer. On February 28, 1997, CSPCo and OPCo implemented four new interruptible electric services in conformance with the PUCO guidelines. Also stemming from the roundtable discussions, on December 24, 1996, the PUCO issued conjunctive electric service guidelines under which customers may be aggregated for cost-of-service, rate design, rate eligibility and billing purposes. Pursuant to a PUCO order, all Ohio electric utilities made conjunctive electric service filings on March 31, 1997. Six unaffiliated utilities have appealed these guidelines to the Ohio Supreme Court. In February 1997, the Ohio General Assembly formed the Joint Committee on Electric Utility Deregulation to study and report to the General Assembly concerning deregulation of the electric utility industry in Ohio. The co- chairs of the Joint Committee issued their report on January 6, 1998, which described plans for introducing electric retail competition to Ohio consumers. On February 18, 1998, the General Assembly's Joint Committee forwarded its report to the House Speaker and Senate President. The report contains the co-chairs report and the comments of other Committee members. The co-chairs report proposes the establishment of a fully competitive marketplace by the year 2000 and utility tax reform intended to place Ohio's utilities on a level playing field with out-of-state suppliers. One of the co-chairs has indicated her intention to introduce legislation based on the co-chairs report's recommendations. However, there are a number of other bills pending which could be used to enact deregulation. Virginia: Pursuant to a resolution of the Virginia legislature, in November 1997 the staff of the Virginia SCC provided its draft of a working model of a restructured electric utility industry for Virginia to the joint subcommittee of the legislature studying restructuring of the electric utility industry. Two major bills providing for the restructuring of the electric utility industry were acted on by the Virginia General Assembly. One bill, introduced by the chairman of the joint subcommittee, was "carried over" to serve as a framework for study and debate over the balance of 1998, with oversight provided by the joint subcommittee. The second bill, passed by the Virginia General Assembly in March 1998, provides a general timetable for the transition to retail competition by January 1, 2004, but leaves the details to be decided in subsequent legislation. West Virginia: In December 1996, the West Virginia PSC issued an order initiating a general investigation into the restructuring of the regulated electric industry. The Task Force established by the West Virginia PSC to study electric industry restructuring issued its Initial Report in October 1997 and Supplemental Report on Recommended Legislation in January 1998. On March 14, 1998, the West Virginia Legislature passed restructuring legislation. If signed into law, the bill would authorize the West Virginia PSC to proceed with the development of a plan for electric industry restructuring in West Virginia, if restructuring is determined by the West Virginia PSC to be in the public interest. Any plan developed and proposed by the West Virginia PSC must be approved by the West Virginia Legislature before such plan can be made effective. AEP Position on Competition In October 1995, AEP announced that it favored freedom for customers to purchase electric power from anyone that they choose. Generation and sale of electric power would be in the competitive marketplace. To facilitate reliable, safe and efficient service, AEP supports creation of independent system operators to operate the transmission system in a region of the United States. In addition, AEP supports the evolution of regional power exchanges which would establish a competitive marketplace for the sale of electric power. Transmission and distribution would remain monopolies and subject to regulation with respect to terms and price. Regulators would be able to establish distribution service charges which would provide, as appropriate, for recovery of stranded costs and regulatory assets. AEP's working model for industry restructuring envisions a progressive transition to full customer choice. Implementation of these measures would require legislative changes and regulatory approvals. Possible Strategic Responses In response to the competitive forces and regulatory changes being faced by AEP and its public utility subsidiaries, as discussed under this heading and under Regulation, AEP and its public utility subsidiaries have from time to time considered, and expect to continue to consider, various strategies designed to enhance their competitive position and to increase their ability to adapt to and anticipate changes in their utility business. These strategies may include business combinations with other companies, internal restructurings involving the complete or partial separation of their generation, transmission and distribution businesses, acquisitions of related or unrelated businesses, and additions to or dispositions of portions of their franchised service territories. AEP and its public utility subsidiaries may from time to time be engaged in preliminary discussions, either internally or with third parties, regarding one or more of these potential strategies. No assurances can be given as to whether any potential transaction of the type described above may actually occur, or as to its ultimate effect on the financial condition or competitive position of AEP and its public utility subsidiaries. New Business Development AEP continues to consider new business opportunities, particularly those which allow use of its expertise. These endeavors began in 1982 and are conducted through AEP Resources, Inc. (Resources), AEP Resources Service Company (formerly AEP Energy Services, Inc.) (AEPRESC) and AEP Energy Services, Inc. (formerly AEP Energy Solutions, Inc.) (AEPES). Resources' primary business is development of, and investment in, exempt wholesale generators, foreign utility companies, qualifying cogeneration facilities and other energy-related domestic and international investment opportunities and projects. On February 24, 1997, AEP and Public Service Company of Colorado (PSCo) jointly agreed with the Board of Directors of Yorkshire Electricity Group plc (Yorkshire Electricity) in the United Kingdom to make a cash tender offer (the Tender Offer) for Yorkshire Electricity. The Tender Offer valued Yorkshire Electricity at U.S. $2.4 billion. The Tender Offer was effected by Yorkshire Holdings plc, a holding company owned by Yorkshire Power Group Limited, which is equally owned and controlled by Resources and New Century International Inc. (NCII), a wholly-owned subsidiary of PSCo, which is a wholly-owned subsidiary of New Century Energies, Inc. Resources and NCII each contributed U.S. $360 million toward the Tender Offer with the remaining U.S. $1.7 billion funded through a non-recourse loan to Yorkshire Power Group Limited. Yorkshire Power Group gained effective control of Yorkshire Electricity on April 1, 1997. Yorkshire Electricity is an English independent regional electricity company. It is principally engaged in the distribution of elec- tricity to 2.1 million customers in its authorized service territory which is comprised of 3,860 square miles and located centrally in the east coast of England. Resources' indirect subsidiary, AEP Pushan Power LDC, has a 70% interest in Nanyang General Light Electric Co., Ltd. (Nanyang Electric), a joint venture organized to develop and build two 125 megawatt coal-fired generating units near Nanyang City in the Henan Province of The Peoples Republic of China. Nanyang Electric was established in 1996 by AEP Pushan Power LDC, Henan Electric Power Development Co. (15% interest) and Nanyang City Hengsheng Energy Development Company Limited (formerly Nanyang Municipal Finance Development Co.) (15% interest). Funding for the construction of the generating units has commenced and will continue through completion which is expected to occur by 1999. Resources' share of the total cost of the project of $190 million is estimated to be approximately $110 million. On October 2, 1997, Resources, DuPont and Conoco, the energy subsidiary of DuPont, signed a letter of intent to form two jointly held venture companies to provide energy management and capital to industrial and large commercial customers. AEP Conoco Energy Capital will acquire and lease back energy assets at industrial and large commercial facilities and provide future capital for energy projects. AEP Conoco Energy Management Services will provide energy management services. The ventures will initially acquire and manage industrial energy assets valued at approximately $1 billion for DuPont energy facilities at 33 U.S. industrial plants. Resources and DuPont will each invest approximately $125 million in equity in the joint ventures with the remainder to be financed through non-recourse debt. AEPRESC offers engineering, construction, project management and other consulting services for projects involving transmission, distribution or generation of electric power both domestically and internationally. AEP Communications, LLC (Communications) was formed in 1997 to pursue opportunities in the telecommunications field. Communications is currently constructing a fiber optic line that stretches between Kentucky, Ohio, Virginia and West Virginia. This fiber optic line will be capable of providing high speed telecommunications capacity to other telecommunications companies. In addition to establishing and providing fiber optic services, Communications also made investments in two companies engaged in providing digital personal communications services, the West Virginia PCS Alliance, LC and the Virginia PCS Alliance, LC. AEP has received approval from the SEC under PUHCA to issue and sell securities in an amount up to 50%, and is seeking approval to finance up to 100%, of its consolidated retained earnings (approximately $1,600,000,000 at December 31, 1997), for investment in exempt wholesale generators and foreign utility companies. Resources expects to investigate opportunities to develop and invest in new, and invest in existing, generation projects worldwide. The SEC adopted Rule 58, effective March 24, 1997, which permits AEP and other registered holding companies to invest up to 15% of consolidated capitalization in energy-related companies. AEPES, an energy-related company under Rule 58, is authorized to engage in energy-related activities, including marketing electricity, gas and other energy commodities. In July 1996, AEP Power Marketing, Inc. (AEPPM), a wholly-owned subsidiary of AEP, requested authority from FERC to market electric power at wholesale at market-based rates. In September 1996, the FERC accepted the filing, conditioned upon, among other things, the utility subsidiaries of AEP refraining from (1) selling nonpower goods or services to any affiliate at a price below its cost or market price, whichever is higher, and (2) purchasing nonpower goods or services from any affiliate at a price above market price. AEPPM has requested FERC to clarify that the applicability of this condition relates only to transactions between AEP utility subsidiaries and AEPPM. AEPPM is inactive pending FERC's decision. These continuing efforts to invest in and develop new business opportunities offer the potential of earning returns which may exceed those of rate-regulated operations. However, they also involve a higher degree of risk which must be carefully considered and assessed. AEP may make substantial investments in these and other new businesses. Proposed AEP-CSW Merger AEP and CSW entered into an Agreement and Plan of Merger, dated as of December 21, 1997, pursuant to which CSW would, on the closing date, merge with and into a wholly owned merger subsidiary of AEP with CSW being the surviving corporation. As a result of the merger, each outstanding share of common stock, par value $3.50 per share, of CSW (other than shares owned by AEP or CSW) shall be converted into the right to receive 0.6 of a share of common stock, par value $6.50 per share, of AEP. Based on the price of AEP's common stock on December 19, 1997, the transaction would be valued at $6.6 billion. The combined company will be named American Electric Power Company, Inc. and will be based in Columbus, Ohio. Consummation of the merger is subject to certain conditions, including receipt of approval of the merger and the transactions contemplated thereby by the shareholders of AEP and CSW and the receipt of the required regulatory approvals. Assuming the receipt of all required approvals, completion of the merger is anticipated to occur in the first half of 1999. CSW is a global, diversified public utility holding company based in Dallas, Texas. CSW owns four domestic electric utility subsidiaries serving 1.7 million customers in portions of the states of Texas, Oklahoma, Louisiana and Arkansas and a regional electricity company in the United Kingdom. CSW owns other international energy operations and non-utility subsidiaries involved in energy-related investments, telecommunications, energy efficiency services and financial transactions. Construction Program New Generation The AEP System companies are continuously involved in an assessment of the adequacy of its generation, transmission, distribution and other facilities necessary to provide for the reliable supply of electric power and energy to its customers. In this assessment and planning process, assumptions are continually being reviewed as new information becomes available, and assessments and plans are modified accordingly, as appropriate. Thus, system reinforcement plans are subject to change, particularly with the anticipated restructuring of the electric utility industry and the move to increasing competition in the marketplace. See Competition and Business Change. Committed or anticipated capability changes to the AEP System generation resources through the year 2001 include: a purchase from an independent power producer's hydro project with an expected capacity value of 28 megawatts, reratings of several existing AEP System generating units, and the expiration of the Rockport Unit 1 sale of 455 megawatts to VEPCo on December 31, 1999 (see AEGCo). Beyond these changes, there are no specific commitments for additions of new generation resources on the AEP System. In this regard, the most recent resource plan filed by AEP's electric utility subsidiaries with various state commissions indicates no need for new generation resources until beyond the year 2002. When the time for commitment to additional generation resources approaches, all means for adding such resources, including self- build and external resource options, will be considered. However, given the restructuring that is expected to take place in the industry, the need of AEP's operating companies for any additional generation resources in the fore- seeable future is highly uncertain. Proposed Transmission Facilities APCo: On September 30, 1997, APCo refiled applications in Virginia and West Virginia for certificates to build the Wyoming-Cloverdale 765,000-volt line. The preferred route for this line is approximately 132 miles in length, connecting APCo's Wyoming Station in southern West Virginia to APCo's Cloverdale Station near Roanoke, Virginia. APCo's estimated cost is $263,300,000. APCo announced this project in 1990. Since then it has been in the process of trying to obtain federal permits and state certificates. At the federal level, the U.S. Forest Service (Forest Service) is directing the preparation of an Environmental Impact Statement (EIS), which is required prior to granting permits for crossing lands under federal jurisdiction. Permits are needed from the (i) Forest Service to cross federal forests, (ii) Army Corps of Engineers to cross the New River and a watershed near the Wyoming Station, and (iii) National Park Service or Forest Service to cross the Appalachian National Scenic Trail. In June 1996, the Forest Service released a Draft EIS and preliminarily identified a "No Action Alternative" as its preferred alternative. If this alternative were incorporated into the Final EIS, APCo would not be authorized to cross federal forests administered by the Forest Service. The Forest Service stated that it would not prepare the Final EIS until after Virginia and West Virginia determined need and routing issues. In an interim order issued in 1995, the Virginia SCC found, based on the record before it, that there is a compelling need for additional electric capacity to serve APCo's Central and Eastern regions and that the proposed transmission line may be the best possible solution. In December 1996, APCo filed a report with the Virginia SCC reviewing the need for the project. Based on that review and after considering all other feasible alternatives, APCo concluded that the need for reinforcement of the transmission system serving its Central and Eastern areas remains compelling and the proposed project is the best alternative for addressing the need. Procedural schedules have been issued in each state. In Virginia, five public hearings will be held in March and April and an evidentiary hearing will be held in July. In West Virginia, three public meetings will be held in early May, followed by an evidentiary hearing. By statute, the West Virginia PSC has 400 days from the filing date, or November 4, 1998, to issue the certificate. If it fails to act, APCo receives the certificate automatically. Virginia does not have such a time constraint. If Virginia and West Virginia issue the required certificates, APCo will cooperate with the Forest Service to complete the EIS process and obtain the federal permits. Management estimates that the project cannot be completed before the winter of 2002-2003. However, given the findings in the Draft EIS, APCo cannot presently predict the schedule for completion of the state and federal permitting process. APCo and KEPCo: APCo and KEPCo have announced an improvement plan to be implemented during a four-year period (1996-1999) to reinforce their 138,000- volt transmission system. Included in this plan is a new transmission line to link KEPCo's Big Sandy Plant to communities in eastern Kentucky. APCo's and KEPCo's estimated project costs are $5,800,000 and $81,600,000, respectively. The KPSC approved the project in its order dated June 11, 1996. Construction commenced in late 1996. Construction Expenditures The following table shows the construction expenditures by AEGCo, APCo, CSPCo, I&M, KEPCo, OPCo and the AEP System and their respective consolidated subsidiaries during 1995, 1996 and 1997 and their current estimate of 1998 construction expenditures, in each case including AFUDC but excluding nuclear fuel and other assets acquired under leases. The construction expenditures for the years 1995-1997 were, and it is anticipated that the estimated construction expenditures for 1998 will be, approximately:
1995 1996 1997 1998 Actual Actual Actual Estimate (in thousands) AEGCo . . . . . . . . . . . $ 4,000 $ 2,200 $ 3,900 $ 4,200 APCo . . . . . . . . . . . 217,600 192,900 218,100 205,600 CSPCo . . . . . . . . . . . 99,500 93,600 108,900 117,900 I&M . . . . . . . . . . . . 113,000 90,500 123,400 169,100 KEPCo . . . . . . . . . . . 39,300 75,800 66,700 53,800 OPCo . . . . . . . . . . . 116,900 113,800 172,700 187,700 AEP System (a) . . . . . $601,200 $578,000 $762,000 $847,000
__________ (a) Includes expenditures of other subsidiaries not shown. Reference is made to the footnotes to the financial statements entitled Commitments and Contingencies incorporated by reference in Item 8, for further information with respect to the construction plans of AEP and its operating subsidiaries for the next three years. The System construction program is reviewed continuously and is revised from time to time in response to changes in estimates of customer demand, business and economic conditions, the cost and availability of capital, en- vironmental requirements and other factors. Changes in construction schedules and costs, and in estimates and projections of needs for additional facilities, as well as variations from currently anticipated levels of net earnings, Federal income and other taxes, and other factors affecting cash requirements, may increase or decrease the estimated capital requirements for the System's construction program. From time to time, as the System companies have encountered the industry problems described above, such companies also have encountered limitations on their ability to secure the capital necessary to finance construction expenditures. Environmental Expenditures: Expenditures related to compliance with air and water quality standards, included in the gross additions to plant of the System, during 1995, 1996 and 1997 and the current estimate for 1998 are shown below. Substantial expenditures in addition to the amounts set forth below may be required by the System in future years in connection with the modification and addition of facilities at generating plants for environmental quality controls in order to comply with air and water quality standards which have been or may be adopted.
1995 1996 1997 1998 Actual Actual Actual Estimate (in thousands) AEGCo . . . . . . . . . . . $ 0 $ 0 $ 0 $ 0 APCo . . . . . . . . . . . 7,800 10,500 9,100 11,500 CSPCo . . . . . . . . . . . 10,000 1,800 1,300 4,500 I&M . . . . . . . . . . . . 1,400 0 100 3,200 KEPCo . . . . . . . . . . . 600 100 1,300 4,000 OPCo . . . . . . . . . . . 3,100 1,600 11,800 32,800 AEP System . . . . . . . $ 22,900 $ 14,000 $ 23,600 $ 56,000
Financing It has been the practice of AEP's operating subsidiaries to finance current construction expenditures in excess of available internally generated funds by initially issuing unsecured short-term debt, principally commercial paper and bank loans, at times up to levels authorized by regulatory agencies, and then to reduce the short-term debt with the proceeds of subsequent sales by such subsidiaries of long-term debt securities and preferred stock, and cash capital contributions by AEP. It has been the practice of AEP, in turn, to finance cash capital contributions to the common stock equities of its subsidiaries by issuing unsecured short-term debt, principally commercial paper, and then to sell additional shares of Common Stock of AEP for the pur- pose of retiring the short-term debt previously incurred. In 1997, AEP issued approximately 1,755,000 shares of Common Stock pursuant to its Dividend Reinvestment and Stock Purchase Plan. Although prevailing interest costs of short-term bank debt and commercial paper generally have been lower than prevailing interest costs of long-term debt securities, whenever interest costs of short-term debt exceed costs of long-term debt, the companies might be adversely affected by reliance on the use of short-term debt to finance their construction and other capital requirements. During the period 1995-1997, external funds from financings and capital contributions by AEP amounted, with respect to APCo and KEPCo, to approximate- ly 28% and 70%, respectively, of the aggregate construction expenditures shown above. During this same period, the amount of funds used to retire long-term and short-term debt and preferred stock of AEGCo, CSPCo, I&M and OPCo exceeded the amount of funds from financings and capital contributions by AEP. The ability of AEP and its subsidiaries to issue short-term debt is limited by regulatory restrictions and, in the case of most of the operating subsidiaries, by provisions contained in certain debt and other instruments. The approximate amounts of short-term debt which the companies estimate that they were permitted to issue under the most restrictive such restriction, at January 1, 1998, and the respective amounts of short-term debt outstanding on that date, on a corporate basis, are shown in the following tabulation:
Total AEP Short-Term Debt AEP AEGCo APCo CSPCo I&M KEPCo OPCo System(a) (in millions) Amount authorized . . . . . . . . . . . $150 $ 80 $250 $175 $175 $150 $250 $1,230 Amount outstanding: Notes payable . . . . . . . . . . . . $ 24 $ 12 $ 34 $ 4 $ 57 -- $ 11 $ 199 Commercial paper . . . . . . . . . . 29 -- 96 63 63 37 68 356 $ 53 $ 12 $130 $ 67 $120 $ 37 $ 79 $ 555
__________ (a) Includes short-term debt of other subsidiaries not shown. Reference is made to the footnotes to the financial statements incorporated by reference in Item 8 for further information with respect to unused short-term bank lines of credit. In order to issue additional first mortgage bonds and preferred stock, it is necessary for APCo, CSPCo, I&M, KEPCo and OPCo to comply with earnings coverage requirements contained in their respective mortgages and charters. The most restrictive of these provisions in each instance generally requires (1) for the issuance of first mortgage bonds for purposes other than the refunding of outstanding first mortgage bonds, a minimum, before income tax, earnings coverage of twice the pro forma annual interest charges on first mortgage bonds and (2) for the issuance of additional preferred stock by APCo, I&M and OPCo, a minimum, after income tax, gross income coverage of one and one-half times pro forma annual interest charges and preferred stock dividends, in each case for a period of twelve consecutive calendar months within the fifteen calendar months immediately preceding the proposed new issue. In computing such coverages, the companies include as a component of earnings revenues collected subject to refund (where applicable) and, to the extent not limited by the instrument under which the computation is made, AFUDC, including amounts positioned and classified as an allowance for borrowed funds used during construction. These coverage provisions have from time to time restricted the ability of one or more of the above subsidiaries of AEP to issue senior securities. The respective mortgage and preferred stock coverages of APCo, CSPCo, I&M, KEPCo and OPCo under their respective mortgage and charter provisions, calculated on the foregoing basis and in accordance with the respective amounts then recorded in the accounts of the companies, assuming, with respect to the preferred stock coverages, that the respective short-term debt of the companies at those dates were to remain outstanding for a twelve-month period at the respective rates of interest prevailing at those dates, were at least those stated in the following table:
December 31, 1995 1996 1997 APCo Mortgage coverage . . . . . . . 3.47 3.98 3.72 Preferred stock coverage . . . 1.78 1.99 1.92 CSPCo Mortgage coverage . . . . . . . 3.90 4.44 4.95 I&M Mortgage coverage . . . . . . . 6.25 6.66 7.57 Preferred stock coverage . . . 2.63 3.07 2.88 KEPCo Mortgage coverage . . . . . . . 2.86 3.22 4.23 OPCo Mortgage coverage . . . . . . . 6.17 8.27 9.74 Preferred stock coverage . . . 3.04 3.63 3.67
Although certain other subsidiaries of AEP either are not subject to any coverage restrictions or are not subject to restrictions as constraining as those to which APCo, CSPCo, I&M, KEPCo and OPCo are subject, their ability to finance substantial portions of their construction programs may be subject to market limitations and other constraints unless other assurances are furnished. AEP believes that the ability of some of its subsidiaries to issue short- and long-term debt securities and preferred stock in the amounts required to finance their business may depend upon the timely approval of rate increase applications. If one or more of the subsidiaries are unable to continue the issuance and sale of securities on an orderly basis, such company or companies will be required to consider the curtailment of construction and other outlays or the use of alternative financing arrangements, if available, which may be more costly. AEP's subsidiaries have also utilized, and expect to continue to utilize, additional financing arrangements, such as leasing arrangements, including the leasing of utility assets, coal mining and transportation equipment and facilities and nuclear fuel. Pollution control revenue bonds have been used in the past and may be used in the future in connection with the construction of pollution control facilities; however, Federal tax law has limited the utilization of this type of financing except for purposes of certain financing of solid waste disposal facilities and of certain refunding of outstanding pollution control revenue bonds issued before August 16, 1986. Rates and Regulation General The rates charged by the electric utility subsidiaries of AEP are approved by the FERC or one of the state utility commissions as applicable. The FERC regulates wholesale rates and the state commissions regulate retail rates. In recent years the number of rate increase applications filed by the operating subsidiaries of AEP with their respective state commissions and the FERC has decreased. Under current rate regulation, if increases in operating, construction and capital costs exceed increases in revenues resulting from previously granted rate increases and increased customer demand, then it may be appropriate for certain of AEP's electric utility subsidiaries to file rate increase applications in the future. Generally the rates of AEP's operating subsidiaries are determined based upon the cost of providing service including a reasonable return on investment. Certain states served by the AEP System allow alternative forms of rate regulation in addition to the traditional cost-of-service approach. The IURC may approve alternative regulatory plans which could include setting customer rates based on market or average prices, price caps, index-based prices and prices based on performance and efficiency. The Virginia SCC may approve (i) special rates, contracts or incentives to individual customers or classes of customers and (ii) alternative forms of regulation including, but not limited to, the use of price regulation, ranges of authorized returns, categories of services and price indexing. All of the seven states served by the AEP System, as well as the FERC, either permit the incorporation of fuel adjustment clauses in a utility company's rates and tariffs, which are designed to permit upward or downward adjustments in revenues to reflect increases or decreases in fuel costs above or below the designated base cost of fuel set forth in the particular rate or tariff, or permit the inclusion of specified levels of fuel costs as part of such rate or tariff. AEP cannot predict the timing or probability of approvals regarding applications for additional rate changes, the outcome of action by regulatory commissions or courts with respect to such matters, or the effect thereof on the earnings and business of the AEP System. See Competition and Business Change. APCo FERC: On February 14, 1992, APCo filed with the FERC applications for an increase in its wholesale rates to Kingsport Power Company and non- affiliated customers in the amounts of approximately $3,933,000 and $4,759,000, respectively. APCo began collecting the rate increases, subject to refund, on September 15, 1992. In addition, the Financial Accounting Standards Board has issued Statement of Financial Accounting Standards No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions (SFAS 106), which requires employers, beginning in 1993, to accrue for the costs of retiree benefits other than pensions. These rates include the higher level of SFAS 106 costs. On November 9, 1993, the administrative law judge issued an initial decision recommending, among other things, the higher level of postretirement benefits other than pensions under SFAS 106. FERC action on APCo's applications is pending. Virginia: In June 1997, APCo filed an application with the Virginia SCC for approval of an alternative regulatory plan (Plan) and proposed, among other things, an increase of $30,500,000 in base rates on an annual basis to be effective July 13, 1997. APCo's Plan would institute a moratorium period during which no changes from the rate levels (including APCo's current 1.482 cents/kwh fuel factor) proposed by APCo would be made prior to January 1, 2001. In addition, the Plan includes a sharing of earnings above certain levels between APCo and its customers, and acceleration of the recovery of generation-related regulatory assets. On July 10, 1997, the Virginia SCC issued an order suspending implementation of the proposed rates until November 11, 1997 when these rates were placed into effect subject to refund. A hearing has been scheduled for July 6, 1998 to consider APCo's proposal. West Virginia: On December 27, 1996, the West Virginia PSC approved a settlement agreement among APCo and other parties. In accordance with that agreement, the West Virginia PSC reduced APCo's base rates and Expanded Net Energy Cost (ENEC) rates by $5,000,000 and $28,000,000, respectively, on a one-time annual basis, effective November 1, 1996. Under the terms of the agreement, APCo's rates would not increase prior to January 1, 2000 and, through this date, ENEC cost variances will be subject to deferred accounting and a cumulative ENEC recovery balance will be maintained. Regardless of the actual cumulative ENEC recovery balance at December 31, 1999, ratepayers will not be responsible for any cumulative underrecovery and any cumulative overre- coveries will be treated in a manner to be determined by the West Virginia PSC, except that ENEC overrecoveries during each calendar year through December 31, 1999, in excess of $10,000,000 per period, will be accumulated and shared equally between APCo and its ratepayers. CSPCo Zimmer Plant: The Zimmer Plant was placed in commercial operation as a 1,300-megawatt coal-fired plant on March 30, 1991. CSPCo owns 25.4% of the Zimmer Plant with the remainder owned by two unaffiliated companies, CG&E (46.5%) and DP&L (28.1%). From the in-service date of March 1991 until rates went into effect in May 1992, deferred carrying charges of $43,000,000 were recorded on the Zimmer Plant investment. Recovery of the deferred carrying charges will be sought in the next PUCO base rate proceeding in accordance with the PUCO accounting order that authorized the deferral. I&M On September 9, 1997, I&M filed a petition with the IURC requesting approval of accounting authority to increase nuclear decommissioning expense in an amount equal to the expiring Rockport phase-in plan amortization expense. The petition would increase I&M's Indiana jurisdictional nuclear decommissioning provision by $10,900,000 annually, effective September 1, 1997. A hearing on I&M's petition was held on February 3, 1998, and an order is awaited from the IURC. I&M has recorded the requested increased nuclear decommissioning expense provision, but has not deposited the increased provision into its nuclear decommissioning trust funds pending IURC approval. OPCo Under the terms of a stipulation agreement approved by the PUCO in November 1992, beginning December 1, 1994, the cost of coal burned at the Gavin Plant is subject to a 15-year predetermined price of $1.575 per million Btus with quarterly escalation adjustments. A 1995 PUCO-approved settlement agreement fixes the EFC factor at 1.465 cents per kwh for the period June 1995 through November 1998. After the first to occur of either full recovery of these costs or November 2009, the price that OPCo can recover for coal from its affiliated Meigs mine which supplies the Gavin Plant will be limited to the lower of cost or the then-current market price. The agreements provide OPCo with the opportunity to recover any operating losses incurred under the predetermined or fixed price, as well as its investment in, and liabilities and closing costs associated with, its affiliated mining operations attributable to its Ohio jurisdiction, to the extent the actual cost of coal burned at the Gavin Plant is below the predetermined price. Based on the estimated future cost of coal burned at Gavin Plant, management believes that the Ohio jurisdictional portion of the investment in, and liabilities and closing costs of, the affiliated mining operations, including deferred amounts, will be recovered under the terms of the pre- determined price agreement. Management intends to seek from non-Ohio jurisdictional ratepayers recovery of the non-Ohio jurisdictional portion of the investment in, and the liabilities and closing costs of, OPCo's Meigs, Muskingum and Windsor mines, but there can be no assurance that such recovery will be approved. The non-Ohio jurisdictional portion of shutdown costs for these mines, which includes the investment in the mines, leased asset buy- outs, reclamation costs and employee benefits, is estimated to be approximately $53,000,000 for Meigs, $37,000,000 for Muskingum and $12,000,000 for Windsor, after tax at December 31, 1997. OPCo's Muskingum and Windsor mines may have to close by January 2000 as a result of compliance by the Muskingum River Plant and Cardinal Unit 1 with the Phase II requirements of the Clean Air Act Amendments of 1990 (see Environmental and Other Matters - Air Pollution Control - Acid Rain). The Muskingum and Windsor mines supply coal to Muskingum River Plant and Cardinal Plant, respectively. The Muskingum and/or Windsor mines could close prior to January 2000 depending on the economics of continued operation under the terms of the 1995 settlement agreement. Unless future shutdown costs and/or the cost of coal production of OPCo's Meigs, Muskingum and Windsor mines can be recovered, AEP's and OPCo's results of operations would be adversely affected. Management anticipates closing the Muskingum mine in 1999, Windsor mine in 2000 and Meigs mine in 2001. Management, however, in making such a determination, will consider certain factors, including the competitiveness of the price of the coal extracted from the mine and the value of SO2 Allowances after the accelerated amortization of mine closure and the recovery of other costs. In November 1992, the municipal wholesale customers of OPCo filed a complaint with the SEC requesting an investigation of the sale of the Martinka mining operation to an unaffiliated company and an investigation into the pricing of OPCo's affiliated coal purchases back to 1986. OPCo has filed a response with the SEC seeking to dismiss this complaint. These customers also sought to intervene in three proceedings before the SEC. In September 1996, the SEC denied two requests to intervene, but has not ruled on the complaint. Fuel Supply The following table shows the sources of power generated by the AEP System:
1993 1994 1995 1996 1997 Coal . . . . . . . . . . . 86% 91% 88% 87% 92% Nuclear . . . . . . . . . . 13% 8% 11% 12% 7% Hydroelectric and other . . 1% 1% 1% 1% 1%
Variations in the generation of nuclear power are primarily related to refueling outages and, in 1997, the shutdown of the Cook Plant to respond to issues raised by the NRC. See Cook Plant Shutdown. Coal The Clean Air Act Amendments of 1990 provide for the issuance of annual allowance allocations covering sulfur dioxide emissions at levels below historic emission levels for many coal-fired generating units of the AEP System. Phase I of this program began in 1995 and Phase II begins in 2000, with both phases requiring significant changes in coal supplies and suppliers. The full extent of such changes, particularly in regard to Phase II, however, has not been determined. See Environmental and Other Matters - Air Pollution Control - Acid Rain for the current compliance plan. In order to meet emission standards for existing and new emission sources, the AEP System companies will, in any event, have to obtain coal supplies, in addition to coal reserves now owned by System companies, through the acquisition of additional coal reserves and/or by entering into additional supply agreements, either on a long-term or spot basis, at prices and upon terms which cannot now be predicted. No representation is made that any of the coal rights owned or controlled by the System will, in future years, produce for the System any major portion of the overall coal supply needed for consumption at the coal- fired generating units of the System. Although AEP believes that in the long run it will be able to secure coal of adequate quality and in adequate quantities to enable existing and new units to comply with emission standards applicable to such sources, no assurance can be given that coal of such quality and quantity will in fact be available. No assurance can be given either that statutes or regulations limiting emissions from existing and new sources will not be further revised in future years to specify lower sulfur contents than now in effect or other restrictions. See Environmental and Other Matters herein. The FERC has adopted regulations relating, among other things, to the circumstances under which, in the event of fuel emergencies or shortages, it might order electric utilities to generate and transmit electric power to other regions or systems experiencing fuel shortages, and to rate-making principles by which such electric utilities would be compensated. In addition, the Federal Government is authorized, under prescribed conditions, to allocate coal and to require the transportation thereof, for the use of power plants or major fuel-burning installations. System companies have developed programs to conserve coal supplies at System plants which involve, on a progressive basis, limitations on sales of power and energy to neighboring utilities, appeals to customers for voluntary limitations of electric usage to essential needs, curtailment of sales to certain industrial customers, voltage reductions and, finally, mandatory reductions in cases where current coal supplies fall below minimum levels. Such programs have been filed and reviewed with officials of Federal and state agencies and, in some cases, the state regulatory agency has prescribed actions to be taken under specified circumstances by System companies, subject to the jurisdiction of such agencies. The mining of coal reserves is subject to Federal requirements with respect to the development and operation of coal mines, and to state and Federal regulations relating to land reclamation and environmental protection, including Federal strip mining legislation enacted in August 1977. Continual evaluation and study is given to possible closure of existing coal mines and divestiture or acquisition of coal properties in light of Federal and state environmental and mining laws and regulations which may affect the System's need for or ability to mine such coal. Western coal purchased by System companies is transported by rail to a terminal on the Ohio River for transloading to barges for delivery to generating stations on the river. Subsidiaries of AEP lease approximately 3,460 coal hopper cars to be used in unit train movements, as well as 13 towboats, 307 jumbo barges and 183 standard barges. Subsidiaries of AEP also own or lease coal transfer facilities at various other locations. The System generating companies procure coal from coal reserves which are owned or mined by subsidiaries of AEP, and through purchases pursuant to long-term contracts, or on a spot purchase basis, from unaffiliated producers. The following table shows the amount of coal delivered to the AEP System during the past five years, the proportion of such coal which was obtained either from coal-mining subsidiaries, from unaffiliated suppliers under long- term contracts or through spot or short-term purchases, and the average delivered price of spot coal purchased by System companies:
1993 1994 1995 1996 1997 Total coal delivered to AEP operated plants (thousands of tons) . . . . . 40,561 49,024 46,867 51,030 54,292 Sources (percentage): Subsidiaries . . . . . . . . . . . . . . . . . . . 20% 15% 14% 13% 14% Long-term contracts . . . . . . . . . . . . . . . 66% 65% 75% 71% 66% Spot or short-term purchases . . . . . . . . . . . 14% 20% 11% 16% 20% Average price per ton of spot-purchased coal . . . $23.55 $23.00 $25.15 $23.85 $24.38
The average cost of coal consumed during the past five years by all AEP System companies, AEGCo, APCo, CSPCo, I&M, KEPCo and OPCo is shown in the following tables:
1993 1994 1995 1996 1997 Dollars per ton AEP System Companies . . . . . 33.57 33.95 32.52 31.70 31.77 AEGCo . . . . . . . . . . . . . 17.74 18.59 18.80 18.22 19.30 APCo . . . . . . . . . . . . . 42.65 39.89 38.86 37.60 36.09 CSPCo . . . . . . . . . . . . . 33.87 32.80 33.23 31.70 31.69 I&M . . . . . . . . . . . . . . 23.80 22.85 23.25 22.99 23.68 KEPCo . . . . . . . . . . . . . 27.08 26.83 26.91 27.25 26.76 OPCo . . . . . . . . . . . . . 38.12 41.10 37.58 35.96 36.00 Cost per Million Btu's AEP System Companies . . . . . 150.89 152.41 145.26 140.48 140.23 AEGCo . . . . . . . . . . . . . 107.71 112.06 112.87 109.25 115.21 APCo . . . . . . . . . . . . . 173.32 161.37 156.96 152.54 146.54 CSPCo . . . . . . . . . . . . . 143.66 140.45 140.79 134.60 134.44 I&M . . . . . . . . . . . . . . 129.39 123.62 125.50 121.16 123.36 KEPCo . . . . . . . . . . . . . 113.90 113.40 114.77 114.42 110.37 OPCo . . . . . . . . . . . . . 161.25 173.51 157.62 151.55 151.66
The coal supplies at AEP System plants vary from time to time depending on various factors, including customers' usage of electric power, space limitations, the rate of consumption at particular plants, labor unrest and weather conditions which may interrupt deliveries. At December 31, 1997, the System's coal inventory was approximately 43 days of normal System usage. This estimate assumes that the total supply would be utilized by increasing or decreasing generation at particular plants. The following tabulation shows the total consumption during 1997 of the coal-fired generating units of AEP's principal electric utility subsidiaries, coal requirements of these units over the remainder of their useful lives and the average sulfur content of coal delivered in 1997 to these units. Reference is made to Environmental and Other Matters for information concerning current emissions limitations in the AEP System's various jurisdictions and the effects of the Clean Air Act Amendments.
Average Sulfur Content of Delivered Coal Estimated Require- Total Consumption ments for Remainder During 1997 of Useful Lives Pounds of SO2 (In Thousands of Tons) (In Millions of Tons) By Weight Per Million Btu's AEGCo(a) . . . . 5,043 251 0.3% 0.7 APCo . . . . . . 11,682 446 0.8% 1.3 CSPCo . . . . . . 6,082(b) 236(b) 2.8% 4.7 I&M(c) . . . . . 7,304 294 0.7% 1.4 KEPCo . . . . . . 2,909 91 1.3% 2.1 OPCo . . . . . . 20,493 642 2.1% 3.5
(a) Reflects AEGCo's 50% interest in the Rockport Plant. (b) Includes coal requirements for CSPCo's interest in Beckjord, Stuart and Zimmer Plants. (c) Includes I&M's 50% interest in the Rockport Plant. AEGCo: See Fuel Supply - I&M for a discussion of the coal supply for the Rockport Plant. APCo: Substantially all of the coal consumed at APCo's generating plants is obtained from unaffiliated suppliers under long-term contracts and/or on a spot purchase basis. The average sulfur content by weight of the coal received by APCo at its generating stations approximated 0.8% during 1997, whereas the maximum sulfur content permitted, for emission standard purposes, for existing plants in the regions in which APCo's generating stations are located ranged between 0.78% and 2% by weight depending in some circumstances on the calorific value of the coal which can be obtained for some generating stations. CSPCo: CSPCo has coal supply agreements with unaffiliated suppliers for the delivery of approximately 3,400,000 tons per year through 1998. Some of this coal is washed to improve its quality and consistency for use principally at Unit 4 of the Conesville Plant. CSPCo has been informed by CG&E and DP&L that, with respect to the CCD Group units partly owned but not operated by CSPCo, sufficient coal has been contracted for or is believed to be available for the approximate lives of the respective units operated by them. Under the terms of the operating agreements with respect to CCD Group units, each operating company is contractually responsible for obtaining the needed fuel. I&M: I&M has two coal supply agreements with unaffiliated suppliers pursuant to which the suppliers are delivering low sulfur coal from surface mines in Wyoming, principally for consumption by the Rockport Plant. Under these agreements, the suppliers will sell to I&M, for consumption by I&M at the Rockport Plant or consignment to other System companies, coal with an average sulfur content not exceeding 1.2 pounds of sulfur dioxide per million Btu's of heat input. One contract with remaining deliveries of 52,010,543 tons expires on December 31, 2014 and another contract with remaining deliv- eries of 43,395,000 tons expires on December 31, 2004. All of the coal consumed at I&M's Tanners Creek Plant is obtained from unaffiliated suppliers under long-term contracts and/or on a spot purchase basis. KEPCo: Substantially all of the coal consumed at KEPCo's Big Sandy Plant is obtained from unaffiliated suppliers under long-term contracts and/or on a spot purchase basis. KEPCo has coal supply agreements with unaffiliated suppliers pursuant to which KEPCo will receive approximately 2,300,000 tons of coal in 1998. To the extent that KEPCo has additional coal requirements, it may purchase coal from the spot market and/or suppliers under contract to supply other System companies. OPCo: The coal consumed at OPCo's generating plants is obtained from both affiliated and unaffiliated suppliers. The coal obtained from unaffiliated suppliers is purchased under long-term contracts and/or on a spot purchase basis. OPCo and certain of its coal-mining subsidiaries own or control coal reserves in the State of Ohio which contain approximately 200,000,000 tons of clean recoverable coal, which ranges in sulfur content between 3.4% and 4.5% sulfur by weight (weighted average, 3.8%), which can be recovered based upon existing mining plans and projections and employing current mining practices and techniques. OPCo and certain of its mining subsidiaries own an additional 113,000,000 tons of clean recoverable coal in Ohio which ranges in sulfur content between 2.4% and 3.4% sulfur by weight (weighted average 2.6%). Recovery of this coal would require substantial development. OPCo and certain of its coal-mining subsidiaries also own or control coal reserves in the State of West Virginia which contain approximately 103,000,000 tons of clean recoverable coal ranging in sulfur content between 1.4% and 4.0% sulfur by weight (weighted average, 2.2%) of which approximately 26,000,000 tons can be recovered based upon existing mining plans and projections and employing current mining practices and techniques. Nuclear I&M has made commitments to meet certain of the nuclear fuel requirements of the Cook Plant. The nuclear fuel cycle consists of the mining and milling of uranium ore to uranium concentrates; the conversion of uranium concentrates to uranium hexafluoride; the enrichment of uranium hexafluoride; the fabrication of fuel assemblies; the utilization of nuclear fuel in the reactor; and the reprocessing or other disposition of spent fuel. Steps cur- rently are being taken, based upon the planned fuel cycles for the Cook Plant, to review and evaluate I&M's requirements for the supply of nuclear fuel. I&M has made and will make purchases of uranium in various forms in the spot, short-term, and mid-term markets until it decides that deliveries under long- term supply contracts are warranted. For purposes of the storage of high-level radioactive waste in the form of spent nuclear fuel, I&M has completed modifications to its spent nuclear fuel storage pool to permit normal operations through 2010. I&M's costs of nuclear fuel consumed do not assume any residual or salvage value for residual plutonium and uranium. Nuclear Waste and Decommissioning The Nuclear Waste Policy Act of 1982, as amended, establishes Federal responsibility for the permanent off-site disposal of spent nuclear fuel and high-level radioactive waste. Disposal costs are paid by fees assessed against owners of nuclear plants and deposited into the Nuclear Waste Fund created by the Act. In 1983, I&M entered into a contract with DOE for the disposal of spent nuclear fuel. Under terms of the contract, for the disposal of nuclear fuel consumed after April 6, 1983 by I&M's Cook Plant, I&M is paying to the fund a fee of one mill per kilowatt-hour, which I&M is currently recovering from customers. For the disposal of nuclear fuel consumed prior to April 7, 1983, I&M must pay the U.S. Treasury a fee estimated at approximately $71,964,000, exclusive of interest of $108,873,000 at December 31, 1997. The aggregate amount has been recorded as long-term debt. Because of the current uncertainties surrounding DOE's program to provide for permanent disposal of spent nuclear fuel, I&M has not yet paid any of the pre-April 1983 fee. At December 31, 1996, funds collected from customers to pay the pre-April 1983 fee and accrued interest approximated the long-term liability. In November 1996, the IURC and MPSC issued orders approving flexible funding procedures in which any excess funds collected for pre-April 7, 1983 spent nuclear fuel dis- posal would be deposited into I&M's nuclear decommissioning trust funds. On May 30, 1995, I&M and a group of unaffiliated utilities owning and operating nuclear plants filed a petition for review in the U.S. Court of Appeals for the District of Columbia Circuit requesting that the court issue a declaration that the Nuclear Waste Policy Act of 1982 (NWPA) imposes on DOE an unconditional obligation to begin acceptance of spent nuclear fuel and high level radioactive waste by January 31, 1998. On July 23, 1996, the court ruled that the NWPA creates an obligation in DOE, reciprocal to the utilities' obligation to pay, to start disposing of the spent nuclear fuel and high level radioactive waste no later than January 31, 1998. The court remanded the case to DOE, holding that determination of a remedy was premature, since DOE had not yet defaulted on its obligations. In December 1996, I&M received a letter from DOE advising that DOE anticipates that it will be unable to begin acceptance of spent nuclear fuel and high level radioactive waste for disposal in a repository or interim storage facility by January 31, 1998. On January 31, 1997, in anticipation of DOE's breach of their statutory and contractual obligations, I&M along with 35 unaffiliated utilities and 33 states filed joint petitions for review in the U.S. Court of Appeals for the District of Columbia Circuit requesting that the court permit the utilities to suspend further payments into the nuclear waste fund, authorize escrow of the payments, and order further action on the part of DOE to meet its obligations under the NWPA. On November 12, 1997, the Court of Appeals issued a decision granting in part and denying in part the utilities' request for relief. The court ordered DOE to proceed with contractual remedies and to refrain from concluding that DOE's delay is unavoidable due to the lack of a repository or the lack of interim storage authority. The court, however, declined to order DOE to begin disposing of fuel. On January 31, 1998, the deadline for DOE's performance, the DOE failed to begin disposing of the utilities' spent nuclear fuel. In February 1998, the states and the utilities filed with the Court of Appeals for additional relief in connection with DOE's failure to meet the January 31, 1998 deadline. Studies completed in 1997 estimate decommissioning and low-level radioactive waste disposal costs for the Cook Plant to range from $700,000,000 to $1.152 billion in 1997 nondiscounted dollars. The wide range is caused by variables in assumptions, including the estimated length of time spent nuclear fuel must be stored at the Cook Plant subsequent to ceasing operations, which depends on future developments in the federal government's spent nuclear fuel disposal program. Continued delays in the federal fuel disposal program can result in increased decommissioning costs. I&M is recovering decommissioning costs in its three rate-making jurisdictions based on at least the lower end of the range in the most recent respective decommissioning study available at the time of the rate proceeding (the study range utilized in the Indiana rate case, I&M's primary jurisdiction, was $588,000,000 to $1.102 billion in 1991 dollars). I&M records decommissioning costs in other operation expense and records a noncurrent liability equal to the decommissioning cost recovered in rates which was $28,000,000 in 1997, $27,000,000 in 1996 and $30,000,000 in 1995 (including $4,000,000 in special deposits). At December 31, 1997, I&M had recognized a decommissioning liability of $381,000,000. I&M will continue to reevaluate periodically the cost of decommissioning and to seek regulatory approval to revise its rates as necessary. Funds recovered through the rate-making process for disposal of spent nuclear fuel consumed prior to April 7, 1983 and for nuclear decommissioning have been segregated and deposited in external funds for the future payment of such costs. Trust fund earnings decrease the amount to be recovered from ratepayers. The ultimate cost of retiring I&M's Cook Plant may be materially different from the estimates contained in the site-specific study and the funding targets as a result of (a) the type of decommissioning plan selected, (b) the escalation of various cost elements (including, but not limited to, general inflation), (c) the further development of regulatory requirements governing decommissioning, (d) the limited availability to date of significant experience in decommissioning such facilities, (e) the technology available at the time of decommissioning differing significantly from that assumed in these studies and (f) the availability of nuclear waste disposal facilities. Accordingly, management is unable to provide assurance that the ultimate cost of decommissioning the Cook Plant will not be significantly greater than current projections. The Low-Level Waste Policy Act of 1980 (LLWPA) mandates that the responsibility for the disposal of low-level waste rests with the individual states. Low-level radioactive waste consists largely of ordinary refuse and other items that have come in contact with radioactive materials. To facilitate this approach, the LLWPA authorized states to enter into regional compacts for low-level waste disposal subject to Congressional approval. The LLWPA also specified that, beginning in 1986, approved compacts may prohibit the importation of low-level waste from other regions, thereby providing a strong incentive for states to enter into compacts. Michigan, the state where the Cook Plant is located, was a member of the Midwest Compact, but its membership was revoked in 1991. Michigan is responsible for developing a disposal site for the low-level waste generated in Michigan. Although Michigan amended its law regarding low-level waste site development in 1994 to allow a volunteer to host a facility, little progress has been made to date. A bill was introduced in 1996 to further address the issue but no action was taken. Development of required legislation and prog- ress with the site selection process has been inhibited by many factors, and management is unable to predict when a new disposal site for Michigan low- level waste will be available. On July 1, 1995, the disposal site in South Carolina reopened to accept waste from most areas of the U.S., including Michigan. This was the first opportunity for the Cook Plant to dispose of low-level waste since 1990. To the extent practicable, the waste formerly placed in storage and the waste presently generated are now being sent to the disposal site. Energy Policy Act - Nuclear Fees The Energy Policy Act of 1992 (Energy Act), contains a provision to fund the decommissioning and decontamination of DOE's existing uranium enrichment facilities from a combination of sources including assessments against electric utilities which purchased enrichment services from DOE facilities. I&M's remaining estimated liability is $39,325,000, subject to inflation adjustments, and is payable in annual assessments over the next nine years. I&M recorded a regulatory asset concurrent with the recording of the liability. The payments are being recorded and recovered as fuel expense. These assessments were held to be unlawful in a June 1995 decision of the U.S. Court of Federal Claims in a case involving an unaffiliated utility. Based upon that decision I&M filed a complaint in the same court seeking refunds of the assessments levied with respect to its enrichment services contracts. In May 1997 the U.S. Court of Appeals for the Federal Circuit reversed the lower court's 1995 decision. The utility has petitioned the U.S. Supreme Court for review of the decision. I&M's complaint has been stayed pending a final decision in this case. Environmental and Other Matters AEP's subsidiaries are subject to regulation by federal, state and local authorities with regard to air and water-quality control and other environmental matters, and are subject to zoning and other regulation by local authorities. It is expected that costs related to environmental requirements will eventually be reflected in the rates of AEP's electric utility subsidiaries and that AEP's electric utility subsidiaries will be able to provide for required environmental controls. However, some customers may curtail or cease operations as a consequence of higher energy costs. There can be no assurance that all such costs will be recovered. Moreover, legislation currently being proposed at the state and federal levels governing restructuring of the electric utility industry may also affect the recovery of certain costs. See Competition and Business Change. Except as noted herein, AEP's subsidiaries which own or operate generating, transmission and distribution facilities are in substantial compliance with pollution control laws and regulations. Air Pollution Control For the AEP System, compliance with the Clean Air Act (CAA) is requiring substantial expenditures that generally are being recovered through increases in the rates of AEP's operating subsidiaries. However, there can be no assurance that all such costs will be recovered. See Construction Program - Construction Expenditures. Acid Rain: The Acid Rain Program (Title IV) of the Clean Air Act Amendments of 1990 (CAAA) created an emission allowance program pursuant to which utilities are authorized to emit a designated quantity of sulfur dioxide (SO2), measured in tons per year, on a system wide or aggregate basis. Emission reductions are required by virtue of the establishment of annual allowance allocations at levels substantially below historical emission levels for most utility units. There are two phases of SO2 control under the Acid Rain Program. Phase I, effective January 1, 1995, requires SO2 emission reductions from certain units that emitted SO2 above a rate of 2.5 pounds per million Btu heat input in 1985. Phase I unit allowance allocations were calculated based on 1985 utilization rates and an emission rate of 2.5 pounds of SO2 per million Btu heat input. Phase I permits have been issued for all Phase I affected units in the AEP System. Phase II, which affects all fossil fuel-fired steam generating units with capacity greater than 25 megawatts imposes more stringent SO2 emission control requirements beginning January 1, 2000. If a unit emitted SO2 in 1985 at a rate in excess of 1.2 pounds per million Btu heat input, the Phase II allowance allocation is premised upon an emission rate of 1.2 pounds at 1985 utilization levels. If actual SO2 emissions for a Phase II affected unit in 1985 were less than 1.2 pounds per million Btu, the allowance allocation is, in most instances, based on the actual 1985 emission rate. In addition to regulating SO2 emissions, Title IV of the CAAA contains provisions regulating emissions of nitrogen oxides (NOx). In April 1995, Federal EPA promulgated NOx emission limitations for tangentially fired boilers and dry bottom wall-fired boilers for Phase I and Phase II units. In addition, on December 19, 1996, Federal EPA published final NOx emission limitations for wet bottom wall-fired boilers, cyclone boilers, units applying cell burner technology and all other types of boilers. The regulations also revised downward the NOx limitations applicable to tangentially fired and wall-fired boilers in Phase II. These emission limitations are to be achieved by January 1, 2000. On February 13, 1998, the U.S. Court of Appeals for the District of Columbia Circuit, in an appeal in which the AEP System operating companies participated, upheld the emission limitations. Title I National Ambient Air Quality Standards Attainment: The CAA contains additional provisions, other than the Acid Rain Program, which could require reductions in emissions of NOx and other pollutants from fossil fuel- fired power plants. Title I, dealing generally with attainment of federally set National Ambient Air Quality Standards (NAAQS), establishes a tiered system for classifying degrees of nonattainment with the one-hour NAAQS for ozone. Depending upon the severity of non-attainment within a given non- attainment area, reductions in NOx emissions from fossil fuel-fired power plants may be required as part of a state's plan for achieving attainment with the one-hour ozone NAAQS. While one-hour ozone NAAQS non-attainment is largely restricted to urban areas, AEP System generating units could be determined to be affecting downwind urban ozone concentrations and may therefore, eventually be required to reduce NOx emissions pursuant to Title I. In July 1997, Federal EPA revised the ozone and particulate matter NAAQS, creating a new eight-hour ozone standard and establishing a new standard for particulate matter less than 2.5 microns in diameter (PM2.5). Both of these new standards have the potential to affect adversely the operation of AEP System generating units. Substantial reductions in NOx emissions from fossil fuel-fired power plants may be required as part of a state's plan to attain the eight-hour ozone standard. The actual implementation of the new PM2.5 NAAQS has been delayed for five years. Substantial reductions in SO2 and/or other emissions from fossil fuel-fired power plants may be required as part of a state's plan to attain the PM2.5 NAAQS. The AEP System operating companies joined with other utilities to appeal the revised NAAQS by filing petitions for review in August and September 1997 in the U.S. Court of Appeals for the District of Columbia Circuit. On July 9, 1997, Federal EPA proposed revisions to the New Source Performance Standards applicable to new and modified fossil fuel-fired power plants. Federal EPA characterized its proposal as "fuel neutral" since it would impose the same stringent NOx emission limit (1.35lb./megawatt-hour net energy output) for coal-fired boilers as for gas-fired boilers. If finalized, the proposal would effectively require costly selective catalytic reduction or comparable technology to control NOx emissions from new or modified coal-fired boilers. NOx SIP Calls and the Ozone Transport Assessment Group: In 1995, the Environmental Council of States formed the Ozone Transport Assessment Group (OTAG) to study the role of transport of ozone and ozone precursor emissions (primarily NOx) in contributing to ozone nonattainment in the Northeast, Chicago, and Atlanta nonattainment areas. OTAG was comprised of the environmental commissioners of 37 eastern states, members of Federal EPA and representatives from environmental and industry groups. OTAG studied the ozone problem for two years, conducting extensive modeling and analysis of ozone levels and the effects of ozone transport. OTAG submitted its final recommendations to Federal EPA in July 1997. After receipt of the OTAG recommendations, Federal EPA in October 1997 issued a notice (NOx transport SIP call) concluding that certain State Implementation Plans are deficient because they allow NOx emissions that contribute excessively to ozone nonattainment in downwind states. Federal EPA's proposed NOx transport SIP call would establish state-by-state NOx emission budgets for the five-month ozone season to be met by the year 2002. The proposed NOx budgets apply to 22 eastern states and are premised mainly on the assumption of controlling power plant NOx emissions to 0.15 lb./MBtu (approximately 85% below 1990 levels). The NOx transport SIP call purports to implement both the new eight-hour ozone standard and the one-hour ozone standard. The NOx reductions called for by Federal EPA are clearly targeted at coal-fired electric utilities and may adversely impact the ability of electric utilities to obtain new and modified source permits. The cost of meeting NOx emissions reduction requirements that might be imposed as a result of the NOx transport SIP call cannot be precisely predicted at this time, but could be significant. Section 126 Petitions: On or about August 14, 1997, eight northeastern states (New York, New Hampshire, Maine, Massachusetts, Rhode Island, Pennsylvania, Connecticut, and Vermont) filed petitions with Federal EPA under Section 126 of the Clean Air Act, claiming that NOx emissions from power plants in midwestern states, including all the coal-fired plants of AEP's operating subsidiaries, prevent the Northeast from attaining the ozone NAAQS. Among other things, the petitioners generally seek NOx emission reductions 85% below 1990 levels from the utility sources in midwestern states. Federal EPA on or about December 19, 1997 entered into a Memorandum of Agreement (MOA) with the petitioning states that establishes a schedule for taking final action on the Section 126 petitions on approximately the same time frame as Federal EPA's final action on the NOx transport SIP call. The MOA calls for a proposed rulemaking on the Section 126 petitions by September 30, 1998 and final action by April 30, 1999 (subject to certain limited exceptions). On January 9, 1998, a number of utilities, including the operating companies of the AEP System, filed a petition in the U.S. Court of Appeals for the District of Columbia Circuit seeking a review of the MOA. On February 25, 1998, the eight northeastern states filed an action in the U.S. District Court for the Southern District of New York seeking an order directing Federal EPA to rule on the Section 126 petitions within 60 days of receipt. SO2 NAAQS: On January 30, 1998, the U.S. Court of Appeals for the District of Columbia Circuit remanded the final rule promulgated in May 1996 by Federal EPA reaffirming the existing primary NAAQS for SO2. The court directed Federal EPA to provide additional justification for the rule but did not specify a schedule for completion. Hazardous Air Pollutants: Hazardous air pollutant emissions from utility boilers are potentially subject to control requirements under Title III of the CAAA. The CAAA specifically directed Federal EPA to study potential public health impacts of hazardous air pollutants emitted from electric utility steam generating units. Federal EPA was required to report the results of this study to Congress by November 1993 and to regulate emissions of these hazardous pollutants if necessary. On February 25, 1998, Federal EPA issued a final report to Congress citing as potential health and environmental threats, mercury and three other hazardous air pollutants present in power plant emissions. Noting uncertainty regarding health effects and the absence of control technology for mercury, no immediate regulatory action was proposed regarding emission reductions. In addition, Federal EPA is required to study the deposition of hazardous pollutants in the Great Lakes, the Chesapeake Bay, Lake Champlain, and other coastal waters. As part of this assessment, Federal EPA is authorized to adopt regulations to prevent serious adverse effects to public health and serious or widespread environmental effects. It is possible that this assessment of water body deposition may result in additional regulation of electric utility steam generating units. Federal EPA was also required to study mercury emissions and report its findings to Congress by 1994. Federal EPA presented that report to Congress in December 1997. The report identifies electric utilities as being the third leading emitter of mercury. Presently, mercury emissions from electric utilities are not regulated under the CAA. However, Federal EPA intends to engage in further studies of mercury emissions, which may lead to additional regulation in the future. Permitting and Enforcement: The CAAA expanded the enforcement authority of the federal government by increasing the range of civil and criminal penalties for violations of the CAA and enhancing administrative civil provisions, adding a citizen suit provision and imposing a national operating permit system, emission fee program and enhanced monitoring, recordkeeping and reporting requirements for existing and new sources. On February 13, 1997, Federal EPA issued the Credible Evidence rule, which allows Federal EPA to use any credible evidence or information in lieu of, or in addition to, the test methods prescribed by the regulation for determining compliance with emission limits. This rule has the potential to expand significantly Federal EPA's ability to bring enforcement actions and to increase the stringency of the emission limits to which AEP System plants are subject. On March 10, 1997, a number of industries, including AEP System operating companies, filed petitions for review of the Credible Evidence Rule with the U.S. Court of Appeals for the District of Columbia Circuit. Oral argument in that case is scheduled to be heard on April 21, 1998. Global Climate Change: In December 1997, delegates from 167 nations, including the United States, agreed to a treaty, known as the "Kyoto Protocol," establishing legally-binding emission reductions for gases suspected of causing climate change. If the U.S. becomes a party to the treaty it will be bound to reduce emissions of carbon dioxide (CO2), methane and nitrous oxides by 7% below 1990 levels and emissions of hydrofluorcarbons, perfluorocarbons and sulphur hexafluoride 7% below 1995 levels in the years 2008-2012. The Protocol will be available for signature from March 1998 to March 1999 and requires ratification by at least 55 nations that account for at least 55% of developed countries' 1990 emissions of CO2 to enter into force. The agreement is not expected to be sent to the U.S. Senate for ratification before 1999. Since the AEP System is a significant emitter of carbon dioxide, its financial condition could be adversely affected by the imposition of limitations on CO2 emissions if compliance costs cannot be fully recovered from customers. In addition, any such severe program to reduce CO2 emissions could impose substantial costs on industry and society and erode the economic base that AEP's operations serve. West Virginia SO2 Limits: West Virginia promulgated SO2 limitations which Federal EPA approved in February 1978. The emission limitations for the Mitchell Plant have been approved by Federal EPA for primary ambient air quality (health-related) standards only. West Virginia is obligated to reanalyze SO2 emission limits for the Mitchell Plant with respect to secondary ambient air quality (welfare-related) standards. Because the CAA provides no specific deadline for approval of emission limits to achieve secondary ambient air quality standards, it is not certain when Federal EPA will take dispositive action regarding the Mitchell Plant. West Virginia has had a request to increase the SO2 emission limitation for Kammer pending before Federal EPA for many years, although the change has not been acted upon by Federal EPA. On August 4, 1994, however, Federal EPA issued a Notice of Violation to OPCo alleging that Kammer Plant was operating in violation of the applicable federally enforceable SO2 emission limit. On May 20, 1996, the Notice of Violation and an enforcement action subsequently filed by Federal EPA were resolved through the entry of a consent decree in the U.S. District Court for the Northern District of West Virginia. The decree provides for compliance with an interim emission limit of 6.5 pounds of SO2 per million Btu actual heat input on a three-hour basis and 5.8 pounds of SO2 per million Btu on an annual basis. West Virginia and industrial sources in the area of the Kammer Plant are developing a revision to the state implementation plan with respect to SO2 emission limitations which is to be submitted no later than November 1998. The interim emission limit for Kammer will remain in effect until after that time. Short Term SO2 Limits: On January 2, 1997, Federal EPA proposed a new intervention level program under the authority of Section 303 of the CAA to address five minute peak SO2 concentrations believed to pose a health risk to certain segments of the population. The proposal establishes a "concern" level and an "endangerment" level. States must investigate exceedances of the concern level and decide whether to take corrective action. If the endangerment level is exceeded, the state must take action to reduce SO2 levels. The effects of this proposed intervention program on AEP operations cannot be predicted at this time. Regional Haze: On July 31, 1997, Federal EPA proposed new rules to regulate regional haze attributable to anthropogenic emissions. The primary goal of the new regional haze program is to address visibility impairment in and around "Class I" protected areas, such as national parks and wilderness areas. Because regional haze precursor emissions are believed by Federal EPA to travel long distances, Federal EPA proposes to regulate such precursor emissions in every state. Under the proposal, each state must develop a regional haze control program that imposes controls necessary to steadily reduce visibility impairment in Class I areas on the worst days and that ensures that visibility remains good on the best days. This is accomplished using a unit of measurement known as a "deciview." The plan's goal is to reduce visibility impairment by one deciview or more over each 10-15 year period. The final time period will be set as part of the final rulemaking. The AEP System is a significant emitter of fine particulate matter and its precursors that could be linked to the creation of regional haze. The finalization of Federal EPA's proposed rule to control regional haze may have an adverse financial impact on AEP as it may trigger the requirement to install costly new pollution control devices to control emissions of fine particulate matter and its precursors (including SO2 and NOx). The actual impact of the regional haze regulations cannot be determined at this time. Life Extension: On July 21, 1992, Federal EPA published final regulations in the Federal Register governing application of new source rules to generating plant repairs and pollution control projects undertaken to comply with the CAA. Generally, the rule provides that plants undertaking pollution control projects will not trigger new source review requirements. The Natural Resources Defense Council and a group of utilities, including five AEP System companies, have filed petitions in the U.S. Court of Appeals for the District of Columbia Circuit seeking a review of the regulations. The court recently requested that the parties submit proposed briefing schedules. Water Pollution Control The Clean Water Act prohibits the discharge of pollutants to waters of the United States from point sources except pursuant to an NPDES permit issued by Federal EPA or a state under a federally authorized state program. Under the Clean Water Act, effluent limitations requiring application of the best available technology economically achievable are to be applied, and those limitations require that no pollutants be discharged if Federal EPA finds elimination of such discharges is technologically and economically achievable. The Clean Water Act provides citizens with a cause of action to enforce compliance with its pollution control requirements. Since 1982, many such actions against NPDES permit holders have been filed. To date, no AEP System plants have been named in such actions. All System Plants are operating with NPDES permits. Under EPA's regulations, operation under an expired NPDES permit is authorized provided an application is filed at least 180 days prior to expiration. Renewal applica- tions are being prepared or have been filed for renewal of NPDES permits which expire in 1998. The NPDES permits generally require that certain thermal impact study programs be undertaken. These studies have been completed for all System plants. Thermal variances are in effect for all plants with once-through cooling water. The thermal variances for Conesville and Muskingum River plants impose thermal management conditions that could result in load curtail- ment under certain conditions, but the cost impacts are not expected to be significant. Based on favorable results of in-stream biological studies, the thermal temperature limits for both Conesville and Muskingum River plants were raised in the renewed permits issued in 1996. Consequently, the potential for load curtailment and adverse cost impacts is further reduced. Certain mining operations conducted by System companies as discussed under Fuel Supply are also subject to Federal and state water pollution control requirements, which may entail substantial expenditures for control facilities, not included at present in the System's construction cost estimates set forth herein. The Federal Water Quality Act of 1987 requires states to adopt stringent water quality standards for a large category of toxic pollutants and to identify specialized control measures for dischargers to waters where it is shown through the use of total maximum daily loads (TMDLs) that water quality standards are not being met. Implementation of these provisions could result in significant costs to the AEP System if biological monitoring requirements and water quality-based effluent limits are placed in NPDES permits. In March 1995, Federal EPA finalized a set of rules which establish minimum water quality standards, anti-degradation policies and implementation procedures for more stringently controlling releases of toxic pollutants into the Great Lakes system. This regulatory package is called the Great Lakes Water Quality Initiative (GLWQI). The most direct compliance cost impact could be related to I&M's Cook Plant. Management cannot presently determine whether the GLWQI would have a significant adverse impact on AEP operations. The significance of such impact will depend on the outcome of Federal EPA's policy on intake credits and site specific variables as well as Michigan's implementation strategy. Federal EPA's rule is presently under review by the District of Columbia Circuit Court of Appeals in litigation initiated by several industry groups. If Indiana and Ohio eventually adopt the GLWQI criteria for statewide application, AEP System plants located in those states could also be affected. Solid and Hazardous Waste Section 311 of the Clean Water Act imposes substantial penalties for spills of Federal EPA-listed hazardous substances into water and for failure to report such spills. The Comprehensive Environmental Response, Compensa- tion, and Liability Act (CERCLA) expanded the reporting requirements to cover the release of hazardous substances generally into the environment, including water, land and air. AEP's subsidiaries store and use some of these hazardous substances, including PCBs contained in certain capacitors and transformers, but the occurrence and ramifications of a spill or release of such substances cannot be predicted. CERCLA and similar state law provide governmental agencies with the authority to require clean-up of hazardous waste sites and releases of hazardous substances into the environment and to seek compensation for damages to natural resources. Since liability under CERCLA is strict and can be applied retroactively, AEP System companies which previously disposed of PCB- containing electrical equipment and other hazardous substances may be required to participate in remedial activities at such disposal sites should environ- mental problems result. AEP System companies are presently defendants in five cases involving cost-recovery lawsuits at Federal EPA-identified CERCLA sites. OPCo is involved at three of these sites and I&M at the two other sites. AEP System companies are identified as Potentially Responsible Parties (PRPs) for seven additional federal sites, including CSPCo, KEPCo and Wheeling Power Company at one site each, I&M at three sites, and OPCo at two sites. I&M has been named as a PRP at one state remediation site. Management's present estimates do not anticipate material cleanup costs for identified sites for which AEP subsidiaries have been declared PRPs or are defendants in CERCLA cost recovery litigation. However, if for reasons not currently identified significant costs are incurred for cleanup, future results of operations and possibly financial condition would be adversely affected unless the costs can be recovered through rates. Regulations issued by Federal EPA under the Toxic Substances Control Act govern the use, distribution and disposal of PCBs, including PCBs in electrical equipment. Deadlines for removing certain PCB-containing electrical equipment from service have been met. In addition to handling hazardous substances, the System companies generate solid waste associated with the combustion of coal, the vast majority of which is fly ash, bottom ash and flue gas desulfurization wastes. These wastes presently are considered to be non-hazardous under RCRA and applicable state law and the wastes are treated and disposed in surface impoundments or landfills in accordance with state permits or authorization or beneficially utilized. As required by RCRA, EPA evaluated whether high volume coal combustion wastes (such as fly ash, bottom ash and flue gas desulfurization wastes) should be regulated as hazardous waste. In August, 1993 EPA issued a regulatory determination that such high volume coal combustion wastes should not be regulated as hazardous waste. For low volume coal combustion wastes, such as metal and boiler cleaning wastes, Federal EPA will gather additional information and make a regulatory determination by April 1999. Until that time, these low volume wastes are provisionally excluded from regulation under the hazardous waste provisions of RCRA. All presently generated hazardous waste is being disposed of at permitted off-site facilities in compliance with applicable Federal and state laws and regulations. For System facilities which generate such wastes, System companies have filed the requisite notices and are complying with RCRA and applicable state regulations for generators. Nuclear waste produced at the Cook Plant regulated under the Atomic Energy Act is excluded from regulation under RCRA. Federal EPA's technical requirements for underground storage tanks containing petroleum will require retrofitting or replacement of an appreciable number of tanks. Compliance costs for tank replacement and site remediation have not been significant to date. Electric and Magnetic Fields (EMF) EMF is found everywhere there is electricity. Electric fields are created by the presence of electric charges. Magnetic fields are produced by the flow of those charges. This means that EMF is created by electricity flowing in transmission and distribution lines, household wiring, and appliances. A number of studies in the past several years have examined the possibility of adverse health effects from EMF. While some of the epidemiological studies have indicated some association between exposure to EMF and health effects, the majority of studies have indicated no such association. On October 31, 1996, the National Academy of Sciences (NAS) released a report, based on a review of over 500 studies spanning 17 years of research, which contained the following summary statement: "... the con- clusion of the committee is that the current body of evidence does not show that exposure to these fields presents a human health hazard..." The epidemi- ological studies that have received the most public attention, including the NAS report, reflect a weak correlation between surrogate or indirect estimates of EMF exposure and certain cancers. Studies using direct measurements of EMF exposure show no such association. On July 3, 1997, the results of a five-year study by the National Cancer Institute (NCI) were released. The NCI researchers found no evidence that EMF in the home increases the risk of childhood cancer. The Energy Policy Act of 1992 established a coordinated Federal EMF research program which will end in 1998. The program funding is $65,000,000, half of which was provided by private parties including utilities. AEP has contributed over $400,000 to this program. AEP has also supported an extensive EMF research program coordinated by the Electric Power Research Institute, working closely with its staff and contributing more than $500,000 to this effort in 1997. See Research and Development. AEP's participation in the programs is a continuation of its efforts to monitor and support further research and to communicate with its customers and employees about this issue. Its operating company subsidiaries provide their residential customers with information and field measurements on request, although there is no scientific basis for interpreting such measurements. A number of lawsuits based on EMF-related grounds have been filed in recent years against electric utilities. A suit was filed on May 23, 1990 against I&M involving claims that EMF from a 345 KV transmission line caused adverse health effects. No specific amount has been requested for damages in this case and no trial date has been set. Some states have enacted regulations to limit the strength of magnetic fields at the edge of transmission line rights-of-way. No state which the AEP System serves has done so. In March 1993, The Ohio Power Siting Board issued its amended rules providing for additional consideration of the possible effects of EMF in the certification of electric transmission facilities. Applicants are required to address possible health effects and discuss the consideration of design alternatives with respect to estimates of EMF levels. Management cannot predict the ultimate impact of the question of EMF exposure and adverse health effects. If further research shows that EMF exposure contributes to increased risk of cancer or other health problems, or if the courts conclude that EMF exposure harms individuals and that utilities are liable for damages, or if states limit the strength of magnetic fields to such a level that the current electricity delivery system must be significantly changed, then the results of operations and financial condition of AEP and its operating subsidiaries could be materially adversely affected unless these costs can be recovered from ratepayers. Research and Development AEP and its subsidiaries are involved in a number of research projects which are directed toward developing more efficient methods of burning coal, reducing the contaminants resulting from combustion of coal, and improving the efficiency and reliability of power transmission, distribution and utilization. AEP System operating companies are members of the Electric Power Research Institute (EPRI), an organization that manages research and development on behalf of the U.S. electric utility industry. EPRI, founded in 1973, manages technical research and development programs for its members to improve power production, delivery and use. Approximately 700 utilities are members. Total AEP dues to EPRI were $15,300,000 for 1997, $9,900,000 for 1996 and $9,600,000 for 1995. Total research and development expenditures by AEP and its subsidiaries, including EPRI dues, were approximately $23,600,000 for the year ended December 31, 1997, $16,400,000 for the year ended December 31, 1996 and $13,600,000 for the year ended December 31, 1995. This includes expenditures of $4,600,000 for 1997, $3,300,000 for 1996 and $1,100,000 for 1995 related to pressurized fluidized-bed combustion, a process in which sulfur is removed during coal combustion and nitrogen oxide formation is minimized. SIGNATURE Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this amendment to the report on Form 10-K to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof. AMERICAN ELECTRIC POWER COMPANY, INC. By: /s/ G. P. Maloney (G. P. Maloney, Vice President) Date: April 1, 1998 -----END PRIVACY-ENHANCED MESSAGE-----