-----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, JXLQyk6RF3EKMTDjEWQQoKlJhEWxB9QjyDtLKgLvBC9vq/MM6KjzB5rMYiHAj0At 9n6TwGQYPeUKvreNzhJbDQ== 0000004904-02-000111.txt : 20020415 0000004904-02-000111.hdr.sgml : 20020415 ACCESSION NUMBER: 0000004904-02-000111 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 6 CONFORMED PERIOD OF REPORT: 20011231 FILED AS OF DATE: 20020329 FILER: COMPANY DATA: COMPANY CONFORMED NAME: CENTRAL POWER & LIGHT CO /TX/ CENTRAL INDEX KEY: 0000018734 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 740550600 STATE OF INCORPORATION: TX FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K405 SEC ACT: 1934 Act SEC FILE NUMBER: 001-12973 FILM NUMBER: 02592780 BUSINESS ADDRESS: STREET 1: 539 N CARANCAHUA ST CITY: CORPUS CHRISTI STATE: TX ZIP: 78401 BUSINESS PHONE: 3618815300 10-K405 1 module.txt AEP AND REPORTING SUBSIDIARIES - -------------------------------------------------------------------------------- SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D. C. 20549 ----------------- FORM 10-K ----------------- (Mark One) |X| ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2001 |_| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from _____________ to ______________
COMMISSION REGISTRANTS; STATES OF INCORPORATION; I.R.S. EMPLOYER FILE NUMBER ADDRESS AND TELEPHONE NUMBER IDENTIFICATION NOS. - ----------- ---------------------------- ------------------- 1-3525 AMERICAN ELECTRIC POWER COMPANY, INC. (A New York Corporation) 13-4922640 0-18135 AEP GENERATING COMPANY (An Ohio Corporation) 31-1033833 1-3457 APPALACHIAN POWER COMPANY (A Virginia Corporation) 54-0124790 0-346 CENTRAL POWER AND LIGHT COMPANY (A Texas Corporation) 74-0550600 1-2680 COLUMBUS SOUTHERN POWER COMPANY (An Ohio Corporation) 31-4154203 1-3570 INDIANA MICHIGAN POWER COMPANY (An Indiana Corporation) 35-0410455 1-6858 KENTUCKY POWER COMPANY (A Kentucky Corporation) 61-0247775 1-6543 OHIO POWER COMPANY (An Ohio Corporation) 31-4271000 0-343 PUBLIC SERVICE COMPANY OF OKLAHOMA (An Oklahoma Corporation) 73-0410895 1-3146 SOUTHWESTERN ELECTRIC POWER COMPANY (A Delaware Corporation) 72-0323455 0-340 WEST TEXAS UTILITIES COMPANY (A Texas Corporation) 75-0646790 1 Riverside Plaza, Columbus, Ohio 43215 Telephone (614) 223-1000
Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes X. No. --- Indicate by check mark if disclosure of delinquent filers with respect to American Electric Power Company, Inc. pursuant to Item 405 of Regulation S-K (229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ] Indicate by check mark if disclosure of delinquent filers with respect to Appalachian Power Company. Indiana Michigan Power Company or Ohio Power Company pursuant to Item 405 of Regulation S-K (229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements of Appalachian Power Company or Ohio Power Company incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. X --- AEP Generating Company, Columbus Southern Power Company, Kentucky Power Company, Public Service Company of Oklahoma and West Texas Utilities 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. SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
NAME OF EACH EXCHANGE REGISTRANT TITLE OF EACH CLASS ON WHICH REGISTERED ---------- ------------------- ------------------- AEP Generating Company None American Electric Common Stock, Power Company, Inc. $6.50 par value................................. New York Stock Exchange Appalachian Power 8-1/4% Junior Subordinated Deferrable Company Interest Debentures, Series A, Due 2026....... New York Stock Exchange 8% Junior Subordinated Deferrable Interest Debentures, Series B, Due 2027....... New York Stock Exchange 7.20% Senior Notes, Series A, Due 2038.............. New York Stock Exchange 7.30% Senior Notes, Series B, Due 2038................New York Stock Exchange Columbus Southern 8-3/8% Junior Subordinated Deferrable Power Company Interest Debentures, Series A, Due 2025........ New York Stock Exchange 7.92% Junior Subordinated Deferrable Interest Debentures, Series B, Due 2027........ New York Stock Exchange CPL Capital I 8.00% Cumulative Quarterly Income Preferred Securities, Series A, Liquidation Preference $25 per Preferred Security............New York Stock Exchange Indiana Michigan 8% Junior Subordinated Deferrable Power Company Interest Debentures, Series A, Due 2026........ New York Stock Exchange 7.60% Junior Subordinated Deferrable Interest Debentures, Series B, Due 2038..........New York Stock Exchange Kentucky Power 8.72% Junior Subordinated Deferrable Company Interest Debentures, Series A, Due 2025........ New York Stock Exchange Ohio Power Company 8.16% Junior Subordinated Deferrable Interest Debentures, Series A, Due 2025........ New York Stock Exchange 7.92% Junior Subordinated Deferrable Interest Debentures Series B, Due 2027..........New York Stock Exchange 7-3/8% Senior Notes, Series A, Due 2038............. New York Stock Exchange PSO Capital I 8.00% Trust Originated Preferred Securities, Series A, Liquidation Preference $25 per Preferred Security.......... New York Stock Exchange SWEPCo Capital I 7.875% Trust Preferred Securities, Series A, Liquidation amount $25 per Preferred Security......................... New York Stock Exchange
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 Central Power and Light Company 4.00% Cumulative Preferred Stock, Non-Voting, $100 par value 4.20% Cumulative Preferred Stock, Non-Voting, $100 par value Columbus Southern Power Company None Indiana Michigan Power Company 4.125% Cumulative Preferred Stock, Non-Voting, $100 par value Kentucky Power Company None Ohio Power Company 4.50% Cumulative Preferred Stock, Voting, $100 par value Public Service Company of Oklahoma None Southwestern Electric Power Company 4.28% Cumulative Preferred Stock, Non-Voting, $100 par value 4.65% Cumulative Preferred Stock, Non-Voting, $100 par value 5.00% Cumulative Preferred Stock, Non-Voting, $100 par value West Texas Utilities Company None
AGGREGATE MARKET VALUE OF VOTING AND NON-VOTING NUMBER OF SHARES COMMON EQUITY HELD OF COMMON STOCK BY NON-AFFILIATES OF OUTSTANDING OF THE REGISTRANTS AT THE REGISTRANTS AT FEBRUARY 1, 2002 FEBRUARY 1, 2002 ------------------------ ------------------ AEP Generating Company None 1,000 ($1,000 par value) American Electric Power Company, Inc. $13,478,213,062 322,368,167 ($6.50 par value) Appalachian Power Company None 13,499,500 (no par value) Central Power and Light Company None 6,755,535 ($25 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) Public Service Company of Oklahoma None 9,013,000 ($15 par value) Southwestern Electric Power Company None 7,536,640 ($18 par value) West Texas Utilities Company None 5,488,560 ($25 par value)
NOTE ON MARKET VALUE OF COMMON EQUITY HELD BY NON-AFFILIATES American Electric Power Company, Inc. owns, directly or indirectly, all of the common stock of AEP Generating Company, Appalachian Power Company, Central Power and Light Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company, Ohio Power Company, Public Service Company of Oklahoma, Southwestern Electric Power Company and West Texas Utilities Company (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 Part II ended December 31, 2001: AEP Generating Company American Electric Power Company, Inc. Appalachian Power Company Central Power and Light Company Columbus Southern Power Company Indiana Michigan Power Company Kentucky Power Company Ohio Power Company Public Service Company of Oklahoma Southwestern Electric Power Company West Texas Utilities Company Portions of Proxy Statement of American Electric Power Company, Inc. for Part III 2002 Annual Meeting of Shareholders, to be filed within 120 days after December 31, 2001 Portions of Information Statements of the following companies for 2002 Part III Annual Meeting of Shareholders, to be filed within 120 days after December 31, 2001: 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, CENTRAL POWER AND LIGHT COMPANY, COLUMBUS SOUTHERN POWER COMPANY, INDIANA MICHIGAN POWER COMPANY, KENTUCKY POWER COMPANY, OHIO POWER COMPANY, PUBLIC SERVICE COMPANY OF OKLAHOMA, SOUTHWESTERN ELECTRIC POWER COMPANY AND WEST TEXAS UTILITIES COMPANY. INFORMATION CONTAINED HEREIN RELATING TO ANY INDIVIDUAL REGISTRANT IS FILED BY SUCH REGISTRANT ON ITS OWN BEHALF. EXCEPT FOR AMERICAN ELECTRIC POWER COMPANY, INC., EACH REGISTRANT MAKES NO REPRESENTATION AS TO INFORMATION RELATING TO THE OTHER REGISTRANTS. ================================================================================ TABLE OF CONTENTS
PAGE NUMBER -------- Glossary of Terms...................................................................... i Forward-Looking Information............................................................ 1 PART I Item 1. Business............................................................. 2 Item 2. Properties........................................................... 35 Item 3. Legal Proceedings.................................................... 39 Item 4. Submission of Matters to a Vote of Security Holders.................. 40 Executive Officers of the Registrants.............................................. 40 PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters........................................... 42 Item 6. Selected Financial Data............................................ 42 Item 7. Management's Discussion and Analysis of Results of Operations and Financial Condition............................. 42 Item 7A. Quantitative and Qualitative Disclosures About Market Risk ...Risk 43 Item 8. Financial Statements and Supplementary Data........................ 43 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure......................... 43 PART III Item 10. Directors and Executive Officers of the Registrants................ 43 Item 11. Executive Compensation............................................. 44 Item 12. Security Ownership of Certain Beneficial Owners and Management................................................ 45 Item 13. Certain Relationships and Related Transactions..................... 46 PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K................................................... 46 Signatures............................................................................. 49 Index to Financial Statement Schedules................................................. S-1 Independent Auditors' Report........................................................... S-2 Exhibit Index.......................................................................... E-1
GLOSSARY OF TERMS The following abbreviations or acronyms used in this Form 10-K are defined below:
ABBREVIATION OR ACRONYM DEFINITION ----------------------- ---------- AEGCo................................... AEP Generating Company, an electric utility subsidiary of AEP. AEP .................................... American Electric Power Company, Inc. AEP System or the System................ The American Electric Power System, an integrated electric utility system, owned and operated by AEP's electric utility subsidiaries. AFUDC................................... Allowance for funds used during construction. Defined in regulatory systems of accounts as the net cost of borrowed funds used for construction and a reasonable rate of return on other funds when so used. APCo.................................... Appalachian Power Company, an electric utility subsidiary of AEP. Btu..................................... British thermal unit. Buckeye................................. Buckeye Power, Inc., an unaffiliated corporation. C3...................................... C3 Communications, Inc. CAA..................................... Clean Air Act. CAAA.................................... Clean Air Act Amendments of 1990. CCD Group............................... CSPCo, CG&E and DP&L. CERCLA.................................. Comprehensive Environmental Response, Compensation and Liability Act of 1980. CG&E.................................... The Cincinnati Gas & Electric Company, an unaffiliated utility company. CO2..................................... Carbon dioxide. Cook Plant.............................. The Donald C. Cook Nuclear Plant, owned by I&M, located near Bridgman, Michigan. CPL..................................... Central Power and Light Company, an electric utility subsidiary of AEP. CSPCo................................... Columbus Southern Power Company, an electric utility subsidiary of AEP. CSW.................................... Central and South West Corporation. DOE..................................... United States Department of Energy. DP&L.................................... The Dayton Power and Light Company, an unaffiliated utility company. East Zone Companies of AEP.............. APCo, CSPCo, I&M, KEPCo and OPCo. ERCOT................................... Electric Reliability Council of Texas. EWG..................................... Exempt wholesale generator. Federal EPA............................. United States Environmental Protection Agency. FERC.................................... Federal Energy Regulatory Commission (an independent commission within the DOE). FUCO.................................... Foreign utility company as defined by PUHCA. I&M..................................... Indiana Michigan Power Company, an electric utility subsidiary of AEP. IURC.................................... Indiana Utility Regulatory Commission. KEPCo................................... Kentucky Power Company, an electric utility subsidiary of AEP. MTM..................................... Mark-to-market. NOx..................................... Nitrogen oxide. NPDES................................... National Pollutant Discharge Elimination System. NRC..................................... Nuclear Regulatory Commission. Ohio EPA................................ Ohio Environmental Protection Agency. OPCo................................... Ohio Power Company, an electric utility subsidiary of AEP. OVEC.................................... Ohio Valley Electric Corporation, an electric utility company in which AEP and CSPCo own a 44.2% equity interest. PCBs.................................... Polychlorinated biphenyls.
i
ABBREVIATION OR ACRONYM DEFINITION ----------------------- ---------- PSO..................................... Public Service Company of Oklahoma, an electric utility subsidiary of AEP. PUCO.................................... The Public Utilities Commission of Ohio. PUHCA................................... Public Utility Holding Company Act of 1935, as amended. QF...................................... Qualifying facility as defined in the Public Utility Regulatory Policies Act of 1978. RCRA.................................... Resource Conservation and Recovery Act of 1976, as amended. Rockport Plant.......................... A generating plant, consisting of two 1,300,000-kilowatt coal-fired generating units, near Rockport, Indiana. SEC..................................... Securities and Exchange Commission. SEEBOARD................................ SEEBOARD Group plc, Crawley, West Sussex, United Kingdom. Service Corporation..................... American Electric Power Service Corporation, a service subsidiary of AEP. SO2..................................... Sulfur dioxide. SO2 Allowance........................... An allowance to emit one ton of sulfur dioxide granted under the Clean Air Act Amendments of 1990. SPP..................................... Southwest Power Pool. STPNOC.................................. STP Nuclear Operating Company, a non-profit Texas corporation which operates STP on behalf of its joint owners including CPL. SWEPCo.................................. Southwestern Electric Power Company, an electric utility subsidiary of AEP. TVA .................................... Tennessee Valley Authority. Vale.................................... Empresa De Electricidade Vale Paranapanema SA, a Brazilian Electric Distribution Company. VEPCo................................... Virginia Electric and Power Company, an unaffiliated utility company. Virginia SCC............................ Virginia State Corporation Commission. West Virginia PSC....................... Public Service Commission of West Virginia. West Zone Companies of AEP.............. CPL, PSO, SWEPCo and WTU. WTU..................................... West Texas Utilities Company, an electric utility subsidiary of AEP. Zimmer or Zimmer Plant.................. Wm. H. Zimmer Generating Station, a 1,300,000-kilowatt coal-fired generating unit commonly owned by CSPCo (25.4%), CG&E (46.5%) and DP&L (28.1%), and operated by CG&E.
ii FORWARD-LOOKING INFORMATION - -------------------------------------------------------------------------------- This report made by AEP and certain of its subsidiaries includes forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. These forward-looking statements reflect assumptions and involve a number of risks and uncertainties. Among the factors that could cause actual results to differ materially from forward-looking statements are: - Electric load and customer growth. - Abnormal weather conditions. - Available sources of and prices for coal and gas. - Availability of generating capacity. - Litigation concerning AEP's merger with CSW. - The timing of the implementation of AEP's restructuring plan. - Risks related to energy trading and construction under contract. - The speed and degree to which competition is introduced to our power generation business. - The ability to recover net regulatory assets, other stranded costs and implementation costs in connection with deregulation of generation in certain states. - New legislation and government regulations. - The structure and timing of a competitive market for electricity and its impact on prices. - The ability of AEP to successfully control its costs. - The success of new business ventures. - International developments affecting AEP's foreign investments. - The effects of fluctuations in foreign currency exchange rates. - The economic climate and growth in AEP's service and trading territories, both domestic and foreign. - The ability of AEP to comply with or to challenge successfully new environmental regulations and to litigate successfully claims that AEP violated the CAA. - Inflationary trends. - Changes in electricity and gas market prices and interest rates. - Other risks and unforeseen events. 1 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 marketing and trading of power and gas and the furnishing of electric service. The service area of AEP's domestic electric utility subsidiaries covers portions of the states of Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia. The generating and transmission facilities of AEP's subsidiaries are physically interconnected, and their operations are coordinated, as a single integrated electric utility system. Transmission networks are interconnected with extensive distribution facilities in the territories served. The electric utility subsidiaries of AEP, which do business as "American Electric Power," have traditionally provided electric service, consisting of generation, transmission and distribution, on an integrated basis to their retail customers. At December 31, 2001, the subsidiaries of AEP had a total of 27,726 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 917,000 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, 2001, APCo and its wholly owned subsidiaries had 2,629 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. CPL (organized in Texas in 1945) is engaged in the generation, sale, purchase, transmission and distribution of electric power to approximately 689,000 customers in southern Texas, and in supplying electric power at wholesale to other utilities, municipalities and rural electric cooperatives. At December 31, 2001, CPL had 1,374 employees. Among the principal industries served by CPL are oil and gas extraction, food processing, apparel, metal refining, chemical and petroleum refining, plastics, and machinery equipment. 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 678,000 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, 2001, CSPCo had 1,222 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. 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. 2 I&M (organized in Indiana in 1925) is engaged in the generation, sale, purchase, transmission and distribution of electric power to approximately 567,000 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, 2001, I&M had 2,851 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 173,000 customers in an area in eastern Kentucky, and in supplying electric power at wholesale to other utilities and municipalities in Kentucky. At December 31, 2001, KEPCo had 427 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 45,000 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, 2001, Kingsport Power Company had 58 employees. OPCo (organized in Ohio in 1907 and re-incorporated in 1924) is engaged in the generation, sale, purchase, transmission and distribution of electric power to approximately 698,000 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, 2001, OPCo and its wholly owned subsidiaries had 2,297 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. PSO (organized in Oklahoma in 1913) is engaged in the generation, sale, purchase, transmission and distribution of electric power to approximately 502,000 customers in eastern and southwestern Oklahoma, and in supplying electric power at wholesale to other utilities, municipalities and rural electric cooperatives. At December 31, 2001, PSO had 989 employees. Among the principal industries served by PSO are natural gas and oil production, oil refining, steel processing, aircraft maintenance, paper manufacturing and timber products, glass, chemicals, cement, plastics, aerospace manufacturing, telecommunications, and rubber goods. SWEPCo (organized in Delaware in 1912) is engaged in the generation, sale, purchase, transmission and distribution of electric power to approximately 431,000 customers in northeastern Texas, northwestern Louisiana, and western Arkansas, and in supplying electric power at wholesale to other utilities, municipalities and rural electric cooperatives. At December 31, 2001, SWEPCo had 1,375 employees. Among the principal industries served by SWEPCo are natural gas and oil production, petroleum 3 refining, manufacturing of pulp and paper, chemicals, food processing, and metal refining. The territory served by SWEPCo also includes several military installations, colleges, and universities. Wheeling Power Company (organized in West Virginia in 1883 and reincorporated in 1911) provides electric service to approximately 41,000 customers in northern West Virginia. Wheeling Power Company has no generating facilities of its own. It purchases electric power distributed to its customers from OPCo. At December 31, 2001, Wheeling Power Company had 64 employees. WTU (organized in Texas in 1927) is engaged in the generation, sale, purchase, transmission and distribution of electric power to approximately 189,000 customers in west and central Texas, and in supplying electric power at wholesale to other utilities, municipalities and rural electric cooperatives. At December 31, 2001, WTU had 689 employees. The principal industry served by WTU is agriculture. The territory served by WTU also includes several military installations and correctional facilities. 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 and KEPCo. 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. The AEP System is an integrated electric utility system and, as a result, the member companies of the AEP System have contractual, financial and other business relationships with the other member companies, such as participation in the AEP System savings and retirement plans and tax returns, sales of electricity, transportation and handling of fuel, sales or rentals of property and interest or dividend payments on the securities held by the companies' respective parents. AEP-CSW MERGER On June 15, 2000, CSW merged with and into a wholly owned merger subsidiary of AEP with CSW being the surviving corporation. The merger was pursuant to an Agreement and Plan of Merger, dated as of December 21, 1997, that AEP and CSW had entered into. 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) was converted into 0.6 of a share of common stock, par value $6.50 per share, of AEP. CSW's four wholly-owned domestic electric utility subsidiaries are CPL, PSO, SWEPCo and WTU. AEP is complying or intends to comply with the following conditions imposed by the FERC as part of the FERC's order approving the merger: - Transfer operational control of AEP's east and west transmission systems to fully-functioning, FERC-approved regional transmission organizations. See Transmission Services for Non-Affiliates. - Two interim transmission-related mitigation measures consisting of market monitoring and independent calculation and posting of available transmission capacity to monitor the operation of AEP's east transmission system. AEP implemented these measures upon the consummation of the merger. - Divestiture of 550 MW of generating capacity comprised of 300 MW of capacity in SPP and 250 MW of capacity in ERCOT. AEP must complete divestiture of the SPP capacity by July 1, 2002. AEP has completed divestiture of the ERCOT capacity. The FERC found that certain energy sales of SPP and ERCOT capacity would be reasonable and effective interim mitigation measures until completion of the required SPP and ERCOT divestitures. As required by the FERC, the proposed interim energy sales were in effect when the merger was consummated. 4 Litigation: On January 18, 2002, the U.S. Court of Appeals for the District of Columbia ruled that the SEC failed to prove that the merger met the requirements of PUHCA and remanded the case to the SEC for further review. The court held that the SEC must explain its conclusion that the merger met PUHCA requirements that utilities be "physically interconnected" and justify its finding that the merger will result in a combined entity that is confined to a "single area or region." In its June 2000 approval of the merger, the SEC agreed with AEP that AEP's and CSW's systems are interconnected because they have transmission access rights to a single high-voltage line through Missouri and also meet the PUHCA's single region requirement because it is now technically possible to centrally control the output of power plants across many states. In its ruling, the court held that the SEC failed to explain its conclusions that the transmission integration and single region requirements are satisfied. Management believes that the merger meets the requirements of PUHCA and expects the matter to be resolved favorably. 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 and CPL are subject to regulation by the NRC under the Atomic Energy Act of 1954, as amended, with respect to the operation of the Cook Plant and STP, respectively. Possible Change to PUHCA The provisions of PUHCA, administered by the SEC, regulate all aspects of a registered holding company system, such as the AEP System. PUHCA requires that the operations of a registered holding company system be limited to a single integrated public utility system and such other businesses as are incidental or necessary to the operations of the system. In addition, PUHCA governs, among other things, financings, sales or acquisitions of assets and intra-system transactions. On June 20, 1995, the SEC released a report from its Division of Investment Management recommending a conditional repeal of PUHCA, including its limits on financing and on geographic and business diversification. Specific federal authority, however, would be preserved over access to the books and records of registered holding company systems, audit authority over registered holding companies and their subsidiaries and oversight over affiliate transactions. This authority would be transferred to the FERC. Following the report, legislation was introduced in Congress to repeal PUHCA and transfer certain federal authority to the FERC as recommended in the SEC report. Since 1997, such PUHCA repeal language has been reintroduced in each session of Congress both as a separate bill and as part of broader legislation regarding changes in the electric industry. Legislative hearings were held but neither the House of Representatives nor the Senate passed any PUHCA repeal legislation. A number of bills contemplating PUHCA repeal separately and with the restructuring of the electric utility industry have been introduced in the current Congress. See Competition and Business Change. If PUHCA is repealed, registered holding company systems, including the AEP System, will be able to compete in the changing industry without the constraints of PUHCA. Management of AEP believes that removal of these constraints would be beneficial to the AEP System. PUHCA and the rules and orders of the SEC currently require that transactions between associated companies in a registered holding company system be performed at cost with limited exceptions. Over the years, the AEP System has developed numerous affiliated service, sales and construction relationships and, in some cases, invested significant capital and developed significant operations in reliance upon the ability to recover its full costs under these provisions. 5 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. Rates 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, except for the states of Ohio, Texas and Virginia as noted below. Certain states served by the AEP System allow alternative forms of rate regulation in addition to the traditional cost-of-service approach. However, the rates of AEP's operating subsidiaries in those states continue to be cost-based. The IURC may approve alternative regulatory plans which could include setting customer rates based on market or average prices, price caps, index-based prices and prices based on performance and efficiency. AEP is exposed to risk from changes in the market prices of coal and natural gas used to generate electricity where generation is no longer regulated or where existing fuel clauses are suspended or frozen. The protection afforded by fuel clause recovery mechanisms has either been eliminated by the implementation of customer choice in Ohio (effective January 1, 2001) and in the ERCOT power grid area of Texas (effective January 1, 2002) or frozen by settlement agreements in Indiana, Michigan, and West Virginia. To the extent the fuel supply of the generating units in these states is not under fixed price long-term contracts, AEP is subject to market price risk. AEP continues to be protected against market price changes by active fuel clauses in Oklahoma, Arkansas, Louisiana, Kentucky, Virginia and the SPP area of Texas. AEP cannot predict the timing or probability of approvals regarding applications for additional rate changes, the outcome of action by regulatory commissions or courts with respect to such matters, or the effect thereof on the earnings and business of the AEP System. In addition, current rate regulation may, and in the case of Ohio, Texas and Virginia has been, subject to significant revision. See Competition and Business Change and the footnote to the financial statements entitled Customer Choice and Industry Restructuring. 6 CLASSES OF SERVICE The principal classes of service from which the domestic electric utility subsidiaries of AEP derive revenues and the amount of such revenues during the year ended December 31, 2001 are as follows:
AEP SYSTEM(a) AEGCo APCo CPL CSPCo --------- ----- ---- --- ----- (IN THOUSANDS) Wholesale Business: Residential............................... $ 3,553,216 $ 0 $ 587,062 $ 660,884 $ 477,341 Commercial................................ 2,328,383 0 267,312 473,337 426,444 Industrial................................ 2,388,354 0 353,070 345,071 141,583 Other Retail Customers.................... 419,232 0 77,258 49,007 46,948 Energy Delivery........................... (3,356,000) (575,036) (473,182) (483,219) ------------- -------------- ------------- --------- --------- Total Retail........................... 5,333,185 0 709,666 1,055,117 609,097 Marketing and Trading-Electricity......... 35,339,641 227,338 5,571,750 1,671,686 3,117,136 Marketing and Trading-Gas................. 14,368,857 0 0 0 0 Unrealized MTM Income:.................... Electric.............................. 209,660 0 29,334 19,930 16,730 Gas................................... 46,990 0 0 0 0 Other..................................... 631,016 210 113,644 101,812 73,681 ------------- -------------- ------------- --------- --------- Total Wholesale Business............ 55,929,349 227,548 6,424,394 2,848,545 3,816,644 ------------- -------------- ------------- --------- --------- Energy Delivery Business:.................... Transmission.............................. 1,029,000 0 180,244 162,734 109,824 Distribution.............................. 2,327,000 0 394,792 310,448 373,395 ------------- -------------- ------------- --------- --------- Total Energy Delivery............... 3,356,000 0 575,036 473,182 483,219 ------------- -------------- ------------- --------- --------- Other Investments:........................... SEEBOARD.................................. 1,451,233 0 0 0 0 CitiPower................................. 349,773 0 0 0 0 Other..................................... 170,645 0 0 0 0 ------------- -------------- ------------- --------- --------- Total Other Investments............. 1,971,651 0 0 0 0 ------------- -------------- ------------- --------- --------- Total Revenues................ $ 61,257,000 $ 227,548 $ 6,999,430 $ 3,321,727 $ 4,299,863 ============= ============== ============= ========= =========
I&M KEPCo OPCo PSO SWEPCo WTU --- ----- ---- --- ------ ---- (IN THOUSANDS) Wholesale Business: Residential............................... $ 350,600 $ 109,882 $ 444,418 $ 381,515 $ 321,022 $ 160,520 Commercial................................ 218,818 47,369 235,220 305,525 226,946 98,153 Industrial................................ 323,157 92,215 526,431 215,038 273,096 60,032 Other Retail Customers.................... 59,983 16,058 68,968 12,746 33,271 44,318 Energy Delivery........................... (314,410) (134,619) (552,713) (261,877) (333,004) (169,036) --------- --------- --------- --------- -------- ------- Total Retail........................... 638,148 130,905 722,324 652,947 521,331 193,987 Marketing and Trading-Electricity......... 3,783,302 1,364,877 4,848,386 1,258,861 1,653,208 648,527 Marketing and Trading-Gas................. 0 0 0 0 0 0 Unrealized MTM Income:.................... Electric............................. 0 0 23,139 0 10,830 4,390 Gas.................................. 0 0 0 0 0 0 Other..................................... 67,765 28,994 115,840 27,564 56,075 48,331 --------- --------- --------- --------- -------- ------- Total Wholesale Business............ 4,489,215 1,524,776 5,709,689 1,939,372 2,241,444 895,235 --------- --------- --------- --------- -------- ------- Energy Delivery Business:.................... Transmission.............................. 122,345 53,697 167,399 63,045 81,324 75,443 Distribution.............................. 192,065 80,922 385,314 198,832 251,680 93,593 --------- --------- --------- --------- -------- ------- Total Energy Delivery............... 314,410 134,619 552,713 261,877 333,004 169,036 --------- --------- --------- --------- -------- ------- Other Investments: SEEBOARD.................................. 0 0 0 0 0 0 CitiPower................................. 0 0 0 0 0 0 Other 0 0 0 0 0 0 --------- --------- --------- --------- -------- ------- Total Other Investments............. 0 0 0 0 0 0 --------- --------- --------- --------- -------- ------- Total Revenues................ $ 4,803,625 $1,659,395 $ 6,262,402 $ 2,201,249 $ 2,574,448 $ 1,064,271 ========= ========= =========== =========== =========== ===========
- --------------------------- (a) Includes revenues of other subsidiaries not shown and elimination of intercompany transactions. 7 SALE OF POWER AEP's electric utility subsidiaries own or lease generating stations with total generating capacity of approximately 38,300 megawatts. See Item 2. Properties, for more information regarding the generating stations. They operate their generating plants as a single interconnected and coordinated electric utility system and, in the east zone, share the costs and benefits in the AEP System Power Pool. As discussed below under AEP System Power Pool, after corporate separation, the public utility subsidiaries that are no longer regulated at the state level will participate in a separate power pool. Most of the electric power generated at AEP's generating stations is sold, in combination with transmission and distribution services, to retail customers of AEP's utility subsidiaries in their service territories. See Regulation--Rates. Some of the electric power is sold at wholesale to non-affiliated companies. AEP System Power Pool APCo, CSPCo, I&M, KEPCo and OPCo are parties to the Interconnection Agreement, dated July 6, 1951, as amended (the Interconnection Agreement), defining how they share the costs and benefits associated with their 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. As part of AEP's restructuring settlement agreement filed with the FERC, CSPCo and OPCo would no longer be parties to the Interconnection Agreement and certain other modifications to its terms would also be made. See Competition and Business Change--AEP Restructuring Plan. Power marketing and trading transactions (trading activities) are conducted by the AEP Power Pool and shared among the parties under the Interconnection Agreement. Trading activities involve the purchase and sale of electricity under physical forward contracts at fixed and variable prices and the trading of electricity contracts including exchange traded futures and options and over-the-counter options and swaps. The majority of these transactions represent physical forward contracts in the AEP System's traditional marketing area and are typically settled by entering into offsetting contracts. The regulated physical forward contracts are recorded on a gross basis in the month when the contract settles. In addition, the AEP Power Pool enters into transactions for the purchase and sale of electricity options, futures and swaps, and for the forward purchase and sale of electricity outside of the AEP System's traditional marketing area. 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, 1999, 2000 and 2001: 1999(a) 2000(a) 2001(a) ---- ---- ---- (IN THOUSANDS) APCo.............. $ (89,100) $(274,000) $(256,700) CSPCo............. (184,500) (250,400) (251,200) I&M............... (61,700) 93,900 166,200 KEPCo............. 23,700 (21,500) (27,600) OPCo.............. 311,600 452,000 369,300 - ------------------------- (a) Includes credits and charges from allowance transfers related to the transactions. CPL, PSO, SWEPCo, WTU, and AEP Service Corporation are parties to a Restated and Amended Operating Agreement originally dated as of January 1, 1997 (CSW Operating Agreement). The CSW Operating Agreement requires the operating companies of the west zone to maintain specified annual planning reserve margins and requires the subsidiaries that have capacity in excess of the required margins to make such capacity available for sale to other AEP subsidiaries as capacity commitments. The CSW Operating Agreement also delegates to AEP Service Corporation the authority to coordinate the acquisition, disposition, planning, design and construction of generating units and to supervise the operation and maintenance of a central control center. As part of AEP's restructuring settlement agreement filed with the FERC, CPL and WTU would no longer be parties to the CSW Operating Agreement and certain other 8 modifications to its terms would also be made. See Competition and Business Change--AEP Restructuring Plan. Wholesale Sales of Power to Non-Affiliates AEP's electric utility subsidiaries also sell electric power on a wholesale basis to non-affiliated electric utilities and power marketers. Such sales are either made (i) by individual companies pursuant to various long-term power agreements or (ii) under the Interconnection Agreement (AEP Power Pool) or the CSW Operating Agreement. Sales made under the Interconnection Agreement are allocated among the East Zone subsidiaries based on member-load ratios. Sales made under the CSW Operating Agreement are allocated among the West Zone subsidiaries based on participation ratios. Reference is made to the footnote to the financial statements entitled Commitments and Contingencies that is incorporated by reference in Item 8 for information with respect to AEP's long-term agreements to sell power. 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 are 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 Regulation--Rates. As discussed below, some transmission services also are separately sold to non-affiliated companies. AEP System Transmission Pool APCo, CSPCo, I&M, KEPCo and OPCo are parties to the Transmission Agreement, dated April 1, 1984, as amended (the Transmission Agreement), defining how they share the costs associated with their relative ownership of the extra-high-voltage transmission system (facilities rated 345 kv and above) and certain facilities operated at lower voltages (138 kv and above). Like the Interconnection Agreement, this sharing is based upon each company's "member-load-ratio." See Sale of Power. The following table shows the net (credits) or charges allocated among the parties to the Transmission Agreement during the years ended December 31, 1999, 2000 and 2001: 1999 2000 2001 ---- ---- ---- (IN THOUSANDS) APCo......... $ (8,300) $ (3,400) $ (3,100) CSPCo........ 39,000 38,300 40,200 I&M.......... (43,900) (43,800) (41,300) KEPCo........ (4,300) (6,000) (4,600) OPCo......... 17,500 14,900 8,800 CPL, PSO, SWEPCo, WTU, and AEP Service Corporation are parties to a Transmission Coordination Agreement originally dated as of January 1, 1997 (TCA). The TCA establishes a coordinating committee, which is charged with the responsibility of overseeing the coordinated planning of the transmission facilities of the west zone operating subsidiaries, including the performance of transmission planning studies, the interaction of such subsidiaries with independent system operators (ISO) and other regional bodies interested in transmission planning and compliance with the terms of the Open Access Transmission Tariff (OATT) filed with the FERC and the rules of the FERC relating to such tariff. Under the TCA, the west zone operating subsidiaries have delegated to AEP Service Corporation the responsibility of monitoring the reliability of their transmission systems and administering the OATT on their behalf. The TCA also provides for the allocation among the west zone operating subsidiaries of revenues collected for transmission and ancillary services provided under the OATT. Transmission Services for Non-Affiliates AEP's electric utility subsidiaries and other System companies also provide transmission services for non-affiliated companies. 9 On April 24, 1996, the FERC issued orders 888 and 889. These orders require each public utility that owns or controls interstate transmission facilities to file an open access network and point-to-point transmission tariff that offers services comparable to the utility's own uses of its transmission system. The orders also require utilities to functionally unbundle their services, by requiring them to use their own tariffs in making off-system and third-party sales. As part of the orders, the FERC issued a pro-forma tariff which reflects the Commission's views on the minimum non-price terms and conditions for non-discriminatory transmission service. In addition, the orders require all transmitting utilities to establish an Open Access Same-time Information System (OASIS) which electronically posts transmission information such as available capacity and prices, and require utilities to comply with Standards of Conduct which prohibit utilities' system operators from providing non-public transmission information to the utility's merchant employees. The orders also allow a utility to seek recovery of certain prudently-incurred stranded costs that result from unbundled transmission service. In December 1999, FERC issued Order 2000, which provides for the voluntary formation of regional transmission organizations (RTOs), entities created to operate, plan and control utility transmission assets. Order 2000 also prescribes certain characteristics and functions of acceptable RTO proposals. On July 9, 1996, the AEP System companies filed a tariff conforming with the FERC's pro-forma transmission tariff. Since 1998 AEP has engaged in discussions with a group of Midwestern utilities regarding the development of the Alliance RTO which may take the form of an ISO or an independent transmission company (Transco), depending upon the occurrence of certain conditions. The Transco, if formed, would operate transmission assets that it would own, and also would operate other owners' transmission assets on a contractual basis. In 2001 the Alliance companies filed with the FERC a proposed business plan for the Alliance RTO. In December 2001, the FERC issued an order approving the proposal of the Midwest ISO (an independent operator of transmission assets in the Midwest) for an RTO and rejecting the Alliance RTO's business plan and finding that the Alliance RTO lacks sufficient scope and regional configuration to exist as a stand-alone RTO. The FERC directed the Alliance companies to negotiate with the Midwest ISO and others to explore possible combinations. Following such discussions, on March 5, 2002, the Alliance RTO filed with the FERC a request for a declaratory order seeking resolution of these issues. COORDINATION OF EAST AND WEST ZONE OPERATING SUBSIDIARIES AEP's System Integration Agreement provides for the integration and coordination of AEP's east and west zone operating subsidiaries, joint dispatch of generation within the AEP System, and the distribution, between the two operating zones, of costs and benefits associated with the System's generating plants. It is designed to function as an umbrella agreement in addition to the AEP Interconnection Agreement and the CSW Operating Agreement, each of which will continue to control the distribution of costs and benefits within each zone for all regulated subsidiaries. AEP's System Transmission Integration Agreement provides for the integration and coordination of the planning, operation and maintenance of the transmission facilities of AEP's east and west zone operating subsidiaries. Like the System Integration Agreement, the System Transmission Integration Agreement functions as an umbrella agreement in addition to the AEP Transmission Agreement and the Transmission Coordination Agreement. The System Transmission Integration Agreement contains two service schedules that govern: - The allocation of transmission costs and revenues. - The allocation of third-party transmission costs and revenues and System dispatch costs. The Transmission Integration Agreement anticipates that additional service schedules may be added as circumstances warrant. 10 CERTAIN POWER AGREEMENTS 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 aggregate power participation ratio of APCo, CSPCo, I&M and OPCo is 42.1%. 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. On September 29, 2000, DOE issued a notice of cancellation of the DOE/OVEC power agreement, such cancellation to be effective no later than April 30, 2003. In conjunction with this notice, DOE released all future rights to OVEC's generating capacity, effective September 1, 2001. DOE was therefore not entitled to any OVEC capacity beyond August 31, 2001, and the sponsoring companies became entitled to receive and pay for all OVEC capacity (approximately 2,200MW) in proportion to their power participation ratios at that time. 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 25 of the rural electric cooperatives which operate in the State of Ohio at 337 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 August 8, 2001, was recorded at 1,344,315 kilowatts. Reference is made to Wholesale Business Operations -- Structured Arrangements Involving Capacity, Energy, and Ancillary Services for a discussion of an agreement with an affiliate of Buckeye to construct and operate a gas-fired electric generating peaking facility. Century Aluminum Century Aluminum of West Virginia, Inc. (formerly Ravenswood Aluminum Corporation), operates a major aluminum reduction plant in the Ohio River Valley at Ravenswood, West Virginia. The power requirement of such plant presently is approximately 357,000 kilowatts. OPCo is providing electric service pursuant to a contract approved by the PUCO for the period July 1, 1996 through July 31, 2003. 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 and KEPCo pursuant to unit power agreements. Pursuant to these unit power agreements, AEGCo is entitled to recover its full cost of service from the purchasers and will be entitled to recover future increases in such costs, including increases in fuel and capital costs. See Unit Power Agreements. Pursuant to a capital funds agreement, AEP has agreed to provide cash capital contributions, or in certain circumstances subordinated loans, to AEGCo, to the extent necessary to enable AEGCo, among other things, to provide its proportionate share of funds required to permit continuation of the commercial operation of the Rockport Plant and to perform all of its obligations, covenants and agreements under, among other things, all loan agreements, leases and related documents to which AEGCo is or becomes a party. See Capital Funds Agreement. Unit Power Agreements A unit power agreement between AEGCo and I&M (the I&M Power Agreement) provides for the sale by AEGCo to I&M of all the power (and the energy associated therewith) available to AEGCo at the Rockport Plant. I&M is obligated, whether or 11 not power is available from AEGCo, to pay as a demand charge for the right to receive such power (and as an energy charge for any associated energy taken by I&M) such amounts, as when added to amounts received by AEGCo from any other sources, will be at least sufficient to enable AEGCo to pay all its operating and other expenses, including a rate of return on the common equity of AEGCo as approved by FERC, currently 12.16%. The I&M Power Agreement will continue in effect until the date that the last of the lease terms of Unit 2 of the Rockport Plant has expired unless extended in specified circumstances. Pursuant to an assignment between I&M and KEPCo, and a unit power agreement between KEPCo and AEGCo, AEGCo sells KEPCo 30% of the power (and the energy associated therewith) available to AEGCo from both units of the Rockport Plant. KEPCo has agreed to pay to AEGCo in consideration for the right to receive such power the same amounts which I&M would have paid AEGCo under the terms of the I&M Power Agreement for such entitlement. The KEPCo unit power agreement expires on December 31, 2004. As part of AEP's restructuring settlement agreement pending with the FERC, the KEPCo unit power agreement would be extended to December 31, 2009 for Unit 1 and December 7, 2022 for Unit 2. See Competition and Business Change--AEP Restructuring Plan. Capital Funds Agreement AEGCo and AEP have entered into a capital funds agreement pursuant to which, among other things, AEP has unconditionally agreed to make cash capital contributions, or in certain circumstances subordinated loans, to AEGCo to the extent necessary to enable AEGCo to (i) maintain such an equity component of capitalization as required by governmental regulatory authorities, (ii) provide its proportionate share of the funds required to permit commercial operation of the Rockport Plant, (iii) enable AEGCo to perform all of its obligations, covenants and agreements under, among other things, all loan agreements, leases and related documents to which AEGCo is or becomes a party (AEGCo Agreements), and (iv) pay all indebtedness, obligations and liabilities of AEGCo (AEGCo Obligations) under the AEGCo Agreements, other than indebtedness, obligations or liabilities owing to AEP. The Capital Funds Agreement will terminate after all AEGCo Obligations have been paid in full. 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 many other electric utilities, have traditionally provided electric generation and energy delivery, consisting of transmission and distribution services, as a single product to their retail customers. Proposals are being made and/or legislation has been enacted in Arkansas, Michigan, Ohio, Oklahoma, Texas, Virginia and West Virginia that would also require electric utilities to sell distribution services separately. These measures generally allow competition in the generation and sale of electric power, but not in its transmission and distribution. However, movement toward retail deregulation in certain of these states is slowing as a consequence of, among other things, adverse developments related to deregulation of the electric industry in California. 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 12 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 competition in generation and sale of electric power is instituted, the public utility subsidiaries of AEP believe that they have a favorable competitive position because of their relatively low costs. If stranded costs are not recovered from customers, however, the public utility subsidiaries of AEP, like all electric utilities, will be required by existing accounting standards to recognize any stranded investment losses. Reference is made to Management's Discussion and Analysis of Results of Operations and Management's Discussion and Analysis of Financial Condition, Contingencies and Other Matters and the footnote to the financial statements entitled Customer Choice and Industry Restructuring incorporated by reference in Items 7 and 8, respectively, for further information with respect to competition and business change. AEP Position on Competition AEP favors 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. 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. The legislatures and/or the regulatory commissions in many states, including some in AEP's service territory, 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 requirement to transmit directly to retail customers would have the result of permitting retail customers to purchase electric power, at the election of such customers, not only from the electric utility in whose service area they are located but from another electric utility, an independent power producer or an intermediary, such as a power marketer. Although AEP's power generation would have competitors under some of these proposals, its transmission and distribution would not. As competition develops in retail power generation, the public utility subsidiaries of AEP believe that they should have a favorable competitive position because of their relatively low costs. 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. 13 Retail The public utility subsidiaries of AEP have the exclusive right to sell electric power at retail within their service areas in the states of Arkansas, Indiana, Kentucky, Louisiana, Oklahoma, Tennessee and West Virginia. Furthermore, while customer choice commenced in Michigan on January 1, 2002, I&M does not have any competing suppliers active in its Michigan service territory at this time. However, AEP's public utility subsidiaries do compete with self-generation and with distributors of other energy sources, such as natural gas, fuel oil and coal, within their service areas. The primary factors in such competition are price, reliability of service and the capability of customers to utilize sources of energy other than electric power. With respect to self-generation, the public utility subsidiaries of AEP believe that they maintain a favorable competitive position on the basis of all of these factors. With respect to alternative sources of energy, the public utility subsidiaries of AEP believe that the reliability of their service and the limited ability of customers to substitute other cost-effective sources for electric power place them in a favorable competitive position, even though their prices may be higher than the costs of some other sources of energy. Significant changes in the global economy in recent years have led to increased price competition for industrial companies in the United States, including those served by the AEP System. Such industrial companies have requested price reductions from their suppliers, including their suppliers of electric power. In addition, industrial companies which are downsizing or reorganizing often close a facility based upon its costs, which may include, among other things, the cost of electric power. The public utility subsidiaries of AEP cooperate with such customers to meet their business needs through, for example, various off-peak or interruptible supply options and believe that, as low cost suppliers of electric power, they should be less likely to be materially adversely affected by this competition and may be benefited by attracting new industrial customers to their service territories. AEP Restructuring Plan As a result of deregulating legislation that has been enacted or is being considered in several of the states in which the AEP public utility subsidiaries provide service, AEP has reassessed the corporate ownership of its public utility subsidiaries' assets. Deregulating legislation in some of the states requires the separation of generation assets from transmission and distribution assets. On November 1, 2000, AEP filed with the SEC under PUHCA for approval of a restructuring plan in part to meet the requirements of this legislation. This application is pending. On July 24, 2001, AEP filed with the FERC for approval of the restructuring plan and on December 21, 2001, a settlement agreement with six state regulatory commissions and other major parties was filed with the FERC. The settlement agreement is pending approval. FERC approval is necessary before the SEC will issue its order. AEP's restructuring plan is designed to align its legal structure and business activities with the requirements of deregulation. AEP's plan contemplates the formation of two first tier subsidiaries that would hold the following public utility assets: - A subsidiary would hold the assets of public utility subsidiaries that remain subject to regulation as to rates by at least one state utility commission. AEP intends for this subsidiary ultimately to hold all transmission and distribution assets. - A subsidiary would hold (i) public utility and non-utility subsidiaries that derive their revenues from competitive activity and (ii) foreign utility subsidiaries and other investments. AEP intends for this subsidiary to ultimately hold all generation assets not subject to regulation. WHOLESALE BUSINESS OPERATIONS AEP's wholesale business operations focus on value-driven asset optimization at each link of the energy chain through the following activities: - A diversified portfolio of owned assets and structured third party arrangements, including: 14 - Power generation facilities and renewable energy sources. - Natural gas pipeline, storage and processing facilities. - Coal mines and related facilities. - Barge, rail and other fuel transportation related assets. - Trade and market energy commodities, including electric power, natural gas, natural gas liquids, oil, coal, and SO2 allowances in North America and Europe. - Price-risk management services and liquidity through a variety of energy-related financial instruments, including exchange-traded futures and over-the-counter forward, option, and swap agreements. - Long-term transactions to buy or sell capacity, energy, and ancillary services of electric generating facilities, either existing or to be constructed, at various locations in North America and Europe. Power Generation Facilities and Renewable Energy Sources In addition to approximately 38,300 MW listed under Item 2. Properties, AEP has ownership interests in the generating facilities listed under AEP-Other Generation of approximately 1,900 MW domestically and 6,700 MW internationally, of which approximately 1,100 MW is from renewable energy sources. Natural Gas Pipeline, Storage and Processing Facilities In June 2001, AEP acquired Houston Pipe Line Company (HPL) and Lodisco LLC for $727 million from Enron Corp. The acquired assets include: (i) a 4,200-mile intrastate gas pipeline in Texas with capacity of approximately 2.4 billion cubic feet per day; (ii) the exclusive right (for 30 years with an additional 20-year extension) to the underground Bammel Storage Facility (one of the largest natural gas storage facilities in North America) with 118 billion cubic feet of storage capacity and appurtenant pipelines including the Bammel Loop, Houston City Loop and the Texas City Loop; and (iii) certain gas marketing contracts. AEP acquired Louisiana Intrastate Gas Company, LLC ("LIG") in 1998. LIG's midstream gas assets include: (i) a 2,000-mile intrastate gas pipeline in Louisiana with capacity of approximately 800 million cubic feet per day; (ii) five natural gas processing plants that straddle the pipeline; and (iii) a ten billion cubic foot underground natural gas storage facility directly connected to the Henry Hub, one of the most active gas trading areas in North America. Coal Mines and Related Facilities In October 2001, to enhance its coal trading and marketing activities, AEP acquired substantially all the assets of Quaker Coal Company as part of a bankruptcy proceeding restructuring. AEP paid $101 million to Quaker's creditors and assumed additional liabilities of approximately $58 million. The acquisition included property, coal reserves, mining operations and royalty interests in Colorado, Kentucky, Ohio, Pennsylvania and West Virginia. AEP will continue to operate the mines and facilities which have approximately 800 employees. Barge, Rail and Other Fuel Transportation Related Assets In November 2001, AEP acquired MEMCO Barge Line Inc. for $270 million as part of its overall asset optimization program. MEMCO is engaged in the transportation of coal and dry bulk commodities, primarily on the Ohio, Illinois, and Lower Mississippi rivers. MEMCO owns or leases 1,200 hopper barges and 30 towboats. The addition of MEMCO's barge assets to AEP's existing fleet places AEP among the leading barge operators in the country. See Fuel Supply--Coal and Lignite for other barges and towboats leased by I&M and OPCo. Trading and Marketing of Energy Commodities Sales: Based upon volumetric sales in the U.S., Power Markets Weekly ranked AEP's wholesale trading business No. 2 in electric sales for the first, second and third quarters of 2001. Platts Gas Daily ranked AEP Nos. 14, 10 and 2 in gas sales for the 15 first, second and third quarters, respectively, of 2001. ICEX: To gain access to additional liquidity trading points, AEP acquired an interest in the internet-based electronic trading system, Intercontinental Exchange, L.L.C. (ICEX), in 2000 that enables participants to initiate, negotiate, and execute trades in the crude oil, natural gas, and spot and forward energy markets. Other investors include global energy companies and leading investment banking firms. Structured Arrangements Involving Capacity, Energy, and Ancillary Services AEP has entered into an agreement with The Dow Chemical Company to construct a 900 MW cogeneration facility at Dow's chemical facility in Plaquemine, Louisiana. Commercial operation is expected in 2003. AEP is entitled to 100% of the facility's capacity and energy and has contracted to sell the power from this facility to an unaffiliated party. In January 2000, OPCo and National Power Cooperative, Inc. (NPC), an affiliate of Buckeye, entered into an agreement relating to construction and operation of a 510 MW gas-fired electric generating peaking facility to be owned by NPC. From the commercial operation date (expected in 2002) until the end of 2005, OPCo will be entitled to 100% of the power generated by the facility, and responsible for the fuel and other costs of the facility. After 2005, NPC and OPCo will be entitled to 80% and 20%, respectively, of the power of the facility, and both parties will generally be responsible for the fuel and other costs of the facility. OPCo will also provide certain back-up power to NPC. INTERNATIONAL ELECTRIC Other international holdings of AEP include the following. Australia: CitiPower Pty. is an electric distribution and retail sales company in Victoria, Australia. CitiPower serves approximately 240,000 customers in the city of Melbourne. With about 3,100 miles of distribution lines in a service area that covers approximately 100 square miles, CitiPower distributes about 4,800 gigawatt-hours annually. AEP acquired CitiPower in 1998 for U.S.$1.1 billion. UK: SEEBOARD, headquartered in Crawley, West Sussex and acquired as part of AEP's merger with CSW, is one of the 12 regional electricity companies formed as a result of the restructuring and subsequent privatization of the United Kingdom electricity industry in 1990. CSW acquired indirect control of SEEBOARD in April 1996. SEEBOARD's principal businesses are the distribution and supply of electricity. In addition, SEEBOARD is engaged in other businesses, including gas supply, electricity generation, and electrical contracting. SEEBOARD has approximately 2,000,000 customers and its service area covers approximately 3,000 square miles in Southeast England with the majority of its customers in Kent, Sussex and parts of Surrey. Possible Divestitures: On February 3, 2002, AEP announced the appointment of investment banks to advise AEP on the prospects for divestment of CitiPower and/or SEEBOARD. Because of pooling of interests accounting restrictions, imposed as part of AEP's merger with CSW and which expire in June 2002, any possible divestment of CitiPower and/or SEEBOARD is not anticipated until after these restrictions lapse. PRO SERV Pro Serv 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 AEP Communications markets wholesale, high capacity, fiber optic services, colocation, and wireless tower infrastructure services under the C3 brand with operations in Arkansas, Kansas, Louisiana, Oklahoma and Texas. AEP Communications joined with several other energy and telecommunications companies to form AFN Communications, LLC. (AFN). AFN is a 16 super regional telecommunications company that provides long haul fiber optic capacity to competitive local exchange carriers, wireless carriers and long distance companies. AFN does business in New York, Pennsylvania, Virginia, West Virginia, Ohio, Indiana, Michigan, Illinois, and Kentucky and has approximately 10,000 route miles of fiber optic network. C3, an entity that was acquired through the merger with CSW, is engaged in providing fiber optic and collocation services in Texas, Louisiana, Oklahoma, Arkansas, and Kansas. C3 does business as C3 Networks and has approximately 5,300 route miles of fiber optic network. Management is evaluating certain of AEP's telecommunications investments for possible disposal. CONSTRUCTION PROGRAM General The AEP System is continuously involved in assessing the adequacy of its generation, transmission, distribution and other facilities to plan and provide for the reliable supply of electric power and energy to its customers. In this assessment process, assumptions are continually being reviewed as new information becomes available, and assessments and plans are modified, as appropriate. Thus, System reinforcement plans are subject to change, particularly with the restructuring of the electric utility industry and the move to increasing competition in the marketplace. See Competition and Business Change. Generation Committed or anticipated capability changes to the AEP System's generation resources includes the expiration of the Rockport Unit 2 sale of 250 megawatts to Carolina Power & Light Company, an unaffiliated company, on December 31, 2009. See AEP-CSW Merger for a discussion of the divestiture of generating capacity as part of the merger. Apart from these changes and temporary power purchases that can be arranged, there are no specific commitments for additions of new generation resources on the AEP System. Given the restructuring taking place in the industry, the extent of the need of AEP's operating companies for any additional generation resources in the foreseeable future is highly uncertain. Proposed Transmission Facilities On September 30, 1997, APCo refiled applications in Virginia and West Virginia for certificates to build a Wyoming-Cloverdale 765,000-volt Project. The preferred route for this line was approximately 132 miles in length, connecting APCo's Wyoming Station in southern West Virginia to APCo's Cloverdale Station near Roanoke, Virginia. APCo originally 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 for the original Wyoming-Cloverdale Project. If this alternative were incorporated into a 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 on non-federal lands. West Virginia: On May 27, 1998, the West Virginia PSC issued an order granting APCo's application for a certificate to construct the Wyoming-Cloverdale 765,000-volt Project. On March 13, 2002, the West Virginia PSC issued an order granting APCo's request to construct the line with a terminus at Jacksons Ferry substation in Virginia instead of the Cloverdale substation as discussed below under Virginia. 17 Virginia: Following several procedural delays and Hearing Examiner's rulings, APCo filed a study in May 1999 identifying the Wyoming-Jacksons Ferry Project as an alternative project to the Wyoming-Cloverdale Project. The Jacksons Ferry Project proposes a line from Wyoming Station in West Virginia to APCo's existing 765,000-volt Jacksons Ferry Station in Virginia. APCo estimates that the Wyoming-Jacksons Ferry line would be 90 miles in length, including 32 miles in West Virginia previously certified. In May 2000, the Virginia SCC held an evidentiary hearing to consider both projects. On October 2, 2000, the Hearing Examiner's report to the Virginia SCC recommended approval of the Wyoming-Jacksons Ferry Alternative Project. On May 31, 2001, the Virginia SCC issued an order granting APCo's application for a certificate to construct the Wyoming-Jacksons Ferry 765,000-volt Project. Proposed Completion Schedule and Estimated Cost: Subsequent to Virginia and West Virginia granting certificates to construct the Project, the Forest Service restarted the EIS process and is scheduled to complete and release a supplement to the Draft EIS in April 2002. The Final EIS process should continue for the balance of 2002, with a decision on the federal permits anticipated in Spring 2003. APCo has also begun required consultation with the U.S. Fish and Wildlife Service under the Endangered Species Act, which should be completed concurrently with the EIS process. Given the status of the Project permitting process, and assuming that the projected schedule of the EIS process will be met, management estimates that the Wyoming-Jacksons Ferry 765,000-volt Project cannot be completed before Summer 2006. Depending upon the outcome of the EIS permitting process by the Forest Service, APCo's estimated cost for the Wyoming-Jacksons Ferry Project ranges from $250 to $280 million, assuming a Summer 2006 in-service date. Construction Expenditures The following table shows construction expenditures during 1999, 2000 and 2001 and current estimates of 2002 construction expenditures, in each case including AFUDC but excluding assets acquired under leases.
1999 2000 2001 2002 ACTUAL ACTUAL ACTUAL ESTIMATE ------ ------ ------ -------- (IN THOUSANDS) AEP System (a).. $1,679,600 $1,773,400 $1,832,000 $1,820,400 AEGCo........ 8,300 5,200 6,900 45,600 APCo......... 211,400 199,300 306,000 258,200 CPL.......... 255,800 199,500 194,100 172,300 CSPCo........ 115,300 128,000 132,500 145,400 I&M.......... 165,300 171,100 91,100 205,400 KEPCo........ 44,300 36,200 37,200 128,800 OPCo......... 193,900 254,000 344,600 349,700 PSO.......... 104,500 176,900 124,900 80,600 SWEPCo....... 112,900 120,200 112,100 111,900 WTU.......... 52,600 64,500 39,800 51,800
- ----------------------- (a) Includes expenditures of other subsidiaries not shown. Reference is made to the footnote to the financial statements entitled Commitments and Contingencies incorporated by reference in Item 8, for further information with respect to the construction plans of AEP and its operating subsidiaries for the next three years. The System construction program is reviewed continuously and is revised from time to time in response to changes in estimates of customer demand, business and economic conditions, the cost and availability of capital, environmental requirements and other factors. Changes in construction schedules and costs, and in estimates and projections of needs for additional facilities, as well as variations from currently anticipated levels of net earnings, Federal income and other taxes, and other factors affecting cash requirements, may increase or decrease the estimated capital requirements for the System's construction program. From time to time, as the System companies have encountered the industry problems described above, such companies also have encountered limitations on their ability to secure the capital necessary to finance construction expenditures. Environmental Expenditures: Expenditures related to compliance with air and water quality standards, included in the gross additions to plant of the System, during 1999, 2000 and 2001 and the current estimate for 2002 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 18 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. 1999 2000 2001 2002 ACTUAL ACTUAL ACTUAL ESTIMATE ------ ------ ------ -------- (IN THOUSANDS) AEGCo............. $ 8 $ 70 $ 3,500 27,700 APCo.............. 24,500 2,100 99,200 86,500 CPL............... (a) (a) 2,500 200 CSPCo............. 10,600 6,600 22,500 25,500 I&M............... 4,500 1,900 700 28,500 KEPCo............. 1,900 400 11,200 60,200 OPCo.............. 37,400 91,200 125,300 103,900 PSO............... (a) (a) 400 400 SWEPCo............ (a) (a) 9,200 9,600 WTU............... (a) (a) 800 3,000 ------- ------ ------- ------- AEP System (a).. $ 78,908 $102,270 $275,300 $345,500 ======== ======== ======== ======== - ----------------------- (a) Amounts not available for west zone companies of AEP prior to AEP-CSW merger. FINANCING It has been the practice of AEP's operating subsidiaries to finance current construction expenditures in excess of available internally generated funds by initially issuing unsecured short-term debt, principally commercial paper and bank loans, at times up to levels authorized by regulatory agencies, and then to reduce the short-term debt with the proceeds of subsequent sales by such subsidiaries of long-term debt securities and cash capital contributions by AEP. 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 unsecured debt and leasing arrangements, including the leasing of utility assets and coal mining and transportation equipment and facilities. Pollution control revenue bonds have been used in the past and may be used in the future in connection with the construction of pollution control facilities; however, Federal tax law has limited the utilization of this type of financing except for purposes of certain financing of solid waste disposal facilities and of certain refunding of outstanding pollution control revenue bonds issued before August 16, 1986. New projects undertaken by AEP's unregulated subsidiaries are generally financed through equity funds provided by AEP, non-recourse debt incurred on a project-specific basis, debt issued by such subsidiaries or through a combination thereof. See Wholesale Business Operations and Item 7 for additional information concerning AEP's unregulated subsidiaries. AEP's revolving credit agreements include covenants and events of default typical for this type of facility, including a maximum debt/capital test and a $50 million cross-acceleration provision. At December 31, 2001, AEP was in compliance with its debt covenants. With the exception of a voluntary bankruptcy or insolvency, any event of default has either or both a cure period or notice requirement before termination of the agreements. A voluntary bankruptcy or insolvency would be considered an immediate termination event. Reference is made to Management's Discussion and Analysis of Results of Operations and Management's Discussion and Analysis of Financial Condition, Contingencies and Other Matters incorporated by reference in Item 7 for information with respect to AEP's plans to restructure its debt to implement corporate separation. See Competition and Business Change--AEP Restructuring Plan herein. FUEL SUPPLY The following table shows the sources of power generated by the AEP System: 1997 1998 1999 2000 2001 ---- ---- ---- ---- ---- Coal.................... 76% 79% 79% 78% 74% Gas..................... 12% 14% 15% 13% 12% Nuclear................. 8% 3% 3% 5% 11% Hydroelectric and other. 4% 4% 3% 4% 3% Variations in the generation of nuclear power are primarily related to refueling outages and, in 1997 through 2000, the shutdown of the Cook Plant to respond to issues raised by the NRC. 19 Natural Gas AEP consumed over 240 billion cubic feet of natural gas during 2001 for the system operating companies. A majority of the gas fired electric generation plants are connected to at least two natural gas pipelines, which provides greater access to competitive supplies and improves reliability. Natural gas requirements for each plant are supplied by a portfolio of long-term and short-term purchase and transportation agreements that are acquired on a competitive basis and based on market prices. Coal and Lignite 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 began 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 -- Title IV Acid Rain Program 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 by entering into additional supply agreements, either on a long-term or spot basis, at prices and upon terms which cannot now be predicted. 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. Western coal purchased by System companies is transported to AEP generating stations by rail and via an affiliated river terminal for subsequent transloading to barges for final delivery. CPL, PSO and SWEPCo own (in the aggregate) 2,982 coal hopper cars and APCo, I&M and OPCo lease (in the aggregate) an additional 4,066 coal hopper cars to be used in unit train movements. I&M and OPCo lease (in the aggregate) 15 towboats, 454 jumbo barges and 143 standard barges. Certain subsidiaries of AEP also own or lease coal transfer facilities at various other locations. See Wholesale Business Operations--Barge, Rail and Other Fuel Transportation Related Assets herein for information with respect to the acquisition of MEMCO Barge Line Inc. in 2001. The System generating companies procure coal through purchases pursuant to long-term contracts or spot purchases from affiliated and 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 20 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:
1997(a) 1998(a) 1999(a) 2000 2001 ---- ---- ---- ---- ---- Total coal delivered to AEP operated plants (thousands of tons)........... 54,292 54,004 54,306 73,259 73,889 Sources (percentage): Subsidiaries........................................ 14% 14% 12% 9% 4% Long-term contracts................................. 66% 66% 64% 67% 68% Spot or short-term purchases........................ 20% 20% 24% 24% 28% Average price per ton of spot-purchased coal........... $24.38 $25.05 $27.18 $24.03 $27.30
- -------------------- (a) Includes east zone companies only. The average cost of coal consumed during the past five years by all AEP System companies is shown below. AEP System companies' data for 1997 includes only AEGCo, APCo, CSPCo, I&M, KEPCo and OPCo.
1997 1998 1999 2000 2001 ---- ---- ---- ---- ---- DOLLARS PER TON AEP System Companies............................................. $ 29.68 $ 29.87 $ 30.01 $ 31.39 $ 28.55 AEGCo......................................................... 19.30 19.37 20.79 20.65 21.01 APCo.......................................................... 36.09 34.81 33.29 32.84 32.41 CPL........................................................... 26.93 26.93 26.49 25.95 26.78 CSPCo......................................................... 31.69 31.63 29.94 28.50 30.63 I&M........................................................... 23.68 22.61 24.54 23.44 23.57 KEPCo......................................................... 26.76 27.42 26.76 25.35 25.02 OPCo.......................................................... 36.00 38.94 40.56 46.52 35.06 PSO........................................................... 21.11 20.37 20.94 21.21 20.45 SWEPCo........................................................ 23.16 23.02 21.34 22.59 24.22 WTU........................................................... 18.19 21.37 21.72 22.26 23.81
1997 1998 1999 2000 2001 ---- ---- ---- ---- ---- CENTS PER MILLION BTU'S AEP System Companies............................................. 140.13 142.17 141.95 149.12 136.85 AEGCo......................................................... 115.21 112.63 116.90 116.23 118.89 APCo.......................................................... 146.54 141.76 135.40 134.86 135.88 CPL........................................................... 136.40 137.00 135.78 137.86 140.22 CSPCo......................................................... 134.44 134.15 127.42 120.83 131.64 I&M........................................................... 123.36 118.02 121.90 117.99 121.27 KEPCo......................................................... 110.37 112.15 109.91 104.88 104.97 OPCo.......................................................... 151.66 164.44 169.23 194.77 146.87 PSO........................................................... 120.91 116.73 119.54 121.83 116.33 SWEPCo........................................................ 152.79 150.62 143.34 144.96 153.88 WTU........................................................... 109.13 126.22 129.13 131.56 143.21
21 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, 2001, the System's coal inventory was approximately 41 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 2001 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 2001 to these units. Reference is made to Environmental and Other Matters for information concerning current emissions limitations in the AEP System's various jurisdictions and the effects of the Clean Air Act Amendments.
AVERAGE SULFUR CONTENT ESTIMATED REQUIRE- OF DELIVERED COAL TOTAL CONSUMPTION MENTS FOR REMAINDER ---------------------------- DURING 2001 OF USEFUL LIVES POUNDS OF SO2 (IN THOUSANDS OF TONS) (IN MILLIONS OF TONS) BY WEIGHT PER MILLION BTU'S -------------------- ------------------- --------- ----------------- AEGCo (a)............................... 4,829 215 0.3% 0.7 APCo.................................... 10,529 375 0.7% 1.2 CPL..................................... 2,470 36 0.3% 0.7 CSPCo................................... 5,637 213(b) 2.4% 4.1 I&M (c)................................. 7,026 244 0.6% 1.2 KEPCo................................... 2,981 80 0.9% 1.5 OPCo.................................... 19,392 546(d) 2.1% 3.5 PSO..................................... 4,049 41 0.4% 0.9 SWEPCo.................................. 12,254 117 0.6% 1.6 WTU..................................... 1,370 32 0.4% 0.8
- ------------------------ (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. (d) Total does not include OPCo's portion of Sporn 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 0.7% during 2001, 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. CPL: CPL has coal supply agreements of one year or less duration with two coal suppliers and various coal trading firms for the delivery of approximately 2,400,000 tons of coal for the year 2002. Approximately one half of the coal delivered to Coleto Creek is from Wyoming with the other half from Colorado. Both sources supply low sulfur coal with a limit of 1.2 lbs/MMBtu. CSPCo: CSPCo has coal supply agreements with unaffiliated suppliers for the delivery of approximately 3,780,000 tons in 2002. 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 22 units, each operating company is contractually responsible for obtaining the needed fuel. I&M: I&M has historically received coal under two coal supply agreements with unaffiliated Wyoming suppliers for low sulfur coal from surface mines principally for consumption at the Rockport Plant. As a result of litigation involving future deliveries from one of these suppliers, there will not be any coal delivered under this contract in 2002. Under the other agreement, the supplier 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. This contract, which expires on December 31, 2004, has remaining deliveries of approximately 22,800,000 tons. 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 648,000 tons of coal in 2002. 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 has historically been supplied from both affiliated and unaffiliated suppliers. As a result of the 2001 sale of AEP's coal mines in Ohio and West Virginia and an agreement to purchase approximately 34,000,000 tons of coal through 2008 from the purchaser of the mines, coal consumed at OPCo's plants in 2002 will be supplied from unaffiliated suppliers under long-term contracts and/or on a spot purchase basis. PSO: PSO takes all its coal from one coal supplier under a contract that provides for the entire plant requirements with at least 16,830,000 tons remaining to be delivered between 2002 and 2007. The coal is supplied from Wyoming and has a maximum sulfur content of 1.2 lbs. SO2 per MMBtu. SWEPCo: SWEPCo receives coal at its plants under a combination of agreements, including one long-term coal contract with a Wyoming producer, one affiliate mine-mouth lignite operation and agreements with various producers and coal trading firms. SWEPCo's long-term coal supply contract provides approximately half of the requirements for both coal plants. SWEPCo must take delivery of 25,625,000 tons of coal through 2006, with the remainder of its coal requirements met through short-term spot agreements for low sulfur (less than 1.2 lbs. SO2 per MMBtu) coal with various Wyoming coal suppliers and trading companies. WTU: WTU has one long-term coal supply contract that provides approximately two-thirds of the coal requirements for the Oklaunion Power Station. This contract has approximately 9,180,000 tons of coal remaining to be delivered between 2002 and mid-2006. The remaining coal requirements for Oklaunion are being purchased under short-term agreements with various Wyoming coal suppliers and coal trading firms, with such coal being low sulfur (less than 1.2 lbs. SO2 per MMBtu). Nuclear I&M and STPNOC have made commitments to meet certain of the nuclear fuel requirements of the Cook Plant and STP, respectively. The nuclear fuel cycle consists of: - Mining and milling of uranium ore to uranium concentrates. - Conversion of uranium concentrates to uranium hexafluoride. - Enrichment of uranium hexafluoride. - Fabrication of fuel assemblies. - Utilization of nuclear fuel in the reactor. - Disposition of spent fuel. Steps currently are being taken, based upon the planned fuel cycles for the Cook Plant, to review and evaluate I&M's requirements for the supply of nuclear fuel. I&M has made and will make 23 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. CPL and the other STP participants have entered into contracts with suppliers for 100% of the uranium concentrate sufficient for the operation of both STP units through Spring 2006 and with an additional 50% of the uranium concentrate needed for STP through Spring 2007. In addition, CPL and the other STP participants have entered into contracts with suppliers for 100% of the nuclear fuel conversion service sufficient for the operation of both STP units through Spring 2003, with additional flexible contracts to provide at least 50% of the conversion service needed for STP through 2008. CPL and the other STP participants have entered into flexible contracts to provide for 100% of enrichment through Fall 2004, with additional flexible contracts to provide at least 50% of enrichment services through Fall 2008. Also, fuel fabrication services have been contracted for operation through 2028 for Unit 1 and 2029 for Unit 2. For purposes of the storage of high-level radioactive waste in the form of spent nuclear fuel, I&M has completed modifications to its spent nuclear fuel storage pool. AEP anticipates that the Cook Plant has storage capacity to permit normal operations through 2012. STP has on-site storage facilities with the capability to store the spent nuclear fuel generated by the STP units over their licensed lives. The costs of nuclear fuel consumed by I&M and CPL do not assume any residual or salvage value for residual plutonium and uranium. Nuclear Waste and Decommissioning Reference is made to Management's Discussion and Analysis of Results of Operations and Management's Discussion and Analysis of Financial Condition, Contingencies and Other Matters in the financial statements and Commitments and Contingencies in the footnotes to these statements that are incorporated by reference in Items 7 and 8, respectively, for information with respect to nuclear waste and decommissioning and related litigation. The ultimate cost of retiring the Cook Plant and STP may be materially different from estimates and funding targets as a result of the: - Type of decommissioning plan selected. - Escalation of various cost elements (including, but not limited to, general inflation). - Further development of regulatory requirements governing decommissioning. - Limited availability to date of significant experience in decommissioning such facilities. - Technology available at the time of decommissioning differing significantly from that assumed in these studies. - Availability of nuclear waste disposal facilities. Accordingly, management is unable to provide assurance that the ultimate cost of decommissioning the Cook Plant and STP will not be significantly greater than current projections. Low-Level Waste: The Low-Level Waste Policy Act of 1980 (LLWPA) mandates that the responsibility for the disposal of low-level waste rests with the individual states. Low-level radioactive waste consists largely of ordinary refuse and other items that have come in contact with radioactive materials. To facilitate this approach, the LLWPA authorized states to enter into regional compacts for low-level waste disposal subject to Congressional approval. The LLWPA also specified that, beginning in 1986, approved compacts may prohibit the importation of low-level waste from other regions, thereby providing a strong incentive for states to enter into compacts. Michigan, the state where the Cook Plant is located, was a member of the Midwest Compact, but its membership was revoked in 1991. As a result, Michigan is responsible for developing a disposal site for the low-level waste generated in Michigan. Although Michigan amended its law regarding low-level waste site development in 1994 to allow a 24 volunteer to host a facility, little progress has been made to date. A bill was introduced in 1996 to further address the issue but no action was taken. Development of required legislation and progress with the site selection process has been inhibited by many factors, and management is unable to predict when a new disposal site for Michigan low-level waste will be available. Texas is a member of the Texas Compact, which includes the states of Maine and Vermont. Texas had identified a disposal site in Hudspeth County for construction of a low-level waste disposal facility. During the licensing process for the Hudspeth site, that site was found to be unsuitable. No additional site has been considered. Management is unable to predict when a disposal site for Texas 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 and Texas. 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 by the Cook Plant and STP are now being sent to the disposal site. Under state law, the amounts of low-level radioactive waste being disposed of at the South Carolina facility from non-regional generators, such as the Cook Plant and STP, are limited and being reduced. Non-regional access to the South Carolina facility is currently allowed through the end of fiscal year 2008. ENVIRONMENTAL AND OTHER MATTERS AEP's subsidiaries are subject to regulation by federal, state and local authorities with regard to air and water-quality control and other environmental matters, and are subject to zoning and other regulation by local authorities. In addition to imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. It is expected that: - Costs related to environmental requirements will eventually be reflected in the rates of AEP's electric utility subsidiaries, or where states are deregulating generation, unbundled transition period generation rates, stranded cost wires charges and future market prices for electricity. - 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 adopted by certain states and proposed at the state and federal level 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 that own or operate generating, transmission and distribution facilities are in substantial compliance with pollution control laws and regulations. AEP's international operations are subject to regulation with respect to air, waste and water quality standards and other environmental matters by various authorities within the host countries. Under certain circumstances, these authorities may require modifications to these facilities and operations or impose fines and other costs for violations of applicable statutes and regulations. From time to time, these operations are made aware of various environmental issues or are named as parties to various legal claims, actions, complaints or other proceedings related to environmental matters. Management does not expect disposition of any such pending environmental proceedings to have a material adverse effect on AEP's consolidated results of operations or financial condition. Reference is made to Management's Discussion and Analysis of Results of Operations and Management's Discussion and Analysis of Financial Condition, Contingencies and Other Matters and the footnote to the financial statements entitled 25 Commitments and Contingencies incorporated by reference in Items 7 and 8, respectively, for further information with respect to environmental matters, including discussion of legislative proposals under consideration by the Administration and Congress focused on reductions in emissions of CO2, NOx, SO2, mercury and other constituents. Air Pollution Control For the AEP System operating companies, compliance with the CAA is requiring substantial expenditures that generally are being recovered through the rates of AEP's operating subsidiaries. Certain matters discussed below may require significant additional operating and capital expenditures. However, there can be no assurance that all such costs will be recovered. See Construction Program -- Construction Expenditures. Title I National Ambient Air Quality Standards Attainment: In July 1997, Federal EPA revised the ozone and particulate matter National Ambient Air Quality Standards (NAAQS), creating a new eight-hour ozone standard and establishing a new standard for particulate matter less than 2.5 microns in diameter (PM2.5). In addition to the potential financial consequences discussed above, both of these new standards have the potential to affect adversely the operation of AEP System generating units. In May 1999, the U.S. Court of Appeals for the District of Columbia Circuit remanded the ozone and PM2.5 NAAQS to Federal EPA. In February 2001, the U.S. Supreme Court issued an opinion reversing in part and affirming in part the Court of Appeals decision. The Supreme Court remanded the case to the Court of Appeals for further proceedings, including a review of whether adoption of the standards was arbitrary and capricious and directed Federal EPA to develop a policy for implementing the revised ozone standard in conformity with the CAA. The Court of Appeals held oral argument on the remanded issues in December 2001. NOx SIP Call: In October 1998, Federal EPA issued a final rule (NOx transport SIP call or NOx SIP Call) establishing state-by-state NOx emission budgets for the five-month ozone season to be met beginning May 1, 2003. The NOx budgets originally applied to 22 eastern states and the District of Columbia and are premised mainly on the assumption of controlling power plant NOx emissions projected for the year 2007 to 0.15 lb. per million Btu (approximately 85% below 1990 levels), although the reductions could be substantially greater for certain State Implementation Plans. The SIP call was accompanied by a proposed Federal Implementation Plan, which could be implemented in any state that fails to submit an approvable SIP. The NOx reductions called for by Federal EPA are targeted at coal-fired electric utilities and may adversely impact the ability of electric utilities to construct new facilities or to operate affected facilities without making significant capital expenditures. In October 1998, the AEP System operating companies joined with certain other parties seeking a review of the final NOx SIP Call rule in the U.S. Court of Appeals for the District of Columbia Circuit. In March 2000, the court issued a decision upholding the major provisions of the rule. The court subsequently extended the date for submission of SIP revisions until October 30, 2000, and the compliance deadline until May 31, 2004. In March 2001, the U.S. Supreme Court denied petitions filed by industry petitioners, including AEP System operating companies, seeking review of the Court of Appeals decision. In May 1999 and March 2000, Federal EPA finalized the NOx budget allocations to be implemented through the NOx SIP Call. AEP and other parties filed petitions for review in the U.S. Court of Appeals for the District of Columbia Circuit and in June 2000 the court issued an opinion remanding the budget determinations for further consideration of certain growth factor assumptions made by Federal EPA. In December 2000, Federal EPA issued a determination that eleven states, including certain states in which AEP System operating companies have sources covered by the NOx SIP Call rule, had failed to submit complying SIP revisions. AEP System operating companies and unaffiliated utilities appealed this determination to the U.S. Court of Appeals for the District of Columbia Circuit and the court has stayed the proceeding pending Federal EPA action on the remand of growth factor issues. 26 In April 2000, the Texas Natural Resource Conservation Commission adopted rules requiring significant reductions in NOx emissions from utility sources, including those of CPL and SWEPCo. The rule compliance date is May 2003 for CPL and May 2005 for SWEPCo. Management's estimates indicate that compliance with the revised NOx SIP Call rule, and SIP revisions already adopted, could result in required capital expenditures for the AEP System of approximately $1.6 billion, of which approximately $450 million has been expended through December 31, 2001. Reference is made to the footnote to the financial statements entitled Commitments and Contingencies incorporated by reference in Item 8 for information with respect to AEP registrant subsidiaries' compliance cost estimates and amounts expended. In May 2001, OPCo completed a $175 million installation of selective catalytic reduction (SCR) technology to reduce NOx emissions on its two-unit 2,600 MW Gavin Plant and, during the 2001 ozone season (May through September), operated the SCR units. Construction of selective catalytic reduction technology on Amos Plant Unit 3, which is jointly owned by OPCo and APCo, and on APCo's Mountaineer Plant, began in 2001. The Amos and Mountaineer projects (expected to be completed in 2002) are estimated to cost a total of $230 million. Management has undertaken the Gavin, Amos and Mountaineer projects to meet applicable NOx emission reduction requirements. Additional expenditures of approximately $7 million are planned or undertaken to address certain operational issues arising during initial operation of the Gavin SCR units. Since compliance costs cannot be estimated with certainty, the actual costs to comply could be significantly different from management's estimates depending upon the compliance alternatives selected to achieve reductions in NOx emissions. Unless capital and operating costs of any additional pollution control equipment necessary for compliance are recovered from customers through regulated rates and market prices for electricity, they could have a material adverse effect on future results of operations, cash flows and possibly financial condition of AEP and its affected subsidiaries. Section 126 Petitions: In January 2000, Federal EPA adopted a revised rule granting petitions filed by certain northeastern states under Section 126 of the CAA. The petitions sought significant reductions in nitrogen oxide emissions from utility and industrial sources. The rule imposed emission reduction requirements comparable to the NOx SIP Call rule beginning May 1, 2003, for most of AEP's coal-fired generating units. Certain AEP System operating companies and other utilities filed petitions for review in the U.S. Court of Appeals for the District of Columbia Circuit. In May 2001, the court issued an opinion which upheld substantially the entire rule. The court did not agree that Federal EPA had properly supported the growth factors for the NOx allowance budgets. In August 2001, the court issued an order tolling the May 1, 2003, compliance date pending resolution of the remand of the growth factor issues. In January 2002, Federal EPA advised that it intends to establish May 31, 2004, as the final compliance date for the rule. Cost estimates for compliance with Section 126 are projected to be somewhat less than those set forth above for the NOx SIP Call rule reflecting the fact that Section 126 does not apply to AEGCo's and I&M's Rockport Plant. West Virginia SO2 Limits: West Virginia promulgated SO2 limitations, which Federal EPA approved in February 1978. The emission limitations for OPCo's 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. In August 1994, 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. In May 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 27 U.S. District Court for the Northern District of West Virginia. Kammer Plant has achieved and maintained compliance with the applicable SO2 emission limit for a period in excess of one year, pursuant to the provisions of the consent decree. In May 2001, the court terminated the consent decree. Short Term SO2 Limits: In January 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. In January 2001, Federal EPA published a Federal Register notice inviting comment with respect to its decision not to promulgate a five-minute SO2 NAAQS and intent to take final action on the intervention level program by the summer of 2001. The effect of this proposed intervention program on AEP operations or financial performance cannot be predicted at this time. Hazardous Air Pollutants: Hazardous air pollutant (HAP) emissions from utility boilers are potentially subject to control requirements under Title III of the CAAA which specifically directed Federal EPA to study potential public health impacts of HAPs emitted from electric utility steam generating units. In December 2000, Federal EPA announced its intent to regulate emissions of mercury from coal and oil-fired power plants, concluding that these emissions pose significant hazards to public health. A decision on whether to regulate other HAPs emissions from these sources was deferred. Federal EPA added coal and oil-fired electric utility steam generating units to the list of "major sources" of HAPs under Section 112 (c) of the CAA, which compels the development of "Maximum Achievable Control Technology" (MACT) standards for these units. Listing under Section 112 (c) also compels a preconstruction permitting obligation to establish case-by-case MACT standards for each new or reconstructed source in the category. MACT standards for utility mercury emissions are scheduled to be proposed by December 2003 and finalized by December 2004. The Utility Air Regulatory Group (which includes AEP System operating companies as members) filed a petition with Federal EPA seeking reconsideration of the decision to regulate mercury emissions from power plants under Section 112(c) of the CAA. 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. In 1998, Federal EPA determined that the CAA is adequate to address any adverse public health or environmental effects associated with the atmospheric deposition of hazardous air pollutants in the Great Lakes. The potential impact of adverse developments in these programs on AEP operations or financial performance cannot be predicted at this time. Title IV Acid Rain Program: The Acid Rain Program (Title IV) of the CAAA created an emission allowance program pursuant to which utilities are authorized to emit a designated quantity of SO2, measured in tons per year. Phase II of the Acid Rain Program, which affects all fossil fuel-fired steam generating units with capacity greater than 25 megawatts imposed 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. Future SO2 requirements will be met through accumulation or acquisition of allowances, the use of controls or fuels, or a combination thereof. See Fuel Supply--Coal and Lignite. Title IV of the CAAA also regulates emissions of NOx. Federal EPA has promulgated NOx emission limitations for all boiler types in the AEP System at levels significantly below original design, which were to be achieved by January 1, 2000 on a unit-by-unit or System-wide average basis. AEP sources subject to Title IV of the CAAA are in 28 compliance with the provisions thereof. Regional Haze: In July 1999, Federal EPA finalized 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, the rules address the potential regulation of such precursor emissions in every state. Under the rule, 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. In addition, Federal EPA intends to require Best Available Retrofit Technology (BART) for power plants and other large emission sources constructed between 1962 and 1977. In January 2001, Federal EPA proposed guidelines for states to use in setting BART emission limits for power plants and other large emission sources and in determining which sources are subject to those limits. The proposed rule calls for technologies which Federal EPA estimates are capable of reducing SO2 emissions by 90 to 95 percent. The proposed rule also contemplates that other visibility-impairing emissions must be reduced. Emission trading programs could be used in lieu of unit-by-unit BART requirements under the proposal, provided they yield greater visibility improvement and emission reductions. The AEP System is a significant emitter of fine particulate matter and other precursors of regional haze and a number of AEP's generating units could be subject to BART controls. Federal EPA's regional haze rule 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. AEP System operating companies and other utilities filed a petition seeking a review of the regional haze rule in the U.S. Court of Appeals for the District of Columbia Circuit in August 1999. 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. - Imposing a national operating permit system, emission fee program and enhanced monitoring, recordkeeping and reporting requirements. Section 103 of CERCLA and Section 304 of the Emergency Planning and Community Right-to-Know Act require notification to state and federal authorities of releases of reportable quantities (RQs) of hazardous and extremely hazardous substances. A number of these substances are emitted by AEP's power plants and other sources. Until recently, emissions of these substances, whether expressly limited in a permit or otherwise subject to federal review or waiver (e.g., mercury), were deemed "federally permitted releases" which did not require emergency notification. In December 1999, Federal EPA published interim guidance in the Federal Register, which provided that any hazardous substance or extremely hazardous substance not expressly and individually limited in a permit must be reported if they are emitted at levels above an RQ. Specifically, constituents of regulated pollutants (e.g., metals contained in particulate matter) were not deemed to be federally permitted. AEP System operating companies have provided supplemental information regarding air releases from their facilities and are submitting follow-up reports. Federal EPA suspended its December 1999 guidance as it considers certain revisions to the guidance. Settlement discussions regarding the guidance are underway. Global Climate Change: In December 1997, delegates from 167 nations, including the U.S., agreed to a treaty, known as the "Kyoto Protocol," establishing legally-binding emission reductions for gases suspected of causing climate change. The Protocol requires ratification by at least 55 nations that account for at least 55% of developed countries' 1990 emissions of CO2 to enter into force. Although the U.S. signed the treaty on November 12, 1998, it was not sent to the Senate for 29 its advice and consent to ratification. In a letter dated March 13, 2001 from President Bush to four U. S. senators, he indicated his opposition to the Kyoto Protocol and said he does not believe that the government should impose mandatory emissions reductions for CO2 on the electric utility sector. Despite U.S. opposition to the treaty, at the Seventh Conference of the Parties to the United Nations Framework Convention on Climate Change, held in Marrakech, Morocco in November 2001, the parties finalized the rules, procedures and guidelines required to facilitate ratification of the treaty by most nations, and entry into force is expected by 2003. Since the AEP System is a significant emitter of carbon dioxide, its results of operations, cash flows and financial condition could be materially adversely affected by the imposition of limitations on CO2 emissions if compliance costs cannot be fully recovered from customers. In addition, any program to reduce CO2 emissions could impose substantial costs on industry and society and erode the economic base that AEP's operations serve. However, it is management's belief that the Kyoto Protocol is highly unlikely to be ratified or implemented in the U.S. in its current form. AEP's 4,000 MW of coal-fired generation in the United Kingdom acquired in 2001 may be exposed to potential carbon dioxide emission control obligations since the U.K. is expected to be a party to the Kyoto Protocol. AEP is developing an emissions mitigation plan for these plants to ensure compliance as necessary. On February 14, 2002, President Bush announced new climate change initiatives for the U.S. Among the policies to be pursued is a voluntary commitment to reduce the "greenhouse gas intensity" of the economy by 18% within the next ten years. It is anticipated that the Administration will seek to partner with various industrial sectors, including the electric utility industry, to reach this goal. AEP is unable to predict at this time the effect that this program will have upon its operations or financial performance in the future. New Source Review: In July 1992, Federal EPA published final regulations 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 (NSR) requirements. The Natural Resources Defense Council and a group of utilities, including five AEP System operating companies, filed petitions in the U.S. Court of Appeals for the District of Columbia Circuit seeking a review of the regulations. In July 1998, Federal EPA requested comment on proposed revisions to the New Source Review rules, which would change New Source Review applicability criteria by eliminating exclusions contained in the current regulation. The Administration and Congress are considering initiatives to reform the NSR requirements, but no regulatory revisions have been proposed to date. New Source Review Litigation: On November 3, 1999, following issuance by Federal EPA of substantial information requests to AEP System operating companies, the Department of Justice (DOJ), on Federal EPA's behalf, filed a complaint in the U.S. District Court for the Southern District of Ohio that alleges AEP made modifications to generating units at certain of its coal-fired generating plants over the course of the past 20 years that extend unit operating lives or restore or increase unit generating capacity without a preconstruction permit in violation of the CAA. The complaint named OPCo's Cardinal Unit 1, Mitchell, Muskingum River, and Sporn plants and I&M's Tanners Creek plant. Federal EPA also issued Notices of Violation to AEP alleging similar violations at certain other AEP plants. In March 2000, DOJ filed an amended complaint that added allegations for certain of the AEP plants previously named in the complaint as well as counts for APCo's Amos, Clinch River, and Kanawha River plants, CSPCo's Conesville Plant, and OPCo's Kammer Plant. In addition to the allegations regarding New Source Review and New Source Performance Standard violations, DOJ included allegations regarding visible particulate emission violations for Cardinal and Muskingum River plants. A number of northeastern and eastern states have been allowed to intervene in the litigation, and 30 a number of special interest groups filed a separate complaint based on substantially similar allegations, which has been consolidated with the DOJ complaint. In addition to the plants named by the government and special interest groups, the intervenor states have included allegations concerning OPCo's Gavin Plant. In May 2000, AEP filed a motion to dismiss with the District Court, which, if granted, would dispose of most of the claims of the government and intervenors. In February 2001, the plaintiffs filed a motion for partial summary judgment seeking a determination that four projects undertaken on units at Sporn, Cardinal, and Clinch River Plants do not constitute "routine maintenance, repair and replacement" as used in the NSR programs. In August 2001, the court issued an order denying the plaintiffs' motion as premature. Management believes its maintenance, repair and replacement activities were in conformity with the CAA and intends to vigorously pursue its defense. A number of unaffiliated utilities have also received notices of violation, complaints, or administrative orders relating to NSR. A notice of violation was issued in June 2000 to DP&L with respect to its ownership interest in Stuart Station, in which CSPCo also owns a 26 percent interest. W.C. Beckjord Unit 6, operated by CG&E, in which CSPCo owns a 12.5 percent interest, is also the subject of an enforcement action. Cinergy Corp., the parent company of CG&E, has entered into an agreement in principle with the DOJ in an attempt to resolve the litigation relating to W.C. Beckjord Unit 6 and other plants owned or operated by Cinergy and its subsidiaries. This agreement in principle also covers the Zimmer Plant which has not been the subject of an enforcement action. VEPCo has also entered into a similar agreement in principle. Neither CG&E nor VEPCo have reached final agreements with the DOJ. Two other unaffiliated utilities, Tampa Electric Company and PSEG Fossil, LLC, have reached settlements with the Federal government. In November 2000, several environmental groups filed a petition with Ohio EPA seeking to have the draft Title V operating permits for OPCo's Cardinal and Muskingum River plants as well as the Beckjord Plant and a plant owned by an unaffiliated utility, modified to incorporate requirements and timetables for compliance with New Source Review requirements. In December 2000, a petition was filed by these groups with the Administrator of Federal EPA seeking a similar modification of the final Title V permit for CSPCo's Conesville Plant. Ohio EPA has refused to consider these petitions outside the regular Title V permit processing procedures or to interfere with the resolution of these issues by the District Court. The CAA authorizes civil penalties of up to $27,500 per day per violation at each generating unit ($25,000 per day prior to January 30, 1997). In March 2001, the District Court issued orders holding that claims for civil penalties based on alleged activities that occurred more than five years prior to the filing of the complaint are barred. Although the plaintiffs' claims for injunctive relief are not barred, the court noted that the nature of the relief ordered may be impacted by the plaintiffs' delay in filing the complaints. Management is unable to estimate the loss or range of loss related to the contingent liability for civil penalties under the CAA proceedings and unable to predict the timing of resolution of these matters due to the number of alleged violations and issues to be determined by the court. In the event the AEP System companies do not prevail, any capital and operating costs of additional pollution control equipment that may be required as well as any penalties imposed could materially adversely affect future results of operations, cash flows and possibly financial condition unless such costs can be recovered through regulated rates and market prices for electricity. 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 31 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 AEP System generating plants are required to have NPDES permits and have received them. NPDES permit conditions and effluent limitations are reviewed during the permit renewal process. Under Federal EPA's regulations, operation under an expired NPDES permit is authorized provided an application is filed at least 180 days prior to expiration. Renewal applications are being prepared or have been filed for renewal of NPDES permits that expire in 2002. 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 CSPCo's Conesville and OPCo's Muskingum River plants impose thermal management conditions that could result in load curtailment under certain conditions, but the cost impacts are not expected to be significant. Based on favorable results of in-stream biological studies, the thermal 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 was further reduced. In early 2002, AEP submitted a petition to Ohio EPA requesting additional less stringent thermal loading limitations for these plants. Section 316(b) of the Clean Water Act requires that cooling water intake structures reflect the best technology available (BTA) for minimizing adverse environmental impact. Federal EPA issued final regulations defining BTA for new sources that were published in the Federal Register on December 18, 2001. New sources are those commencing construction after January 17, 2002. On February 28, 2002, Federal EPA issued a proposed rule addressing BTA for intake structures at existing plants. This proposal is expected to be published in the Federal Register for comment in April 2002. Under a previous court-established schedule, Federal EPA is required to issue final regulations for existing plants by August 2003. Federal EPA's rulemaking could result in a definition of BTA that could ultimately require retrofitting of certain existing plant intake structures. Such changes would involve costs for AEP System operating companies, but the significance of these costs cannot be determined at this time. 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. Section 303 of the Federal Clean Water Act 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 that water quality standards are not being met. In order to bring these waters back into compliance, total maximum daily load (TMDL) allocations of these pollutants will be made, and subsequently translated into discharge limits in NPDES permits. Federal EPA has also directed that states take action to adopt enhanced anti-degradation of water quality requirements. In October 2001, Federal EPA issued a rule delaying until April 30, 2003, the effective date of its TMDL rule issued in July 2000, the effective date of which had been previously delayed by Congress. Implementation of these provisions could result in significant costs to the AEP System if biological monitoring requirements and water quality-based effluent limits and requirements are placed in NPDES permits. In March 1995, Federal EPA finalized a set of rules that 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 32 related to I&M's Cook Plant. Based on Federal EPA's current policy on intake credits and site specific variables and Michigan's implementation strategy, management does not presently expect the GLWQI will have a significant adverse impact on Cook Plant operations. If Indiana and Ohio eventually adopt the GLWQI criteria for statewide application, AEP System plants located in those states could be adversely affected, although the significance depends on the implementation strategy of those states. Oil Pollution Act: The Oil Pollution Act of 1990 (OPA) defines certain facilities that, due to oil storage volume, and location, could reasonably be expected to cause significant and substantial harm to the environment by discharging oil. Such facilities must operate under approved spill response plans and implement spill response training and drill programs. OPA imposes substantial penalties for failure to comply. AEP System operating companies with oil handling and storage facilities meeting the OPA criteria have in place required response plans, training and drill programs. Solid and Hazardous Waste Section 311 of the Clean Water Act imposes substantial penalties for spills of Federal EPA-listed hazardous substances into water and for failure to report such spills. CERCLA expanded the reporting requirement to cover the release of hazardous substances generally into the environment, including water, land and air. AEP's subsidiaries store and use some of these hazardous substances, including PCBs contained in certain capacitors and transformers, but the occurrence and ramifications of a spill or release of such substances cannot be predicted. CERCLA, RCRA and similar state laws provide governmental agencies with the authority to require cleanup of hazardous waste sites and releases of hazardous substances into the environment and to seek compensation for damages to natural resources. Since liability under CERCLA is strict, joint and several, and can be applied retroactively, AEP System operating companies which previously disposed of PCB-containing electrical equipment and other hazardous substances may be required to participate in remedial activities at such disposal sites should environmental problems result. AEP System operating companies are identified as Potentially Responsible Parties (PRPs) for five federal sites where remediation has not been completed, including APCo at one site, CSPCo at one site, I&M at two sites, and OPCo at one site. AEP has also been named a PRP at two sites under state law. Management's present estimates do not anticipate material clean-up costs for identified sites for which AEP subsidiaries have been declared PRPs. In addition, AEP subsidiary companies are engaged in certain remedial projects at various locations, the costs of which are not expected to be material. However, if significant costs are incurred for cleanup, future results of operations and possibly financial condition could be adversely affected unless the costs can be recovered through rates and/or future market prices for electricity where generation is deregulated. 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 of in surface impoundments or landfills in accordance with state permits or authorization or are beneficially utilized. As required by RCRA, Federal 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, Federal EPA issued a regulatory determination that such high volume coal combustion wastes should not be regulated as hazardous waste. Federal EPA chose to address separately the issue of low volume wastes (such as metal and boiler cleaning wastes) associated with burning coal and other fossil fuels. In May 2000, Federal EPA issued a regulatory determination that such low volume wastes are also 33 excluded from regulation under the RCRA hazardous waste provisions when mixed and co-managed with high volume fossil fuel combustion wastes. 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 that 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 and STP and regulated under the Atomic Energy Act is excluded from regulation under RCRA. Underground Storage Tanks: Federal EPA's technical requirements for underground storage tanks containing petroleum required retrofitting or replacement of an appreciable number of tanks. Compliance costs for tank replacement were not significant. Some limited site remediation associated with tank removal is ongoing, but these costs are not expected to be significant. 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, electrical equipment, household wiring, and appliances. A number of studies in the past several years have examined the possibility of adverse health effects from EMF. While some of the epidemiological studies have indicated some association between exposure to EMF and health effects, the majority of studies have indicated no such association. The Energy Policy Act of 1992 established a coordinated Federal EMF research program which ended in 1998. In 1999, the National Institute of Environmental Health Sciences (NIEHS), as required by the Act, provided a report to Congress summarizing the results of this program. The report concluded that "the probability that ...EMF is truly a health hazard is currently small" and that the evidence that exists for health effects is "insufficient to warrant aggressive regulatory actions." Nevertheless, the NIEHS identified several areas where further research might be warranted. AEP has supported EMF research through the years and continues to fund the Electric Power Research Institute's EMF research program, contributing over $400,000 to this program in 2001, and intending to contribute a similar amount in 2002. See Research and Development. AEP's participation in these programs is a continuation of its efforts to monitor and support further research and to communicate with its customers and employees about this issue. Residential customers of AEP are provided information and field measurements on request, although there is no scientific basis for interpreting such measurements. 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. 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 over 100 research projects that focus on: - Exploring new methods of generating electricity, such as through renewable sources (e.g., wind, solar). - Enhancing energy trading infrastructure. - Developing more efficient methods of operating generating plants. 34 - Optimizing and efficiently managing generation and other energy-related assets. - Reducing emissions resulting from the burning of fossil fuels (coal and natural gas). - Improving the efficiency, utilization and reliability of the transmission and distribution systems. - Exploring the application of new technologies. AEP System operating companies are members of the Electric Power Research Institute (EPRI), an organization founded in 1973 that manages science and technology initiatives on behalf of its members. EPRI's members include investor owned and public utilities, independent power producers, international organizations and others. AEP participates in EPRI programs that meet its research and development objectives. Total AEP dues to EPRI were $9,000,000 for 2001, $17,000,000 for 2000 and $22,000,000 for 1999. Of these amounts, the former CSW System paid approximately $7,000,000 in 2000 and $8,000,000 in 1999 for EPRI programs. Total research and development expenditures by AEP and its subsidiaries, including EPRI dues, were approximately $15,000,000 for 2001, $20,000,000 for 2000 and $25,000,000 for 1999. Item 2. PROPERTIES - -------------------------------------------------------------------------------- At December 31, 2001, the AEP System owned (or leased where indicated) generating plants with net power capabilities (east zone subsidiaries-winter rating; west zone subsidiaries-summer rating) shown in the following table:
Coal Natural Gas Hydro Nuclear Lignite Other Total Company Stations MW MW MW MW MW MW MW - ------------------------------------------------------------------------------------------------------------------------- AEGCo 1(a) 1,300 1,300 APCo 17(b) 5,081 777 5,858 CPL 12(c)(d) 686 3,175 6 630 4,497 CSPCo 6(e) 2,595 2,595 I&M 10(a) 2,295 11 2,110 4,416 KEPCo 1 1,060 1,060 OPCo 8(b)(f) 8,464 48 8,512 PSO 8(c) 1,043 3,169 25(g) 4,237 SWEPCo 9 1,848 1,797 842 4,487 WTU 12(c) 377 999 16(g) 1,392 - ------------------------------------------------------------------------------------------------------------------------- Totals: 84 24,749 9,140 842 2,740 842 41 38,354 - -------------------------------------------------------------------------------------------------------------------------
- ---------------------------------- (a) Unit 1 of the Rockport Plant is owned one-half by AEGCo and one-half by I&M. Unit 2 of the Rockport Plant is leased one-half by AEGCo and one-half by I&M. The leases terminate in 2022 unless extended. (b) Unit 3 of the John E. Amos Plant is owned one-third by APCo and two-thirds by OPCo. (c) CPL, PSO, and WTU jointly own the Oklaunion power station. Their respective ownership interests are reflected in this table. (d) Reflects CPL's interest in STP. (e) CSPCo owns generating units in common with CG&E and DP&L. Its ownership interest of 1,330 MW is reflected in this table. (f) The scrubber facilities at the General James M. Gavin Plant are leased. The lease terminates in 2010 unless extended. (g) PSO and WTU have 25 MW and 10 MW respectively of facilities designed primarily to burn oil. WTU has one 6 MW wind farm facility. 35 AEP-Other Generation: In addition to the generating facilities described above, AEP has ownership interests in other electrical generating facilities, both foreign and domestic. Information concerning these facilities at December 31, 2001 is listed below (except for Bajio which went into commercial operation in March 2002).
CAPACITY OWNERSHIP FACILITY FUEL LOCATION TOTAL MW INTEREST STATUS - --------------------------------------------------------------------------------------------------------------------- Brush II Natural gas Colorado 68 47.75% QF Eastex Natural gas Texas 440 50% QF Indian Mesa Wind Texas 161 100% EWG Mulberry Natural gas Florida 120 46.25% QF Newgulf Natural gas Texas 85 100% EWG Orange Cogen Natural gas Florida 103 50% QF Sweeny Natural gas Texas 480 50% QF Thermo Cogeneration Natural gas Colorado 272 50% QF Trent Wind Farm Wind Texas 150 100% EWG - --------------------------------------------------------------------------------------------------------------------- Total U.S. 1,879 - --------------------------------------------------------------------------------------------------------------------- Bajio Natural gas Mexico 605 50% FUCO Bakun Hydro Philippines 70 10% FUCO Codrington Wind Australia 18 20% FUCO Ferrybridge Coal United Kingdom 2,000 100% FUCO Fiddler's Ferry Coal United Kingdom 2,000 100% FUCO Medway Natural gas United Kingdom 675 37.5% FUCO Nanyang Coal China 250 70% FUCO Ord Hydro Hydro Australia 30 20% FUCO Southcoast Natural gas United Kingdom 380 50% FUCO Vale Hydro/Thermal Brazil 665 (a) FUCO Victoria Hydro Australia 10 20% FUCO - --------------------------------------------------------------------------------------------------------------------- Total International 6,703 - ---------------------------------------------------------------------------------------------------------------------
(a) AEP has varying minority interests which aggregate to 168 MW. See Item 1 under Fuel Supply for information concerning coal reserves owned or controlled by subsidiaries of AEP and under Wholesale Business Operations for information concerning AEP's natural gas pipeline, storage and processing facilities. The following table sets forth the total overhead circuit miles of transmission and distribution lines of the AEP System and its operating companies and that portion of the total representing 765,000-volt lines: TOTAL OVERHEAD CIRCUIT MILES OF TRANSMISSION AND CIRCUIT MILES OF DISTRIBUTION LINES 765,00-VOLT LINES ------------------ ----------------- AEP System (a).............. 211,300(b) 2,023 APCo..................... 51,295 642 CPL...................... 31,210 --- CSPCo (a)................ 13,703 --- I&M...................... 20,672 614 KEPCo.................... 10,443 258 OPCo .................... 29,347 509 PSO...................... 18,713 --- SWEPCo................... 19,873 --- WTU...................... 12,605 --- - ---------------------- (a) Includes 766 miles of 345,000-volt jointly owned lines. (b) Includes 73 miles of transmission lines not identified with an operating company. 36 TITLES The AEP System's electric generating stations are generally located on lands owned in fee simple. The greater portion of the transmission and distribution lines of the System has been constructed over lands of private owners pursuant to easements or along public highways and streets pursuant to appropriate statutory authority. The rights of the System in the realty on which its facilities are located are considered by it to be adequate for its use in the conduct of its business. Minor defects and irregularities customarily found in title to properties of like size and character may exist, but such defects and irregularities do not materially impair the use of the properties affected thereby. System companies generally have the right of eminent domain whereby they may, if necessary, acquire, perfect or secure titles to or easements on privately-held lands used or to be used in their utility operations. Substantially all the fixed physical properties and franchises of the AEP System operating companies, except for limited conditions and limitations, are subject to the lien of the mortgage and deed of trust securing the first mortgage bonds of each such company. SYSTEM TRANSMISSION LINES AND FACILITY SITING Legislation in the states of Arkansas, Indiana, Kentucky, Michigan, Ohio, Texas, Virginia, and West Virginia requires prior approval of sites of generating facilities and/or routes of high-voltage transmission lines. Delays and additional costs in constructing facilities have been experienced as a result of proceedings conducted pursuant to such statutes, as well as in proceedings in which operating companies have sought to acquire rights-of-way through condemnation, and such proceedings may result in additional delays and costs in future years. PEAK DEMAND The east zone system is interconnected through 121 high-voltage transmission interconnections with 25 neighboring electric utility systems. The all-time and 2001 one-hour peak system demands were 25,940,000 and 25,433,000 kilowatts, respectively (which included 7,314,000 and 5,469,000 kilowatts, respectively, of scheduled deliveries to unaffiliated systems which the system might, on appropriate notice, have elected not to schedule for delivery) and occurred on June 17, 1994 and July 24, 2001, respectively. The net dependable capacity to serve the system load on such date, including power available under contractual obligations, was 23,457,000 and 23,974,000 kilowatts, respectively. The all-time and 2001 one-hour internal peak demand was 20,218,000 kilowatts, and occurred on August 8, 2001. The net dependable capacity to serve the system load on such date, including power dedicated under contractual arrangements, was 23,935,000 kilowatts. The all-time one-hour integrated and internal net system peak demands and 2001 peak demands for the east zone generating subsidiaries are shown in the following tabulation: ALL-TIME ONE-HOUR INTEGRATED 2001 ONE-HOUR INTEGRATED NET SYSTEM PEAK DEMAND NET SYSTEM PEAK DEMAND - ------------------------------ -------------------------- (IN THOUSANDS) NUMBER OF NUMBER OF KILOWATTS DATE KILOWATTS DATE ----------- ------ ----------- ------- APCo...... 8,303 January 17, 1997 7,750 January 10, 2001 CSPCo..... 4,833 July 23, 2001 4,833 July 23, 2001 I&M....... 5,403 June 23, 2001 5,403 July 23, 2001 KEPCo..... 1,860 January 10, 2001 1,860 January 10, 2001 OPCo...... 7,291 June 17, 1994 6,668 July 24, 2001 ALL-TIME ONE-HOUR INTEGRATED 2001 ONE-HOUR INTEGRATED NET INTERNAL PEAK DEMAND NET INTERNAL PEAK DEMAND - ------------------------------ -------------------------- (IN THOUSANDS) NUMBER OF NUMBER OF KILOWATTS DATE KILOWATTS DATE ----------- ------ ----------- ------- APCo ...... 6,908 February 5, 1996 6,402 January 3, 2001 CSPCo...... 3,927 August 8, 2001 3,927 August 8, 2001 I&M........ 4,232 August 8, 2001 4,232 August 8, 2001 KEPCo..... 1,579 January 3, 2001 1,579 January 3, 2001 OPCo....... 5,705 June 11, 1999 5,341 July 24, 2001 The all-time and 2001 one-hour internal peak demand for the west zone system was 15,048,000 and 14,648,000 kilowatts, respectively, and occurred on August 31, 2000 and July 23, 2001, respectively. The all-time one-hour internal net system peak demands and 2001 peak demands for the west zone generating subsidiaries are shown in the following tabulation: 37 ALL-TIME ONE-HOUR INTEGRATED 2001 ONE-HOUR INTEGRATED NET INTERNAL PEAK DEMAND NET INTERNAL PEAK DEMAND - ------------------------------- ------------------------- (IN THOUSANDS) NUMBER OF NUMBER OF KILOWATTS DATE KILOWATTS DATE ----------- ----- ----------- ------- CPL ....... 4,623 September 5, 2000 4,323 June 12, 2001 PSO........ 3,823 August 30, 2000 3,785 August 9, 2001 SWEPCo..... 4,625 August 31, 2000 4,344 July 18, 2001 WTU....... 1,537 September 5, 2000 1,472 July 19, 2001 HYDROELECTRIC PLANTS AEP has 18 hydro facilities, of which 16 are licensed through FERC. The license for the Elkhart hydroelectric plant in Indiana was issued in January 2001 and extends for a period of thirty years. The license for the Mottville hydroelectric plant in Michigan expires in 2003 and the application for a new license was filed with FERC in September 2001. COOK NUCLEAR PLANT AND STP The following table provides operating information relating to the Cook Plant and STP. COOK PLANT STP(a) ------------------- ------------------ UNIT 1 UNIT 2 UNIT 1 UNIT 2 ------ ------ ------ ------ Year Placed in Operation 1975 1978 1988 1989 Year of Expiration of Nrc License (b) 2014 2017 2027 2028 Nominal Net Electrical Rating in 1,020,000 1,090,000 1,250,600 1,250,600 Kilowatts Net Capacity Factors 2001 (c) 87.3% 83.4% 94.4% 87.1% 2000 (d) 1.4% 50.0% 78.2% 96.1% - --------------------- (a) Reflects total plant. (b) For economic or other reasons, operation of the Cook Plant and STP for the full term of their operating licenses cannot be assured. (c) The capacity factor for both units of the Cook Plant was significantly reduced in 2001 due to an unplanned dual maintenance outage in September 2001 to implement design changes that improved the performance of the essential service water system. (d) The Cook Plant was shut down in September 1997 to respond to issues raised regarding the operability of certain safety systems. The restart of both units of the Cook Plant was completed with Unit 2 reaching 100% power on July 5, 2000 and Unit 1 achieving 100% power on January 3, 2001. Costs associated with the operation (excluding fuel), maintenance and retirement of nuclear plants continue to be of greater significance and less predictable than costs associated with other sources of generation, in large part due to changing regulatory requirements and safety standards, availability of nuclear waste disposal facilities and experience gained in the construction and operation of nuclear facilities. I&M and CPL may also incur costs and experience reduced output at Cook Plant and STP, respectively, because of the design criteria prevailing at the time of construction and the age of the plant's systems and equipment. Nuclear industry-wide and Cook Plant and STP initiatives have contributed to slowing the growth of operating and maintenance costs at these plants. However, the ability of I&M and CPL to obtain adequate and timely recovery of costs associated with the Cook Plant and STP, respectively, including replacement power, any unamortized investment at the end of the useful life of the Cook Plant and STP (whether scheduled or premature), the carrying costs of that investment and retirement costs, is not assured. See Competition and Business Change. POTENTIAL UNINSURED LOSSES Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including liabilities relating to damage to the Cook Plant or STP and costs of replacement power in the event of a nuclear incident at the Cook Plant or STP. Future losses or liabilities which are not completely insured, unless allowed to be recovered through rates, could have a material adverse effect on results of operations and the financial condition of AEP, CPL, I&M and other AEP System companies. Reference is made to the footnote to the financial statements entitled Commitments and Contingencies that is incorporated by reference in Item 8 for information with respect to nuclear incident liability insurance. 38 Item 3. LEGAL PROCEEDINGS - -------------------------------------------------------------------------------- Federal EPA Notice of Violation to OPCo: On August 31, 2000, Region V, Federal EPA, issued a Notice of Violation (NOV) to OPCo's Gavin Plant that alleges violations of the Federal EPA-approved Ohio mass particulate emission limit, opacity, and air pollution nuisance rules. AEP has submitted information in response to the allegations and requested a conference to discuss the NOV with Region V representatives. Ohio EPA Notices of Violation to OPCo: On August 17, 2001, Ohio EPA issued proposed findings and orders to OPCo's Gavin Plant based on the alleged failure of a mass particulate emissions test on May 17, 2000. OPCo requested a conference to discuss the proposed findings and orders and submitted the results of its investigation of the test procedures, which confirmed that the May 17 test was invalid due to the corrosion and disintegration of the test probe. On December 27, 2001, Ohio EPA issued two NOVs to OPCo's Gavin Plant, alleging that OPCo failed to notify Ohio EPA of a malfunction of the flyash handling system at the plant, and that OPCo failed to conduct a required mass particulate emissions test. OPCo has submitted additional control plans for the flyash handling system and information regarding the particulate testing completed at the Gavin Plant in response to the NOVs. COLI Litigation: On February 20, 2001, the U.S. District Court for the Southern District of Ohio ruled against AEP in its suit against the United States over deductibility of interest claimed by AEP in its consolidated federal income tax return related to its COLI program. AEP had filed suit to resolve the IRS' assertion that interest deductions for AEP's COLI program should not be allowed. In 1998 and 1999 AEP paid the disputed taxes and interest attributable to COLI interest deductions for taxable years 1991-98 to avoid the potential assessment by the IRS of additional interest on the contested tax. The payments were included in other assets pending the resolution of this matter. As a result of the U.S. District Court's decision to deny the COLI interest deductions, net income was reduced in 2000 as follows: (IN MILLIONS) AEP System operating companies...... $ 319 APCo............................. 82 CSPCo............................ 41 I&M.............................. 66 KEPCo............................ 8 OPCo............................. 118 The Company has filed an appeal of the U.S. District Court's decision with the U.S. Court of Appeals for the Sixth Circuit. ---------------------- See Item 1 for a discussion of certain environmental matters. ---------------------- Reference is made to the footnote to the financial statements entitled Commitments and Contingencies incorporated by reference in Item 8 for further information with respect to other legal proceedings. 39 Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS - -------------------------------------------------------------------------------- AEP, APCO, CPL, I&M, OPCO AND SWEPCO. None. AEGCO, CSPCO, KEPCO, PSO AND WTU. Omitted pursuant to Instruction I(2)(c). ---------------------- EXECUTIVE OFFICERS OF THE REGISTRANTS AEP. The following persons are, or may be deemed, executive officers of AEP. Their ages are given as of March 1, 2002.
NAME AGE OFFICE (a) - ---- --- --------- E. Linn Draper, Jr............. 60 Chairman of the Board, President and Chief Executive Officer of AEP and of the Service Corporation Thomas V. Shockley, III........ 56 Vice Chairman and Chief Operating Officer of the Service Corporation Henry W. Fayne................. 55 Executive Vice President of the Service Corporation Robert P. Powers............... 48 Executive Vice President-Nuclear Generation and Technical Services of the Service Corporation Susan Tomasky.................. 48 Executive Vice President-Policy, Finance and Strategic Planning of the Service Corporation J. H. Vipperman................ 61 Executive Vice President-Shared Services of the Service Corporation
- ------------------------- (a) All of the executive officers listed above have been employed by the Service Corporation or System companies in various capacities (AEP, as such, has no employees) during the past five years, except for Messrs. Powers and Shockley and Ms. Tomasky. Prior to joining the Service Corporation in July 1998 as Senior Vice President-Generation, Mr. Powers was Vice President of Pacific Gas & Electric and plant manager of its Diablo Canyon Nuclear Generating Station (1996-1998). Prior to joining the Service Corporation in July 1998 as Senior Vice President, Ms. Tomasky was a partner with the law firm of Hogan & Hartson (August 1997-July 1998) and General Counsel of the Federal Energy Regulatory Commission (May 1993-August 1997). Mr. Powers and Ms. Tomasky became executive officers of AEP effective with their promotions to Executive Vice President on October 24, 2001 and January 26, 2000, respectively. Prior to joining the Service Corporation in his current position upon the merger with CSW, Mr. Shockley was President and Chief Operating Officer of CSW (1997-2000) and Executive Vice President of CSW (1990-1997). All of the above officers are appointed annually for a one-year term by the board of directors of AEP, the board of directors of the Service Corporation, or both, as the case may be. APCO, CPL, I&M, OPCO AND SWEPCO. The names of the executive officers of APCo, CPL, I&M, OPCo and SWEPCo, the positions they hold with these companies, their ages as of March 1, 2002, and a brief account of their business experience during the past five years appear below. The directors and executive officers of APCo, CPL, I&M, OPCo and SWEPCo are elected annually to serve a one-year term.
NAME AGE POSITION (a)(b) PERIOD - ---- --- --------------- ------ E. Linn Draper, Jr............ 60 Director of CPL and SWEPCo 2000-Present Chairman of the Board and Chief Executive Officer of CPL and SWEPCo 2000-Present Director of APCo, I&M and OPCo 1992-Present Chairman of the Board and Chief Executive Officer of APCo, I&M and OPCo 1993-Present Chairman of the Board, President and Chief Executive Officer of AEP and the Service Corporation 1993-Present
40
NAME AGE POSITION (a)(b) PERIOD - ---- --- --------------- ------ Thomas V. Shockley, III....... 56 Director and Vice President of APCo, CPL, I&M, OPCo and SWEPCo 2000-Present Chief Operating Officer of the Service Corporation 2001-Present Vice Chairman of AEP and the Service Corporation 2000-Present President and Chief Operating Officer of CSW 1997-2000 Executive Vice President of CSW 1990-1997 Henry W. Fayne................ 55 President of APCo, CPL, I&M, OPCo and SWEPCo 2001-Present Director of CPL and SWEPCO 2000-Present Director of APCo 1995-Present Director of OPCo 1993-Present Director of I&M 1998-Present Vice President of CPL and SWEPCo 2000-2001 Vice President of APCo, I&M and OPCo 1998-2001 Vice President of AEP 1998-Present Chief Financial Officer of AEP 1998-2001 Executive Vice President of the Service Corporation 2001-Present Executive Vice President-Finance and Analysis of the Service Corporation 2000-2001 Executive Vice President-Financial Services of the Service Corporation 1998-2000 Senior Vice President-Corporate Planning & Budgeting of the Service Corporation 1995-1998 Robert P. Powers.............. 48 Director and Vice President of APCo, CPL, OPCo and SWEPCo 2001-Present Director of I&M 2001-Present Vice President of I&M 1998-Present Executive Vice President-Nuclear Generation and Technical Services of the Service Corporation 2001-Present Senior Vice President-Nuclear Operations of the Service Corporation 2000-2001 Senior Vice President-Nuclear Generation of the Service Corporation 1998-2000 Vice President of Pacific Gas & Electric and Plant Manager of its Diablo Canyon Nuclear Generating Station 1996-1998 Susan Tomasky................. 48 Director and Vice President of APCo, CPL, I&M, OPCo and SWEPCo 2000-Present Executive Vice President-Policy, Finance and Strategic Planning of the Service Corporation 2001-Present Executive Vice President-Legal, Policy and Corporate Communications and General Counsel of the Service Corporation 2000-2001 Senior Vice President and General Counsel of the Service Corporation 1998-2000 Hogan & Hartson (law firm) 1997-1998 General Counsel of the FERC 1993-1997
41
NAME AGE POSITION (a)(b) PERIOD - ---- --- --------------- ------ J. H. Vipperman............... 61 Director and Vice President of CPL and SWEPCo 2000-Present Director of APCo 1985-Present Director of I&M and OPCo 1996-Present Vice President of APCo, I&M and OPCo 1996-Present Executive Vice President-Shared Services of the Service Corporation 2000-Present Executive Vice President-Corporate Services of the Service Corporation 1998-2000 Executive Vice President-Energy Delivery of the Service Corporation 1996-1997
- ----------------- (a) Dr. Draper is a director of BCP Management, Inc., which is the general partner of Borden Chemicals and Plastics L.P. (b) Dr. Draper, Messrs. Fayne, Powers, Shockley and Vipperman and Ms. Tomasky are directors of AEGCo, CSPCo, KEPCo, PSO and WTU. Dr. Draper and Mr. Shockley are also directors of AEP. PART II ------------------------------------------------------------------------ Item 5. MARKET FOR REGISTRANTS' COMMON EQUITY AND RELATED STOCKHOLDER MATTERS - -------------------------------------------------------------------------------- AEP. The information required by this item is incorporated herein by reference to the material under Common Stock and Dividend Information in the 2001 Annual Report. AEGCO, APCO, CPL, CSPCO, I&M, KEPCO, OPCO, PSO, SWEPCO AND WTU. The common stock of these companies is held solely by AEP. The amounts of cash dividends on common stock paid by these companies to AEP during 2001 and 2000 are incorporated by reference to the material under Statement of Retained Earnings in the 2001 Annual Reports. Item 6. SELECTED FINANCIAL DATA - -------------------------------------------------------------------------------- AEGCO, CSPCO, KEPCO, PSO AND WTU. Omitted pursuant to Instruction I(2)(a). AEP, APCO, CPL, I&M, OPCO AND SWEPCO. The information required by this item is incorporated herein by reference to the material under Selected Consolidated Financial Data in the 2001 Annual Reports. Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION - -------------------------------------------------------------------------------- AEGCO, CSPCO, KEPCO, PSO AND WTU. Omitted pursuant to Instruction I(2)(a). Management's narrative analysis of the results of operations and other information required by Instruction I(2)(a) is incorporated herein by reference to the material under Management's Narrative Analysis of Results of Operations in the 2001 Annual Reports. AEP, APCO, CPL, I&M, OPCO AND SWEPCO. The information required by this item is incorporated herein by reference to the material under Management's Discussion and Analysis of Results of Operations and Management's Discussion and Analysis of Financial Condition, Contingencies and Other Matters in the 2001 Annual Reports. 42 Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK - -------------------------------------------------------------------------------- AEGCO, AEP, APCO, CPL, CSPCO, I&M, KEPCO, OPCO, PSO, SWEPCO AND WTU. The information required by this item is incorporated herein by reference to the material under Management's Discussion and Analysis of Financial Condition, Contingencies and Other Matters in the 2001 Annual Reports. Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA - -------------------------------------------------------------------------------- AEGCO, AEP, APCO, CPL, CSPCO, I&M, KEPCO, OPCO, PSO, SWEPCO AND WTU. The information required by this item is incorporated herein by reference to the financial statements and supplementary data described under Item 14 herein. Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE - -------------------------------------------------------------------------------- AEGCO, AEP, APCO, CSPCO, I&M, KEPCO AND OPCO. None. CPL, PSO, SWEPCO AND WTU. The information required by this item is incorporated herein by reference to each company's Current Report on Form 8-K dated July 5, 2000. PART III ----------------------------------------------------------------------- Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS - -------------------------------------------------------------------------------- AEGCo, CSPCo, KEPCo, PSO and WTU. Omitted pursuant to Instruction I(2)(c). AEP. The information required by this item is incorporated herein by reference to the material under Nominees for Director and Section 16(a) Beneficial Ownership Reporting Compliance of the definitive proxy statement of AEP for the 2002 annual meeting of shareholders, to be filed within 120 days after December 31, 2001. Reference also is made to the information under the caption Executive Officers of the Registrants in Part I of this report. APCO AND OPCO. The information required by this item is incorporated herein by reference to the material under Election of Directors of the definitive information statement of each company for the 2002 annual meeting of stockholders, to be filed within 120 days after December 31, 2001. Reference also is made to the information under the caption Executive Officers of the Registrants in Part I of this report. CPL AND SWEPCO. The information required by this item is incorporated herein by reference to the material under Election of Directors of the definitive information statement of APCo for the 2002 annual meeting of stockholders, to be filed within 120 days after December 31, 2001. Reference also is made to the information under the caption Executive Officers of the Registrants in Part I of this report. I&M. The names of the directors and executive officers of I&M, the positions they hold 43 with I&M, their ages as of March 12, 2002, and a brief account of their business experience during the past five years appear below and under the caption Executive Officers of the Registrants in Part I of this report.
NAME AGE POSITION (a) PERIOD - ---- --- ------------ ------ K. G. Boyd..................... 50 Director 1997-Present Vice President - Fort Wayne Region Distribution Operations 2000-Present Indiana Region Manager 1997-2000 Fort Wayne District Manager 1994-1997 John E. Ehler.................. 45 Director 2001-Present Manager of Distribution Systems-Fort Wayne District 2000-Present Region Operations Manager 1997-2000 David L. Lahrman............... 50 Director and Manager, Region Support 2001-Present Fort Wayne District Manager 1997-2001 Region Operations Manager 1994-1997 Marc E. Lewis.................. 47 Director 2001-Present Assistant General Counsel of the Service Corporation 2001-Present Senior Counsel of the Service Corporation 2000-2001 Senior Attorney of the Service Corporation 1994-2000 Susanne M. Moorman............ 52 Director and General Manager, Community Services 2000-Present Manager, Customer Services Operations 1997-2000 Director, Customer Services 1994-1997 John R. Sampson................ 49 Director and Vice President 1999-Present Indiana State President 2000-Present Indiana & Michigan State President 1999-2000 Site Vice President, Cook Nuclear Plant 1998-1999 Plant Manager, Cook Nuclear Plant 1996-1998 D. B. Synowiec................. 58 Director 1995-Present Plant Manager, Rockport Plant 1990-Present
- ----------------- (a) Positions are with I&M unless otherwise indicated. Item 11. EXECUTIVE COMPENSATION - -------------------------------------------------------------------------------- AEGCO, CSPCO, KEPCO, PSO AND WTU. Omitted pursuant to Instruction I(2)(c). AEP. The information required by this item is incorporated herein by reference to the material under Directors Compensation and Stock Ownership Guidelines, Executive Compensation and the performance graph of the definitive proxy statement of AEP for the 2002 annual meeting of shareholders to be filed within 120 days after December 31, 2001. APCO AND OPCO. The information required by this item is incorporated herein by reference to the material under Executive Compensation of the definitive information statement of each company for the 2002 annual meeting of stockholders, to be filed within 120 days after December 31, 2001. CPL, I&M AND SWEPCO. The information required by this item is incorporated herein by reference to the material under Executive Compensation of the definitive information 44 statement of APCo for the 2002 annual meeting of stockholders, to be filed within 120 days after December 31, 2001. Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT - -------------------------------------------------------------------------------- AEGCO, CSPCO, KEPCO, PSO AND WTU. Omitted pursuant to Instruction I(2)(c). AEP. The information required by this item is incorporated herein by reference to the material under Share Ownership of Directors and Executive Officers of the definitive proxy statement of AEP for the 2002 annual meeting of shareholders to be filed within 120 days after December 31, 2001. APCO AND OPCO. The information required by this item is incorporated herein by reference to the material under Share Ownership of Directors and Executive Officers in the definitive information statement of each company for the 2002 annual meeting of stockholders, to be filed within 120 days after December 31, 2001. CPL AND SWEPCO. The information required by this item is incorporated herein by reference to the material under Share Ownership of Directors and Executive Officers in the definitive information statement of APCo for the 2002 annual meeting of stockholders, to be filed within 120 days after December 31, 2001. I&M. All 1,400,000 outstanding shares of Common Stock, no par value, of I&M are directly and beneficially held by AEP. Holders of the Cumulative Preferred Stock of I&M generally have no voting rights, except with respect to certain corporate actions and in the event of certain defaults in the payment of dividends on such shares. The table below shows the number of shares of AEP Common Stock and stock-based units that were beneficially owned, directly or indirectly, as of January 1, 2002, by each director and nominee of I&M and each of the executive officers of I&M named in the summary compensation table, and by all directors and executive officers of I&M as a group. It is based on information provided to I&M by such persons. No such person owns any shares of any series of the Cumulative Preferred Stock of I&M. Unless otherwise noted, each person has sole voting power and investment power over the number of shares of AEP Common Stock and stock-based units set forth opposite his name. Fractions of shares and units have been rounded to the nearest whole number.
STOCK ----- NAME SHARES (a) UNITS (b) TOTAL - ---- --------- -------- ----- Karl G. Boyd........................................................... 6,964 88 7,052 E. Linn Draper, Jr..................................................... 238,274(c) 119,218 357,492 John E. Ehler.......................................................... 7 -- 7 Henry W. Fayne......................................................... 72,685(d) 13,735 86,420 David L. Lahrman....................................................... 360 -- 360 Marc E. Lewis.......................................................... 1,117 -- 1,117 Susanne M. Moorman..................................................... 841 -- 841 Robert P. Powers....................................................... 21,269 1,209 22,478 John R. Sampson........................................................ 5,525 109 5,634 Thomas V. Shockley, III................................................ 138,822(d)(e) -- 138,822 David B. Synowiec...................................................... 2,361 129 2,490 Susan Tomasky.......................................................... 67,322 4,329 71,651 Joseph H. Vipperman.................................................... 78,043(c)(d) 7,201 85,244 All Directors and Executive Officers................................... 633,590(d)(f) 146,018 779,608
45 - ------------------------- (a) Includes share equivalents held in the AEP Retirement Savings Plan (and for Mr. Shockley, the CSW Retirement Savings Plan) in the amounts listed below:
AEP RETIREMENT SAVINGS AEP RETIREMENT SAVINGS NAME PLAN (SHARE EQUIVALENTS) NAME PLAN (SHARE EQUIVALENTS) ---- ------------------------ ---- ------------------------ Mr. Boyd............................. 1,964 Mr. Powers................................. 436 Dr. Draper........................... 4,280 Mr. Sampson................................ 525 Mr. Ehler............................ 7 Mr. Shockley............................... 6,579 Mr. Fayne............................ 5,412 Mr. Synowiec............................... 695 Mr. Lahrman.......................... 360 Ms. Tomasky................................ 656 Mr. Lewis............................ 1,117 Mr. Vipperman.............................. 10,498 Ms. Moorman.........................` 841 All Directors and Executive Officers............ 33,370
With respect to the share equivalents held in the AEP Retirement Savings Plan, such persons have sole voting power, but the investment/disposition power is subject to the terms of the Plan. Also, includes the following numbers of shares attributable to options exercisable within 60 days: Mr. Boyd, 5,000; Dr. Draper, 233,333; Mr. Powers, 20,833; Mr. Sampson, 5,000; Mr. Shockley, 94,450; Mr. Synowiec, 1,666; and Messrs. Fayne and Vipperman and Ms. Tomasky, 66,666. (b) This column includes amounts deferred in stock units and held under AEP's officer benefit plans. (c) Includes the following numbers of shares held in joint tenancy with a family member: Dr. Draper, 661; and Mr. Vipperman, 80. (d) Does not include, for Messrs. Fayne, Shockley and Vipperman, 85,231 shares in the American Electric Power System Educational Trust Fund over which Messrs. Fayne, Shockley and Vipperman share voting and investment power as trustees (they disclaim beneficial ownership). The amount of shares shown for all directors and executive officers as a group includes these shares (e) Includes the following numbers of shares held by family members over which beneficial ownership is disclaimed: Mr. Shockley, 496. (f) Represents less than 1% of the total number of shares outstanding Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS - -------------------------------------------------------------------------------- AEP, APCO, CPL, I&M, OPCO AND SWEPCO. None. AEGCO, CSPCO, KEPCO, PSO AND WTU. Omitted pursuant to Instruction I(2)(c). PART IV ------------------------------------------------------------------------ Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K - -------------------------------------------------------------------------------- (a) The following documents are filed as a part of this report: 1. FINANCIAL STATEMENTS: The following financial statements have been incorporated herein by reference pursuant to Item 8.
PAGE ---- AEGCo: Independent Auditors' Report; Statements of Income for the years ended December 31, 2001, 2000, and 1999; Statements of Retained Earnings for the years ended December 31, 2001, 2000 and 1999; Statements of Cash Flows for the years ended December 31, 2001, 2000, and 1999; Balance Sheets as of December 31, 2001 and 2000; Statements of Capitalization as of December 31, 2001 and 2000; Combined Notes to Financial Statements. AEP and its subsidiaries consolidated: Consolidated Statements of Income for the years ended December 31, 2001, 2000, and 1999; Consolidated Balance Sheets as of December 31, 2001 and 2000; Consolidated
46 PAGE ---- Statements of Cash Flows for the years ended December 31, 2001, 2000, and 1999; Consolidated Statements of Common Shareholders' Equity and Comprehensive Income for the years ended December 31, 2001, 2000, and 1999; Combined Notes to Financial Statements; Schedule of Consolidated Cumulative Preferred Stocks of Subsidiaries at December 31, 2001 and 2000; Schedule of Consolidated Long-term Debt of Subsidiaries at December 31, 2001 and 2000; Independent Auditors' Reports. APCo, I&M, and OPCo: Independent Auditors' Report; Consolidated Statements of Income for the years ended December 31, 2001, 2000, and 1999; Consolidated Statements of Comprehensive Income for the years ended December 31, 2001, 2000 and 1999; Consolidated Balance Sheets as of December 31, 2001 and 2000; Consolidated Statements of Cash Flows for the years ended December 31, 2001, 2000, and 1999; Consolidated Statements of Retained Earnings for the years ended December 31, 2001, 2000, and 1999; Consolidated Statements of Capitalization as of December 31, 2001 and 2000; Schedule of Consolidated Long-term Debt as of December 31, 2001 and 2000; Combined Notes to Financial Statements. CPL, CSPCo, PSO, and SWEPCo: Independent Auditors' Report(s); Consolidated Statements of Income for the years ended December 31, 2001, 2000, and 1999; Consolidated Balance Sheets as of December 31, 2001 and 2000; Consolidated Statements of Cash Flows for the years ended December 31, 2001, 2000, and 1999; Consolidated Statements of Retained Earnings for the years ended December 31, 2001, 2000, and 1999; Consolidated Statements of Capitalization as of December 31, 2001 and 2000; Schedule of Consolidated Long-term Debt as of December 31, 2001 and 2000; Combined Notes to Financial Statements. KEPCo: Independent Auditors' Report; Statements of Income for the years ended December 31, 2001, 2000, and 1999; Statements of Retained Earnings for the years ended December 31, 2001, 2000, and 1999; Statements of Cash Flows for the years ended December 31, 2001, 2000, and 1999; Statements of Comprehensive Income for the years ended December 31, 2001, 2000 and 1999; Balance Sheets as of December 31, 2001 and 2000; Statements of Capitalization as of December 31, 2001 and 2000; Schedule of Long-term Debt as of December 31, 2001 and 2000; Combined Notes to Financial Statements. WTU: Independent Auditors' Reports; Statements of Income for the years ended December 31, 2001, 2000, and 1999; Statements of Retained Earnings for the years ended December 31, 2001, 2000, and 1999; Statements of Cash Flows for the years ended December 31, 2001, 2000, and 1999; Balance Sheets as of December 31, 2001 and 2000; Statements of Capitalization as of December 31, 2001 and 2000; Schedule of Long-term Debt as of December 31, 2001 and 2000; Combined Notes to Financial Statements. 47 PAGE ----
2. FINANCIAL STATEMENT SCHEDULES: Page ---- Financial Statement Schedules are listed in the Index to Financial Statement Schedules (Certain schedules have been omitted because the required information is contained in the notes to financial statements or because such schedules are not required or are not applicable). S-1 Independent Auditors' Report S-2 3. EXHIBITS: Exhibits for AEGCo, AEP, APCo, CPL, CSPCo, I&M, KEPCo, OPCo, PSO, SWEPCo and WTU are listed in the Exhibit Index and are incorporated herein by reference E-1 (b) No Reports on Form 8-K were filed during the quarter ended December 31, 2001.
48 SIGNATURES PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED. AMERICAN ELECTRIC POWER COMPANY, INC. BY: /s/ SUSAN TOMASKY ------------------------------------------- (SUSAN TOMASKY, VICE PRESIDENT, SECRETARY AND CHIEF FINANCIAL OFFICER) Date: March 18, 2002 PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED.
SIGNATURE TITLE DATE --------- ----- ----- (i) PRINCIPAL EXECUTIVE OFFICER: *E. LINN DRAPER, JR. Chairman of the Board, President, Chief Executive Officer And Director (ii) PRINCIPAL FINANCIAL OFFICER: /s/ SUSAN TOMASKY Vice President, Secretary and March 18, 2002 - -------------------------------------------- Chief Financial Officer (SUSAN TOMASKY) (iii) PRINCIPAL ACCOUNTING OFFICER: /s/ JOSEPH M. BUONAIUTO Controller and March 18, 2002 - ------------------------------------------- Chief Accounting Officer (JOSEPH M. BUONAIUTO) (iv) A MAJORITY OF THE DIRECTORS: *E. R. BROOKS *DONALD M. CARLTON *JOHN P. DESBARRES *ROBERT W. FRI *WILLIAM R. HOWELL *LESTER A. HUDSON, JR. *LEONARD J. KUJAWA *JAMES L. POWELL *RICHARD L. SANDOR *THOMAS V. SHOCKLEY, III *DONALD G. SMITH *LINDA GILLESPIE STUNTZ *KATHRYN D. SULLIVAN March 18, 2002 *By: /s/ SUSAN TOMASKY --------------------------------- (SUSAN TOMASKY, ATTORNEY-IN-FACT)
49 SIGNATURES PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED. THE SIGNATURE OF THE UNDERSIGNED COMPANY SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING REFERENCE TO SUCH COMPANY AND ANY SUBSIDIARIES THEREOF. AEP GENERATING COMPANY APPALACHIAN POWER COMPANY CENTRAL POWER AND LIGHT COMPANY COLUMBUS SOUTHERN POWER COMPANY KENTUCKY POWER COMPANY OHIO POWER COMPANY PUBLIC SERVICE COMPANY OF OKLAHOMA SOUTHWESTERN ELECTRIC POWER COMPANY WEST TEXAS UTILITIES COMPANY BY: /s/ SUSAN TOMASKY --------------------------------- (SUSAN TOMASKY, VICE PRESIDENT) Date: March 18, 2002 PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED. THE SIGNATURE OF EACH OF THE UNDERSIGNED SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING REFERENCE TO THE ABOVE-NAMED COMPANY AND ANY SUBSIDIARIES THEREOF.
SIGNATURE TITLE DATE --------- ----- ----- (i) PRINCIPAL EXECUTIVE OFFICER: *E. LINN DRAPER, JR. Chairman of the Board, Chief Executive Officer And Director (ii) PRINCIPAL FINANCIAL OFFICER: /s/ SUSAN TOMASKY Vice President March 18, 2002 ------------------------------------------- And Director (SUSAN TOMASKY) (iii) PRINCIPAL ACCOUNTING OFFICER: /s/ JOSEPH M. BUONAIUTO Controller and March 18, 2002 ------------------------------------------- Chief Accounting Officer (JOSEPH M. BUONAIUTO) (iv) A MAJORITY OF THE DIRECTORS: *HENRY W. FAYNE *A. A. PENA *ROBERT P. POWERS *THOMAS V. SHOCKLEY, III *J. H. VIPPERMAN March 18, 2002 *By: /s/ SUSAN TOMASKY ------------------------------------------- (SUSAN TOMASKY, ATTORNEY-IN-FACT)
50 SIGNATURES PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED. THE SIGNATURE OF THE UNDERSIGNED COMPANY SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING REFERENCE TO SUCH COMPANY AND ANY SUBSIDIARIES THEREOF. INDIANA MICHIGAN POWER COMPANY BY: /s/ SUSAN TOMASKY ---------------------------------------- (SUSAN TOMASKY, VICE PRESIDENT) Date: March 18, 2002 PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED. THE SIGNATURE OF EACH OF THE UNDERSIGNED SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING REFERENCE TO THE ABOVE-NAMED COMPANY AND ANY SUBSIDIARIES THEREOF.
SIGNATURE TITLE DATE --------- ----- ----- (i) PRINCIPAL EXECUTIVE OFFICER: *E. LINN DRAPER, JR. Chairman of the Board, Chief Executive Officer And Director (ii) PRINCIPAL FINANCIAL OFFICER: /s/ SUSAN TOMASKY Vice President March 18, 2002 ------------------------------------------------ And Director (SUSAN TOMASKY) (iii) PRINCIPAL ACCOUNTING OFFICER: /s/ JOSEPH M. BUONAIUTO Controller and March 18, 2002 ------------------------------------------------ Chief Accounting Officer (JOSEPH M. BUONAIUTO) (iv) A MAJORITY OF THE DIRECTORS : *K. G. BOYD *JOHN E. EHLER *HENRY W. FAYNE *DAVID L. LAHRMAN *MARC E. LEWIS *SUSANNE M. MOORMAN *ROBERT P. POWERS *JOHN R. SAMPSON *THOMAS V. SHOCKLEY, III *D. B. SYNOWIEC *J. H. VIPPERMAN *By: /s/ SUSAN TOMASKY -------------------------------------------------- (SUSAN TOMASKY, ATTORNEY-IN-FACT) March 18, 2002
51 INDEX TO FINANCIAL STATEMENT SCHEDULES Page INDEPENDENT AUDITORS' REPORT ............................................................................... S-2 The following financial statement schedules are included in this report on the pages indicated. AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Schedule II-- Valuation and Qualifying Accounts and Reserves ....................................... S-3 APPALACHIAN POWER COMPANY AND SUBSIDIARIES Schedule II-- Valuation and Qualifying Accounts and Reserves ....................................... S-3 CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARY Schedule II-- Valuation and Qualifying Accounts and Reserves ....................................... S-3 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Schedule II-- Valuation and Qualifying Accounts and Reserves ....................................... S-4 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Schedule II-- Valuation and Qualifying Accounts and Reserves........................................ S-4 KENTUCKY POWER COMPANY Schedule II-- Valuation and Qualifying Accounts and Reserves ....................................... S-4 OHIO POWER COMPANY AND SUBSIDIARIES Schedule II-- Valuation and Qualifying Accounts and Reserves....................................... S-5 PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES Schedule II-- Valuation and Qualifying Accounts and Reserves....................................... S-5 SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Schedule II-- Valuation and Qualifying Accounts and Reserves....................................... S-5 WEST TEXAS UTILITIES COMPANY Schedule II-- Valuation and Qualifying Accounts and Reserves....................................... S-6
S-1 INDEPENDENT AUDITORS' REPORT AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARIES: We have audited the consolidated financial statements of American Electric Power Company, Inc. and its subsidiaries and the financial statements of certain of its subsidiaries, listed in Item 14 herein, as of December 31, 2001 and 2000, and for each of the three years in the period ended December 31, 2001, and have issued our reports thereon dated February 22, 2002; such financial statements and reports are included in the 2001 Annual Reports and are incorporated herein by reference. Our audits also included the financial statement schedules of American Electric Power Company, Inc. and its subsidiaries and of certain of its subsidiaries, listed in Item 14, except for the financial statement schedules of Central Power and Light Company and subsidiary, Public Service Company of Oklahoma and its subsidiaries, Southwestern Electric Power Company and subsidiaries, and West Texas Utilities Company for the year ended December 31, 1999 and the financial information of Central and South West Corporation and its subsidiaries that is included in the financial statement schedule for American Electric Power Company, Inc. and its subsidiaries for the year ended December 31, 1999. These financial statement schedules are the responsibility of the respective company's management. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedules, when considered in relation to the corresponding basic financial statements taken as a whole, present fairly in all material respects the information set forth therein. DELOITTE & TOUCHE LLP Columbus, Ohio February 22, 2002 S-2
=========================================================================================================================== AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES =========================================================================================================================== COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E - --------------------------------------------------------------------------------------------------------------------------- ADDITIONS ---------------------------- BALANCE AT CHARGED TO CHARGED TO BALANCE AT BEGINNING COSTS AND OTHER END OF DESCRIPTION OF PERIOD EXPENSES ACCOUNTS DEDUCTIONS PERIOD - --------------------------------------------------------------------------------------------------------------------------- (IN THOUSANDS) DEDUCTED FROM ASSETS: Accumulated Provision for Uncollectible Accounts: Year Ended December 31, 2001....... $71,722 $124,542 $19,766(a) $106,589(b) $109,441 ======= ======== ======= ======== ======== Year Ended December 31, 2000....... $63,207 $ 70,670 $ 8,358(a) $ 70,513(b) $ 71,722 ======= ======== ======= ======== ======== Year Ended December 31, 1999....... $52,543 $ 38,347 $15,802(a) $ 43,485(b) $ 63,207 ======= ======== ======= ======== ======== - --------------------- (a) Recoveries on accounts previously written off. (b) Uncollectible accounts written off. ===========================================================================================================================
=========================================================================================================================== APPALACHIAN POWER COMPANY AND SUBSIDIARIES SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES =========================================================================================================================== COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E - --------------------------------------------------------------------------------------------------------------------------- ADDITIONS ---------------------------- BALANCE AT CHARGED TO CHARGED TO BALANCE AT BEGINNING COSTS AND OTHER END OF DESCRIPTION OF PERIOD EXPENSES ACCOUNTS DEDUCTIONS PERIOD - --------------------------------------------------------------------------------------------------------------------------- (IN THOUSANDS) DEDUCTED FROM ASSETS: Accumulated Provision for Uncollectible Accounts: Year Ended December 31, 2001....... $2,588 $2,644 $1,017(a) $4,372(b) $1,877 ====== ====== ====== ====== ====== Year Ended December 31, 2000....... $2,609 $6,592 $1,526(a) $8,139(b) $2,588 ====== ====== ====== ====== ====== Year Ended December 31, 1999....... $2,234 $5,492 $1,995(a) $7,112(b) $2,609 ====== ====== ====== ====== ====== - --------------------- (a) Recoveries on accounts previously written off. (b) Uncollectible accounts written off. ===========================================================================================================================
=========================================================================================================================== CENTRAL POWER AND LIGHT AND SUBSIDIARY SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES =========================================================================================================================== COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E - --------------------------------------------------------------------------------------------------------------------------- ADDITIONS ---------------------------- BALANCE AT CHARGED TO CHARGED TO BALANCE AT BEGINNING COSTS AND OTHER END OF DESCRIPTION OF PERIOD EXPENSES ACCOUNTS DEDUCTIONS PERIOD - --------------------------------------------------------------------------------------------------------------------------- (IN THOUSANDS) DEDUCTED FROM ASSETS: Accumulated Provision for Uncollectible Accounts: Year Ended December 31, 2001....... $1,675 $ 186 $ --_ (a) $1,675(b) $ 186 ====== ====== ====== ====== ====== Year Ended December 31, 2000....... $-- $1,675 $ -- (a) $ -- (b) $1,675 ====== ====== ====== ====== ====== Year Ended December 31, 1999....... $-- $-- $ -- (a) $ -- (b) $-- ====== ====== ====== ====== ====== - --------------------- (a) Recoveries on accounts previously written off. (b) Uncollectible accounts written off. ===========================================================================================================================
S-3
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES =========================================================================================================================== COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E - --------------------------------------------------------------------------------------------------------------------------- ADDITIONS ---------------------------- BALANCE AT CHARGED TO CHARGED TO BALANCE AT BEGINNING COSTS AND OTHER END OF DESCRIPTION OF PERIOD EXPENSES ACCOUNTS DEDUCTIONS PERIOD - --------------------------------------------------------------------------------------------------------------------------- (IN THOUSANDS) DEDUCTED FROM ASSETS: Accumulated Provision for Uncollectible Accounts: Year Ended December 31, 2001....... $ 659 $ 331 $ --(a) $ 245(b) $ 745 ====== ====== ======= ======= ======= Year Ended December 31, 2000....... $3,045 $2,082 $ 1,405(a) $ 5,873(b) $ 659 ====== ====== ======= ======= ======= Year Ended December 31, 1999....... $2,598 $3,334 $10,782(a) $13,669(b) $ 3,045 ====== ====== ======= ======= ======= - --------------------- (a) Recoveries on accounts previously written off. (b) Uncollectible accounts written off. ===========================================================================================================================
=========================================================================================================================== INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES =========================================================================================================================== COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E - --------------------------------------------------------------------------------------------------------------------------- ADDITIONS ---------------------------- BALANCE AT CHARGED TO CHARGED TO BALANCE AT BEGINNING COSTS AND OTHER END OF DESCRIPTION OF PERIOD EXPENSES ACCOUNTS DEDUCTIONS PERIOD - --------------------------------------------------------------------------------------------------------------------------- (IN THOUSANDS) DEDUCTED FROM ASSETS: Accumulated Provision for Uncollectible Accounts: Year Ended December 31, 2001....... $ 759 $ 65 $ 3(a) $ 86(b) $ 741 ====== ====== ====== ====== ====== Year Ended December 31, 2000....... $1,848 $ (235) $ 907(a) $1,761(b) $ 759 ====== ====== ====== ====== ====== Year Ended December 31, 1999....... $2,027 $3,966 $1,367(a) $5,512(b) $1,848 ====== ====== ====== ====== ====== - --------------------- (a) Recoveries on accounts previously written off. (b) Uncollectible accounts written off. ===========================================================================================================================
=========================================================================================================================== KENTUCKY POWER COMPANY SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E - --------------------------------------------------------------------------------------------------------------------------- ADDITIONS ---------------------------- BALANCE AT CHARGED TO CHARGED TO BALANCE AT BEGINNING COSTS AND OTHER END OF DESCRIPTION OF PERIOD EXPENSES ACCOUNTS DEDUCTIONS PERIOD - --------------------------------------------------------------------------------------------------------------------------- (IN THOUSANDS) DEDUCTED FROM ASSETS: Accumulated Provision for Uncollectible Accounts: Year Ended December 31, 2001....... $282 $ -- $(24)(a) $ (6)(b) $264 ==== ====== ===== ======= ==== Year Ended December 31, 2000....... $637 $ 187 $ 9 (a) $ 551(b) $282 ==== ====== ===== ====== ==== Year Ended December 31, 1999....... $848 $1,032 $ 467(a) $1,710(b) $637 ==== ====== ===== ====== ==== - --------------------- (a) Recoveries on accounts previously written off. (b) Uncollectible accounts written off. ===========================================================================================================================
S-4
=========================================================================================================================== OHIO POWER COMPANY AND SUBSIDIARIES SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES =========================================================================================================================== COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E - --------------------------------------------------------------------------------------------------------------------------- ADDITIONS ---------------------------- BALANCE AT CHARGED TO CHARGED TO BALANCE AT BEGINNING COSTS AND OTHER END OF DESCRIPTION OF PERIOD EXPENSES ACCOUNTS DEDUCTIONS PERIOD - --------------------------------------------------------------------------------------------------------------------------- (IN THOUSANDS) DEDUCTED FROM ASSETS: Accumulated Provision for Uncollectible Accounts: Year Ended December 31, 2001....... $1,054 $ 554 $ -- (a) $ 229(b) $1,379 ====== ====== ====== ====== ====== Year Ended December 31, 2000....... $2,223 $ 472 $ 778(a) $2,419(b) $1,054 ====== ====== ====== ====== ====== Year Ended December 31, 1999....... $1,678 $4,730 $1,273(a) $5,458(b) $2,223 ====== ====== ====== ====== ====== - --------------------- (a) Recoveries on accounts previously written off. (b) Uncollectible accounts written off. ===========================================================================================================================
=========================================================================================================================== PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES =========================================================================================================================== COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E - --------------------------------------------------------------------------------------------------------------------------- ADDITIONS ---------------------------- BALANCE AT CHARGED TO CHARGED TO BALANCE AT BEGINNING COSTS AND OTHER END OF DESCRIPTION OF PERIOD EXPENSES ACCOUNTS DEDUCTIONS PERIOD - --------------------------------------------------------------------------------------------------------------------------- (IN THOUSANDS) DEDUCTED FROM ASSETS: Accumulated Provision for Uncollectible Accounts: Year Ended December 31, 2001....... $ 467 $ 44 $ -- (a) $ 467(b) $ 44 ====== ======= ====== ======= ====== Year Ended December 31, 2000....... $-- $ 467 $ -- (a) $ -- (b) $ 467 ====== ======= ====== ======= ====== Year Ended December 31, 1999....... $-- $ -- $ -- (a) $ -- (b) $ -- ====== ======= ====== ======= ====== - --------------------- (a) Recoveries on accounts previously written off. (b) Uncollectible accounts written off. ===========================================================================================================================
=========================================================================================================================== SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES =========================================================================================================================== COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E - --------------------------------------------------------------------------------------------------------------------------- ADDITIONS ---------------------------- BALANCE AT CHARGED TO CHARGED TO BALANCE AT BEGINNING COSTS AND OTHER END OF DESCRIPTION OF PERIOD EXPENSES ACCOUNTS DEDUCTIONS PERIOD - --------------------------------------------------------------------------------------------------------------------------- (IN THOUSANDS) DEDUCTED FROM ASSETS: Accumulated Provision for Uncollectible Accounts: Year Ended December 31, 2001....... $ 911 $ 89 $ -- (a) $ 911(b) $ 89 ====== ====== ======= ====== ====== Year Ended December 31, 2000....... $4,428 $ 911 $(4,428)(a) $ -- (b) $ 911 ====== ====== ======= ====== ====== Year Ended December 31, 1999....... $3,269 $5,415 $ -- (a) $4,256(b) $4,428 ====== ====== ======= ====== ====== - --------------------- (a) Recoveries on accounts previously written off. (b) Uncollectible accounts written off. ===========================================================================================================================
S-5
=========================================================================================================================== WEST TEXAS UTILITIES COMPANY SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES =========================================================================================================================== COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E - --------------------------------------------------------------------------------------------------------------------------- ADDITIONS ---------------------------- BALANCE AT CHARGED TO CHARGED TO BALANCE AT BEGINNING COSTS AND OTHER END OF DESCRIPTION OF PERIOD EXPENSES ACCOUNTS DEDUCTIONS PERIOD - --------------------------------------------------------------------------------------------------------------------------- (IN THOUSANDS) DEDUCTED FROM ASSETS: Accumulated Provision for Uncollectible Accounts: Year Ended December 31, 2001....... $288 $ 13 $35(a) $ 140(b) $196 ==== ====== === ====== ==== Year Ended December 31, 2000....... $186 $1,499 $46(a) $1,443(b) $288 ==== ====== === ====== ==== Year Ended December 31, 1999....... $497 $ (66) $43(a) $ 288(b) $186 ==== ===== === ====== ==== - --------------------- (a) Recoveries on accounts previously written off. (b) Uncollectible accounts written off. ===========================================================================================================================
S-6 EXHIBIT INDEX Certain of the following exhibits, designated with an asterisk(*), are filed herewith. The exhibits not so designated have heretofore been filed with the Commission and, pursuant to 17 C.F.R. 229.10(d) and 240.12b-32, are incorporated herein by reference to the documents indicated in brackets following the descriptions of such exhibits. Exhibits, designated with a dagger (+), are management contracts or compensatory plans or arrangements required to be filed as an exhibit to this form pursuant to Item 14(c) of this report.
EXHIBIT NUMBER DESCRIPTION - -------------- ----------- AEGCO 3(a) -- Copy of Articles of Incorporation of AEGCo [Registration Statement on Form 10 for the Common Shares of AEGCo, File No. 0-18135, Exhibit 3(a)]. 3(b) -- Copy of the Code of Regulations of AEGCo (amended as of June 15, 2000) [Annual Report on Form 10-K of AEGCo for the fiscal year ended December 31, 2000, File No. 0-18135, Exhibit 3(b)]. 10(a) -- Copy of Capital Funds Agreement dated as of December 30, 1988 between AEGCo and AEP [Registration Statement No. 33-32752, Exhibit 28(a)]. 10(b)(1) -- Copy of Unit Power Agreement dated as of March 31, 1982 between AEGCo and I&M, as amended [Registration Statement No. 33-32752, Exhibits 28(b)(1)(A) and 28(b)(1)(B)]. 10(b)(2) -- Copy of Unit Power Agreement, dated as of August 1, 1984, among AEGCo, I&M and KEPCo [Registration Statement No. 33-32752, Exhibit 28(b)(2)]. 10(b)(3) -- Copy of Agreement, dated as of October 1, 1984, among AEGCo, I&M, APCo and Virginia Electric and Power Company [Registration Statement No. 33-32752, Exhibit 28(b)(3)]. 10(c) -- Copy of Lease Agreements, dated as of December 1, 1989, between AEGCo and Wilmington Trust Company, as amended [Registration Statement No. 33-32752, Exhibits 28(c)(1)(C), 28(c)(2)(C), 28(c)(3)(C), 28(c)(4)(C), 28(c)(5)(C) and 28(c)(6)(C); Annual Report on Form 10-K of AEGCo for the fiscal year ended December 31, 1993, File No. 0-18135, Exhibits 10(c)(1)(B), 10(c)(2)(B), 10(c)(3)(B), 10(c)(4)(B), 10(c)(5)(B) and 10(c)(6)(B)]. *13 -- Copy of those portions of the AEGCo 2001 Annual Report (for the fiscal year ended December 31, 2001) which are incorporated by reference in this filing. *24 -- Power of Attorney. AEP++ 3(a) -- Copy of Restated Certificate of Incorporation of AEP, dated October 29, 1997 [Quarterly Report on Form 10-Q of AEP for the quarter ended September 30, 1997, File No. 1-3525, Exhibit 3(a)]. 3(b) -- Copy of Certificate of Amendment of the Restated Certificate of Incorporation of AEP, dated January 13, 1999 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1998, File No. 1-3525, Exhibit 3(b)]. 3(c) -- Composite copy of the Restated Certificate of Incorporation of AEP, as amended [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1998, File No. 1-3525, Exhibit 3(c)]. 3(d) -- Copy of By-Laws of AEP, as amended through January 28, 1998 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1997, File No. 1-3525, Exhibit 3(b)]. *4(a) -- Indenture (for unsecured debt securities), dated as of May 1, 2001, between AEP and The Bank of New York, as Trustee.
E-1
EXHIBIT NUMBER DESCRIPTION - -------------- ----------- *4(b) -- First Supplemental Indenture, dated as of May 1, 2001, between AEP and The Bank of New York, as Trustee, for 6.125% Senior Notes, Series A, due May 15, 2006. *4(c) -- Second Supplemental Indenture, dated as of May 1, 2001, between AEP and The Bank of New York, as Trustee, for 5.50% Putable Callable Notes, Series B, Putable Callable May 15, 2003. 10(a) -- Interconnection Agreement, dated July 6, 1951, among APCo, CSPCo, KEPCo, OPCo and I&M and with the Service Corporation, as amended [Registration Statement No. 2-52910, Exhibit 5(a); Registration Statement No. 2-61009, Exhibit 5(b); and Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1990, File No. 1-3525, Exhibit 10(a)(3)]. 10(b) -- Copy of Transmission Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KEPCo, OPCo and with the Service Corporation as agent, as amended [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(b); and Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1988, File No. 1-3525, Exhibit 10(b)(2)]. 10(c) -- Copy of Lease Agreements, dated as of December 1, 1989, between AEGCo or I&M and Wilmington Trust Company, as amended [Registration Statement No. 33-32752, Exhibits 28(c)(1)(C), 28(c)(2)(C), 28(c)(3)(C), 28(c)(4)(C), 28(c)(5)(C) and 28(c)(6)(C); Registration Statement No. 33-32753, Exhibits 28(a)(1)(C), 28(a)(2)(C), 28(a)(3)(C), 28(a)(4)(C), 28(a)(5)(C) and 28(a)(6)(C); and Annual Report on Form 10-K of AEGCo for the fiscal year ended December 31, 1993, File No. 0-18135, Exhibits 10(c)(1)(B), 10(c)(2)(B), 10(c)(3)(B), 10(c)(4)(B), 10(c)(5)(B) and 10(c)(6)(B); Annual Report on Form 10-K of I&M for the fiscal year ended December 31, 1993, File No. 1-3570, Exhibits 10(e)(1)(B), 10(e)(2)(B), 10(e)(3)(B), 10(e)(4)(B), 10(e)(5)(B) and 10(e)(6)(B)]. 10(d) -- Lease Agreement dated January 20, 1995 between OPCo and JMG Funding, Limited Partnership, and amendment thereto (confidential treatment requested) [Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1994, File No. 1-6543, Exhibit 10(l)(2)]. 10(e) -- Modification No. 1 to the AEP System Interim Allowance Agreement, dated July 28, 1994, among APCo, CSPCo, I&M, KEPCo, OPCo and the Service Corporation [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(l)]. 10(f)(1) -- Agreement and Plan of Merger, dated as of December 21, 1997, By and Among American Electric Power Company, Inc., Augusta Acquisition Corporation and Central and South West Corporation [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1997, File No. 1-3525, Exhibit 10(f)]. 10(f)(2) -- Amendment No. 1, dated as of December 31, 1999, to the Agreement and Plan of Merger [Current Report on Form 8-K of AEP dated December 15, 1999, File No. 1-3525, Exhibit 10]. +10(g)(1) -- AEP Deferred Compensation Agreement for certain executive officers [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(e)]. +10(g)(2) -- Amendment to AEP Deferred Compensation Agreement for certain executive officers [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1986, File No. 1-3525, Exhibit 10(d)(2)]. +10(h) -- AEP Accident Coverage Insurance Plan for directors [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1985, File No. 1-3525,Exhibit 10(g)].
E-2
EXHIBIT NUMBER DESCRIPTION - -------------- ----------- +10(i)(1) -- AEP Deferred Compensation and Stock Plan for Non-Employee Directors, as amended June 1, 2000 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2000, File No. 1-3525, Exhibit 10(i)(1)]. *+10(i)(2) -- AEP Stock Unit Accumulation Plan for Non-Employee Directors, as amended January 1, 2002. +10(j)(1)(A) -- AEP System Excess Benefit Plan, Amended and Restated as of January 1, 2001 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2000, File No. 1-3525, Exhibit 10(j)(1)(A)]. +10(j)(1)(B) -- Guaranty by AEP of the Service Corporation Excess Benefits Plan [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1990, File No. 1-3525, Exhibit 10(h)(1)(B)]. +10(j)(2) -- AEP System Supplemental Retirement Savings Plan, Amended and Restated as of June 1, 2001 (Non-Qualified) [Registration Statement No. 333-66048, Exhibit 4]. +10(j)(3) -- Service Corporation Umbrella Trust for Executives [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1993, File No. 1-3525, Exhibit 10(g)(3)]. +10(k) -- Employment Agreement between E. Linn Draper, Jr. and AEP and the Service Corporation [Annual Report on Form 10-K of AEGCo for the fiscal year ended December 31, 1991, File No. 0-18135, Exhibit 10(g)(3)]. +10(l) -- AEP System Senior Officer Annual Incentive Compensation Plan[Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(i)(1)]. +10(m) -- AEP System Survivor Benefit Plan, effective January 27, 1998 [Quarterly Report on Form 10-Q of AEP for the quarter ended September 30, 1998, File No. 1-3525, Exhibit 10]. +10(n) -- AEP Senior Executive Severance Plan for Merger with Central and South West Corporation, effective March 1, 1999 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1998, File No. 1-3525, Exhibit 10(o)]. *+10(o) -- AEP Change In Control Agreement. +10(p) -- AEP System 2000 Long-Term Incentive Plan [Proxy Statement of AEP, March 10, 2000]. +10(q) -- Memorandum of agreement between Susan Tomasky and the Service Corporation dated January 3, 2001 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2000, File No. 1-3525, Exhibit 10(s)]. +10(r)(1) -- Central and South West System Special Executive Retirement Plan as amended and restated effective July 1, 1997 [Annual Report on Form 10-K of CSW for the fiscal year ended December 31, 1998, File No. 1-1443, Exhibit 18]. *+10(r)(2) -- Certified CSW Board Resolution of April 18, 1991. +10(r)(3) -- CSW 1992 Long-Term Incentive Plan [Proxy Statement of CSW, March 13, 1992]. *12 -- Statement re: Computation of Ratios. *13 -- Copy of those portions of the AEP 2001 Annual Report (for the fiscal year ended December 31, 2001) which are incorporated by reference in this filing. *21 -- List of subsidiaries of AEP. *23(a) -- Consent of Deloitte & Touche LLP. *23(b) -- Consent of Arthur Andersen LLP. *23(c) -- Consent of KPMG Audit plc. *24 -- Power of Attorney.
E-3
EXHIBIT NUMBER DESCRIPTION - -------------- ----------- APCO++ 3(a) -- Copy of Restated Articles of Incorporation of APCo, and amendments thereto to November 4, 1993 [Registration Statement No. 33-50163, Exhibit 4(a); Registration Statement No. 33-53805, Exhibits 4(b) and 4(c)]. 3(b) -- Copy of Articles of Amendment to the Restated Articles of Incorporation of APCo, dated June 6, 1994 [Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1994, File No. 1-3457, Exhibit 3(b)]. 3(c) -- Copy of Articles of Amendment to the Restated Articles of Incorporation of APCo, dated March 6, 1997 [Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1996, File No. 1-3457, Exhibit 3(c)]. 3(d) -- Composite copy of the Restated Articles of Incorporation of APCo (amended as of March 7, 1997) [Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1996, File No. 1-3457, Exhibit 3(d)]. *3(e) -- Copy of By-Laws of APCo (amended as of October 24, 2001). 4(a) -- Copy of Mortgage and Deed of Trust, dated as of December 1, 1940, between APCo and Bankers Trust Company and R. Gregory Page, as Trustees, as amended and supplemented [Registration Statement No. 2-7289, Exhibit 7(b); Registration Statement No. 2-19884, Exhibit 2(1); Registration Statement No. 2-24453, Exhibit 2(n); Registration Statement No. 2-60015, Exhibits 2(b)(2), 2(b)(3), 2(b)(4), 2(b)(5), 2(b)(6), 2(b)(7), 2(b)(8), 2(b)(9), 2(b)(10), 2(b)(12), 2(b)(14), 2(b)(15), 2(b)(16), 2(b)(17), 2(b)(18), 2(b)(19), 2(b)(20), 2(b)(21), 2(b)(22), 2(b)(23), 2(b)(24), 2(b)(25), 2(b)(26), 2(b)(27) and 2(b)(28); Registration Statement No. 2-64102, Exhibit 2(b)(29); Registration Statement No. 2-66457, Exhibits (2)(b)(30) and 2(b)(31); Registration Statement No. 2-69217, Exhibit 2(b)(32); Registration Statement No. 2-86237, Exhibit 4(b); Registration Statement No. 33-11723, Exhibit 4(b); Registration Statement No. 33-17003, Exhibit 4(a)(ii), Registration Statement No. 33-30964, Exhibit 4(b); Registration Statement No. 33-40720, Exhibit 4(b); Registration Statement No. 33-45219, Exhibit 4(b); Registration Statement No. 33-46128, Exhibits 4(b) and 4(c); Registration Statement No. 33-53410, Exhibit 4(b); Registration Statement No. 33-59834, Exhibit 4(b); Registration Statement No. 33-50229, Exhibits 4(b) and 4(c); Registration Statement No. 33-58431, Exhibits 4(b), 4(c), 4(d) and 4(e); Registration Statement No. 333-01049, Exhibits 4(b) and 4(c); Registration Statement No. 333-20305, Exhibits 4(b) and 4(c); Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1996, File No. 1-3457, Exhibit 4(b); Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1998, File No. 1-3457, Exhibit 4(b)]. 4(b) -- Indenture (for unsecured debt securities), dated as of January 1, 1998, between APCo and The Bank of New York, As Trustee [Registration Statement No. 333-45927, Exhibit 4(a); Registration Statement No. 333-49071, Exhibit 4(b); Registration Statement No. 333-84061, Exhibits 4(b) and 4(c); Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1999, File No. 1-3457, Exhibit 4(c); Registration Statement No. 333-81402, Exhibits 4(b), 4(c) and 4(d)].
E-4
EXHIBIT NUMBER DESCRIPTION - -------------- ----------- 10(a)(1) -- Copy of Power Agreement, dated October 15, 1952, between OVEC and United States of America, acting by and through the United States Atomic Energy Commission, and, subsequent to January 18, 1975, the Administrator of the Energy Research and Development Administration, as amended [Registration Statement No. 2-60015, Exhibit 5(a); Registration Statement No. 2-63234, Exhibit 5(a)(1)(B); Registration Statement No 2-66301, Exhibit 5(a)(1)(C); Registration Statement No. 2-67728, Exhibit 5(a)(1)(D); Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1989, File No. 1-3457, Exhibit 10(a)(1)(F); and Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1992, File No. 1-3457, Exhibit 10(a)(1)(B)]. 10(a)(2) -- Copy of Inter-Company Power Agreement, dated as of July 10, 1953, among OVEC and the Sponsoring Companies, as amended [Registration Statement No. 2-60015, Exhibit 5(c); Registration Statement No. 2-67728, Exhibit 5(a)(3)(B); and Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1992, File No. 1-3457, Exhibit 10(a)(2)(B)]. 10(a)(3) -- Copy of Power Agreement, dated July 10, 1953, between OVEC and Indiana-Kentucky Electric Corporation, as amended [Registration Statement No. 2-60015, Exhibit 5(e)]. 10(b) -- Copy of Interconnection Agreement, dated July 6, 1951, among APCo, CSPCo, KEPCo, OPCo and I&M and with the Service Corporation, as amended [Registration Statement No. 2-52910, Exhibit 5(a); Registration Statement No. 2-61009, Exhibit 5(b); Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1990, File No. 1-3525, Exhibit 10(a)(3)]. 10(c) -- Copy of Transmission Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KEPCo, OPCo and with the Service Corporation as agent, as amended [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(b); Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1988, File No. 1-3525, Exhibit 10(b)(2)]. 10(d) -- Copy of Modification No. 1 to the AEP System Interim Allowance Agreement, dated July 28, 1994, among APCo, CSPCo, I&M, KEPCo, OPCo and the Service Corporation [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(l)]. 10(e)(1) -- Agreement and Plan of Merger, dated as of December 21, 1997, By and Among American Electric Power Company, Inc., Augusta Acquisition Corporation and Central and South West Corporation [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1997, File No. 1-3525, Exhibit 10(f)]. 10(e)(2) -- Amendment No. 1, dated as of December 31, 1999, to the Agreement and Plan of Merger [Current Report on Form 8-K of APCo dated December 15, 1999, File No. 1-3457, Exhibit 10]. +10(f)(1) -- AEP Deferred Compensation Agreement for certain executive officers [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(e)]. +10(f)(2) -- Amendment to AEP Deferred Compensation Agreement for certain executive officers [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1986, File No. 1-3525, Exhibit 10(d)(2)]. +10(g) -- AEP System Senior Officer Annual Incentive Compensation Plan [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(i)(1)].
E-5
EXHIBIT NUMBER DESCRIPTION - -------------- ----------- +10(h)(1) -- AEP System Excess Benefit Plan, Amended and Restated as of January 1, 2001 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2000, File No. 1-3525, Exhibit 10(j)(1)(A)]. +10(h)(2) -- AEP System Supplemental Retirement Savings Plan, Amended and Restated as of January 1, 2001 (Non-Qualified) [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2000, File No. 1-3525, Exhibit 10(j)(2)]. +10(h)(3) -- Umbrella Trust for Executives [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1993, File No. 1-3525, Exhibit 10(g)(3)]. +10(i) -- Employment Agreement between E. Linn Draper, Jr. and AEP and the Service Corporation [Annual Report on Form 10-K of AEGCo for the fiscal year ended December 31, 1991, File No. 0-18135, Exhibit 10(g)(3)]. +10(j) -- AEP System Survivor Benefit Plan, effective January 27, 1998 [Quarterly Report on Form 10-Q of AEP for the quarter ended September 30, 1998, File No. 1-3525, Exhibit 10]. +10(k) -- AEP Senior Executive Severance Plan for Merger with Central and South West Corporation, effective March 1, 1999[Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1998, File No. 1-3525, Exhibit 10(o)]. +10(l) -- AEP Change In Control Agreement [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2001, File No. 1-3525, Exhibit 10(o)]. +10(m) -- AEP System 2000 Long-Term Incentive Plan [Proxy Statement of AEP, March 10, 2000]. +10(n) -- Memorandum of agreement between Susan Tomasky and the Service Corporation dated January 3, 2001 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2000, File No. 1-3525, Exhibit 10(s)]. +10(o)(1) -- Central and South West System Special Executive Retirement Plan as amended and restated effective July 1, 1997 [Annual Report on Form 10-K of CSW for the fiscal year ended December 31, 1998, File No. 1-1443, Exhibit 18]. +10(o)(2) -- Certified CSW Board Resolution of April 18, 1991 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2001, File No. 1-3525, Exhibit 10(r)(2)]. +10(o)(3) -- CSW 1992 Long-Term Incentive Plan [Proxy Statement of CSW, March 13, 1992]. *12 -- Statement re: Computation of Ratios. *13 -- Copy of those portions of the APCo 2001 Annual Report (for the fiscal year ended December 31, 2001) which are incorporated by reference in this filing. 21 -- List of subsidiaries of APCo [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2001, File No. 1-3525, Exhibit 21]. *24 -- Power of Attorney. CPL++ 3(a) -- Restated Articles of Incorporation Without Amendment, Articles of Correction to Restated Articles of Incorporation Without Amendment, Articles of Amendment to Restated Articles of Incorporation, Statements of Registered Office and/or Agent, and Articles of Amendment to the Articles of Incorporation [Quarterly Report on Form 10-Q of CPL for the quarter ended March 31, 1997, File No. 0-346, Exhibit 3.1]. 3(b) -- By-Laws of CPL (amended as of April 19, 2000) [Annual Report on Form 10-K of CPL for the fiscal year ended December 31, 2000, File No. 0-346, Exhibit 3(b)].
E-6
EXHIBIT NUMBER DESCRIPTION - -------------- ----------- 4(a) -- Indenture of Mortgage or Deed of Trust, dated November 1, 1943, between CPL and The First National Bank of Chicago and R. D. Manella, as Trustees, as amended and supplemented [Registration Statement No. 2-60712, Exhibit 5.01; Registration Statement No. 2-62271, Exhibit 2.02; Form U-1 No. 70-7003, Exhibit 17; Registration Statement No. 2-98944, Exhibit 4 (b); Form U-1 No. 70-7236, Exhibit 4; Form U-1 No. 70-7249, Exhibit 4; Form U-1 No. 70-7520, Exhibit 2; Form U-1 No. 70-7721, Exhibit 3; Form U-1 No. 70-7725, Exhibit 10; Form U-1 No. 70-8053, Exhibit 10 (a); Form U-1 No. 70-8053, Exhibit 10 (b); Form U-1 No. 70-8053, Exhibit 10 (c); Form U-1 No. 70-8053, Exhibit 10 (d); Form U-1 No. 70-8053, Exhibit 10 (e); Form U-1 No. 70-8053, Exhibit 10 (f)]. 4(b) -- CPL-obligated, mandatorily redeemable preferred securities of subsidiary trust holding solely Junior Subordinated Debentures of CPL: (1) Indenture, dated as of May 1, 1997, between CPL and the Bank of New York, as Trustee [Quarterly Report on Form 10-Q of CPL dated March 31, 1997, File No. 0-346, Exhibits 4.1 and 4.2]. (2) Amended and Restated Trust Agreement of CPL Capital I, dated as of May 1, 1997, among CPL, as Depositor, the Bank of New York, as Property Trustee, The Bank of New York (Delaware), as Delaware Trustee, and the Administrative Trustee [Quarterly Report on Form 10-Q of CPL dated March 31, 1997, File No. 0-346, Exhibit 4.3]. (3) Guarantee Agreement, dated as of May 1, 1997, delivered by CPL for the benefit of the holders of CPL Capital I's Preferred Securities [Quarterly Report on Form 10-Q of CPL dated March 31, 1997, File No. 0-346, Exhibit 4.4]. (4) Agreement as to Expenses and Liabilities dated as of May 1, 1997, between CPL and CPL Capital I [Quarterly Report on Form 10-Q of CPL dated March 31, 1997, File No. 0-346, Exhibit 4.5]. 4(c) -- Indenture (for unsecured debt securities), dated as of November 15, 1999, between CPL and The Bank of New York, as Trustee, as amended and supplemented [Annual Report on Form 10-K of CPL for the fiscal year ended December 31, 2000, File No. 0-346, Exhibits 4(c), 4(d) and 4(e)]. *12 -- Statement re: Computation of Ratios. *13 -- Copy of those portions of the CPL 2001 Annual Report (for the fiscal year ended December 31, 2001) which are incorporated by reference in this filing. *23(a) -- Consent of Deloitte & Touche LLP. *23(b) -- Consent of Arthur Andersen LLP. *24 -- Power of Attorney. CSPCO++ 3(a) -- Copy of Amended Articles of Incorporation of CSPCo, as amended to March 6, 1992 [Registration Statement No. 33-53377, Exhibit 4(a)]. 3(b) -- Copy of Certificate of Amendment to Amended Articles of Incorporation of CSPCo, dated May 19, 1994 [Annual Report on Form 10-K of CSPCo for the fiscal year ended December 31, 1994, File No. 1-2680, Exhibit 3(b)]. 3(c) -- Composite copy of Amended Articles of Incorporation of CSPCo, as amended [Annual Report on Form 10-K of CSPCo for the fiscal year ended December 31, 1994, File No. 1-2680, Exhibit 3(c)]. 3(d) -- Copy of Code of Regulations and By-Laws of CSPCo [Annual Report on Form 10-K of CSPCo for the fiscal year ended December 31, 1987, File No. 1-2680, Exhibit 3(d)].
E-7
EXHIBIT NUMBER DESCRIPTION - -------------- ----------- 4(a) -- Copy of Indenture of Mortgage and Deed of Trust, dated September 1, 1940, between CSPCo and City Bank Farmers Trust Company (now Citibank, N.A.), as trustee, as supplemented and amended [Registration Statement No. 2-59411, Exhibits 2(B) and 2(C); Registration Statement No. 2-80535, Exhibit 4(b); Registration Statement No. 2-87091, Exhibit 4(b); Registration Statement No. 2-93208, Exhibit 4(b); Registration Statement No. 2-97652, Exhibit 4(b); Registration Statement No. 33-7081, Exhibit 4(b); Registration Statement No. 33-12389, Exhibit 4(b); Registration Statement No. 33-19227, Exhibits 4(b), 4(e), 4(f), 4(g) and 4(h); Registration Statement No. 33-35651, Exhibit 4(b); Registration Statement No. 33-46859, Exhibits 4(b) and 4(c); Registration Statement No. 33-50316, Exhibits 4(b) and 4(c); Registration Statement No. 33-60336, Exhibits 4(b), 4(c) and 4(d); Registration Statement No. 33-50447, Exhibits 4(b) and 4(c); Annual Report on Form 10-K of CSPCo for the fiscal year ended December 31, 1993, File No. 1-2680, Exhibit 4(b)]. 4(b) -- Copy of Indenture (for unsecured debt securities), dated as of September 1, 1997, between CSPCo and Bankers Trust Company, as Trustee [Registration Statement No. 333-54025, Exhibits 4(a), 4(b), 4(c) and 4(d); Annual Report on Form 10-K of CSPCo for the fiscal year ended December 31, 1998, File No. 1-2680, Exhibits 4(c) and 4(d)]. 10(a)(1) -- Copy of Power Agreement, dated October 15, 1952, between OVEC and United States of America, acting by and through the United States Atomic Energy Commission, and, subsequent to January 18, 1975, the Administrator of the Energy Research and Development Administration, as amended [Registration Statement No. 2-60015, Exhibit 5(a); Registration Statement No. 2-63234, Exhibit 5(a)(1)(B); Registration Statement No. 2-66301, Exhibit 5(a)(1)(C); Registration Statement No. 2-67728, Exhibit 5(a)(1)(B); Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1989, File No. 1-3457, Exhibit 10(a)(1)(F); and Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1992, File No. 1-3457, Exhibit 10(a)(1)(B)]. 10(a)(2) -- Copy of Inter-Company Power Agreement, dated July 10, 1953, among OVEC and the Sponsoring Companies, as amended [Registration Statement No. 2-60015, Exhibit 5(c); Registration Statement No. 2-67728, Exhibit 5(a)(3)(B); and Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1992, File No. 1-3457, Exhibit 10(a)(2)(B)]. 10(a)(3) -- Copy of Power Agreement, dated July 10, 1953, between OVEC and Indiana-Kentucky Electric Corporation, as amended [Registration Statement No. 2-60015, Exhibit 5(e)]. 10(b) -- Copy of Interconnection Agreement, dated July 6, 1951, among APCo, CSPCo, KEPCo, OPCo and I&M and the Service Corporation, as amended [Registration Statement No. 2-52910, Exhibit 5(a); Registration Statement No. 2-61009, Exhibit 5(b); and Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1990, File No. 1-3525, Exhibit 10(a)(3)]. 10(c) -- Copy of Transmission Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KEPCo, OPCo, and with the Service Corporation as agent, as amended [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(b); and Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1988, File No. 1-3525, Exhibit 10(b)(2)]. 10(d) -- Copy of Modification No. 1 to the AEP System Interim Allowance Agreement, dated July 28, 1994, among APCo, CSPCo, I&M, KEPCo, OPCo and the Service Corporation [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(l)].
E-8
EXHIBIT NUMBER DESCRIPTION - -------------- ----------- 10(e)(1) -- Agreement and Plan of Merger, dated as of December 21, 1997, By and Among American Electric Power Company, Inc., Augusta Acquisition Corporation and Central and South West Corporation [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1997, File No. 1-3525, Exhibit 10(f)]. 10(e)(2) -- Amendment No. 1, dated as of December 31, 1999, to the Agreement and Plan of Merger [Current Report on Form 8-K of CSPCo dated December 15, 1999, File No. 1-2680, Exhibit 10]. *12 -- Statement re: Computation of Ratios. *13 -- Copy of those portions of the CSPCo 2001 Annual Report (for the fiscal year ended December 31, 2001) which are incorporated by reference in this filing. *23 -- Consent of Deloitte & Touche LLP. *24 -- Power of Attorney. I&M++ 3(a) -- Copy of the Amended Articles of Acceptance of I&M and amendments thereto [Annual Report on Form 10-K of I&M for fiscal year ended December 31, 1993, File No. 1-3570, Exhibit 3(a)]. 3(b) -- Copy of Articles of Amendment to the Amended Articles of Acceptance of I&M, dated March 6, 1997 [Annual Report on Form 10-K of I&M for fiscal year ended December 31, 1996, File No. 1-3570, Exhibit 3(b)]. 3(c) -- Composite Copy of the Amended Articles of Acceptance of I&M (amended as of March 7, 1997) [Annual Report on Form 10-K of I&M for the fiscal year ended December 31, 1996, File No. 1-3570, Exhibit 3(c)]. *3(d) -- Copy of the By-Laws of I&M (amended as of November 28, 2001). 4(a) -- Copy of Mortgage and Deed of Trust, dated as of June 1, 1939, between I&M and Irving Trust Company (now The Bank of New York) and various individuals, as Trustees, as amended and supplemented [Registration Statement No. 2-7597, Exhibit 7(a); Registration Statement No. 2-60665, Exhibits 2(c)(2), 2(c)(3), 2(c)(4), 2(c)(5), 2(c)(6), 2(c)(7), 2(c)(8), 2(c)(9), 2(c)(10), 2(c)(11), 2(c)(12), 2(c)(13), 2(c)(14), 2(c)(15), (2)(c)(16), and 2(c)(17); Registration Statement No. 2-63234, Exhibit 2(b)(18); Registration Statement No. 2-65389, Exhibit 2(a)(19); Registration Statement No. 2-67728, Exhibit 2(b)(20); Registration Statement No. 2-85016, Exhibit 4(b); Registration Statement No. 33-5728, Exhibit 4(c); Registration Statement No. 33-9280, Exhibit 4(b); Registration Statement No. 33-11230, Exhibit 4(b); Registration Statement No. 33-19620, Exhibits 4(a)(ii), 4(a)(iii), 4(a)(iv) and 4(a)(v); Registration Statement No. 33-46851, Exhibits 4(b)(i), 4(b)(ii) and 4(b)(iii); Registration Statement No. 33-54480, Exhibits 4(b)(I) and 4(b)(ii); Registration Statement No. 33-60886, Exhibit 4(b)(I); Registration Statement No. 33-50521, Exhibits 4(b)(I), 4(b)(ii) and 4(b)(iii); Annual Report on Form 10-K of I&M for the fiscal year ended December 31, 1993, File No. 1-3570, Exhibit 4(b); Annual Report on Form 10-K of I&M for the fiscal year ended December 31, 1994, File No. 1-3570, Exhibit 4(b); Annual Report on Form 10-K of I&M for the fiscal year ended December 31, 1996, File No. 1-3570, Exhibit 4(b)]. 4(b) -- Copy of Indenture (for unsecured debt securities), dated as of October 1, 1998, between I&M and The Bank of New York, as Trustee [Registration Statement No. 333-88523, Exhibits 4(a), 4(b) and 4(c); Registration Statement No. 58656, Exhibits 4(b) and 4(c)]. *4(c) -- Copy of Company Order and Officers' Certificate, dated December 12, 2001, establishing certain terms of the 6.125% Notes, Series C, due 2006.
E-9
EXHIBIT NUMBER DESCRIPTION - -------------- ----------- 10(a)(1) -- Copy of Power Agreement, dated October 15, 1952, between OVEC and United States of America, acting by and through the United States Atomic Energy Commission, and, subsequent to January 18, 1975, the Administrator of the Energy Research and Development Administration, as amended [Registration Statement No. 2-60015, Exhibit 5(a); Registration Statement No. 2-63234, Exhibit 5(a)(1)(B); Registration Statement No. 2-66301, Exhibit 5(a)(1)(C); Registration Statement No. 2-67728, Exhibit 5(a)(1)(D); Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1989, File No. 1-3457, Exhibit 10(a)(1)(F); and Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1992, File No. 1-3457, Exhibit 10(a)(1)(B)]. 10(a)(2) -- Copy of Inter-Company Power Agreement, dated as of July 10, 1953, among OVEC and the Sponsoring Companies, as amended [Registration Statement No. 2-60015, Exhibit 5(c); Registration Statement No. 2-67728, Exhibit 5(a)(3)(B); Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1992, File No. 1-3457, Exhibit 10(a)(2)(B)]. 10(a)(3) -- Copy of Power Agreement, dated July 10, 1953, between OVEC and Indiana-Kentucky Electric Corporation, as amended [Registration Statement No. 2-60015, Exhibit 5(e)]. 10(a)(4) -- Copy of Inter-Company Power Agreement, dated as of July 10, 1953, among OVEC and the Sponsoring Companies, as amended [Registration Statement No. 2-60015, Exhibit 5(c); Registration Statement No. 2-67728, Exhibit 5(a)(3)(B); Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1992, File No. 1-3457, Exhibit 10(a)(2)(B)]. 10(a)(5) -- Copy of Power Agreement, dated July 10, 1953, between OVEC and Indiana-Kentucky Electric Corporation, as amended [Registration Statement No. 2-60015, Exhibit 5(e)]. 10(b) -- Copy of Interconnection Agreement, dated July 6, 1951, among APCo, CSPCo, KEPCo, I&M, and OPCo and with the Service Corporation, as amended [Registration Statement No. 2-52910, Exhibit 5(a); Registration Statement No. 2-61009, Exhibit 5(b); and Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1990, File No. 1-3525, Exhibit 10(a)(3)]. 10(c) -- Copy of Transmission Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KEPCo, OPCo and with the Service Corporation as agent, as amended [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(b); and Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1988, File No. 1-3525, Exhibit 10(b)(2)]. 10(d) -- Copy of Modification No. 1 to the AEP System Interim Allowance Agreement, dated July 28, 1994, among APCo, CSPCo, I&M, KEPCo, OPCo and the Service Corporation [Annual Report on Form 10-K of AEP for the fiscal year ended December 1, 1996, File No. 1-3525, Exhibit 10(l)]. 10(e) -- Copy of Nuclear Material Lease Agreement, dated as of December 1, 1990, between I&M and DCC Fuel Corporation [Annual Report on Form 10-K of I&M for the fiscal year ended December 31, 1993, File No. 1-3570, Exhibit 10(d)]. 10(f) -- Copy of Lease Agreements, dated as of December 1, 1989, between I&M and Wilmington Trust Company, as amended [Registration Statement No. 33-32753, Exhibits 28(a)(1)(C), 28(a)(2)(C), 28(a)(3)(C), 28(a)(4)(C), 28(a)(5)(C) and 28(a)(6)(C); Annual Report on Form 10-K of I&M for the fiscal year ended December 31, 1993, File No. 1-3570, Exhibits 10(e)(1)(B), 10(e)(2)(B), 10(e)(3)(B), 10(e)(4)(B), 10(e)(5)(B) and 10(e)(6)(B)].
E-10
EXHIBIT NUMBER DESCRIPTION - -------------- ----------- 10(g)(1) -- Agreement and Plan of Merger, dated as of December 21, 1997, By and Among American Electric Power Company, Inc., Augusta Acquisition Corporation and Central and South West Corporation [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1997, File No. 1-3525, Exhibit 10(f)]. 10(g)(2) -- Amendment No. 1, dated as of December 31, 1999, to the Agreement and Plan of Merger [Current Report on Form 8-K of I&M dated December 15, 1999, File No. 1-3570, Exhibit 10]. *12 -- Statement re: Computation of Ratios. *13 -- Copy of those portions of the I&M 2001 Annual Report (for the fiscal year ended December 31, 2001) which are incorporated by reference in this filing. 21 -- List of subsidiaries of I&M [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2001, File No. 1-3525, Exhibit 21]. *23 -- Consent of Deloitte & Touche LLP. *24 -- Power of Attorney. KEPCO++ 3(a) -- Copy of Restated Articles of Incorporation of KEPCo [Annual Report on Form 10-K of KEPCo for the fiscal year ended December 31, 1991, File No. 1-6858, Exhibit 3(a)]. 3(b) -- Copy of By-Laws of KEPCo (amended as of June 15, 2000) [Annual Report on Form 10-K of KEPCo for the fiscal year ended December 31, 2000, File No. 1-6858, Exhibit 3(b)]. 4(a) -- Copy of Mortgage and Deed of Trust, dated May 1, 1949, between KEPCo and Bankers Trust Company, as supplemented and amended [Registration Statement No. 2-65820, Exhibits 2(b)(1), 2(b)(2), 2(b)(3), 2(b)(4), 2(b)(5), and 2(b)(6); Registration Statement No. 33-39394, Exhibits 4(b) and 4(c); Registration Statement No. 33-53226, Exhibits 4(b) and 4(c); Registration Statement No. 33-61808, Exhibits 4(b) and 4(c), Registration Statement No. 33-53007, Exhibits 4(b), 4(c) and 4(d)]. 4(b) -- Copy of Indenture (for unsecured debt securities), dated as of September 1, 1997, between KEPCo and Bankers Trust Company, as Trustee [Registration Statement No. 333-75785, Exhibits 4(a), 4(b), 4(c) and 4(d); Annual Report on Form 10-K of KEPCo for the fiscal year ended December 31, 1999, File No. 1-6858, Exhibit 4(c); Annual Report on Form 10-K of KEPCo for the fiscal year ended December 31, 2000, File No. 1-6858, Exhibit 4(c)]. 10(a) -- Copy of Interconnection Agreement, dated July 6, 1951, among APCo, CSPCo, KEPCo, I&M and OPCo and with the Service Corporation, as amended [Registration Statement No. 2-52910, Exhibit 5(a);Registration Statement No. 2-61009, Exhibit 5(b); and Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1990, File No. 1-3525, Exhibit 10(a)(3)]. 10(b) -- Copy of Transmission Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KEPCo, OPCo and with the Service Corporation as agent, as amended [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(b); and Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1988, File No. 1-3525, Exhibit 10(b)(2)]. 10(c) -- Copy of Modification No. 1 to the AEP System Interim Allowance Agreement, dated July 28, 1994, among APCo, CSPCo, I&M, KEPCo, OPCo and the Service Corporation [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(l)].
E-11
EXHIBIT NUMBER DESCRIPTION - -------------- ----------- 10(d)(1) -- Agreement and Plan of Merger, dated as of December 21, 1997, By and Among American Electric Power Company, Inc., Augusta Acquisition Corporation and Central and South West Corporation [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1997, File No. 1-3525, Exhibit 10(f)]. 10(d)(2) -- Amendment No. 1, dated as of December 31, 1999, to the Agreement and Plan of Merger [Current Report on Form 8-K of KEPCo dated December 15, 1999, File No. 1-6858, Exhibit 10]. *12 -- Statement re: Computation of Ratios. *13 -- Copy of those portions of the KEPCo 2001 Annual Report (for the fiscal year ended December 31, 2001) which are incorporated by reference in this filing. *24 -- Power of Attorney. OPCO++ 3(a) -- Copy of Amended Articles of Incorporation of OPCo, and amendments thereto to December 31, 1993 [Registration Statement No. 33-50139, Exhibit 4(a); Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1993, File No. 1-6543, Exhibit 3(b)]. 3(b) -- Certificate of Amendment to Amended Articles of Incorporation of OPCo, dated May 3, 1994 [Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1994, File No. 1-6543, Exhibit 3(b)]. 3(c) -- Copy of Certificate of Amendment to Amended Articles of Incorporation of OPCo, dated March 6, 1997 [Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1996, File No. 1-6543, Exhibit 3(c)]. 3(d) -- Composite copy of the Amended Articles of Incorporation of OPCo (amended as of March 7, 1997) [Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1996, File No. 1-6543, Exhibit 3(d)]. 3(e) -- Copy of Code of Regulations of OPCo [Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1990, File No. 1-6543, Exhibit 3(d)]. 4(a) -- Copy of Mortgage and Deed of Trust, dated as of October 1, 1938, between OPCo and Manufacturers Hanover Trust Company (now Chemical Bank), as Trustee, as amended and supplemented [Registration Statement No. 2-3828, Exhibit B-4; Registration Statement No. 2-60721, Exhibits 2(c)(2), 2(c)(3), 2(c)(4), 2(c)(5), 2(c)(6), 2(c)(7), 2(c)(8), 2(c)(9), 2(c)(10), 2(c)(11), 2(c)(12), 2(c)(13), 2(c)(14), 2(c)(15), 2(c)(16), 2(c)(17), 2(c)(18), 2(c)(19), 2(c)(20), 2(c)(21), 2(c)(22), 2(c)(23), 2(c)(24), 2(c)(25), 2(c)(26), 2(c)(27), 2(c)(28), 2(c)(29), 2(c)(30), and 2(c)(31); Registration Statement No. 2-83591, Exhibit 4(b); Registration Statement No. 33-21208, Exhibits 4(a)(ii), 4(a)(iii) and 4(a)(iv); Registration Statement No. 33-31069, Exhibit 4(a)(ii); Registration Statement No. 33-44995, Exhibit 4(a)(ii); Registration Statement No. 33-59006, Exhibits 4(a)(ii), 4(a)(iii) and 4(a)(iv); Registration Statement No. 33-50373, Exhibits 4(a)(ii), 4(a)(iii) and 4(a)(iv); Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1993, File No. 1-6543, Exhibit 4(b)]. 4(b) -- Copy of Indenture (for unsecured debt securities), dated as of September 1, 1997, between OPCo and Bankers Trust Company, as Trustee [Registration Statement No. 333-49595, Exhibits 4(a), 4(b) and 4(c); Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1998, File No. 1-6543, Exhibits 4(c) and 4(d); Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1999, File No. 1-6543, Exhibits 4(c) and 4(d); Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 2000, File No. 1-6543, Exhibit 4(c)].
E-12
EXHIBIT NUMBER DESCRIPTION - -------------- ----------- 10(a)(1) -- Copy of Power Agreement, dated October 15, 1952, between OVEC and United States of America, acting by and through the United States Atomic Energy Commission, and, subsequent to January 18, 1975, the Administrator of the Energy Research and Development Administration, as amended [Registration Statement No. 2-60015, Exhibit 5(a); Registration Statement No. 2-63234, Exhibit 5(a)(1)(B); Registration Statement No. 2-66301, Exhibit 5(a)(1)(C); Registration Statement No. 2-67728, Exhibit 5(a)(1)(D); Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1989, File No. 1-3457, Exhibit 10(a)(1)(F); Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1992, File No. 1-3457, Exhibit 10(a)(1)(B)]. 10(a)(2) -- Copy of Inter-Company Power Agreement, dated July 10, 1953, among OVEC and the Sponsoring Companies, as amended [Registration Statement No. 2-60015, Exhibit 5(c); Registration Statement No. 2-67728, Exhibit 5(a)(3)(B); Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1992, File No. 1-3457, Exhibit 10(a)(2)(B)]. 10(a)(3) -- Copy of Power Agreement, dated July 10, 1953, between OVEC and Indiana-Kentucky Electric Corporation, as amended [Registration Statement No. 2-60015, Exhibit 5(e)]. 10(b) -- Copy of Interconnection Agreement, dated July 6, 1951, among APCo, CSPCo, KEPCo, I&M and OPCo and with the Service Corporation, as amended [Registration Statement No. 2-52910, Exhibit 5(a); Registration Statement No. 2-61009, Exhibit 5(b); Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1990, File 1-3525, Exhibit 10(a)(3)]. 10(c) -- Copy of Transmission Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KEPCo, OPCo and with the Service Corporation as agent [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(b); Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1988, File No. 1-3525, Exhibit 10(b)(2)]. 10(d) -- Copy of Modification No. 1 to the AEP System Interim Allowance Agreement, dated July 28, 1994, among APCo, CSPCo, I&M, KEPCo, OPCo and the Service Corporation [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(l)]. 10(e) -- Copy of Amendment No. 1, dated October 1, 1973, to Station Agreement dated January 1, 1968, among OPCo, Buckeye and Cardinal Operating Company, and amendments thereto [Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1993, File No. 1-6543, Exhibit 10(f)]. 10(f) -- Lease Agreement dated January 20, 1995 between OPCo and JMG Funding, Limited Partnership, and amendment thereto (confidential treatment requested) [Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1994, File No. 1-6543, Exhibit 10(l)(2)]. 10(g)(1) -- Agreement and Plan of Merger, dated as of December 21, 1997, by and among American Electric Power Company, Inc., Augusta Acquisition Corporation and Central and South West Corporation [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1997, File No. 1-3525, Exhibit 10(f)]. 10(g)(2) -- Amendment No. 1, dated as of December 31, 1999, to the Agreement and Plan of Merger [Current Report on Form 8-K of OPCo dated December 15, 1999, File No. 1-6543, Exhibit 10].
E-13
EXHIBIT NUMBER DESCRIPTION - -------------- ----------- +10(h)(1) -- AEP Deferred Compensation Agreement for certain executive officers [Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(e)]. +10(h)(2) -- Amendment to AEP Deferred Compensation Agreement for certain executive officers [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1986, File No. 1-3525, Exhibit 10(d)(2)]. +10(i) -- AEP System Senior Officer Annual Incentive Compensation Plan [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(i)(1)]. +10(j)(1) -- AEP System Excess Benefit Plan, Amended and Restated as of January 1, 2001 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2000, File No. 1-3525, Exhibit 10(j)(1)(A)]. +10(j)(2) -- AEP System Supplemental Retirement Savings Plan, Amended and Restated as of January 1, 2001 (Non-Qualified) [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2000, File No. 1-3525, Exhibit 10(j)(2)]. +10(j)(3) -- Umbrella Trust for Executives [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1993, File No. 1-3525, Exhibit 10(g)(3)]. +10(k) -- Employment Agreement between E. Linn Draper, Jr. and AEP and the Service Corporation [Annual Report on Form 10-K of AEGCo for the fiscal year ended December 31, 1991, File No. 0-18135, Exhibit 10(g)(3)]. +10(l) -- AEP System Survivor Benefit Plan, effective January 27, 1998 [Quarterly Report on Form 10-Q of AEP for the quarter ended September 30, 1998, File No. 1-3525, Exhibit 10]. +10(m) -- AEP Senior Executive Severance Plan for Merger with Central and South West Corporation, effective March 1, 1999[Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1998, File No. 1-3525, Exhibit 10(o)]. +10(n) -- AEP Change In Control Agreement [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2001, File No. 1-3525, Exhibit 10(o)]. +10(o) -- AEP System 2000 Long-Term Incentive Plan [Proxy Statement of AEP, March 10, 2000]. +10(p) -- Memorandum of agreement between Susan Tomasky and the Service Corporation dated January 3, 2001 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2000, File No. 1-3525, Exhibit 10(s)]. +10(q)(1) -- Central and South West System Special Executive Retirement Plan as amended and restated effective July 1, 1997 [Annual Report on Form 10-K of CSW for the fiscal year ended December 31, 1998, File No. 1-1443, Exhibit 18]. +10(q)(2) -- Certified CSW Board Resolution of April 18, 1991 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2001, File No. 1-3525, Exhibit 10(r)(2)]. +10(q)(3) -- CSW 1992 Long-Term Incentive Plan [Proxy Statement of CSW, March 13, 1992]. *12 -- Statement re: Computation of Ratios. *13 -- Copy of those portions of the OPCo 2001 Annual Report (for the fiscal year ended December 31, 2001) which are incorporated by reference in this filing. 21 -- List of subsidiaries of OPCo [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2001, File No. 1-3525, Exhibit 21]. *23 -- Consent of Deloitte & Touche LLP. *24 -- Power of Attorney.
E-14
EXHIBIT NUMBER DESCRIPTION - -------------- ----------- PSO++ 3(a) -- Restated Certificate of Incorporation of PSO [Annual Report on Form U5S of Central and South West Corporation for the fiscal year ended December 31, 1996, File No. 1-1443, Exhibit B-3.1]. 3(b) -- By-Laws of PSO (amended as of June 28, 2000) [Annual Report on Form 10-K of PSO for the fiscal year ended December 31, 2000, File No. 0-343, Exhibit 3(b)]. 4(a) -- Indenture, dated July 1, 1945, between PSO and Liberty Bank and Trust Company of Tulsa, National Association, as Trustee, as amended and supplemented [Registration Statement No. 2-60712, Exhibit 5.03; Registration Statement No. 2-64432, Exhibit 2.02; Registration Statement No. 2-65871, Exhibit 2.02; Form U-1 No. 70-6822, Exhibit 2; Form U-1 No. 70-7234, Exhibit 3; Registration Statement No. 33-48650, Exhibit 4(b); Registration Statement No. 33-49143, Exhibit 4(c); Registration Statement No. 33-49575, Exhibit 4(b); Annual Report on Form 10-K of PSO for the fiscal year ended December 31, 1993, File No. 0-343, Exhibit 4(b); Current Report on Form 8-K of PSO dated March 4, 1996, No. 0-343, Exhibit 4.01; Current Report on Form 8-K of PSO dated March 4, 1996, No. 0-343, Exhibit 4.02; Current Report on Form 8-K of PSO dated March 4, 1996, No. 0-343, Exhibit 4.03]. 4(b) -- PSO-obligated, mandatorily redeemable preferred securities of subsidiary trust holding solely Junior Subordinated Debentures of PSO: (1) Indenture, dated as of May 1, 1997, between PSO and The Bank of New York, as Trustee [Quarterly Report on Form 10-Q of PSO dated March 31, 1997, File No. 0-343, Exhibits 4.6 and 4.7]. (2) Amended and Restated Trust Agreement of PSO Capital I, dated as of May 1, 1997, among PSO, as Depositor, The Bank of New York, as Property Trustee, The Bank of New York (Delaware), as Delaware Trustee, and the Administrative Trustee [Quarterly Report on Form 10-Q of PSO dated March 31, 1997, File No. 0-343, Exhibit 4.8]. (3) Guarantee Agreement, dated as of May 1, 1997, delivered by PSO for the benefit of the holders of PSO Capital I's Preferred Securities [Quarterly Report on Form 10-Q of PSO dated March 31, 1997, File No. 0-343, Exhibits 4.9]. (4) Agreement as to Expenses and Liabilities, dated as of May 1, 1997, between PSO and PSO Capital I [Quarterly Report on Form 10-Q of PSO dated March 31, 1997, File No. 0-343, Exhibits 4.10]. 4(c) -- Indenture (for unsecured debt securities), dated as of November 1, 2000, between PSO and The Bank of New York, as Trustee [Annual Report on Form 10-K of PSO for the fiscal year ended December 31, 2000, File No. 0-343, Exhibits 4(c) and 4(d)] *12 -- Statement re: Computation of Ratios. *13 -- Copy of those portions of the PSO 2001 Annual Report (for the fiscal year ended December 31, 2001) which are incorporated by reference in this filing. *23(a) -- Consent of Deloitte & Touche LLP. *23(b) -- Consent of Arthur Andersen LLP. *24 -- Power of Attorney. SWEPCO++ 3(a) -- Restated Certificate of Incorporation, as amended through May 6, 1997, including Certificate of Amendment of Restated Certificate of Incorporation [Quarterly Report on Form 10-Q of SWEPCo for the quarter ended March 31, 1997, File No. 1-3146, Exhibit 3.4].
E-15
EXHIBIT NUMBER DESCRIPTION - -------------- ----------- 3(b) -- By-Laws of SWEPCo (amended as of April 27, 2000) [Quarterly Report on Form 10-Q of SWEPCo for the quarter ended March 31, 2000, File No. 1-3146, Exhibit 3.3]. 4(a) -- Indenture, dated February 1, 1940, between SWEPCo and Continental Bank, National Association and M. J. Kruger, as Trustees, as amended and supplemented [Registration Statement No. 2-60712, Exhibit 5.04; Registration Statement No. 2-61943, Exhibit 2.02; Registration Statement No. 2-66033, Exhibit 2.02; Registration Statement No. 2-71126, Exhibit 2.02; Registration Statement No. 2-77165, Exhibit 2.02; Form U-1 No. 70-7121, Exhibit 4; Form U-1 No. 70-7233, Exhibit 3; Form U-1 No. 70-7676, Exhibit 3; Form U-1 No. 70-7934, Exhibit 10; Form U-1 No. 72-8041, Exhibit 10(b); Form U-1 No. 70-8041, Exhibit 10(c); Form U-1 No. 70-8239, Exhibit 10(a)]. 4(b) -- SWEPCO-obligated, mandatorily redeemable preferred securities of subsidiary trust holding solely Junior Subordinated Debentures of SWEPCo: (1) Indenture, dated as of May 1, 1997, between SWEPCo and the Bank of New York, as Trustee [Quarterly Report on Form 10-Q of SWEPCo dated March 31, 1997, File No. 1-3146, Exhibits 4.11 and 4.12]. (2) Amended and Restated Trust Agreement of SWEPCo Capital I, dated as of May 1, 1997, among SWEPCo, as Depositor, the Bank of New York, as Property Trustee, The Bank of New York (Delaware), as Delaware Trustee, and the Administrative Trustee [Quarterly Report on Form 10-Q of SWEPCo dated March 31, 1997, File No. 1-3146, Exhibit 4.13]. (3) Guarantee Agreement, dated as of May 1, 1997, delivered by SWEPCo for the benefit of the holders of SWEPCo Capital I's Preferred Securities [Quarterly Report on Form 10-Q of SWEPCo dated March 31, 1997, File No. 1-3146, Exhibit 4.14]. (4) Agreement as to Expenses and Liabilities, dated as of May 1, 1997 between SWEPCo and SWEPCo Capital I [Quarterly Report on Form 10-Q of SWEPCo dated March 31, 1997, File No. 1-3146, Exhibits 4.15]. 4(c) -- Indenture (for unsecured debt securities), dated as of February 4, 2000, between SWEPCo and The Bank of New York, as Trustee [Annual Report on Form 10-K of SWEPCo for the fiscal year ended December 31, 2000, File No. 1-3146, Exhibits 4(c) and 4(d)]. *12 -- Statement re: Computation of Ratios. *13 -- Copy of those portions of the SWEPCo 2001 Annual Report (for the fiscal year ended December 31, 2001) which are incorporated by reference in this filing. *23(a) -- Consent of Deloitte & Touche LLP. *23(b) -- Consent of Arthur Andersen LLP. *24 -- Power of Attorney. WTU++ 3(a) -- Restated Articles of Incorporation, as amended, and Articles of Amendment to the Articles of Incorporation [Annual Report on Form 10-K of WTU for the fiscal year ended December 31, 1996, File No. 0-340, Exhibit 3.5]. 3(b) -- By-Laws of WTU (amended as of May 1, 2000) [Quarterly Report on Form 10-Q of WTU for the quarter ended March 31, 2000, File No. 0-340, Exhibit 3.4].
E-16
EXHIBIT NUMBER DESCRIPTION - -------------- ----------- 4(a) -- Indenture, dated August 1, 1943, between WTU and Harris Trust and Savings Bank and J. Bartolini, as Trustees, as amended and supplemented [Registration Statement No. 2-60712, Exhibit 5.05; Registration Statement No. 2-63931, Exhibit 2.02; Registration Statement No. 2-74408, Exhibit 4.02; Form U-1 No. 70-6820, Exhibit 12; Form U-1 No. 70-6925, Exhibit 13; Registration Statement No. 2-98843, Exhibit 4(b); Form U-1 No. 70-7237, Exhibit 4; Form U-1 No. 70-7719, Exhibit 3; Form U-1 No. 70-7936, Exhibit 10; Form U-1 No. 70-8057, Exhibit 10; Form U-1 No. 70-8265, Exhibit 10; Form U-1 No. 70-8057, Exhibit 10(b); Form U-1 No. 70-8057, Exhibit 10(c)]. *12 -- Statement re: Computation of Ratios. *13 -- Copy of those portions of the WTU 2001 Annual Report (for the fiscal year ended December 31, 2001) which are incorporated by reference in this filing. *24 -- Power of Attorney.
------------------------------------- ++Certain instruments defining the rights of holders of long-term debt of the registrants included in the financial statements of registrants filed herewith have been omitted because the total amount of securities authorized thereunder does not exceed 10% of the total assets of registrants. The registrants hereby agree to furnish a copy of any such omitted instrument to the SEC upon request. E-17 EX-12 4 x12cpl.txt Exhibit 12 Central Power and Light Company Ratio of Earnings to Fixed Charges For Years Ended December 31
2001 2000 1999 1998 1997 (thousands, except ratios) Operating Income...............$295,731 $307,098 $293,985 $282,787 $251,319 Adjustments Income Taxes................. 188,922 84,329 83,508 126,738 39,329 Provision for Deferred Income Taxes.................... (72,568) 16,263 19,938 (8,328) 34,458 Deferred Investment Tax Credits.............. (5,207) (5,207) (5,207) (3,858) (4,819) Charges for Investments and Plant Development Costs, Net of Tax........ - - - - (1,281) Other Income and Deductions.... 1,954 7,235 8,113 709 7,834 Allowance for Borrowed and Equity Funds Used During Construction................. 7,804 6,216 4,532 2,822 3,778 Earnings.......................$416,636 $415,934 $404,869 $400,870 $330,618 Fixed Charges: Interest on Long-term Debt..............$ 86,980 $ 96,212 $ 87,413 $ 93,301 $105,081 Interest on Short-term Debt............. 25,023 22,830 19,498 19,506 20,613 Distributions on Trust Preferred Securities........ 11,208 11,940 12,000 12,000 7,533 Fixed Charges..............$123,211 $130,982 $118,911 $124,807 $133,227 Ratio of Earnings to Fixed Charges................ 3.38 3.17 3.40 3.21 2.48
EX-13 5 x13.txt 2001 Annual Reports American Electric Power Company, Inc. AEP Generating Company Appalachian Power Company Central Power and Light Company Columbus Southern Power Company Indiana Michigan Power Company Kentucky Power Company Ohio Power Company Public Service Company of Oklahoma Southwestern Electric Power Company West Texas Utilities Company Audited Financial Statements and Management's Discussion and Analysis
Contents Page Glossary of Terms i Forward Looking Information iv American Electric Power Company, Inc. and Subsidiary Companies Selected Consolidated Financial Data A-1 Management's Discussion and Analysis of Results of Operations A-2 Consolidated Statements of Income A-12 Consolidated Balance Sheets A-13 Consolidated Statements of Cash Flows A-15 Consolidated Statements of Common Shareholders' Equity and A-16 Comprehensive Income Schedule of Consolidated Cumulative Preferred Stocks of Subsidiaries A-17 Schedule of Consolidated Long-term Debt of Subsidiaries A-18 Index to Notes to Consolidated Financial Statements A-19 Management's Responsibility A-20 Independent Auditors' Report A-21 AEP Generating Company Selected Financial Data B-1 Management's Narrative Analysis of Results of Operations B-2 Statements of Income and Statements of Retained Earnings B-3 Balance Sheets B-4 Statements of Cash Flows B-6 Statements of Capitalization B-7 Index to Notes to Financial Statements B-8 Independent Auditors' Report B-9 Appalachian Power Company and Subsidiaries Selected Consolidated Financial Data C-1 Management's Discussion and Analysis of Results of Operations C-2 Consolidated Statements of Income and Consolidated Statements of C-7 Comprehensive Income Consolidated Balance Sheets C-8 Consolidated Statements of Cash Flows C-10 Consolidated Statements of Retained Earnings C-11 Consolidated Statements of Capitalization C-12 Schedule of Long-term Debt C-13 Index to Notes to Consolidated Financial Statements C-14 Independent Auditors' Report C-15 Central Power and Light Company and Subsidiaries Selected Consolidated Financial Data D-1 Management's Discussion and Analysis of Results of Operations D-2 Consolidated Statements of Income D-6 Consolidated Balance Sheets D-7 Consolidated Statements of Cash Flows D-9 Consolidated Statements of Retained Earnings D-10 Consolidated Statements of Capitalization D-11 Schedule of Long-term Debt D-12 Index to Notes to Consolidated Financial Statements D-13 Independent Auditors' Report D-14 Columbus Southern Power Company and Subsidiaries Selected Consolidated Financial Data E-1 Management's Narrative and Analysis of Results of Operations E-2 Consolidated Statements of Income and Consolidated Statements of Retained Earnings E-6 Consolidated Balance Sheets E-7 Consolidated Statements of Cash Flows E-9 Consolidated Statements of Capitalization E-10 Schedule of Long-term Debt E-11 Index to Notes to Consolidated Financial Statements E-12 Independent Auditors' Report E-13 Indiana Michigan Power Company and Subsidiaries Selected Consolidated Financial Data F-1 Management's Discussion and Analysis of Results of Operations F-2 Consolidated Statements of Income and Consolidated Statements of F-7 Comprehensive Income Consolidated Balance Sheets F-8 Consolidated Statements of Cash Flows F-10 Consolidated Statements of Retained Earnings F-11 Consolidated Statements of Capitalization F-12 Schedule of Long-term Debt F-13 Index to Notes to Consolidated Financial Statements F-15 Independent Auditors' Report F-16 Kentucky Power Company Selected Financial Data G-1 Management's Narrative Analysis of Results of Operations G-2 Statements of Income, Statements of Comprehensive Income G-6 and Statements of Retained Earnings Balance Sheets G-7 Statements of Cash Flows G-9 Statements of Capitalization G-10 Schedule of Long-term Debt G-11 Index to Notes to Financial Statements G-12 Independent Auditors' Report G-13 Ohio Power Company and Subsidiaries Selected Consolidated Financial Data H-1 Management's Discussion and Analysis of Results of Operations H-2 Consolidated Statements of Income and Consolidated Statements of H-7 Comprehensive Income Consolidated Balance Sheets H-8 Consolidated Statements of Cash Flows H-10 Consolidated Statements of Retained Earnings H-11 Consolidated Statements of Capitalization H-12 Schedule of Long-term Debt H-13 Index to Notes to Consolidated Financial Statements H-15 Independent Auditors' Report H-16 Public Service Company of Oklahoma and Subsidiaries Selected Consolidated Financial Data I-1 Management's Narrative Analysis of Results of Operations I-2 Consolidated Statements of Income and Consolidated Statements of Retained Earnings I-5 Consolidated Balance Sheets I-6 Consolidated Statements of Cash Flows I-8 Consolidated Statements of Capitalization I-9 Schedule of Long-term Debt I-10 Index to Notes to Consolidated Financial Statements I-11 Independent Auditors' Report I-12 Southwestern Electric Power Company and Subsidiaries Selected Consolidated Financial Data J-1 Management's Discussion and Analysis of Results of Operations J-2 Consolidated Statements of Income and Consolidated Statements of Retained Earnings J-6 Consolidated Balance Sheets J-7 Consolidated Statements of Cash Flows J-9 Consolidated Statements of Capitalization J-10 Schedule of Long-term Debt J-11 Index to Notes to Consolidated Financial Statements J-12 Independent Auditors' Report J-13 West Texas Utilities Company Selected Financial Data K-1 Management's Narrative Analysis of Results of Operations K-2 Statements of Income and Statements of Retained Earnings K-6 Balance Sheets K-7 Statements of Cash Flows K-9 Statements of Capitalization K-10 Schedule of Long-term Debt K-11 Index to Notes to Consolidated Financial Statements K-12 Independent Auditors' Report K-13 Notes to Financial Statements L-1 Management's Discussion and Analysis of Financial Condition, Contingencies and Other Matters M-1
GLOSSARY OF TERMS When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below. Term Meaning 2004 True-up Proceeding............ A filing to be made after January 10, 2004 under the Texas Legislation to finalize the amount of stranded costs and the recovery of such costs. AEGCo.............................. AEP Generating Company, an electric utility subsidiary of AEP. AEP................................ American Electric Power Company, Inc. AEP Consolidated................... AEP and its majority owned subsidiaries consolidated. AEP Credit,Inc. AEP Credit, Inc., a subsidiary of AEP which factors accounts receivable and accrued utility revenues for affiliated and unaffiliated domestic electric utility companies. AEP East electric operating companies.......................... APCo, CSPCo, I&M, KPCo and OPCo. AEPR............................... AEP Resources, Inc. AEP System or the System........... The American Electric Power System, an integrated electric utility system, owned and operated by AEP's electric utility subsidiaries. AEPSC.............................. American Electric Power Service Corporation, a service subsidiary providing management and professional services to AEP and its subsidiaries. AEP Power Pool..................... AEP System Power Pool. Members are APCo, CSPCo, I&M, KPCo and OPCo. The Pool shares the generation, cost of generation and resultant wholesale system sales of the member companies. AEP West electric operating companies.......................... CPL, PSO, SWEPCo and WTU. AFUDC.............................. Allowance for funds used during construction, a noncash nonoperating income item that is capitalized and recovered through depreciation over the service life of domestic regulated electric utility plant. Alliance RTO....................... Alliance Regional Transmission Organization, an ISO formed by AEP and four unaffiliated utilities. Amos Plant......................... John E. Amos Plant, a 2,900 MW generation station jointly owned and operated by APCo and OPCo. APCo............................... Appalachian Power Company, an AEP electric utility subsidiary. Arkansas Commission................ Arkansas Public Service Commission. Buckeye............................ Buckeye Power, Inc., an unaffiliated corporation. CLECO.............................. Central Louisiana Electric Company, Inc., an unaffiliated corporation. COLI............................... Corporate owned life insurance program. Cook Plant......................... The Donald C. Cook Nuclear Plant, a two-unit, 2,110 MW nuclear plant owned by I&M. CPL................................ Central Power and Light Company, an AEP electric utility subsidiary. CSPCo.............................. Columbus Southern Power Company, an AEP electric utility subsidiary. CSW............................... Central and South West Corporation, a subsidiary of AEP. CSW Energy......................... CSW Energy, Inc., an AEP subsidiary which invests in energy projects and builds power plants. CSW International.................. CSW International, Inc., an AEP subsidiary which invests in energy projects and entities outside the United States. D.C. Circuit Court................. The United States Court of Appeals for the District of Columbia Circuit. DHMV............................... Dolet Hills Mining Venture. DOE................................ United States Department of Energy. ECOM............................... Excess Cost Over Market. ENEC............................... Expanded Net Energy Costs. EITF............................... The Financial Accounting Standards Board's Emerging Issues Task Force. ERCOT.............................. The Electric Reliability Council of Texas. EWGs............................... Exempt Wholesale Generators. FASB............................... Financial Accounting Standards Board. Federal EPA........................ United States Environmental Protection Agency. FERC............................... Federal Energy Regulatory Commission. FMB ............................... First Mortgage Bond. FUCOs.............................. Foreign Utility Companies. GAAP............................... Generally Accepted Accounting Principles. I&M................................ Indiana Michigan Power Company, an AEP electric utility subsidiary. IPC................................ Installment Purchase Contract. IRS................................ Internal Revenue Service. IURC............................... Indiana Utility Regulatory Commission. ISO................................ Independent system operator. Joint Stipulation.................. Joint Stipulation and Agreement for Settlement of APCo's WV rate proceeding. KPCo............................... Kentucky Power Company, an AEP electric utility subsidiary. KPSC............................... Kentucky Public Service Commission. KWH................................ Kilowatthour. LIG................................ Louisiana Intrastate Gas. Michigan Legislation............... The Customer Choice and Electricity Reliability Act, a Michigan law which provides for customer choice of electricity supplier. Midwest ISO........................ An independent operator of transmission assets in the Midwest. MLR................................ Member load ratio, the method used to allocate AEP Power Pool transactions to its members. Money Pool......................... AEP System's Money Pool. MPSC............................... Michigan Public Service Commission. MTN................................ Medium Term Notes. MW................................. Megawatt. MWH................................ Megawatthour. NEIL............................... Nuclear Electric Insurance Limited. Nox................................ Nitrogen oxide. NOx Rule........................... A final rules issued by Federal EPA which requires NOx reductions in 22 eastern states including seven of the states in which AEP companies operates. NP................................. Notes Payable. NRC................................ Nuclear Regulatory Commission. Ohio Act........................... The Ohio Electric Restructuring Act of 1999. Ohio EPA........................... Ohio Environmental Protection Agency. OPCo.............................. Ohio Power Company, an AEP electric utility subsidiary. OVEC............................... Ohio Valley Electric Corporation, an electric utility company in which AEP and CSPCo own a 44.2% equity interest. PCBs............................... Polychlorinated Biphenyls. PJM................................ Pennsylvania - New Jersey - Maryland regional transmission organization. PRP.............................. Potentially Responsible Party. PSO................................ Public Service Company of Oklahoma, an AEP electric utility subsidiary. PUCO............................... The Public Utilities Commission of Ohio. PUCT............................... The Public Utility Commission of Texas. PUHCA.............................. Public Utility Holding Company Act of 1935, as amended. PURPA.............................. The Public Utility Regulatory Policies Act of 1978. RCRA............................... Resource Conservation and Recovery Act of 1976, as amended. Registrant Subsidiaries............ AEP subsidiaries who are SEC registrants; AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU. Rockport Plant..................... A generating plant, consisting of two 1,300 MW coal-fired generating units near Rockport, Indiana owned by AEGCo and I&M. RTO................................ Regional Transmission Organization. SEC................................ Securities and Exchange Commission. SFAS............................... Statement of Financial Accounting Standards issued by the Financial Accounting Standards Board. SFAS 71............................ Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation. SFAS 101........................... Statement of Financial Accounting Standards No. 101, Accounting for the Discontinuance of Application of Statement 71. SFAS 121........................... Statement of Financial Accounting Standards No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of. SFAS 133........................... Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities. SNF................................ Spent Nuclear Fuel. SPP................................ Southwest Power Pool. STP................................ South Texas Project Nuclear Generating Plant, owned 25.2% by Central Power and Light Company, an AEP electric utility subsidiary . STPNOC............................. STP Nuclear Operating Company, a non-profit Texas corporation which operates STP on behalf of its joint owners including CPL. Superfund......................... The Comprehensive Environmental, Response, Compensation and Liability Act. SWEPCo............................. Southwestern Electric Power Company, an AEP electric utility subsidiary. Texas Appeals Court................ The Third District of Texas Court of Appeals. Texas Legislation.................. Legislation enacted in 1999 to restructure the electric utility industry in Texas. Travis District Court.............. State District Court of Travis County, Texas. TVA ............................... Tennessee Valley Authority. U.K................................ The United Kingdom. UN................................. Unsecured Note. VaR................................ Value at Risk, a method to quantify risk exposure. Virginia SCC....................... Virginia State Corporation Commission. WV................................. West Virginia. WVPSC.............................. Public Service Commission of West Virginia. WPCo............................... Wheeling Power Company, an AEP electric distribution subsidiary. WTU................................ West Texas Utilities Company, an AEP electric utility subsidiary. Yorkshire.......................... Yorkshire Electricity Group plc, a U.K. regional electricity company owned jointly by AEP and New Century Energies until April 2001. Zimmer Plant....................... William H. Zimmer Generating Station, a 1,300 MW coal-fired unit owned 25.4% by Columbus Southern Power Company, an AEP subsidiary.
FORWARD LOOKING INFORMATION This discussion includes forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. These forward-looking statements reflect assumptions, and involve a number of risks and uncertainties. Among the factors both foreign and domestic that could cause actual results to differ materially from forward looking statements are: electric load and customer growth; abnormal weather conditions; available sources of and prices for coal and gas; availability of generating capacity; risks related to energy trading and construction under contract; the speed and degree to which competition is introduced to our power generation business; the structure and timing of a competitive market for electricity and its impact on prices, the ability to recover net regulatory assets, other stranded costs and implementation costs in connection with deregulation of generation in certain states; the timing of the implementation of AEP's restructuring plan; new legislation and government regulations; the ability to successfully control costs; the success of new business ventures; international developments affecting our foreign investments; the economic climate and growth in our service and trading territories both domestic and foreign; the ability of the Company to successfully challenge new environmental regulations and to successfully litigate claims that the Company violated the Clean Air Act; inflationary trends; litigation concerning AEP's merger with CSW; changes in electricity and gas market prices and interest rates; fluctuations in foreign currency exchange rates, and other risks and unforeseen events.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Selected Consolidated Financial Data Year Ended December 31, 2001 2000 1999 1998 1997 - ----------------------- ---- ---- ---- ---- ---- INCOME STATEMENTS DATA (in millions): Total Revenues $61,257 $36,706 $24,745 $18,420 $11,427 Operating Income 2,395 2,004 2,304 2,258 2,180 Income Before Extraordinary Items and Cumulative Effect 1,003 302 986 975 949 Extraordinary Losses (50) (35) (14) - (285) Cumulative Effect of Accounting Change 18 - - - - Net Income 971 267 972 975 664 Year Ended December 31, 2001 2000 1999 1998 1997 - ----------------------- ---- ---- ---- ---- ---- BALANCE SHEETS DATA (in millions): Property, Plant and Equipment $40,709 $38,088 $36,938 $35,655 $33,496 Accumulated Depreciation and Amortization 16,166 15,695 15,073 14,136 13,229 ------ ------ ------ ------ ------ Net Property, Plant and Equipment $24,543 $22,393 $21,865 $21,519 $20,267 ======= ======= ======= ======= ======= Total Assets $47,281 $53,350 $35,693 $33,418 $30,092 Common Shareholders' Equity 8,229 8,054 8,673 8,452 8,220 Cumulative Preferred Stocks of Subsidiaries* 156 161 182 350 377 Trust Preferred Securities 321 334 335 335 335 Long-term Debt* 12,053 10,754 11,524 11,113 9,354 Obligations Under Capital Leases* 451 614 610 539 549 Year Ended December 31, 2001 2000 1999 1998 1997 - ----------------------- ---- ---- ---- ---- ---- COMMON STOCK DATA: Earnings per Common Share: Before Extraordinary Item and Cumulative Effect $ 3.11 $0.94 $3.07 $3.06 $2.99 Extraordinary Losses (0.16) (.11) (.04) - (.90) Cumulative Effect of Accounting Change 0.06 - - - - ---- --- --- --- --- Earnings Per Share $ 3.01 $0.83 $3.03 $3.06 $2.09 ====== ===== ===== ===== ===== Average Number of Shares Outstanding (in millions) 322 322 321 318 316 Market Price Range: High $51.20 $48-15/16 $48-3/16 $53-5/16 $ 52 Low 39.25 25-15/16 30-9/16 42-1/16 39-1/8 Year-end Market Price 43.53 46-1/2 32-1/8 47-1/16 51-5/8 Cash Dividends on Common** $2.40 $2.40 $2.40 $2.40 $2.40 Dividend Payout Ratio** 79.7% 289.2% 79.2% 78.4% 114.8% Book Value per Share $25.54 $25.01 $26.96 $26.46 $25.91
The consolidated financial statements give retroactive effect to AEP's merger with CSW, which was accounted for as a pooling of interests. *Including portion due within one year **Based on AEP historical dividend rate. AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Management's Discussion and Analysis of Results of Operations American Electric Power Company, Inc. (AEP) is one of the largest investor owned electric public utility holding companies in the US. We provide generation, transmission and distribution service to over 4.9 million retail customers in eleven states (Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia) through our electric utility operating companies. We market and trade electricity and natural gas in the US and Europe. We have a significant presence throughout the domestic energy value chain. Our US electric assets include: o 38,000 megawatts of generating capacity (the largest US generation portfolio with a significant cost advantage in the Midwest and Southwest markets); o 38,000 miles of transmission lines and o 186,000 miles of distribution lines Our natural gas assets include: o 128 Bcf of gas storage facilities o 6,400 miles of gas pipelines in Louisiana and Texas which provide a basis for market knowledge. With our coal and transportation assets we: o control over 7,000 railcars o control over 1,800 barges and 37 tug boats o operate two coal handling terminals with 20 million tons of capacity. o produce over 7 million tons of coal annually in the US. AEP is one of the largest traders of electricity and natural gas in the US: o over 576 million MWH of electricity trades in 2001 o over 3,800 billion cubic feet (Bcf) of gas trades in 2001 In addition we: o consume 80 million tons of coal annually o consume 310 Bcf of natural gas annually AEP's focus is in the US but we also have smaller footprints in other parts of the world: o a growing energy trading operation in Europe based in the UK. o 4,000 megawatts of generating capacity in the United Kingdom which represents 16% of the UK's total generation capacity. Other foreign investments include distribution operations in the U.K., Australia, and Brazil. We have additional generating facilities in China and Mexico. We also offer engineering and construction services worldwide. Business Strategy Our strategy is a balanced business model of regulated and unregulated businesses backed by assets, supported by enterprise-wide risk management and a strong balance sheet. We have been focused on the wholesale side of the business since it provides the greater growth opportunities. But, this is complemented by a robust regulated business that has a predictable earnings stream and cash flows. Strong risk management and a disciplined analysis of markets protected us from the California energy crisis and Enron's bankruptcy filing. Our balanced business model is one where AEP integrates its assets, marketing, trading and market analysis and resources to create a superior knowledge about the commodity markets which keeps us a step ahead of our competition. Our power, gas, coal, and barging assets and operations provide us with market knowledge and customer connectivity giving us the ability to make informed marketing and trading decision and to customize our products and services. AEP provides investors with a balanced portfolio since it has: o a growing unregulated wholesale energy marketing and trading business o predictable cash flow and earnings streams from the regulated electricity business, and o a high dividend yield relative to today's low-interest rate environment. We are currently in the process of restructuring our assets and operations to separate the regulated operations from the non-regulated operations. We filed with the SEC for approval to form two separate legal holding company subsidiaries of AEP Co. Inc., the parent company. Approval is needed from the SEC under the PUHCA and the FERC to make these organizational changes. Certain state regulatory commissions have intervened in the FERC proceedings. We have reached a settlement with those state commissions and are awaiting the FERC's approval before the SEC will make a final ruling on our filing. We are implementing a corporate separation restructuring plan to support our objective of unlocking shareholder value for our domestic businesses. Our plan provides for: o transparency and clarity to investors, o a simpler structure to conduct business, and to anticipate and monitor performance, o compliance with states' restructuring laws promoting customer choice, and o more efficient financing. The new corporate structure will consist of a regulated holding company and an unregulated holding company. The regulated holding company's investments will be in integrated utilities and Ohio and Texas wires. The unregulated holding company's investments will be in Ohio and Texas generation, independent power producers, gas pipe line and storage, UK generation, barging, coal mining and marketing and trading. The risks in our business are: o Margin erosion on electric trading as markets mature, o Diminished opportunities for signifi-cant gains as volatility declines, o Retail price reductions mandated with the implementation of customer choice in Texas and Ohio, o Movement towards re-regulation in California through market caps and other challenges to the continuation of deregulation of the retail electricity supply business in the U.S., o The continued negative impact of a slowly recovering economy. Our business plan considers these risks and we believe that we can deliver earnings growth of 6-8% annually across the energy value chain through the disciplined integration of strategic assets and intellectual capital to generate these returns for our shareholders. Our strategies to achieve our business plan are: o Unregulated o Disciplined approach to asset acquisition and disposition o Value-driven asset optimiz-ation through the linkage of superior commercial, analytical and technical skills o Broad participation across all energy markets with a disciplined and opportunistic allocation of risk capital o Continued investment in both technology and process improvement to enhance our competitive advantage o Continued expansion of intellectual capital through ongoing recruiting, performance-linked compensation and the development of a structure that promotes sound decision-making and innovation at all levels. o Regulated o Maintain moderate but steady earnings growth o Maximize value of trans-mission assets and protect revenue stream through RTO/Alliance membership o Continue process improve-ment to maintain distribution service quality while en-hancing financial performance o Optimize generation assets through enhanced availability of off-system sales o Manage regulatory process to maximize retention of earnings improvement Our significant accomplishments in 2001 were : o Adding the following assets to integrate with and support our trading and marketing competitive advantage: o 4,200 miles of gas pipeline, 118 Bcf gas storage and re-lated gas marketing contracts o 1,200 hopper barges and 30 tugboats o 4,000 megawatts of coal-fired generation in England o 160 megawatts of wind generation in Texas o coal mining properties, coal reserves, mining operations and royalty interests in Colorado, Kentucky, Ohio, Pennsylvania and West Virginia o Entering into new markets through the acquisition of existing contracts and hiring key staff including 57 employees from Enron's London based international coal trading group in December 2001 and Enron's Nordic energy trading group in January 2002. We now trade power and gas in the UK, France, Germany, and the Netherlands and coal throughout the world o Adding other energy-related commodities to our power and gas portfolio i.e. coal, SO2 allowances, natural gas liquids (NGLs)and oil o Disposing of the following assets that did not fit our strategy: o 120 MWs of generation in Mexico, o Above market coal mines in Ohio and West Virginia, o A 50 % investment in Yorkshire, a U.K. electric supply and distribution company, o An investment in a Chilean electric company o Datapult, an energy information data and analysis tool. In addition we sold 500 MWs of generating capacity in Texas under a FERC order that approved our merger with CSW. Our divesture of non-strategic assets is somewhat limited by the pooling of interest accounting requirements applied to the merger of CSW and AEP in June 2000. We are presently evaluating certain tele-communications and foreign investments for possible disposal and have not yet decided whether to dispose of such investments. Disposal of investments determined to be non-strategic will be considered in accordance with the pooling of interests restrictions which end in June 2002. We are committed to continually evaluate the need to reallocate resources to areas with greater potential, to match investments with our strategy and to pare investments that do not produce sufficient return and shareholder value. Any investment dispositions could affect future results of operations. Outlook for 2002 Growth in 2002 will be driven in part by our continued strategic development of wholesale products and geographies, as demonstrated in recent months by our move into global coal markets and Nordic energy. A full year of operation of assets acquired in 2001 - Houston Pipe Line, Quaker Coal, the MEMCO barge line and two power plants in the United Kingdom - will also contribute to growth in 2002 earnings. Although we expect that the future outlook for results of operations is excellent there are contingencies and challenges. We discuss these matters in detail in the Notes to Financial Statements and in this Management's Discussion and Analysis. We intend to work diligently to resolve these matters by finding workable solutions that balance the interests of our customers, our employees and our shareholders. As discussed above we expect to continue evaluating certain investments for possible disposal due to either their non-strategic nature or limited future earnings potential for AEP. Any dispositions could result in gains or losses being recorded in our income statement. Results of Operations In 2001 AEP's principal operating business segments and their major activities were: o Wholesale: o Generation of electricity for sale to retail and wholesale customers o Gas pipeline and storage services o Marketing and trading of electricity, gas and coal o Coal mining, bulk commodity barging operations and other energy supply related business. o Energy Delivery o Domestic electricity trans-mission, o Domestic electricity distri-bution o Other Investments o Foreign electric distribution and supply investments, o Telecommunication services. Net Income Net income increased to $971 million or $3.01 per share from $267 million or $0.83 per share. The increase of $704 million or $2.18 per share was due to the growth of AEP's wholesale marketing and trading business, increased revenues and the controlling of our operating and maintenance costs in the energy delivery business, and declining capital costs. Also contributing to the earnings improvement in 2001 was the effect of 2000 charges for a disallowance of COLI-related tax deductions, expenses of the merger with CSW, write-offs related to non-regulated investments and restart costs of the Cook Nuclear Plant. The favorable effect on comparative net income of these 2000 charges was offset in part by current year losses from Enron's bankruptcy and extraordinary losses for the effects of deregulation and a loss on reacquired debt. The decline in net income to $267 million or $0.83 per share in 2000 from $972 million or $3.03 per share in 1999 was primarily due to the 2000 charges described above and an extraordinary losses from the discontinuance of regulatory accounting for generation in certain states. A strong performance in the first nine months of 2001 was partially offset by unfavorable operating conditions in the fourth quarter. Extremely mild November and December weather combined with weak economic conditions in the fourth quarter, reduced retail energy sales and wholesale margins. Heating degree days in the fourth quarter were down 33% from the same period in 2000. Although the fourth quarter was disappointing, 2001 net income before extraordinary items and cumulative effect of accounting change reached the $1 billion mark. Our wholesale business continues to perform well despite a slowing economy that reduced both wholesale energy margins and energy use by industrial customers. Our wholesale business, which includes generation, retail and wholesale sales of power and natural gas and trading of power and natural gas and natural gas pipeline and storage services, contributed to the earnings increase by successfully returning the Cook Plant to service in 2000 and by growing AEP's wholesale business. Our energy delivery business, which consists of domestic electricity transmission and distribution services, contributed to the increase in earnings by controlling operating and maintenance expenses and by increasing revenues. Capital costs decreased due primarily to interest paid to the IRS in 2000 on a COLI deduction disallowance and declining short-term market interest rate conditions. Critical Accounting Policies Revenue Recognition - Traditional Electricity Supply and Delivery Activities - As the owner of cost-based rate-regulated electric public utility companies, AEP Co., Inc.'s consolidated financial statements recognize revenues on an accrual basis for traditional electricity supply sales and for electricity transmission and distribution delivery services. These revenues are recognized in our income statement when the energy is delivered to the customer and include unbilled as well as billed amounts. In general, expenses are recorded when incurred. As a result of our cost based rate regulated operations, our financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate regulated. In accordance with SFAS 71, "Accounting for the Effects of Certain Types of Regulation," regulatory assets (deferred expenses) and regulatory liabilities (future revenue reductions or refunds) are recorded to reflect the economic effects of regulation by matching in the same accounting period regulated expenses with their recovery through regulated revenues. When regulatory assets are probable of recovery through regulated rates, we record them as assets on the balance sheet. We test for probability of recovery whenever new events occur, for example a regulatory commission order or passage of new legislation. If we determine that recovery of a regulatory asset is no longer probable, we write off that regulatory asset as a charge against net income. A write off of regulatory assets may also reduce future cash flows since there may be no recovery through regulated rates. We discontinued application of SFAS 71 for the generation portion of our business in Ohio for OPCo and CSPCo in September 2000, in Virginia and West Virginia for APCo in June 2000, in Texas for CPL, WTU, and SWEPCo in September 1999 and in Arkansas for SWEPCo in September 1999 in recognition of the passage of legislation to transition to customer choice and market pricing for the supply of electricity. We recorded extraordinary losses when we discontinued the application of SFAS 71. See Note 2, "Extraordinary Items and Cumulative Effect" for additional information. Wholesale Energy Marketing and Trading Activities - We engage in non-regulated wholesale electricity and natural gas marketing and trading transactions (trading activities). Trading activities involve the purchase and sale of energy under forward contracts at fixed and variable prices and buying and selling financial energy contracts which includes exchange futures and options and over-the-counter options and swaps. Although trading contracts are generally short-term, there are also long-term trading contracts. We recognize revenues from trading activities generally based on changes in the fair value of energy trading contracts. Recording the net change in the fair value of trading contracts as revenues prior to settlement is commonly referred to as mark-to-market (MTM) accounting. It represents the change in the unrealized gain or loss throughout the contract's term. When the contract actually settles, that is, the energy is actually delivered in a sale or received in a purchase or the parties agree to forego delivery and receipt and net settle in cash, the unrealized gain or loss is reversed out of revenues and the actual realized cash gain or loss is recognized in revenues for a sale or in purchased energy expense for a purchase. Therefore, over the term of the trading contracts an unrealized gain or loss is recognized as the contract's market value changes. When the contract settles the total gain or loss is realized in cash but only the difference between the accumulated unrealized net gains or losses recorded in prior months and the cash proceeds is recognized. Unrealized mark-to-market gains and losses are included in the Balance Sheet as energy trading and derivative contract assets or liabilities as appropriate. The majority of our trading activities represent physical forward electricity and gas contracts that are typically settled by entering into offsetting contracts. An example of our trading activities is when, in January, we enter into a forward sales contract to deliver electricity or gas in July. At the end of each month until the contract settles in July, we would record any difference between the contract price and the market price as an unrealized gain or loss in revenues. In July when the contract settles, we would realize the gain or loss in cash and reverse to revenues the previously recorded unrealized gain or loss. Prior to settlement, the change in the fair value of physical forward sale and purchase contracts is included in revenues on a net basis. Upon settlement of a forward trading contract, the amount realized is included in revenues for a sales contract and realized costs are included in purchased energy expense for a purchase contract with the prior change in unrealized fair value reversed in revenues. Continuing with the above example, assume that later in January or sometime in February through July we enter into an offsetting forward contract to buy electricity or gas in July. If we do nothing else with these contracts until settlement in July and if the commodity type, volumes, delivery point, schedule and other key terms match then the difference between the sale price and the purchase price represents a fixed value to be realized when the contracts settle in July. If the purchase contract is perfectly matched with the sales contract, we have effectively fixed the profit or loss; specifically it is the difference between the contracted settlement price of the two contracts. Mark-to-market accounting for these contracts will have no further impact on operating results but has an offsetting and equal effect on trading contract assets and liabilities. Of course we could also do similar transactions but enter into a purchase contract prior to entering into a sales contract. If the sale and purchase contracts do not match exactly as to commodity type, volumes, delivery point, schedule and other key terms, then there could be continuing mark-to-market effects on revenues from recording additional changes in fair values using mark-to-market accounting. Trading of electricity and gas options, futures and swaps, represents financial transactions with unrealized gains and losses from changes in fair values reported net in revenues until the contracts settle. When these contracts settle, we record the net proceeds in revenues and reverse to revenues the prior unrealized gain or loss. The fair value of open short-term trading contracts are based on exchange prices and broker quotes. We mark-to-market open long-term trading contracts based mainly on Company-developed valuation models. These models estimate future energy prices based on existing market and broker quotes and supply and demand market data and assumptions. The fair values determined are reduced by reserves to adjust for credit risk and liquidity risk. Credit risk is the risk that the counterparty to the contract will fail to perform or fail to pay amounts due AEP. Liquidity risk represents the risk that imperfections in the market will cause the price to be less than or more than what the price should be based purely on supply and demand. There are inherent risks related to the underlying assumptions in models used to fair value open long-term trading contracts. We have independent controls to evaluate the reasonableness of our valuation models. However, energy markets, especially electricity markets, are imperfect and volatile and unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a contract's term and when contracts settle. Therefore, there could be significant adverse or favorable effects on future results of operations and cash flows if market prices do not correlate with the Company-developed price models. We also mark to market derivatives that are not trading contracts in accordance with generally accepted accounting principles. Derivatives are contracts whose value is derived from the market value of an underlying commodity. Our revenues of $61 billion for 2001 included $257 million of unrealized net gains from marking to market open trading and derivative contracts. AEP's net revenues, (revenues less fuel and energy purchases) excluding mark-to-market revenues totaled $8.3 billion and were realized during 2001. Unrealized net mark-to-market revenues are only 3% of total net revenues. A significant portion of the net unrealized revenues from marking to market trading contracts and derivatives included in our balance sheet at December 31, 2001 as energy trading and derivative contract assets and liabilities, will be realized in 2002. We defer as regulatory assets or liabilities the effect on net income of marking to market open electricity trading contracts in our regulated jurisdictions since these transactions are included in cost of service on a settlement basis for ratemaking purposes. Changes in mark-to-market valuations impact net income in our non-regulated business. Volatility in energy commodities markets affects the fair values of all of our open trading and derivative contracts exposing AEP to market risk causing our results of operations to be more volatile. See "Market Risks" section below for a discussion of the policies and procedures AEP uses to manage its exposure to market and other risks from trading activities. Revenues Increase Our revenues have increased significantly from the marketing and trading of electricity and natural gas. The level of electricity trading transactions tends to fluctuate due to the highly competitive nature of the short-term (spot) energy market and other factors, such as affiliated and unaffiliated generating plant availability, weather conditions and the economy. The FERC's introduction of a greater degree of competition into the wholesale energy market, has had a major effect on the volume of wholesale power marketing and trading especially in the short-term market. AEP's total revenues increased 66.9% in 2001 and 48.3% in 2000. The following table shows the components of revenues in millions. For The Year Ended December 31 2001 2000 1999 ---- ---- ---- (in millions) WHOLESALE BUSINESS: Residential $ 3,553 $ 3,511 $ 3,290 Commercial 2,328 2,249 2,083 Industrial 2,388 2,444 2,515 Other Retail Customers 419 414 394 Electricity Marketing and Trading 35,339 18,858 11,417 Gas Marketing and Trading 14,369 6,127 2,290 Unrealized MTM Income: Electric 210 38 2 Gas 47 132 21 Other 632 838 599 Less Transmission and Distribution Revenues Assigned to Energy Delivery* (3,356) (3,174) (3,068) ------- ------- ------- TOTAL WHOLESALE BUSINESS 55,929 31,437 19,543 ------- ------- ------- ENERGY DELIVERY BUSINESS: Transmission 1,029 1,009 960 Distribution 2,327 2,165 2,108 ------- ------- ------- TOTAL ENERGY DELIVERY 3,356 3,174 3,068 ------- ------- ------- OTHER INVESTMENTS: SEEBOARD 1,451 1,596 1,705 CITIPOWER 350 338 318 Other 171 161 111 ------- ------- ------- TOTAL OTHER INVESTMENTS 1,972 2,095 2,134 ------- ------- ------- TOTAL REVENUES $61,257 $36,706 $24,745 ======= ======= ======= *Certain revenues in Wholesale business include energy delivery revenues due primarily to bundled tariffs that are assignable to the Energy Delivery business. The $25 billion increase in 2001 revenues was due to substantial increases in electric and gas trading volumes. The increase in sales of purchased power and purchased gas during the past two years reflect AEP's intention to be a leading national wholesale energy merchant. Wholesale natural gas trading volume for 2001 was 3,874 Bcf, a 178% increase from 2000 volume of 1,391 Bcf. Electric trading volume increased 48% to 576 million MWH. We have invested in resources required to optimize our assets and emerge as a leader in the industry. The maturing of the Intercontinental Exchange, the development of proprietary tools, and the increased staffing of energy traders have faciliated increased power and gas sales. Our June 2001 purchase of Houston Pipe Line enhanced our gas trading and marketing operation. Although we will trade and market only when we believe profitable opportunites exist, we expect the increased level of activity to continue. While wholesale marketing and trading volumes rose, kilowatthour sales to industrial customers decreased by 5% in 2001. This decrease was due to the economic recession. In the fourth quarter, sales to residential, commercial and wholesale customers declined 9%. The recession reduced demand and wholesale prices especially in the fourth quarter. While margins available from selling power that the company generates generally are higher than from selling purchased power, such sales are limited by the amount of generating assets owned. Furthermore, the profit available from simply selling excess generation is reduced by the inherent market transparency of such sales. The coordinated sales of excess generation in conjunction with trading and marketing activity optimizes assets, mitigates risk, and increases overall profit. The $12 billion increase in 2000 revenues was primarily due to a 27% increase in wholesale electricity trading volume and increased retail fuel revenues as a result of higher gas prices used to generate electricity. The reduction in industrial revenues in 2000 is attributable to the expiration of a long-term contract on December 31, 1999. The significant increase in 2000 electricity trading volume, which accounted for a 66% increase in electricity trading revenues, resulted from: o efforts to grow AEP's energy marketing and trading operations, o favorable market conditions, and o the availability of additional generation Generation availability improved due to the return to service of one of the Cook Plant nuclear units in June 2000 and to improved outage management. The second Cook Plant unit which returned to service in December 2000 did not have a significant impact on 2000 revenues. Gas revenues increased in 2000 due to increased natural gas and gas liquid product prices. Operating Expenses Increase Changes in the components of operating expenses were as follows: Increase (Decrease) From Previous Year ------------------------- (Dollars in Millions) 2001 2000 ---- ---- Amount % Amount % Fuel and Purchased Energy $24,035 83.7 $11,474 66.5 Maintenance and Other Operation 196 5.1 565 17.2 Non-recoverable Merger Costs (182)(89.7) 203 N.M. Depreciation and Amortization 133 10.6 38 3.1 Taxes Other Than Income Taxes (22) (3.2) (19)(2.7) ------- ------- Total $24,160 69.6 $12,261 54.6 ======= ======= Our fuel and purchased energy expense in 2001 increased 84% due to increased trading volume and an increase in nuclear generation cost. The return to service of the Cook Plant's two nuclear generating units in June 2000 and December 2000 accounted for the increase in nuclear generation costs. Fuel and purchased energy expense increased 67% in 2000 due to increased trading volume and a significant increase in the cost of natural gas used for generation. Natural gas usage for generation declined 5% while the cost of natural gas consumed rose 60%. Net income was not impacted by this significant cost increase due to the operation of fuel recovery rate mechanisms. These fuel recovery rate mechanisms generally provide for the deferral of fuel costs above the amounts included in existing rates or the accrual of revenues for fuel costs not yet recovered. Upon regulatory commission review and approval of the unrecovered fuel costs, the accrued or deferred amounts are billed to customers. With the introduction of customer choice of electricity supplier and a transition to market-based generation rates, the protection offered by fuel recovery mechanisms against changes in fuel costs was eliminated in Ohio effective January 1, 2001 and in the ERCOT area of Texas effective January 1, 2002. As a result, AEP's exposure to the risk of fuel price increases that could adversely affect future results of operations and cash flows is increasing. See Note 1 for applicability of fuel recovery mechanisms by jurisdiction. Maintenance and other operation expense rose in 2001 mainly as a result of additional traders' incentive compensation and accruals for severance costs related to corporate restructuring. The increase in maintenance and other operation expense in 2000 was mainly due to increased expenditures to prepare the Cook Plant nuclear units for restart following an extended NRC monitored outage and increased usage and prices of emissions allowances. The increase in Cook Plant restart costs resulted from the effect of deferring restart costs in 1999 and an increase in the restart expenditure level in 2000. Cook Plant began its extended outage in September 1997 when both nuclear generating units were shut down because of questions regarding the operability of certain safety systems. In 1999 a portion of incremental restart expenses were deferred in accordance with IURC and MPSC settlement agreements which resolved all jurisdictional rate-related issues related to the Cook Plant's extended outage. With NRC approval Unit 2 returned to service in June and achieved full power operation on July 5, 2000 and Unit 1 returned to service in December and achieved full power operation on January 3, 2001. The increase in emission allowance usage and prices resulted from the stricter air quality standards of Phase II of the 1990 Clean Air Act Amendments, which became effective on January 1, 2000. With the consummation of the merger with CSW, certain deferred merger costs were expensed in 2000. The merger costs charged to expense included transaction and transition costs not allocable to and recoverable from ratepayers under regulatory commission approved settlement agreements to share net merger savings. As expected merger costs declined in 2001 after the merger was consummated. Depreciation and amortization expense increased in 2001 primarily as a result of the commencement of amortization of transition generation regulatory assets in the Ohio, Virginia and West Virginia jurisdictions due to passage of restructuring legislation, the new businesses acquired in 2001 and additional investments in property, plant and equipment. Interest, Preferred Stock Dividends, Minority Interest Interest expense deceased 15% in 2001 due to the effect of interest paid the IRS on a COLI deduction disallowance in 2000 and lower average outstanding short-term debt balances and a decrease in average short-term interest rates. In 2001 we issued a preferred member interest to finance the acquisition of HPL and paid a preferred return of $13 million to the preferred member interest. In 2000 interest increased by 17% due to additional interest expense from the ruling disallowing COLI tax deductions and AEP's effort to maintain flexibility for corporate separation by issuing short-term debt at flexible rates. The use of fixed interest rate swaps has been employed to mitigate the risk from floating interest rates. Other Income Other income increased $166 million in 2001. This increase was primarily caused by the sale in March 2001 of Frontera, a generating plant required to be divested under a FERC approved merger settlement agree-ment, which produced a pretax $73 million gain and the effect from the December 2000 impairment writedown of $43 million to reflect the pending sale of AEP's Yorkshire investment. Other income decreased $66 million in 2000 primarily due to a loss in equity earnings from the 2000 write-down of the Yorkshire investment and losses from certain non-regulated subsidiaries accounted for on an equity basis. Other expenses increased in 2000 mainly from a charge for the discontinuance of an electric storage water heater demand side management program of the regulated business. Income Taxes Although pre-tax book income increased considerably, income taxes decreased due to the effect of recording in 2000 prior year federal income taxes as a result of the disallowance of COLI interest deductions by the IRS and nondeductible merger related costs in 2000. Income taxes increased in 2000 over 1999 levels primarily due to the disallowance of the COLI interest deductions and the non-deductible merger related costs discussed above. Extraordinary Losses and Cumulative Effect In 2001 we recorded an extraordinary loss of $48 million net of tax to write-off prepaid Ohio excise taxes stranded by Ohio deregulation. The application of regulatory accounting for generation was discontinued in 2000 for the Ohio, Virginia and West Virginia jurisdictions which resulted in the after tax extraordinary loss of $35 million. New accounting rules that became effective in 2001 regarding accounting for derivatives required us to mark to market certain fuel supply contracts that qualify as financial derivatives. The effect of initially adopting the new rules at July 1, 2001 was a favorable earnings effect of $18 million, net of tax, which is reported as a cumulative effect of accounting change.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Consolidated Statements of Income - --------------------------------- (in millions - except per share amounts) Year Ended December 31, ---------------------------------- 2001 2000 1999 ---- ---- ---- REVENUES: Electricity Marketing and Trading $41,513 $25,178 $17,232 Gas Marketing and Trading 14,416 6,259 2,311 Domestic Electricity Delivery 3,356 3,174 3,068 Other Investment 1,972 2,095 2,134 ----- ----- ----- TOTAL REVENUES 61,257 36,706 24,745 ------ ------ ------ EXPENSES: Fuel and Purchased Energy: Electricity Marketing and Trading 37,558 21,246 13,646 Gas Marketing and Trading 14,004 6,227 2,305 Other Investment 1,191 1,245 1,293 ----- ----- ----- TOTAL FUEL AND PURCHASED ENERGY 52,753 28,718 17,244 Maintenance and Other Operation 4,037 3,841 3,276 Non-recoverable Merger Costs 21 203 - Depreciation and Amortization 1,383 1,250 1,212 Taxes Other Than Income Taxes 668 690 709 --- --- --- TOTAL EXPENSES 58,862 34,702 22,441 ------ ------ ------ OPERATING INCOME 2,395 2,004 2,304 OTHER INCOME 302 136 202 OTHER EXPENSES 130 81 42 LESS: INTEREST 972 1,149 977 PREFERRED STOCK DIVIDEND REQUIREMENTS OF SUBSIDIARIES 10 11 19 MINORITY INTEREST IN FINANCE SUBSIDIARY 13 - - -- ---- ---- INCOME BEFORE INCOME TAXES 1,572 899 1,468 INCOME TAXES 569 597 482 --- --- --- INCOME BEFORE EXTRAORDINARY ITEM AND CUMULATIVE EFFECT 1,003 302 986 EXTRAORDINARY LOSSES (NET OF TAX): DISCONTINUANCE OF REGULATORY ACCOUNTING FOR GENERATION (48) (35) (8) LOSS ON REACQUIRED DEBT (2) - (6) CUMULATIVE EFFECT OF ACCOUNTING CHANGE 18 - - -- ---- ---- NET INCOME $ 971 $ 267 $ 972 ===== ===== ===== AVERAGE NUMBER OF SHARES OUTSTANDING 322 322 321 === === === EARNINGS PER SHARE: Income Before Extraordinary Item and Cumulative Effect $ 3.11 $0.94 $3.07 Extraordinary Losses (0.16) (.11) (.04) Cumulative Effect of Accounting Change .06 - - --- --- --- Earnings Per Share (Basic and Dilutive) $ 3.01 $0.83 $3.03 ====== ===== ===== CASH DIVIDENDS PAID PER SHARE $2.40 $2.40 $2.40 ===== ===== =====
See Notes to Consolidated Financial Statements beginning on page L-1.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Consolidated Balance Sheets - --------------------------- (in millions - except share data) December 31, ------------------------- 2001 2000 ---- ---- ASSETS - ------ CURRENT ASSETS: Cash and Cash Equivalents $ 333 $ 342 Accounts Receivable: Customers 626 888 Miscellaneous 1,365 2,883 Allowance for Uncollectible Accounts (109) (72) Energy Trading and Derivative Contracts 8,572 15,497 Other 1,776 1,363 ----- ----- TOTAL CURRENT ASSETS 12,563 20,901 ------ ------ PROPERTY PLANT AND EQUIPMENT: Electric: Production 17,477 16,328 Transmission 5,879 5,609 Distribution 11,310 10,843 Other (including gas and coal mining assets And nuclear fuel) 4,941 4,077 Construction Work in Progress 1,102 1,231 ----- ----- Total Property, Plant and Equipment 40,709 38,088 Accumulated Depreciation and Amortization 16,166 15,695 ------ ------ NET PROPERTY, PLANT AND EQUIPMENT 24,543 22,393 ------ ------ REGULATORY ASSETS 3,162 3,698 ----- ----- INVESTMENTS IN POWER, DISTRIBUTION AND COMMUNICATIONS PROJECTS 677 782 --- --- GOODWILL (NET OF AMORTIZATION) 1,494 1,382 ----- ----- LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 2,370 1,552 ----- ----- OTHER ASSETS 2,472 2,642 ----- ----- TOTAL $47,281 $53,350 ======= =======
See Notes to Consolidated Financial Statements beginning on page L-1.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Consolidated Balance Sheets December 31, ------------------------ 2001 2000 ---- ---- LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES: Accounts Payable $ 2,245 $ 2,627 Short-term Debt 3,155 4,333 Long-term Debt Due Within One Year* 2,300 1,152 Energy Trading and Derivative Contracts 8,311 15,671 Other 2,088 2,154 ----- ----- TOTAL CURRENT LIABILITIES 18,099 25,937 ------ ------ LONG-TERM DEBT* 9,753 9,602 ----- ----- LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 2,183 1,313 ----- ----- DEFERRED INCOME TAXES 4,823 4,875 ----- ----- DEFERRED INVESTMENT TAX CREDITS 491 528 --- --- DEFERRED CREDITS AND REGULATORY LIABILITIES 948 637 --- --- DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2 194 203 --- --- OTHER NONCURRENT LIABILITIES 1,334 1,706 ----- ----- COMMITMENTS AND CONTINGENCIES (Note 8) CERTAIN SUBSIDIARY OBLIGATED, MANDATORILY REDEEMABLE, PREFERRED SECURITIES OF SUBSIDIARY TRUSTS HOLDING SOLELY JUNIOR SUBORDINATED DEBENTURES OF SUCH SUBSIDIARIES 321 334 --- --- MINORITY INTEREST IN FINANCE SUBSIDIARY 750 - --- ----- CUMULATIVE PREFERRED STOCK OF SUBSIDIARIES* 156 161 --- --- COMMON SHAREHOLDERS' EQUITY: Common Stock-Par Value $6.50: 2001 2000 ---- ---- Shares Authorized. .600,000,000 600,000,000 Shares Issued. . . .331,234,997 331,019,146 (8,999,992 shares were held in treasury at December 31, 2001 and 2000) 2,153 2,152 Paid-in Capital 2,906 2,915 Accumulated Other Comprehensive Income (Loss) (126) (103) Retained Earnings 3,296 3,090 ----- ----- TOTAL COMMON SHAREHOLDERS' EQUITY 8,229 8,054 ----- ----- TOTAL $47,281 $53,350 ======= =======
*See Accompanying Schedules.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Consolidated Statements of Cash Flows - ------------------------------------- (in millions) Year Ended December 31, ------------------------------------- 2001 2000 1999 ---- ---- ---- OPERATING ACTIVITIES: Net Income $ 971 $ 267 $ 972 Adjustments for Noncash Items: Depreciation and Amortization 1,413 1,299 1,294 Deferred Federal Income Taxes 163 (170) 180 Deferred Investment Tax Credits (29) (36) (38) Amortization (Deferral) of Operating Expenses and Carrying Charges (net) 40 48 (151) Equity in Earnings of Yorkshire Electricity Group plc - (44) (45) Extraordinary Loss 50 35 14 Cumulative Effect of Accounting Change (18) - - Deferred Costs Under Fuel Clause Mechanisms 340 (449) (191) Mark to Market of Energy Trading Contracts (257) (170) (23) Miscellaneous Accrued Expenses (384) 217 101 Changes in Certain Current Assets and Liabilities: Accounts Receivable (net) 1,764 (1,632) (80) Fuel, Materials and Supplies (82) 147 (162) Accrued Utility Revenues 26 (79) (35) Accounts Payable (461) 1,322 74 Taxes Accrued (147) 172 29 Premium Options (76) 74 8 Payment of Disputed Tax and Interest Related to COLI - 319 (16) Change in Other Assets (213) (92) (87) Change in Other Liabilities (147) 205 (245) ---- --- ---- Net Cash Flows From Operating Activities 2,953 1,433 1,599 ----- ----- ----- INVESTING ACTIVITIES: Construction Expenditures (1,832) (1,773) (1,680) Purchase of Houston Pipe Line (727) - - Purchase of U.K. Generation (943) - - Purchase of Quaker Coal Co. (101) - - Purchase of Memco (266) - - Purchase of Indian Mesa (175) - - Sale of Yorkshire 383 - - Sale of Frontera 265 - - Other (36) 19 7 --- -- - Net Cash Flows Used For Investing Activities (3,432) (1,754) (1,673) ------ ------ ------ FINANCING ACTIVITIES: Issuance of Common Stock 10 14 93 Issuance of Minority Interest 747 - - Issuance of Long-term Debt 2,931 1,124 1,391 Retirement of Cumulative Preferred Stock (5) (20) (170) Retirement of Long-term Debt (1,835) (1,565) (915) Change in Short-term Debt (net) (597) 1,308 812 Dividends Paid on Common Stock (773) (805) (833) Dividends on Minority Interest in Subsidiary (5) - - Other Financing Activities - - (43) ---- ---- --- Net Cash Flows From Financing Activities 473 56 335 --- -- --- Effect of Exchange Rate Change on Cash (3) 23 (2) -- -- -- Net Increase (Decrease) in Cash and Cash Equivalents (9) (242) 259 Cash and Cash Equivalents January 1 342 584 325 --- --- --- Cash and Cash Equivalents December 31 $ 333 $ 342 $ 584 ===== ===== =====
See Notes to Consolidated Financial Statements beginning on page L-1.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Consolidated Statements of Common Shareholders' Equity and Comprehensive Income - ------------------------------------------------------------------------------- (in millions) Accumulated Other Common Stock Paid-In Retained Comprehensive Shares Amount Capital Earnings Income (Loss) Total JANUARY 1, 1999 328 $2,134 $2,818 $3,493 $ 7 $8,452 Issuances 3 15 77 - - 92 Retirements and Other - - 3 - - 3 Cash Dividends Declared - - - (833) - (833) Other - - - (2) - (2) ------ 7,712 Comprehensive Income: Other Comprehensive Income, Net of Taxes Foreign Currency Translation Adjustment - - - - (13) (13) Minimum Pension Liability - - - - 2 2 Net Income - - - 972 - 972 ------ Total Comprehensive Income 961 --- ------ ------ ------ ----- ------ DECEMBER 31, 1999 331 2,149 2,898 3,630 (4) 8,673 Issuances - 3 11 - - 14 Cash Dividends Declared - - - (805) - (805) Other - - 6 (2) - 4 ------ 7,886 Comprehensive Income: Other Comprehensive Income, Net of Taxes Foreign Currency Translation Adjustment - - - - (119) (119) Reclassification Adjustment For Loss Included in Net Income - - - - 20 20 Net Income - - - 267 267 ------ Total Comprehensive Income 168 --- ------ ------ ------ ----- ------ DECEMBER 31, 2000 331 2,152 2,915 3,090 (103) $8,054 Issuances - 1 9 - - 10 Cash Dividends Declared - - - (773) - (773) Other - - (18) 8 - (10) ------ 7,281 Comprehensive Income: Other Comprehensive Income, Net of Taxes Foreign Currency Translation Adjustment - - - - (14) (14) Unrealized Gain (Loss) on Hedged Derivatives (3) (3) Minimum Pension Liability - - - - (6) (6) Net Income - - - 971 971 ------ Total Comprehensive Income 948 --- ------ ------ ------ ----- ------ DECEMBER 31, 2001 331 $2,153 $2,906 $3,296 $(126) $8,229 === ====== ====== ====== ===== ======
See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Schedule of Consolidated Cumulative Preferred Stocks of Subsidiaries December 31, 2001 ------------------------------------------------------------------- Call Price per Shares Shares Amount (In Share (a) Authorized(b) Outstanding(f) Millions) - -------------------------------------------------------------------------------------------------------- Not Subject to Mandatory Redemption: 4.00% - 5.00% $102-$110 1,525,903 614,608 $61 === Subject to Mandatory Redemption: 5.90% - 5.92% (c) (d) 1,950,000 333,100 $33 6.02% - 6-7/8% (c) $100 1,650,000 513,450 52 7% (e) (e) 250,000 100,000 10 --- Total Subject to Mandatory Redemption (c) $95 ===
December 31, 2000 ----------------------------------------------------------------- Call Price per Shares Shares Amount (In Share (a) Authorized(b) Outstanding(f) Millions) - -------------------------------------------------------------------------------------------------------- Not Subject to Mandatory Redemption: 4.00% - 5.00% $102-$110 1,525,903 614,608 $ 61 ==== Subject to Mandatory Redemption: 5.90% - 5.92% (c) (d) 1,950,000 333,100 $ 33 6.02% - 6-7/8% (c) $100 1,650,000 513,450 52 7% (e) (e) 250,000 150,000 15 ---- Total Subject to Mandatory Redemption (c) $100 ====
NOTES TO SCHEDULE OF CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES (a) At the option of the subsidiary the shares may be redeemed at the call price plus accrued dividends. The involuntary liquidation preference is $100 per share for all outstanding shares. (b) As of December 31, 2001 the subsidiaries had 13,642,750, 22,200,000 and 7,713,495 shares of $100, $25 and no par value preferred stock, respectively, that were authorized but unissued. (c) Shares outstanding and related amounts are stated net of applicable retirements through sinking funds(generally at par) and reacquisitions of shares in anticipation of future requirements. The subsidiaries reacquired enough shares in 1997 to meet all sinking fund requirements on certain series until 2008 and on certain series until 2009 when all remaining outstanding shares must be redeemed. The sinking fund provisions of the series subject to mandatory redemption aggregate (after deducting sinking fund requirements) of $5 million in 2002 and $5 million in 2003. (d) Not callable prior to 2003; after that the call price is $100 per share. (e) With sinking fund. (f) The number of shares of preferred stock redeemed is 50,000 shares in 2001, 209,563 shares in 2000 and 1,698,276 shares in 1999.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Schedule of Consolidated Long-term Debt of Subsidiaries Weighted Average Maturity Interest Rate Interest Rates at December 31, December 31, - -------- ----------------- ------------------------------ ---------------------- December 31, 2001 2001 2000 2001 2000 ----------------- ---- ---- ---- ---- (in millions) ------------- FIRST MORTGAGE BONDS (a) 2001-2003 6.95% 6.00%-7.70% 5.91%-8.95% $ 852 $ 1,247 2004-2008 6.98% 6-1/8%-8.00% 6-1/8%-8% 1,092 1,140 2020-2025 7.66% 6-7/8%-8.80% 6-7/8%-8.80% 850 1,104 INSTALLMENT PURCHASE CONTRACTS (b) 2001-2009 4.30% 1.80%-7.70% 4.90%-7.70% 446 234 2011-2030 5.88% 1.55%-8.20% 4.875%-8.20% 1,234 1,447 NOTES PAYABLE (c) 2001-2021 5.41% 4.0483%-9.60% 6.20%-9.60% 2,237 1,181 SENIOR UNSECURED NOTES 2001-2004 4.81% 2.31%-7.45% 6.50%-7.45% 1,874 2,049 2005-2009 6.24% 6.125%-6.91% 6.24%-6.91% 1,763 475 2038 7.30% 7.20%-7-3/8% 7.20%-7-3/8% 340 340 JUNIOR DEBENTURES 2025-2038 8.05% 7.60%-8.72% 7.60%-8.72% 618 620 YANKEE BONDS AND EURO BONDS 2001-2006 8.71% 8.50%-8.875% 7.98%-8.875% 479 684 OTHER LONG-TERM DEBT (d) 308 280 Unamortized Discount (net) (40) (47) ------- ------- Total Long-term Debt Outstanding (e) 12,053 10,754 Less Portion Due Within One Year 2,300 1,152 ------- ------- Long-term Portion $ 9,753 $ 9,602 ======= =======
NOTES TO SCHEDULE OF CONSOLIDATED LONG-TERM DEBT OF SUBSIDIARIES (a) First mortgage bonds are secured by first mortgage liens on electric property, plant and equipment. (b) For certain series of installment purchase contracts interest rates are subject to periodic adjustment. Certain series will be purchased on demand at periodic interest-adjustment dates. Letters of credit from banks and standby bond purchase agreements support certain series. (c) Notes payable represent outstanding promissory notes issued under term loan agreements and revolving credit agreements with a number of banks and other financial institutions. At expiration all notes then issued and outstanding are due and payable. Interest rates are both fixed and variable. Variable rates generally relate to specified short-term interest rates. (d) Other long-term debt consists of a liability along with accrued interest for disposal of spent nuclear fuel (see Note 8 of the Notes to Consolidated Financial Statements) and financing obligation under sale lease back agreements. (e) Long-term debt outstanding at December 31, 2001 is payable as follows: Principal Amount (in millions) 2002 $ 2,300 2003 2,086 2004 902 2005 616 2006 1,943 Later Years 4,246 ------- Total Principal Amount 12,093 Unamortized Discount 40 ------- Total $12,053 ======= AMERICAN ELECTRIC POWER COMPANY INC. AND SUBSIDIARY COMPANIES Index to Notes to Consolidated Financial Statements The notes listed below are combined with the notes to financial statements for AEP and its other subsidiary registrants. The combined footnotes begin on page L-1. Combined Footnote Reference Significant Accounting Policies Note 1 Extraordinary Items and Cumulative Effect Note 2 Merger Note 3 Nuclear Plant Restart Note 4 Rate Matters Note 5 Effects of Regulation Note 6 Customer Choice and Industry Restructuring Note 7 Commitments and Contingencies Note 8 Acquisitions and Dispositions Note 9 Benefit Plans Note 10 Stock-Based Compensation Note 11 Business Segments Note 12 Risk Management, Financial Instruments And Derivatives Note 13 Income Taxes Note 14 Basic and Diluted Earnings Per Share Note 15 Supplementary Information Note 16 Power, Distribution and Communications Projects Note 17 Leases Note 18 Lines of Credit and Sale of Receivables Note 19 Unaudited Quarterly Financial Information Note 20 Trust Preferred Securities Note 21 Minority Interest in Finance Subsidiary Note 22 MANAGEMENT'S RESPONSIBILITY The management of American Electric Power Company, Inc. is responsible for the integrity and objectivity of the information and representations in this annual report, including the consolidated financial statements. These statements have been prepared in conformity with generally accepted accounting principles, using informed estimates where appropriate, to reflect the Company's financial condition and results of operations. The information in other sections of the annual report is consistent with these statements. The Company's Board of Directors has oversight responsibilities for determining that management has fulfilled its obligation in the preparation of the financial statements and in the ongoing examination of the Company's established internal control structure over financial reporting. The Audit Committee, which consists solely of outside directors and which reports directly to the Board of Directors, meets regularly with management, Deloitte & Touche LLP - independent auditors and the Company's internal audit staff to discuss accounting, auditing and reporting matters. To ensure auditor independence, both Deloitte & Touche LLP and the internal audit staff have unrestricted access to the Audit Committee. The financial statements have been audited by Deloitte & Touche LLP, whose report appears on the next page. The auditors provide an objective, independent review as to management's discharge of its responsibilities insofar as they relate to the fairness of the Company's reported financial condition and results of operations. Their audit includes procedures believed by them to provide reasonable assurance that the financial statements are free of material misstatement and includes an evaluation of the Company's internal control structure over financial reporting. INDEPENDENT AUDITORS' REPORT To the Shareholders and Board of Directors of American Electric Power Company, Inc.: We have audited the consolidated balance sheets of American Electric Power Company, Inc. and its subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of income, cash flows, and common shareholders' equity and comprehensive income for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. The consolidated financial statements give retroactive effect to the merger of American Electric Power Company, Inc. and its subsidiaries and Central and South West Corporation and its subsidiaries, which has been accounted for as a pooling of interests as described in Note 3 to the consolidated financial statements. We did not audit the consolidated statements of income, and cash flows, and stockholder's equity and comprehensive income of Central and South West Corporation and its subsidiaries for the year ended December 31, 1999, which statements reflect total revenues of $5,516,000,000 for the year ended December 31, 1999. Those consolidated statements, before the restatement described in Note 3, were audited by other auditors whose report, dated February 25, 2000, has been furnished to us, and our opinion, insofar as it relates to those amounts included for Central and South West Corporation and its subsidiaries for 1999, is based solely on the report of such other auditors. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits and the report of the other auditors provide a reasonable basis for our opinion. In our opinion, based on our audits and the report of the other auditors, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of American Electric Power Company, Inc. and its subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America. We also audited the adjustments described in Note 3 that were applied to restate the 1999 financial statements to give retroactive effect to the change in the method of accounting for vacation pay accruals. In our opinion, such adjustments are appropriate and have been properly applied. Deloitte & Touche LLP Columbus, Ohio February 22, 2002 AEP GENERATING COMPANY
AEP GENERATING COMPANY Selected Financial Data Year Ended December 31, ------------ ----------------------- 2001 2000 1999 1998 1997 ---- ---- ---- ---- ---- (in thousands) INCOME STATEMENTS DATA: Operating Revenues $227,548 $228,516 $217,189 $224,146 $227,868 Operating Expenses 220,571 220,092 211,849 215,415 218,828 ------- ------- ------- ------- ------- Operating Income 6,977 8,424 5,340 8,731 9,040 Nonoperating Income 3,484 3,429 3,659 3,364 3,603 Interest Charges 2,586 3,869 2,804 3,149 3,857 ----- ----- ----- ----- ----- Net Income $7,875 $7,984 $6,195 $8,946 $8,786 ====== ====== ====== ====== ====== December 31, ------------------------------- 2001 2000 1999 1998 1997 ---- ---- ---- ---- ---- (in thousands) BALANCE SHEETS DATA: Electric Utility Plant $648,254 $642,302 $640,093 $636,460 $633,450 Accumulated Depreciation 337,151 315,566 295,065 277,855 257,191 ------- ------- ------- ------- ------- Net Electric Utility Plant $311,103 $326,736 $345,028 $358,605 $376,259 ======== ======== ======== ======== ======== Total Assets $361,341 $374,602 $398,640 $403,892 $419,058 ======== ======== ======== ======== ======== Common Stock and Paid-in Capital $ 24,434 $ 24,434 $ 30,235 $ 36,235 $ 40,235 Retained Earnings 13,761 9,722 3,673 2,770 2,528 ------ ----- ----- ----- ----- Total Common Shareholder's Equity $ 38,195 $ 34,156 $ 33,908 $ 39,005 $ 42,763 ======== ======== ======== ======== ======== Long-term Debt (a) $ 44,793 $ 44,808 $ 44,800 $ 44,792 $ 69,570 ======== ======== ======== ======== ======== Total Capitalization And Liabilities $361,341 $374,602 $398,640 $403,892 $419,058 ======== ======== ======== ======== ======== (a) Including portion due within one year.
AEP GENERATING COMPANY Management's Narrative Analysis of Results of Operations AEP Generating Company is engaged in the generation and wholesale sale of electric power to two affiliates under long-term agreements. Operating revenues are derived from the sale of Rockport Plant energy and capacity to two affiliated companies, I&M and KPCo pursuant to FERC approved long-term unit power agreements. Under the terms of its unit power agreement, I&M is required to buy all of AEGCo's Rockport capacity when the unit power agreement with KPCo expires in 2004. The unit power agreements provide for recovery of costs including a FERC approved rate of return on common equity and a return on other capital net of temporary cash investments. Under terms of the unit power agreements, AEGCo accumulates all expenses monthly and prepares the bills for its affiliates. In the month the expenses are incurred, AEGCo recognizes the billing revenues and establishes a receivable from the affiliated companies. Net income decreased $0.1 million or 1% as a result of a slight decrease in the return on other capital. Lower interest charges caused the return on other capital to decrease. Income statement items which changed significantly were: Increase (Decrease) (dollars in millions) From Previous Year Amount % Operating Revenues $(1.0) N.M. Other Operation Expense 0.7 7 Maintenance Expense (0.8) (8) Taxes Other Than Income Taxes 0.4 10 Interest Charges (1.3) (33) N.M. = Not Meaningful The decrease in operating revenues reflects a decrease in the return on other capital reflecting a decline in interest charges. Other operation expense increased due to the costs of an air quality test project and increased benefits and compensation costs. The decrease in maintenance expense can be attributed to a shorter duration of maintenance outages for boiler inspection and repair in 2001. Taxes other than income taxes increased due to an increase in Indiana real and personal property taxes reflecting an unfavorable accrual adjustment and a higher estimated liability accrued in 2001. The decrease in interest charges was primarily due to a decline in interest rates in 2001. The Federal Reserve reduced short-term interest rates eleven times in 2001. AEGCo benefited from the declining short-term interest rates since its short-term borrowings and through July 13, 2001 its long-term debt were based on short-term interest rates. AEGCo's long-term debt interest rates varied daily until July 2001 when we chose to fix the rate at 4.05% for five years.
AEP GENERATING COMPANY Statements of Income Year Ended December 31, -------------------------------------- 2001 2000 1999 ---- ---- ---- (in thousands) OPERATING REVENUES: Sales to AEP Affiliates $227,338 $227,983 $152,559 Other 210 533 64,630 --- ----- --- -- ------ TOTAL OPERATING REVENUES 227,548 228,516 217,189 ------- - ------- - ------- OPERATING EXPENSES: Fuel 102,828 102,978 94,481 Rent - Rockport Plant Unit 2 68,283 68,283 68,283 Other Operation 11,025 10,295 10,451 Maintenance 8,853 9,616 10,492 Depreciation 22,423 22,162 21,845 Taxes Other Than Income Taxes 4,257 3,854 3,866 Income Taxes 2,902 2,904 2,431 ----- --- ----- --- ----- TOTAL OPERATING EXPENSES 220,571 220,092 211,849 ------- - ------- - ------- OPERATING INCOME 6,977 8,424 5,340 NONOPERATING INCOME 30 6 92 NONOPERATING EXPENSES 16 17 27 NONOPERATING INCOME TAX CREDITS 3,470 3,440 3,594 INTEREST CHARGES 2,586 3,869 2,804 ----- --- ----- --- ----- NET INCOME $7,875 $7,984 $6,195 ====== ====== ======
Statements of Retained Earnings Year Ended December 31, -------------------------------------- 2001 2000 1999 ---- ---- ---- (in thousands) RETAINED EARNINGS JANUARY 1 $ 9,722 $3,673 $2,770 NET INCOME 7,875 7,984 6,195 CASH DIVIDENDS DECLARED 3,836 1,935 5,292 ----- - ----- - ----- RETAINED EARNINGS DECEMBER 31 $13,761 $9,722 $3,673 ======= ====== ======
See Notes to Financial Statements beginning on page L-1. AEP GENERATING COMPANY Balance Sheets December 31, ------------------------ 2001 2000 ---- ---- (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production $638,297 $635,215 General 3,012 2,795 Construction Work in Progress 6,945 4,292 ----- ----- Total Electric Utility Plant 648,254 642,302 Accumulated Depreciation 337,151 315,566 ------- ------- NET ELECTRIC UTILITY PLANT 311,103 326,736 ------- ------- OTHER PROPERTY AND INVESTMENTS 119 6 --- - CURRENT ASSETS: Cash and Cash Equivalents 983 2,757 Accounts Receivable: Affiliated Companies 22,344 21,374 Miscellaneous 147 2,341 Fuel - at average cost 15,243 11,006 Materials and Supplies - at average cost 4,480 3,979 Prepayments 244 145 --- --- TOTAL CURRENT ASSETS 43,441 41,602 ------ ------ REGULATORY ASSETS 5,207 5,504 ----- ----- DEFERRED CHARGES 1,471 754 ----- --- TOTAL $361,341 $374,602 ======== ======== See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY December 31, ------------------------ 2001 2000 ---- ---- (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock - Par Value $1,000: Authorized and Outstanding - 1,000 Shares $1,000 $1,000 Paid-in Capital 23,434 23,434 Retained Earnings 13,761 9,722 ------ ----- Total Common Shareholder's Equity 38,195 34,156 Long-term Debt 44,793 - ------ ---- TOTAL CAPITALIZATION 82,988 34,156 ------ ------ OTHER NONCURRENT LIABILITIES 76 358 -- --- CURRENT LIABILITIES: Long-term Debt Due Within One Year - 44,808 Advances from Affiliates 32,049 28,068 Accounts Payable: General 7,582 6,109 Affiliated Companies 1,654 7,724 Taxes Accrued 4,777 4,993 Rent Accrued - Rockport Plant Unit 2 4,963 4,963 Other 3,481 4,443 ----- ----- Total CURRENT LIABILITIES 54,506 101,108 ------ ------- DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2 116,617 122,188 ------- ------- REGULATORY LIABILITIES: Deferred Investment Tax Credits 56,304 59,718 Amounts Due to Customers for Income Taxes 22,725 23,996 ------ ------ Total REGULATORY LIABILITIES 79,029 83,714 ------ ------ DEFERRED INCOME TAXES 27,975 32,928 ------ ------ DEFERRED CREDITS 150 150 --- --- CONTINGENCIES (Note 8) TOTAL $361,341 $374,602 ======== ========
See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY Statements of Cash Flows Year Ended December 31, -------------------------------------- 2001 2000 1999 ---- ---- ---- (in thousands) OPERATING ACTIVITIES: Net Income $7,875 $7,984 $6,195 Adjustments for Noncash Items: Depreciation 22,423 22,162 21,845 Deferred Federal Income Taxes (6,224) (5,842) (5,282) Deferred Investment Tax Credits (3,414) (3,396) (3,448) Amortization of Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2 (5,571) (5,571) (5,571) Change in Certain Current Assets and Liabilities: Accounts Receivable 1,224 1,392 (2,213) Fuel, Materials and Supplies (4,738) 6,486 (6,263) Accounts Payable (4,597) (13,157) 14,394 Taxes Accrued (216) 708 1,058 Other Assets (569) 1,636 (6) Other Liabilities (1,244) (404) (1,564) ------ ---- ------ Net Cash Flows From Operating Activities 4,949 11,998 19,145 ----- ------ ------ INVESTING ACTIVITIES: Construction Expenditures (6,868) (5,190) (8,349) Proceeds From Sales of Property - - 331 ---- ---- --- Net Cash Flows Used For Investing Activities (6,868) (5,190) (8,018) ------ ------ ------ FINANCING ACTIVITIES: Return of Capital to Parent Company - (5,801) (6,000) Change in Short-term Debt (net) - (24,700) 250 Change in Advances From Affiliates (net) 3,981 28,068 - Dividends Paid (3,836) (1,935) (5,292) ------ ------ ------ Net Cash Flows From (Used For) Financing Activities 145 (4,368) (11,042) --- ------ ------- Net Increase (Decrease) in Cash and Cash Equivalents (1,774) 2,440 85 Cash and Cash Equivalents January 1 2,757 317 232 ----- --- --- Cash and Cash Equivalents December 31 $ 983 $2,757 $ 317 =====- ====== =====
Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $1,509,000, $3,531,000 and $2,468,000 and for income taxes was $8,597,000, $6,820,000 and $6,565,000 in 2001, 2000 and 1999, respectively. See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY Statements of Capitalization December 31, 2001 2000 ---- ---- (in thousands) COMMON STOCK EQUITY (a) $38,195 $ 34,156 ------- -------- LONG-TERM DEBT Installment Purchase Contracts - City of Rockport (b) Series Due Date 1995 A, 2025 (c) 22,500 22,500 1995 B, 2025 (c) 22,500 22,500 Unamortized Discount (207) (192) Amount Due Within One Year - (44,808) ---- - ------- Long-term Debt Excluding Amount Due Within One Year 44,793 - ------ ---- ---- TOTAL CAPITALIZATION $82,988 $ 34,156 ======= ========
(a) In 2000 and 1999, AEGCo returned capital to AEP in the amounts of $5.8 million and $6 million, respectively. There were no other material transactions affecting common stock and paid-in capital in 2001, 2000 and 1999. (b)Installment purchase contracts were entered into in connection with the issuance of pollution control revenue bonds by the City of Rockport, Indiana. The terms of the installment purchase contracts require AEGCo to pay amounts sufficient to enable the payment of interest and principal on the related pollution control revenue bonds issued to refinance the construction costs of pollution control facilities at the Rockport Plant. (c) These series have an adjustable interest rate that can be a daily, weekly, commercial paper or term rate as designated by AEGCo. Prior to July 13, 2001, AEGCo selected a daily rate which ranged from 0.9% to 5.6% during 2001 and from 1.65% to 6.1% during 2000 and averaged 2.8% in 2001 and 4.1% in 2000. Effective July 13, 2001, AEGCo selected a term rate of 4.05% for five years ending July 12, 2006. The interest rates were 5% for Series A and 4.9% for Series B at December 31, 2000. See Notes to Financial Statements beginning on page L-1. AEP GENERATING COMPANY Index to Notes to Financial Statements The notes to AEGCo's financial statements are combined with the notes to financial statements for AEP and its other subisidiary registrants. Listed below are the combined notes that apply to AEGCo. The combined footnotes begin on page L-1. Combined Footnote Reference Significant Accounting Policies Note 1 Effects of Regulation Note 6 Commitments and Contingencies Note 8 Business Segments Note 12 Risk Management, Financial Instruments and Derivatives Note 13 Income Taxes Note 14 Leases Note 18 Lines of Credit and Sale of Receivables Note 19 Unaudited Quarterly Financial Information Note 20 Related Party Transactions Note 24 INDEPENDENT AUDITORS' REPORT To the Shareholder and Board of Directors of AEP Generating Company: We have audited the accompanying balance sheets and statements of capitalization of AEP Generating Company as of December 31, 2001 and 2000, and the related statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such financial statements present fairly, in all material respects, the financial position of AEP Generating Company as of December 31, 2001 and 2000, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America. Deloitte & Touche LLP Columbus, Ohio February 22, 2002 APPALACHIAN POWER COMPANY AND SUBSIDIARIES
APPALACHIAN POWER COMPANY AND SUBSIDIARIES Selected Consolidated Financial Data Year Ended December 31, 2001 2000 1999 1998 1997 ---- ---- ---- ---- ---- (in thousands) INCOME STATEMENTS DATA: Operating Revenues $6,999,430 $5,087,308 $3,970,647 $3,291,385 $1,720,010 Operating Expenses 6,724,444 4,886,154 3,729,411 3,062,842 1,480,016 --------- --------- --------- --------- --------- Operating Income 274,986 201,154 241,236 228,543 239,994 Nonoperating Income (Loss) 6,868 11,752 8,096 (8,301) (222) Interest Charges 120,036 148,000 128,840 126,912 119,258 ------- ------- ------- ------- ------- Income Before Extraordinary Item 161,818 64,906 120,492 93,330 120,514 Extraordinary Gain - 8,938 - - - ---- ----- ---- --------- ---- Net Income 161,818 73,844 120,492 93,330 120,514 Preferred Stock Dividend Requirements 2,011 2,504 2,706 2,497 7,006 ----- ----- ----- ----- ----- Earnings Applicable to Common Stock $159,807 $ 71,340 $117,786 $ 90,833 $113,508 ======== ======== ======== ======== ======== December 31, 2001 2000 1999 1998 1997 ---- ---- ---- ---- ---- (in thousands) BALANCE SHEETS DATA: Electric Utility Plant $5,664,657 $5,418,278 $5,262,951 $5,087,359 $4,901,046 Accumulated Depreciation and Amortization 2,296,481 2,188,796 2,079,490 1,984,856 1,869,057 --------- --------- --------- --------- --------- Net Electric Utility Plant $3,368,176 $3,229,482 $3,183,461 $3,102,503 $3,031,989 ========== ========== ========== ========== ========== Total Assets $5,107,938 $6,633,724 $4,354,400 $4,047,038 $3,883,430 ========== ========== ========== ========== ========== Common Stock and Paid-in Capital $976,244 $975,676 $974,717 $924,091 $873,506 Accumulated Other Comprehensive Income (Loss) (340) - - - - Retained Earnings 150,797 120,584 175,854 179,461 207,544 ------- ------- ------- ------- ------- Total Common Shareholder's Equity $1,126,701 $1,096,260 $1,150,571 $1,103,552 $1,081,050 ========== ========== ========== ========== ========== Cumulative Preferred Stock: Not Subject to Mandatory Redemption $ 17,790 $ 17,790 $ 18,491 $ 19,359 $ 19,747 Subject to Mandatory Redemption 10,860 10,860 20,310 22,310 22,310 ------ ------ ------ ------ ------ Total Cumulative Preferred Stock $ 28,650 $ 28,650 $ 38,801 $ 41,669 $ 42,057 ======== ======== ======== ======== ======== Long-term Debt (a) $1,556,559 $1,605,818 $1,665,307 $1,552,455 $1,494,535 ========== ========== ========== ========== ========== Obligations Under Capital Leases (a) $ 46,285 $ 63,160 $ 64,645 $ 65,175 $ 60,110 ======== ======== ======== ======== ======== Total Capitalization And Liabilities $5,107,938 $6,633,724 $4,354,400 $4,047,038 $3,883,430 ========== ========== ========== ========== ========== (a) Including portion due within one year.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES Management's Discussion and Analysis of Results of Operations APCo is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to 917,000 retail customers in southwestern Virginia and southern West Virginia. APCo as a member of the AEP Power Pool shares in the revenues and costs of the AEP Power Pool's wholesale sales to neighboring utility systems and power marketers including power trading transactions. APCo also sells wholesale power to municipalities. The cost of the AEP Power Pool's generating capacity is allocated among the Pool members based on their relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity credits. AEP Power Pool members are also compensated for their out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each company's prior twelve month peak demand relative to the total peak demand of all member companies as a basis for sharing revenues and costs. The result of this calculation is the member load ratio (MLR) which determines each company's percentage share of revenues and costs. Critical Accounting Policies - Revenue Recognition Regulatory Accounting - As a result of our cost-based rate-regulated transmission and distribution operations, our financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate regulated. In accordance with SFAS 71, regulatory assets (deferred expenses) and regulatory liabilities (future revenue reductions or refunds) are recorded to reflect the economic effects of regulation by matching expenses with their recovery through regulated revenues in the same accounting period. When regulatory assets are probable of recovery through regulated rates, we record them as assets on the balance sheet. We test for probability of recovery whenever new events occur, for example a regulatory commission order or passage of new legislation. If we determine that recovery of a regulatory asset is no longer probable, we write off that regulatory asset as a charge against net income. A write off of regulatory assets may also reduce future cash flows since there may be no recovery through regulated rates. Traditional Electricity Supply and Delivery Activities - We recognize revenues on an accrual basis for electricity supply sales and electricity transmission and distribution delivery services. The revenues are recognized in our income statement when the energy is delivered to the customer and include unbilled as well as billed amounts. In general expenses are recorded when incurred. Energy Marketing and Trading Activities - AEP engages in wholesale electricity marketing and trading transactions (trading activities). A portion of the revenues and costs of AEP's trading activities are allocated to APCo as a member of the AEP Power Pool. Trading activities involve the purchase and sale of energy under physical forward contracts at fixed and variable prices and buying and selling financial energy contracts which includes exchange traded futures and options and over-the-counter options and swaps. Although trading contracts are generally short-term, there are also long-term trading contracts. We recognize revenues from trading activities generally based on changes in the fair value of energy trading contracts. Recording the net change in the fair value of trading contracts prior to settlement is commonly referred to as mark-to-market (MTM) accounting. It represents the change in the unrealized gain or loss throughout the contract's term. When the contract actually settles, that is, the energy is actually delivered in a sale or received in a purchase or the parties agree to forego delivery and receipt of electricity and net settle in cash, the unrealized gain or loss is reversed and the actual realized cash gain or loss is recognized. Therefore, over the trading contract's term an unrealized gain or loss is recognized as the contract's market value changes. When the contract settles the total gain or loss is realized in cash but only the difference between the accumulated unrealized net gains or losses recorded in prior months and the cash proceeds is recognized. Unrealized mark-to-market gains and losses are included in the Balance Sheet as energy trading contract assets or liabilities as appropriate. The majority of our trading activities represent physical forward electricity contracts that are typically settled by entering into offsetting contracts. An example of our trading activities is when, in January, we enter into a forward sales contract to deliver electricity in July. At the end of each month until the contract settles in July, we would record our share of any difference between the contract price and the market price as an unrealized gain or loss. In July when the contract settles, we would realize our share of the gain or loss in cash and reverse the previously recorded unrealized gain or loss. Depending on whether the delivery point for the electricity is in AEP's traditional marketing area or not determines where the contract is reported on APCo's income statement. AEP's traditional marketing area is up to two transmission systems from the AEP service territory. Physical forward trading sale contracts with delivery points in AEP's traditional marketing area are included in revenues when the contracts settle. Physical forward trading purchase contracts with delivery points in AEP's traditional marketing area are included in purchased power expense when they settle. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts in AEP's traditional marketing area are included in revenues on a net basis. Physical forward sales contracts for delivery outside of AEP's traditional marketing area are included in nonoperating income when the contract settles. Physical forward purchase contracts for delivery outside of AEP's traditional marketing area are included in nonoperating expenses when the contract settles. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts with delivery points outside of AEP's traditional marketing area are included in nonoperating income on a net basis. Continuing with the above example, assume that later in January or sometime in February through July we enter into an offsetting forward contract to buy electricity in July. If we do nothing else with these contracts until settlement in July and if the volumes, delivery point, schedule and other key terms match then the difference between the sale price and the purchase price represents a fixed value to be realized when the contracts settle in July. If the purchase contract is perfectly matched with the sales contract, we have effectively fixed the profit or loss; specifically it is the difference between the contracted settlement price of the two contracts. Mark-to-market accounting for these contracts will have no further impact on results of operations but will have an offsetting and equal effect on trading contract assets and liabilities. Of course we could also do similar transactions but enter into a purchase contract prior to entering into a sales contract. If the sale and purchase contracts do not match exactly as to volumes, delivery point, schedule and other key terms, then there could be continuing mark-to-market effects on results of operations from recording additional changes in fair values using mark-to-market accounting. Trading of electricity options, futures and swaps, represents financial transactions with unrealized gains and losses from changes in fair values reported net in nonoperating income until the contracts settle. When these financial contracts settle, we record our share of the net proceeds in nonoperating income and reverse to nonoperating income the prior unrealized gain or loss. The fair value of open short-term trading contracts are based on exchange prices and broker quotes. We mark-to-market open long-term trading contracts based mainly on AEP-developed valuation models. These models estimate future energy prices based on existing market and broker quotes and supply and demand market data and assumptions. The fair values determined are reduced by reserves to adjust for credit risk and liquidity risk. Credit risk is the risk that the counterparty to the contract will fail to perform or fail to pay amounts due AEP. Liquidity risk represents the risk that imperfections in the market will cause the price to be less than or more than what the price should be based purely on supply and demand. There are inherent risks related to the underlying assumptions in models used to fair value open long-term trading contracts. AEP has independent controls to evaluate the reasonableness of our valuation models. However, energy markets, especially electricity markets, are imperfect and volatile and unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a contract's term and when contracts settle. Therefore, there could be significant adverse or favorable effects on future results of operations and cash flows if market prices do not correlate with the AEP-developed price models. Volatility in commodities markets affects the fair values of all of our open trading contracts exposing APCo to market risk. See "Market Risks" section of MD&A for a discussion of the policies and procedures used to manage exposure to risk from trading activities. Results of Operations Net Income Net income increased $88 million or 119% in 2001 primarily due to the effect of a court decision related to a corporate owned life insurance (COLI) program recorded in 2000. In February 2001 the U.S. District Court for the Southern District of Ohio ruled against AEP and certain of its subsidiaries, including APCo, in a suit over deductibility of interest claimed in AEP's consolidated tax return related to COLI. In 1998 and 1999 APCo paid the disputed taxes and interest attributable to the COLI interest deductions for taxable years 1991-98. The payments were included in Other Property and Investments pending the resolution of this matter. Also contributing to the increase in net income was growth in and strong performance by the wholesale marketing and trading business in the first half of 2001 offset in part by the effect of extremely mild November and December weather combined with weak economic conditions which reduced retail energy sales. The adverse court decision on COLI caused the $47 million decrease in 2000's net income. Income before extraordinary items decreased $56 million or 46% in 2000 primarily due to the COLI decision. An extraordinary gain from the discontinuance of SFAS 71 regulatory accounting of $9 million after tax was recorded in June 2000. (See Note 2, "Extraordinary Items and Cumulative Effect".) Operating Revenues Operating revenues increased 38% in 2001 and 28% in 2000 mainly due to a significant increase in wholesale marketing and trading volume. The changes in the components of revenues were as follows: Increase (Decrease) From Previous Year (dollars in millions) 2001 2000 --------------------------- Amount % Amount % Retail* $ (38.9) (5) $ 2 N.M. Wholesale Marketing and Trading 1,859.1 52 1,091.2 44 Unrealized MTM 46.3 272 (22.0) N.M. Other 8.9 14 (18.2) (22) -------- -------- Total Marketing and Trading 1,875.4 43 1,053.0 32 Energy Delivery* 20.1 3 9.3 2 Sales to AEP Affiliates 16.6 11 54.4 54 -------- -------- Total Revenues $1,912.1 38 $1,116.7 28 ======== ======== N.M. = Not Meaningful *Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery. Wholesale marketing and trading revenues increased significantly in 2001 and 2000 as a result of an increase in electric marketing and trading volume (39% in 2001 and 42% in 2000). The maturing of the Intercontinental Exchange, the development of proprietary tools, and increased staffing of energy traders have resulted in an increase in the number of forward electricity purchase and sale contracts in AEP's traditional marketing area. While wholesale marketing and trading volumes rose, kilowatthour sales to industrial customers decreased in 2001. This decrease was due to the economic recession. Also, in the fourth quarter, sales to residential and commercial customers declined. The recession reduced demand, especially, in the fourth quarter. The increase in sales to AEP affiliates in 2000 is due to a significant increase in AEP Power Pool transactions. As the quantity of energy sold by the AEP Power Pool rose, APCo's contribution of energy to the Pool rose, accounting for the increase in APCo's revenues from sales to AEP affiliates. The AEP Power Pool was able to make additional sales to third parties in 2000 as a result of an affiliated company's major industrial customer's decision not to continue its purchased power agreement. Operating Expenses The increase in operating expenses in 2001 of 38% is due to increases in electricity marketing and trading expense and depreciation and amortization expenses partially offset by decreases in income taxes, other operation expense and fuel expenses. Operating expenses increased 31% in 2000 due to an increase in electricity marketing and trading expense, power purchases from AEP affiliates, other operation expense and income taxes offset in part by a decrease in fuel expense. Changes in the components of operating expenses are as follows: Increase (Decrease) From Previous Year (dollars in millions) 2001 2000 ----------------------------- Amount % Amount % Fuel $ (17.6) (5) $ (75.6) (17) Marketing and Trading Purchases 1,904.7 57 906.4 37 AEP Affiliate Purchases (8.9) (3) 224.8 172 Other Operation (18.8) (7) 33.0 13 Maintenance 7.9 6 0.7 1 Depreciation and Amortization 17.3 11 14.2 10 Taxes Other Than Income Taxes (11.8)(11) (1.0) (1) Income Taxes (34.5)(27) 54.2 72 -------- -------- Total $1,838.3 38 $1,156.7 31 ======== ======== The decrease in fuel expense in 2001 is due to a decline in generation as a result of scheduled plant maintenance. Fuel expense decreased in 2000 due to the combined effect of the discontinuance of deferral accounting for over or under recovery of fuel costs in the West Virginia jurisdiction effective January 1, 2000 under the terms of a rate settlement agreement and a decline in generation due to scheduled plant maintenance. Electricity marketing and trading purchased power expense increased substantially in 2001 and 2000 due to increases in trading volume and wholesale electricity prices. Purchased power from AEP affiliates decreased in 2001 as the result of a decrease in AEP Power Pool capacity charges due to a reduction in APCo's MLR. The significant increase in purchased power from AEP affiliates in 2000 reflects additional purchases of power from the AEP Power Pool as a result of increased availability of generation. The AEP Power Pool was able to supply more power to APCo since an affiliate's nuclear unit returned to service in June 2000, a major industrial customer discontinued purchasing power from an affiliate in January 2000, and generating unit outage management improved. Other operation expense decreased in 2001 mainly due to the effect of AEPSC billings in 2000 for the disallowance of the COLI program interest deduction. Additionally, the decrease was the result of a gain recorded on the disposition of SO2 emission allowances offset in part by increased wholesale power trading incentive compensation expense. The increase in other operation expense in 2000 was due to increased wholesale marketing and trading costs including increased accruals for incentive compensation, increased use of emission allowances due to stricter air quality standards of Phase II of the 1990 Clean Air Act Amendments which became effective January 1, 2000 and AEPSC billings for the COLI disallowance. During June 2000 we discontinued the application of SFAS 71 in the Virginia and West Virginia jurisdictions. Consequently net generation-related regulatory assets were transferred to the energy delivery business' regulated distribution business where the Virginia and West Virginia jurisdictions authorized the recovery of these transition regulatory assets through regulated rates. Depreciation and amortization expense increased in 2001 and 2000 due to accelerated amortization, beginning in July 2000, of the transition regulatory assets. Additional investments in the energy delivery business' distribution and transmission plant also contributed to the increases in depreciation and amortization expense. The decrease in taxes other than income taxes in 2001 is due to the elimination of the Virginia gross receipts tax as a result of a tax law change due to deregulation in that state. Income taxes attributable to operations decreased in 2001 due to the effect of the disallowance of COLI interest deductions in 2000 offset in part by an increase in pre-tax operating income. The increase in income taxes attributable to operations in 2000 was due to the disallowance of COLI interest deductions. Nonoperating Income and Nonoperating Expenses The increase in nonoperating income and nonoperating expenses for both 2001 and 2000 is due to considerable increases in the wholesale business' trading transactions outside of the AEP System's traditional marketing area. Interest Charges Interest charges decreased in 2001 primarily due to the effect of recognizing in 2000 previously deferred interest payments to the IRS related to the COLI disallowances and interest on resultant state income tax deficiencies. Additionally, the decrease in 2001 is due to the retirement of first mortgage bonds in 2000. The increase in interest charges in 2000 was due to the recognition of deferred interest payments related to the COLI disallowances and interest on the resultant prior years state income taxes. Extraordinary Gain The extraordinary gain recorded in June 2000 was the result of the discontinuance of SFAS 71 for the generation portion of APCo's business.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Income Year Ended December 31, ------------------------------------------- 2001 2000 1999 ---- ---- ---- (in thousands) OPERATING REVENUES: Electricity Marketing and Trading $6,233,109 $4,357,712 $3,304,755 Energy Delivery 595,036 574,918 565,660 Sales to AEP Affiliates 171,285 154,678 100,232 ------- ------- ------- Total Operating Revenues 6,999,430 5,087,308 3,970,647 --------- --------- --------- OPERATING EXPENSES: Fuel 351,557 369,161 444,711 Purchased Power: Electricity Marketing and Trading 5,253,983 3,349,279 2,442,819 AEP Affiliates 346,878 355,774 130,991 Other Operation 263,798 282,610 249,616 Maintenance 132,373 124,493 123,834 Depreciation and Amortization 180,393 163,089 148,874 Taxes Other Than Income Taxes 99,878 111,692 112,722 Income Taxes 95,584 130,056 75,844 ------ ------- ------ Total Operating Expenses 6,724,444 4,886,154 3,729,411 --------- --------- --------- OPERATING INCOME 274,986 201,154 241,236 NONOPERATING INCOME 2,320,649 1,415,530 684,080 NONOPERATING EXPENSES 2,312,642 1,400,655 675,793 NONOPERATING INCOME TAX EXPENSE 1,139 3,123 191 INTEREST CHARGES 120,036 148,000 128,840 ------- ------- ------- INCOME BEFORE EXTRAORDINARY ITEM 161,818 64,906 120,492 EXTRAORDINARY GAIN - DISCONTINUANCE OF REGULATORY ACCOUNTING FOR GENERATION (Inclusive of Tax Benefit of $7,872,000) - 8,938 - ---- ----- ---- NET INCOME 161,818 73,844 120,492 PREFERRED STOCK DIVIDEND REQUIREMENTS 2,011 2,504 2,706 ----- ----- ----- EARNINGS APPLICABLE TO COMMON STOCK $159,807 $ 71,340 $117,786 ======== ======== ========
Consolidated Statements of Comprehensive Income Year Ended December 31, ------------------------------------------- 2001 2000 1999 ---- ---- ---- (in thousands) NET INCOME $161,818 $73,844 $120,492 OTHER COMPREHENSIVE INCOME (LOSS) Foreign Currency Exchange Rate Hedge (340) - - ---- ---- ---- COMPREHENSIVE INCOME $161,478 $73,844 $120,492 ======== ======= ========
See Notes to Financial Statements beginning on page L-1. APPALACHIAN POWER COMPANY AND SUBSIDIARIES Consolidated Balance Sheets December 31, ------------------------ 2001 2000 ---- ---- (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production $2,093,532 $2,058,952 Transmission 1,222,226 1,177,079 Distribution 1,887,020 1,816,925 General 257,957 254,371 Construction Work in Progress 203,922 110,951 ------- ------- Total Electric Utility Plant 5,664,657 5,418,278 Accumulated Depreciation and Amortization 2,296,481 2,188,796 --------- --------- NET ELECTRIC UTILITY PLANT 3,368,176 3,229,482 --------- --------- OTHER PROPERTY AND INVESTMENTS 53,736 56,967 ------ ------ LONG-TERM ENERGY TRADING CONTRACTS 316,249 322,038 ------- ------- CURRENT ASSETS: Cash and Cash Equivalents 13,663 5,847 Advances to Affiliates - 8,387 Accounts Receivable: Customers 113,371 243,298 Affiliated Companies 63,368 63,919 Miscellaneous 11,847 16,179 Allowance for Uncollectible Accounts (1,877) (2,588) Fuel - at average cost 56,699 39,076 Materials and Supplies - at average cost 59,849 57,515 Accrued Utility Revenues 30,907 66,499 Energy Trading Contracts 566,284 2,024,222 Prepayments 16,018 6,307 ------ ----- TOTAL CURRENT ASSETS 930,129 2,528,661 ------- --------- REGULATORY ASSETS 397,383 447,750 ------- ------- DEFERRED CHARGES 42,265 48,826 ------ ------ TOTAL $5,107,938 $6,633,724 ========== ========== See Notes to Financial Statements beginning on page L-1. APPALACHIAN POWER COMPANY AND SUBSIDIARIES December 31, ------------------------ 2001 2000 ---- ---- (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock - No Par Value: Authorized - 30,000,000 Shares Outstanding - 13,499,500 Shares $260,458 $260,458 Paid-in Capital 715,786 715,218 Accumulated Other Comprehensive Income (Loss) (340) - Retained Earnings 150,797 120,584 ------- ------- Total Common Shareholder's Equity 1,126,701 1,096,260 Cumulative Preferred Stock: Not Subject to Mandatory Redemption 17,790 17,790 Subject to Mandatory Redemption 10,860 10,860 Long-term Debt 1,476,552 1,430,812 --------- --------- TOTAL CAPITALIZATION 2,631,903 2,555,722 --------- --------- OTHER NONCURRENT LIABILITIES 84,104 105,883 ------ ------- CURRENT LIABILITIES: Long-term Debt Due Within One Year 80,007 175,006 Short-term Debt - 191,495 Advances From Affiliates 291,817 - Accounts Payable - General 131,387 153,422 Accounts Payable - Affiliated Companies 84,518 107,556 Taxes Accrued 55,583 63,258 Customer Deposits 13,177 12,612 Interest Accrued 21,770 21,555 Energy Trading Contracts 549,703 2,080,025 Other 75,299 85,378 ------ ------ Total CURRENT LIABILITIES 1,303,261 2,890,307 --------- --------- DEFERRED INCOME TAXES 703,575 682,474 ------- ------- DEFERRED INVESTMENT TAX CREDITS 38,328 43,093 ------ ------ LONG-TERM ENERGY TRADING CONTRACTS 257,129 258,788 ------- ------- REGULATORY LIABILITIES AND DEFERRED CREDITS 89,638 97,457 ------ ------ COMMITMENTS AND CONTINGENCIES (Note 8) TOTAL $5,107,938 $6,633,724 ========== ========== See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Cash Flows Year Ended December 31, ---------------------------------------- 2001 2000 1999 ---- ---- ---- (in thousands) OPERATING ACTIVITIES: Net Income $ 161,818 $73,844 $ 120,492 Adjustments for Noncash Items: Depreciation and Amortization 180,505 163,202 149,791 Deferred Federal Income Taxes 42,498 8,602 13,033 Deferred Investment Tax Credits (4,765) (4,915) (4,972) Deferred Power Supply Costs (net) 1,411 (84,408) 35,955 Mark-to-Market of Energy Trading Contracts (68,254) (1,843) (8,939) Provision for Rate Refunds - (4,818) 4,818 Extraordinary Gain - (8,938) - Change in Certain Current Assets and Liabilities: Accounts Receivable (net) 134,099 (166,911) 10,989 Fuel, Materials and Supplies (19,957) 18,487 (4,812) Accrued Utility Revenues 35,592 (13,081) (7,433) Accounts Payable (45,073) 159,369 (9,273) Taxes Accrued (7,675) 14,220 13,319 Revenue Refunds Accrued - 181 (95,267) Incentive Plan Accrued (2,451) 10,662 1,507 Disputed Tax and Interest Related to COLI - 72,440 (4,124) Change in Operating Reserves (5,358) (19,770) 7,451 Rate Stabilization Deferral - 75,601 - Change in Other Assets 19,418 (13,021) (8,669) Change in Other Liabilities (27,954) 9,817 (22,455) ------- ----- ------- Net Cash Flows From Operating Activities 393,854 288,720 191,411 ------- ------- ------- INVESTING ACTIVITIES: Construction Expenditures (306,046) (199,285) (211,416) Proceeds From Sales of Property and Other 1,182 159 19,296 Net Cost of Removal and Other (8,434) (7,500) (24,373) ------ ------ ------- Net Cash Flows Used For Investing Activities (313,298) (206,626) (216,493) -------- -------- -------- FINANCING ACTIVITIES: Capital Contributions from Parent Company - - 50,000 Issuance of Long-term Debt 124,588 74,788 227,236 Retirement of Cumulative Preferred Stock - (9,924) (2,675) Retirement of Long-term Debt (175,000) (136,166) (116,688) Change in Short-term Debt (net) (191,495) 68,015 47,080 Change in Advances From Affiliates 300,204 (8,387) - Dividends Paid on Common Stock (129,594) (126,612) (121,392) Dividends Paid on Cumulative Preferred Stock (1,443) (1,938) (2,257) ------ ------ ------ Net Cash Flows From (Used For) Financing Activities (72,740) (140,224) 81,304 ------- -------- ------ Net Increase (Decrease) in Cash and Cash Equivalents 7,816 (58,130) 56,222 Cash and Cash Equivalents January 1 5,847 63,977 7,755 ----- ------ ----- Cash and Cash Equivalents December 31 $13,663 $ 5,847 $63,977 ======= ======= =======
Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $117,283,000, $124,579,000 and $125,900,000 and for income taxes was $56,981,000, $63,682,000 and $55,157,000 in 2001, 2000 and 1999, respectively. Noncash acquisitions under capital leases were $2,510,000, $14,116,000 and $13,868,000 in 2001, 2000 and 1999, respectively. See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Retained Earnings Year Ended December 31, ----------------------------------------- 2001 2000 1999 ---- ---- ---- (in thousands) Retained Earnings January 1 $120,584 $175,854 $179,461 Net Income 161,818 73,844 120,492 ------- ------ ------- 282,402 249,698 299,953 ------- ------- ------- Deductions: Cash Dividends Declared: Common Stock 129,594 126,612 121,392 Cumulative Preferred Stock: 4-1/2% Series 801 811 850 5.90% Series 278 307 425 5.92% Series 364 364 364 6.85% Series - 289 579 ---- --- --- Total Cash Dividends Declared 131,037 128,383 123,610 Capital Stock Expense 568 731 489 --- --- --- Total Deductions 131,605 129,114 124,099 ------- ------- ------- Retained Earnings December 31 $150,797 $120,584 $175,854 ======== ======== ========
See Notes to Financial Statements Beginning on Page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Capitalization December 31, ----------------------------- 2001 2000 ---- ---- (in thousands) COMMON SHAREHOLDER'S EQUITY $1,126,701 $1,096,260 ---------- ---------- PREFERRED STOCK: No par value - authorized shares 8,000,000 Call Price Shares December 31, Number of Shares Redeemed Outstanding Series(a) 2001 (b) Year Ended December 31, December 31, 2001 - ------ ------------ ---------------------------- ----------------- 2001 2000 1999 ---- ---- ---- Not Subject to Mandatory Redemption: 4-1/2% $110 - 7,011 8,671 177,905 17,790 17,790 ---------- ---------- Subject to Mandatory Redemption: 5.90% (c) (d) - 10,000 20,000 47,100 4,710 4,710 5.92% (c) (d) - - - 61,500 6,150 6,150 ---------- ---------- 10,860 10,860 ---------- ---------- LONG-TERM DEBT (See Schedule of Long-term Debt): First Mortgage Bonds 639,365 739,015 Installment Purchase Contracts 234,904 234,782 Senior Unsecured Notes 518,247 468,113 Junior Debentures 161,507 161,367 Other Long-term Debt 2,536 2,541 Less Portion Due Within One Year (80,007) (175,006) ---------- ---------- Long-term Debt Excluding Portion Due Within One Year 1,476,552 1,430,812 ---------- ---------- TOTAL CAPITALIZATION $2,631,903 $2,555,722 ========== ==========
(a) The sinking fund provisions of each series subject to mandatory redemption have been met by purchase of shares in advance of the due date. APCo redeemed 84,500 shares of the 6.85% series of preferred stock subject to mandatory redemption in 2000. (b) The cumulative preferred stock is callable at the price indicated plus accrued dividends. The involuntary liquidation preference is $100 per share. The aggregate involuntary liquidation price for all shares of cumulative preferred stock may not exceed $300 million. The unissued shares of the cumulative preferred stock may or may not possess mandatory redemption characteristics upon issuance. (c) Commencing in 2003 and continuing through 2007 APCo may redeem at $100 per share 25,000 shares of the 5.90% series and 30,000 shares of the 5.92% series outstanding under sinking fund provisions at its option and all outstanding shares must be reacquired in 2008. Shares previously redeemed may be applied to meet the sinking fund requirement. (d) Not callable until after 2002. See Notes to Financial Statements beginning on page L-1. APPALACHIAN POWER COMPANY AND SUBSIDIARIES Schedule of Long-term Debt First mortgage bonds outstanding were as follows: December 31, -------------------- 2001 2000 ---- ---- (in thousands) % Rate Due 6-3/8 2001 - March 1 $ - $100,000 7.38 2002 - August 15 50,000 50,000 7.40 2002 - December 1 30,000 30,000 6.65 2003 - May 1 40,000 40,000 6.85 2003 - June 1 30,000 30,000 6.00 2003 - November 1 30,000 30,000 7.70 2004 - September 1 21,000 21,000 7.85 2004 - November 1 50,000 50,000 8.00 2005 - May 1 50,000 50,000 6.89 2005 - June 22 30,000 30,000 6.80 2006 - March 1 100,000 100,000 8.50 2022 - December 1 70,000 70,000 7.80 2023 - May 1 30,237 30,237 7.15 2023 - November 1 20,000 20,000 7.125 2024 - May 1 45,000 45,000 8.00 2025 - June 1 45,000 45,000 Unamortized Discount (1,872) (2,222) -------- -------- Total $639,365 $739,015 ======== ======== First mortgage bonds are secured by first mortgage liens on electric utility plant. Certain indentures relating to the first mortgage bonds contain improvement, maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. Installment purchase contracts have been entered into, in connection with the issuance of pollution control revenue bonds by governmental authorities as follows: December 31, 2001 2000 ---- ---- (in thousands) % Rate Due Industrial Development Authority of Russell County, Virginia: 7.70 2007 - November 1 $ 17,500 $ 17,500 5.00 2021 - November 1 19,500 19,500 Putnam County, West Virginia: 5.45 2019 - June 1 40,000 40,000 6.60 2019 - July 1 30,000 30,000 Mason County, West Virginia: 7-7/8 2013 - November 1 10,000 10,000 6.85 2022 - June 1 40,000 40,000 6.60 2022 - October 1 50,000 50,000 6.05 2024 - December 1 30,000 30,000 Unamortized Discount (2,096) (2,218) -------- -------- Total $234,904 $234,782 ======== ======== Under the terms of the installment purchase contracts, APCo is required to pay amounts sufficient to enable the payment of interest on and the principal (at stated maturities and upon mandatory redemptions) of related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants. Senior unsecured notes outstanding were as follows: December 31, 2001 2000 ---- ---- (in thousands) % Rate Due (a) 2001 - June 27 $ - $ 75,000 (a) 2003 - August 20 125,000 - 7.45 2004 - November 1 50,000 50,000 6.60 2009 - May 1 150,000 150,000 7.20 2038 - March 31 100,000 100,000 7.30 2038 - June 30 100,000 100,000 Unamortized Discount (6,753) (6,887) -------- -------- Total $518,247 $468,113 ======== ======== (a) A floating interest rate is determined monthly. The rate on December 31, 2001 and 2000 was 2.839% and 6.95%, respectively. Junior debentures outstanding were as follows: December 31, 2001 2000 ---- ---- (in thousands) 8-1/4% Series A due 2026 - September 30 $ 75,000 $ 75,000 8% Series B due 2027 - March 31 90,000 90,000 Unamortized Discount (3,493) (3,633) -------- -------- Total $161,507 $161,367 ======== ======== Interest may be deferred and payment of principal and interest on the junior debentures is subordinated and subject in right to the prior payment in full of all senior indebtedness of the Company. At December 31, 2001, future annual long-term debt payments are as follows: Amount ------ (in thousands) 2002 $ 80,007 2003 225,007 2004 121,008 2005 80,010 2006 100,011 Later Years 964,730 ---------- Total Principal Amount 1,570,773 Unamortized Discount (14,214) ---------- Total $1,556,559 ========== APPALACHIAN POWER COMPANY AND SUBSIDIARIES Index to Notes to Consolidated Financial Statements The notes to APCo's financial statements are combined with the notes to financial statements for AEP and its other subsidiary registrants. Listed below are the combined notes that apply to APCo. The combined footnotes begin on page L-1. Combined Footnote Reference Significant Accounting Policies Note 1 Extraordinary Items and Cumulative Effect Note 2 Rate Matters Note 5 Effects of Regulation Note 6 Customer Choice and Industry Restructuring Note 7 Commitments and Contingencies Note 8 Benefit Plans Note 10 Business Segments Note 12 Risk Management, Financial Instruments and Derivatives Note 13 Income Taxes Note 14 Supplementary Information Note 16 Leases Note 18 Lines of Credit and Sale of Receivables Note 19 Unaudited Quarterly Financial Information Note 20 Related Party Transactions Note 24 INDEPENDENT AUDITORS' REPORT To the Shareholders and Board of Directors of Appalachian Power Company: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Appalachian Power Company and its subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of income, comprehensive income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Appalachian Power Company and its subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America. DELOITTE & TOUCHE LLP Columbus, Ohio February 22, 2002 CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES Selected Consolidated Financial Data Year Ended December 31, 2001 2000 1999 1998 1997 ---- ---- ---- ---- ---- (in thousands) INCOME STATEMENTS DATA: Operating Revenues $3,321,727 $2,349,503 $1,482,475 $1,406,117 $1,376,282 Operating Expenses 3,025,996 2,042,405 1,188,490 1,123,330 1,124,963 --------- --------- --------- --------- --------- Operating Income 295,731 307,098 293,985 282,787 251,319 Nonoperating Income (Loss) 5,324 7,235 8,113 760 8,277 Interest Charges 116,268 124,766 114,380 122,036 131,173 ------- ------- ------- ------- ------- Income Before Extraordinary Item 184,787 189,567 187,718 161,511 128,423 Extraordinary Loss (2,509) - (5,517) - - ------ ---- ------ ---- ---- Net Income 182,278 189,567 182,201 161,511 128,423 Preferred Stock Dividend Requirements 242 241 6,931 6,901 9,523 Gain (Loss) on Reacquired Preferred Stock - - (2,763) - 2,402 ---- ---- ------ ---- ----- Earnings Applicable To Common Stock $182,036 $189,326 $172,507 $154,610 $121,302 ======== ======== ======== ======== ======== Year Ended December 31, 2001 2000 1999 1998 1997 ---- ---- ---- ---- ---- (in thousands) BALANCE SHEETS DATA: Electric Utility Plant $5,769,707 $5,592,444 $5,511,894 $5,336,191 $5,215,749 Accumulated Depreciation And Amortization 2,446,027 2,297,189 2,247,225 2,072,686 1,891,406 --------- --------- --------- --------- --------- Net Electric Utility Plant $3,323,680 $3,295,255 $3,264,669 $3,263,505 $3,324,343 ========== ========== ========== ========== ========== Total Assets $5,115,986 $5,467,684 $4,847,850 $4,735,476 $4,897,380 ========== ========== ========== ========== ========== Common Stock and Paid-in Capital $573,888 $573,888 $573,888 $573,888 $573,888 Retained Earnings 826,197 792,219 758,894 734,387 828,777 ------- ------- ------- ------- ------- Total Common Shareholder's Equity $1,400,085 $1,366,107 $1,332,782 $1,308,275 $1,402,665 ========== ========== ========== ========== ========== Preferred Stock $ 5,967 $ 5,967 $ 5,967 $163,204 $163,204 ======= ======= ======= ======== ======== CPL - Obligated, Mandatorily Redeemable Preferred Securities of Subsidiary Trust Holding Solely Junior Subordinated Dentures of CPL $136,250 $148,500 $150,000 $150,000 $150,000 ======== ======== ======== ======== ======== Long-term Debt (a) $1,253,768 $1,454,559 $1,454,541 $1,350,706 $1,414,335 ========== ========== ========== ========== ========== Total Capitalization And Liabilities $5,115,986 $5,467,684 $4,847,850 $4,735,476 $4,897,380 ========== ========== ========== ========== ==========
(a) Including portion due within one year. CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES Management's Discussion and Analysis of Results of Operations CPL is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to approximately 689,000 retail customers in southern Texas. CPL also sells electric power at wholesale to other utilities, municipalities and rural electric cooperatives. Wholesale power marketing and trading activities are conducted on CPL's behalf by AEP. CPL shares in the revenues and costs of the AEP Power Pool's wholesale sales to and forward trades with other utility systems and power marketers. Critical Accounting Policies - Revenue Recognition Regulatory Accounting - As a result of our cost-based rate-regulated transmission and distribution operations, our financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate regulated. In accordance with SFAS 71, regulatory assets (deferred expenses) and regulatory liabilities (future revenue reductions or refunds) are recorded to reflect the economic effects of regulation by matching expenses with their recovery through regulated revenues in the same accounting period. When regulatory assets are probable of recovery through regulated rates, we record them as assets on the balance sheet. We test for probability of recovery whenever new events occur, for example a regulatory commission order or passage of new legislation. If we determine that recovery of a regulatory asset is no longer probable, we write off that regulatory asset as a charge against net income. A write off of regulatory assets may also reduce future cash flows since there may be no recovery through regulated rates. Traditional Electricity Supply and Delivery Activities - We recognize revenues on an accrual basis for electricity supply sales and electricity transmission and distribution delivery services. The revenues are recognized in our income statement when the energy is delivered to the customer and include unbilled as well as billed amounts. In general expenses are recorded when incurred. Energy Marketing and Trading Activities - AEP engages in wholesale electricity marketing and trading transactions (trading activities). A portion of the revenues and costs of AEP's trading activities are allocated to CPL. Trading activities allocated to CPL involve the purchase and sale of energy under physical forward contracts at fixed and variable prices. Although trading contracts are generally short-term, there are also long-term trading contracts. We recognize revenues from trading activities generally based on changes in the fair value of energy trading contracts. Recording the net change in the fair value of trading contracts as revenues prior to settlement is commonly referred to as mark-to-market (MTM) accounting. It represents the change in the unrealized gain or loss throughout the contract's term. When the contract actually settles, that is, the energy is actually delivered in a sale or received in a purchase or the parties agree to forego delivery and receipt of electricity and net settle in cash, the unrealized gain or loss is reversed out of revenues and the actual realized cash gain or loss is recognized in revenues for a sale or in purchased power expense for a purchase. Therefore, over the trading contract's term an unrealized gain or loss is recognized as the contract's market value changes. When the contract settles the total gain or loss is realized in cash but only the difference between the accumulated unrealized net gains or losses recorded in prior months and the cash proceeds is recognized. Unrealized mark-to-market gains and losses are included in the Balance Sheet as energy trading contract assets or liabilities as appropriate. Our trading activities represent physical forward electricity contracts that are typically settled by entering into offsetting contracts. An example of our trading activities is when, in January, we enter into a forward sales contract to deliver electricity in July. At the end of each month until the contract settles in July, we would record our share of any difference between the contract price and the market price as an unrealized gain or loss in revenues. In July when the contract settles, we would realize our share of the gain or loss in cash and reverse to revenues the previously recorded unrealized gain or loss. Prior to settlement, the change in the fair value of physical forward sale and purchase contracts is included in revenues on a net basis. Upon settlement of a forward trading contract, the amount realized is included in revenues for a sales contract and realized costs are included in purchased power expense for a purchase contract with the prior change in unrealized fair value reversed in revenues. Continuing with the above example, assume that later in January or sometime in February through July we enter into an offsetting forward contract to buy electricity in July. If we do nothing else with these contracts until settlement in July and if the volumes, delivery point, schedule and other key terms match then the difference between the sale price and the purchase price represents a fixed value to be realized when the contracts settle in July. If the purchase contract is perfectly matched with the sales contract, we have effectively fixed the profit or loss; specifically it is the difference between the contracted settlement price of the two contracts. Mark-to-market accounting for these contracts will have no further impact on results of operations but will have an offsetting and equal effect on trading contract assets and liabilities. Of course we could also do similar transactions but enter into a purchase contract prior to entering into a sales contract. If the sale and purchase contracts do not match exactly as to volumes, delivery point, schedule and other key terms, then there could be continuing mark-to-market effects on revenues from recording additional changes in fair values using mark-to-market accounting. The fair value of open short-term trading contracts are based on exchange prices and broker quotes. We mark-to-market open long-term trading contracts based mainly on AEP-developed valuation models. These models estimate future energy prices based on existing market and broker quotes and supply and demand market data and assumptions. The fair values determined are reduced by reserves to adjust for credit risk and liquidity risk. Credit risk is the risk that the counterparty to the contract will fail to perform or fail to pay amounts due AEP. Liquidity risk represents the risk that imperfections in the market will cause the price to be less than or more than what the price should be based purely on supply and demand. There are inherent risks related to the underlying assumptions in models used to fair value open long-term trading contracts. AEP has independent controls to evaluate the reasonableness of our valuation models. However, energy markets, especially electricity markets, are imperfect and volatile and unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a contract's term and when contracts settle. Therefore, there could be significant adverse or favorable effects on future results of operations and cash flows if market prices do not correlate with the AEP-developed price models. Volatility in commodities markets affects the fair values of all of our open trading contracts exposing CPL to market risk. See "Market Risks" section of MD&A for a discussion of the policies and procedures used to manage exposure to risk from trading activities. Results of Operations Although operating revenues increased, income before extraordinary item decreased $5 million or 3% in 2001. The decrease was primarily a result of a settlement of Texas municipal franchise fees (see Note 8) and increased maintenance expense. Income before extraordinary item increased $2 million or 1% in 2000 primarily as a result of increased retail energy sales, the post merger sharing of AEP's power marketing and trading operations which increased wholesale sales to neighboring utilities and power marketers and the effect of an unfavorable adjustment in 1999 as a result of FERC's approval of a transmission coordination agreement. These items were offset in part by a rise in interest expense. Operating Revenues Rise Operating revenues increased 41% in 2001 and 58% in 2000. Both increases are primarily due to an increase in wholesale marketing and trading activities. The following analyzes the changes in operating revenues: Increase (Decrease) From Previous Year (dollars in millions) 2001 2000 ---- ---- Amount % Amount % ------ - ------ - Retail* $ 4.2 - $193.6 23 Wholesale Marketing and Trading 924.6 127 651.4 859 Unrealized MTM 28.1 343 (8.2) - Other 16.9 27 (8.9) (12) Total Marketing and Trading 973.8 53 827.9 82 Energy Delivery* (5.6) (1) 29.1 6 Sales to AEP Affiliates 4.0 11 10.0 36 --- ---- Total Revenues $972.2 41 $867.0 58 ====== ====== *Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery. Retail operating revenues increased 23% in 2000 due to an increase in fuel and purchased power related revenues, reflecting rising prices for natural gas and purchased power, and an increase in weather-related demand for electricity. Through December 31, 2001 the Texas fuel and purchased power clause recovery mechanism provides for the accrual of revenues to recover fuel and purchased power cost increases until reviewed and approved for billing to customers by the PUCT. As a result increases in fuel and purchased power expenses and related accrued revenues do not adversely affect results of opertions. The significant increase in wholesale marketing and trading revenues in 2001 is attributable to a full year of participation in AEP's power marketing and trading operations. Trading involves the purchase and sale of substantial amounts of electricity with non-affiliated parties. The significant increase in wholesale marketing and trading revenues in 2000 is primarily attributable to CPL's initial participation in AEP's power marketing and trading operations. Since becoming a subsidiary of AEP as a result of the merger in June 2000, CPL shares in AEP's power marketing and trading transactions with other non-affiliated entities. Operating Expenses Increase Total operating expenses increased 48% in 2001 and 72% in 2000. The 2001 increase is due primarily to purchased power, taxes and maintenance, partially offset by a decrease in fuel costs. The 2000 increase was primarily due to increased costs of fuel and purchased power and a rise in other operation expense. The changes in the components of operating expenses were: Increase (Decrease) From Previous Year (dollars in millions) 2001 2000 ---- ---- Amount % Amount % ------ - ------ - Fuel $(58.8) (11) $146.9 36 Marketing And Trading Purchases 987.6 137 671.6 N.M. AEP Affiliate Purchases 26.0 80 15.9 95 Other Operation 1.7 1 28.4 10 Maintenance 10.7 18 (9.6) (14) Depreciation And Amortization (10.4) (6) 1.1 1 Taxes Other Than Income Taxes 14.4 19 2.7 4 Income Taxes 12.4 12 (3.1) (3) ---- ---- Total $983.6 48 $853.9 72 ====== ====== N.M. = Not Meaningful The decrease in fuel expense in 2001 was primarily due to a reduction in the average cost of fuel primarily from a decline in natural gas prices. CPL uses natural gas as fuel for 71% of its generating capacity. The nature of the natural gas market is such that both long-term and short-term contracts are generally based on the current spot market price. Changes in natural gas prices affect CPL's fuel expense, however, as explained above, they generally do not impact results of operations. Fuel expense increased in 2000 primarily due to a rise in the average cost of fuel reflecting large increases in natural gas prices. The significant increase in electricity marketing and trading purchased power in 2001 and 2000 was attributable to our participation in AEP's power marketing and trading operation. Purchased power from AEP affiliates increased largely due to higher natural gas prices. Although gas prices declined in 2001, they were higher during the first half of 2001 when CPL was making most of its purchases. Throughout 2000 gas prices were increasing accounting for the rise in AEP affiliated purchased power expense. Other operation expense increased in 2000 due primarily to an increase in transmission expenses that resulted from new prices for the ERCOT transmission grid. Each year ERCOT establishes new rates to allocate the costs of the Texas transmission system to Texas electric utilities. In addition to higher transmission expenses, other operation expense increased due to higher administrative expenses resulting from the Company's share of STP voluntary severance expenses and Texas regulatory expenses. The principal cause of the increase in maintenance expense in 2001 was two refueling outages at the STP verses one in 2000. Also contributing to the increase in maintenance expense were scheduled major overhauls of four power plants. Maintenance expense decreased in 2000 as a result of a 10-year service inspection and refueling of STP Units 1 and 2 performed in 1999. Taxes other than income taxes increased in 2001 due primarily to an increase in franchise related taxes, including a settlement of disputed franchise fees (see Note 8), and a new tax levied by the PUCT, the Texas System Benefit Fund Assessment. The increase in income tax expense was primarily due to adjustments associated with prior year tax returns and an increase in pre-tax book income. Interest Charges The decrease in interest charges in 2001 was attributable to lower average interest rates associated with short-term and long-term debt. The increase in interest charges in 2000 can be attributed to higher average interest rates on debt. Extraordinary Loss The extraordinary loss on reacquired debt recorded in 2001 was the result of reacquisition of installment purchase contracts for Matagorda County, Navigation District, Texas. Preferred Stock Dividends Preferred stock dividends decreased in 2000 as a result of the redemption of preferred stock in the fourth quarter of 1999, which resulted in a loss on reacquired preferred stock recorded in 1999.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES Consolidated Statements of Income Year Ended December 31, ---------------------------------------- 2001 2000 1999 ---- ---- ---- (in thousands) OPERATING REVENUES: Electricity Marketing and Trading $2,806,783 $1,832,937 $1,005,037 Energy Delivery 473,182 478,814 449,667 Sales to AEP Affiliates 41,762 37,752 27,771 ------ ------ ------ TOTAL REVENUES 3,321,727 2,349,503 1,482,475 OPERATING EXPENSES: Fuel 492,057 550,903 403,989 Purchased Power: Electricity Marketing and Trading 1,710,706 723,122 51,482 AEP Affiliates 58,641 32,591 16,673 Other Operation 321,227 319,539 291,131 Maintenance 71,212 60,528 70,165 Depreciation and Amortization 168,341 178,786 177,702 Taxes Other Than Income Taxes 90,916 76,477 73,823 Income Taxes 112,896 100,459 103,525 ------- ------- ------- Total Operating Expenses 3,025,996 2,042,405 1,188,490 --------- --------- --------- OPERATING INCOME 295,731 307,098 293,985 NONOPERATING INCOME 22,552 5,830 6,420 NONOPERATING EXPENSES 17,626 3,668 3,593 NONOPERATING INCOME TAX EXPENSE (CREDIT) (398) (5,073) (5,286) INTEREST CHARGES 116,268 124,766 114,380 ------- ------- ------- INCOME BEFORE EXTRAORDINARY ITEM 184,787 189,567 187,718 EXTRAORDINARY LOSS ON REACQUIRED DEBT (Inclusive of Tax $1,351,000 and $2,971,000 for 2001 and 1999, respectively) (2,509) - (5,517) ------ ---- ------ NET INCOME 182,278 189,567 182,201 PREFERRED STOCK DIVIDEND REQUIREMENTS 242 241 6,931 LOSS ON REACQUIRED PREFERRED STOCK - - (2,763) ---- ---- ------ EARNINGS APPLICABLE TO COMMON STOCK $182,036 $189,326 $172,507 ======== ======== ========
See Notes to Financial Statements Beginning on Page L-1. CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES Consolidated Balance Sheets December 31, ----------------------- 2001 2000 ---- ---- (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production $3,169,421 $3,175,867 Transmission 663,655 581,931 Distribution 1,279,037 1,221,750 General 241,137 237,764 Construction Work in Progress 169,075 138,273 Nuclear Fuel 247,382 236,859 ------- ------- Total Electric Utility Plant 5,769,707 5,592,444 Accumulated Depreciation and Amortization 2,446,027 2,297,189 --------- --------- NET ELECTRIC UTILITY PLANT 3,323,680 3,295,255 --------- --------- OTHER PROPERTY AND INVESTMENTS 47,950 44,225 ------ ------ LONG-TERM ENERGY TRADING CONTRACTS 72,502 65,786 ------ ------ CURRENT ASSETS: Cash and Cash Equivalents 10,909 14,253 Accounts Receivable: General 38,459 67,787 Affiliated Companies 6,249 31,272 Allowance for Uncollectible Accounts (186) (1,675) Fuel Inventory - at LIFO cost 38,690 22,842 Materials and Supplies - at average cost 55,475 53,108 Under-recovered Fuel Costs - 127,295 Energy Trading Contracts 212,979 476,839 Prepayments 2,742 3,014 ----- ----- TOTAL CURRENT ASSETS 365,317 794,735 ------- ------- REGULATORY ASSETS 226,806 202,440 ------- ------- REGULATORY ASSETS DESIGNATED FOR SECURITIZATION 959,294 953,249 ------- ------- NUCLEAR DECOMMISSIONING TRUST FUND 98,600 93,592 ------ ------ DEFERRED CHARGES 21,837 18,402 ------ ------ TOTAL $5,115,986 $5,467,684 ========== ========== See Notes to Financial Statements beginning on page L-1.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES December 31, ------------------------ 2001 2000 ---- ---- (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock - $25 Par Value: Authorized - 12,000,000 Shares Outstanding - 6,755,535 Shares $168,888 $168,888 Paid-in Capital 405,000 405,000 Retained Earnings 826,197 792,219 ------- ------- Total Common Shareholder's Equity 1,400,085 1,366,107 Preferred Stock 5,967 5,967 CPL - Obligated, Mandatorily Redeemable Preferred Securities of Subsidiary Trust Holding Solely Junior Subordinated Debentures of CPL 136,250 148,500 Long-term Debt 988,768 1,254,559 ------- --------- TOTAL CAPITALIZATION 2,531,070 2,775,133 --------- --------- CURRENT LIABILITIES: Long-term Debt Due Within One Year 265,000 200,000 Advances from Affiliates 354,277 269,712 Accounts Payable - General 65,307 128,957 Accounts Payable - Affiliated Companies 49,301 40,962 Over-Recovered Fuel 57,762 - Taxes Accrued 83,512 55,526 Interest Accrued 18,524 26,217 Energy Trading Contracts 219,486 485,521 Other 49,512 40,630 ------ ------ Total CURRENT LIABILITIES 1,162,681 1,247,525 --------- --------- DEFERRED INCOME TAXES 1,163,795 1,242,797 --------- --------- DEFERRED INVESTMENT TAX CREDITS 122,892 128,100 ------- ------- LONG-TERM ENERGY TRADING CONTRACTS 62,138 65,295 ------ ------ DEFERRED CREDITS 73,410 8,834 ------ ----- COMMITMENTS AND CONTINGENCIES (Note 8) TOTAL $5,115,986 $5,467,684 ========== ==========
See Notes to Financial Statements beginning on page L-1.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES Consolidated Statements of Cash Flows Year Ended December 31, ----------------------- 2001 2000 1999 ---- ---- ---- (in thousands) OPERATING ACTIVITIES: Net Income $ 182,278 $ 189,567 $ 182,201 Adjustments for Noncash Items: Depreciation and Amortization 168,341 178,786 177,702 Extraordinary Loss on Reacquired Debt 2,509 - 5,517 Deferred Income Taxes (72,568) 16,263 19,938 Deferred Investment Tax Credits (5,208) (5,207) (5,207) Mark-to-Market of Energy Trading Contracts (12,048) 8,191 - Change in Certain Current Assets and Liabilities: Accounts Receivable (net) 52,862 (32,902) (13,426) Fuel, Materials and Supplies (18,215) 8,680 (4,476) Interest Accrued (7,693) 11,494 (12,313) Fuel Recovery 185,057 (96,872) (40,046) Accounts Payable (55,311) 45,873 (3,061) Taxes Accrued 27,986 14,405 (5,734) Transmission Coordination Agreement Settlement - 15,519 (15,519) Change in Other Assets 10,756 599 19,974 Change in Other Liabilities 11,174 12,233 (554) ------ ------ ----- Net Cash Flows From Operating Activities 469,920 366,629 304,996 ------- ------- ------- INVESTING ACTIVITIES: Construction Expenditures (193,732) (199,484) (210,823) Proceeds From Sales of Property and Other (354) - 15,063 ---- ---- ------ Net Cash Flows Used For Investing Activities (194,086) (199,484) (195,760) -------- -------- -------- FINANCING ACTIVITIES: Issuance of Long-term Debt 260,162 149,248 358,887 Retirement of Preferred Stock - - (160,001) Retirement of Long-term Debt (475,606) (151,440) (261,700) Change in Advances from Affiliates (net) 84,565 (52,446) 161,860 Special Deposit for Reacquisition of Long-term Debt - 50,000 (50,000) Dividends Paid on Common Stock (148,057) (156,000) (148,000) Dividends Paid on Cumulative Preferred Stock (242) (249) (7,835) ---- ---- ------ Net Cash Flows Used For Financing Activities (279,178) (160,887) (106,789) -------- -------- -------- Net Increased (Decrease) in Cash and Cash Equivalents (3,344) 6,258 2,447 Cash and Cash Equivalents January 1 14,253 7,995 5,548 ------ ----- ----- Cash and Cash Equivalents December 31 $10,909 $14,253 $ 7,995 ======= ======= =======
Supplemental Disclosure: Cash paid for interest net of capitalized amounts (including distributions on Trust Preferred Securities) was $109,835,000, $110,010,000 and $125,222,000 and for income taxes was $161,529,000, $48,141,000 and $78,393,000 in 2001, 2000 and 1999,respectively. See Notes to Financial Statements beginning on page L-1.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES Consolidated Statements of Retained Earnings Year Ended December 31, ----------------------------------------- 2001 2000 1999 ---- ---- ---- (in thousands) BEGINNING OF PERIOD $792,219 $758,894 $734,387 NET INCOME 182,278 189,567 182,201 DEDUCTIONS: Cash Dividends Declared: Common Stock 148,057 156,000 148,000 Preferred Stock 242 241 6,931 Other 1 1 - LOSS ON REACQUIRED PREFERRED STOCK - - (2,763) ---- ---- ------ BALANCE AT END OF PERIOD $826,197 $792,219 $758,894 ======== ======== ========
See Notes to Financial Statements beginning on page L-1.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES Consolidated Statements of Capitalization December 31, ----------------------------- 2001 2000 ---- ---- (in thousands) COMMON SHAREHOLDERS' EQUITY $1,400,085 $1,366,107 ---------- ---------- PREFERRED STOCK - authorized shares 3,035,000 $100 par value Call Price Shares December 31, Number of Shares Redeemed Outstanding Series 2001 Year Ended December 31, December 31, 2001 - ------ ------------ ---------------------------- ----------------- 2001 2000 1999 ---- ---- ---- Not Subject to Mandatory Redemption: 4.00% $105.75 - - - 42,038 4,204 4,204 4.20% 103.75 - - - 17,476 1,748 1,748 Premium 15 15 ---------- ---------- Total Preferred Stock 5,967 5,967 ---------- ---------- TRUST PREFERRED SECURITIES: CPL-obligated, mandatorily redeemable preferred securities of subsidiary trust holding solely Junior Subordinated Debentures of CPL, 8.00%, due April 30, 2037 136,250 148,500 ---------- ---------- LONG-TERM (See Schedule of Long-term Debt): First Mortgage Bonds 614,200 615,000 Installment Purchase Contracts 489,568 489,559 Senior Unsecured Notes 150,000 350,000 Less Portion Due Within One year (265,000) (200,000) ---------- ---------- Long-term Debt Excluding Portion Due Within One Year 988,768 1,254,559 ---------- ---------- TOTAL CAPITALIZATION $2,531,070 $2,775,133 ========== ==========
See Notes to Financial Statements beginning on page L-1. CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES Schedule of Long-term Debt First mortgage bonds outstanding were as follows: December 31, ----------------- 2001 2000 ---- ---- (in thousands) % Rate Due 7.25 2004 - October 1 $100,000 $100,000 7.50 2002 - December 1 115,000 115,000 6-7/8 2003 - February 1 49,200 50,000 7-1/8 2008 - February 1 75,000 75,000 7.50 2023 - April 1 75,000 75,000 6-5/8 2005 - July 1 200,000 200,000 Unamortized Discount - - -------- ----- Total $614,200 $615,000 ======== ======== First mortgage bonds are secured by first mortgage liens on electric utility plant. Certain indentures relating to the first mortgage bonds contain improvement, maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. Installment purchase contracts have been entered into in connection with the issuance of pollution control revenue bonds by governmental authorities as follows: December 31, 2001 2000 ---- ---- (in thousands) % Rate Due Matagorda County Navigation District, Texas: 6.00 2028 - July 1 $120,265 $120,265 6.10 2028 - July 1 - 100,635 6-1/8 2030 - May 1 60,000 60,000 4.90 2030 - May 1 - 111,700 4.95 2030 - May 1 - 50,000 3.75 2030(a) - May 1 111,700 - 4.00 2030(a) - May 1 50,000 - 4.55 2029(a) - Nov 1 100,635 - Guadalupe-Blanco River Authority District, Texas: (b) 2015 - November 1 40,890 40,890 Red River Authority District, Texas: 6.00 2020 - June 1 6,330 6,330 Unamortized Discount (252) (261) -------- -------- Total $489,568 $489,559 ======== ======== (a)Installment Purchase Contract provides for bonds to be tendered in 2003 for 3.75% and 4.00% series and in 2006 for 4.55% series. Therefore, these installment purchase contracts have been classified for payments in those years. (b) A floating interest rate is determined monthly. The rate on December 31, 2001 was 1.9%. Under the terms of the installment purchase contracts, CPL is required to pay amounts sufficient to enable the payment of interest on and the principal (at stated maturities and upon mandatory redemptions) of related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants. Senior unsecured notes outstanding were as follows: December 31, ----------------- 2001 2000 ---- ---- (in thousands) % Rate Due 2001 - November 23 $ - $200,000 (c) 2002 - February 22 150,000 150,000 -------- -------- Total $150,000 $350,000 ======== ======== (c) A floating interest rate is determined monthly. The rate on December 31, 2001 and 2000 was 2.56% and 7.20%, respectively. At December 31, 2001, future annual long-term debt payments are as follows: Amount ------ (in thousands) 2002 $265,000 2003 210,900 2004 100,000 2005 200,000 2006 100,635 Later Years 377,485 ------- Total Principal Amount 1,254,020 Unamortized Discount (252) ---- Total $1,253,768 ========== CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES Index to Notes to Consolidated Financial Statements The notes to CPL financial statements are combined with the notes to financial statements for AEP and its other subsidiary registrants. Listed below are the combined notes that apply to CPL. The combined footnotes begin on page L-1. Combined Footnote Reference Significant Accounting Policies Note 1 Extraordinary Items and Cumulative Effect Note 2 Merger Note 3 Rate Matters Note 5 Effects of Regulation Note 6 Customer Choice and Industry Restructuring Note 7 Commitments and Contingencies Note 8 Benefit Plans Note 10 Business Segments Note 12 Risk Management, Financial Instruments and Derivatives Note 13 Income Taxes Note 14 Leases Note 18 Lines of Credit and Sale of Receivables Note 19 Unaudited Quarterly Financial Information Note 20 Trust Preferred Securities Note 21 Jointly Owned Electric Utility Plant Note 23 Related Party Transactions Note 24 INDEPENDENT AUDITORS' REPORT To the Shareholders and Board of Directors of Central Power and Light Company: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Central Power and Light Company and subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of income, retained earnings, and cash flows for the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. The consolidated financial statements of the Company for the year ended December 31, 1999, before the restatement described in Note 3 to the consolidated financial statements, were audited by other auditors whose report, dated February 25, 2000, expressed an unqualified opinion on those statements. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such 2001 and 2000 consolidated financial statements present fairly, in all material respects, the financial position of Central Power and Light Company and subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America. We also audited the adjustments described in Note 3 that were applied to restate the 1999 consolidated financial statements to give retroactive effect to the conforming change in the method of accounting for vacation pay accruals. In our opinion, such adjustments are appropriate and have been properly applied. Deloitte & Touche LLP Columbus, Ohio February 22, 2002 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Selected Consolidated Financial Data Year Ended December 31, 2001 2000 1999 1998 1997 ---- ---- ---- ---- ---- (in thousands) INCOME STATEMENTS DATA: Operating Revenues $4,299,863 $3,165,615 $2,631,739 $2,102,295 $1,139,604 Operating Expenses 4,047,686 2,969,738 2,408,949 1,890,084 944,477 --------- --------- --------- --------- ------- Operating Income 252,177 195,877 222,790 212,211 195,127 Nonoperating Income (Loss) 7,738 5,153 2,709 (1,343) 3,137 Interest Charges 68,015 80,828 75,229 77,824 78,885 ------ ------ ------ ------ ------ Income Before Extraordinary Item 191,900 120,202 150,270 133,044 119,379 Extraordinary Loss (30,024) (25,236) - - - ------- ------- ---- ---- ---- Net Income 161,876 94,966 150,270 133,044 119,379 Preferred Stock Dividend Requirements 1,095 1,783 2,131 2,131 2,442 ----- ----- ----- ----- ----- Earnings Applicable to Common Stock $160,781 $93,183 $148,139 $130,913 $116,937 ======== ======= ======== ======== ======== Year Ended December 31, 2001 2000 1999 1998 1997 ---- ---- ---- ---- ---- (in thousands) BALANCE SHEETS DATA: Electric Utility Plant $3,354,320 $3,266,794 $3,151,619 $3,053,565 $2,976,110 Accumulated Depreciation 1,377,032 1,299,697 1,210,994 1,134,348 1,074,588 --------- --------- --------- --------- --------- Net Electric Utility Plant $1,977,288 $1,967,097 $1,940,625 $1,919,217 $1,901,522 ========== ========== ========== ========== ========== Total Assets $3,105,868 $3,888,302 $2,809,990 $2,681,690 $2,613,860 ========== ========== ========== ========== ========== Common Stock and Paid-in Capital $615,395 $614,380 $613,899 $613,518 $613,138 Retained Earnings 176,103 99,069 246,584 186,441 138,172 ------- ------ ------- ------- ------- Total Common Shareholder's Equity $791,498 $713,449 $860,483 $799,959 $751,310 ======== ======== ======== ======== ======== Cumulative Preferred Stock - Subject to Mandatory Redemption (a) $ 10,000 $ 15,000 $ 25,000 $ 25,000 $ 25,000 ======== ======== ======== ======== ======== Long-term Debt (a) $791,848 $899,615 $924,545 $959,786 $969,600 ======== ======== ======== ======== ======== Obligations Under Capital Leases (a) $ 34,887 $ 42,932 $ 40,270 $ 42,362 $ 38,587 ======== ======== ======== ======== ======== Total Capitalization and Liabilities $3,105,868 $3,888,302 $2,809,990 $2,681,690 $2,613,860 ========== ========== ========== ========== ==========
(a) Including portion due within one year. COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Management's Narrative Analysis of Results of Operations Columbus Southern Power Company is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to 678,000 retail customers in central and southern Ohio. CSPCo as a member of the AEP Power Pool shares in the revenues and costs of the AEP Power Pool's wholesale sales to neighboring utility systems and power marketers including power trading transactions. CSPCo also sells wholesale power to municipalities. The cost of the AEP Power Pool's generating capacity is allocated among the Pool members based on their relative peak demands and generating reserves through the payment of capacity charges and receipt of capacity credits. AEP Power Pool members are also compensated for their out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each company's prior twelve month peak demand relative to the total peak demand of all member companies as a basis for sharing AEP Power Pool revenues and costs. The result of this calculation is the member load ratio (MLR) which determines each company's percentage share of AEP Power Pool revenues and costs. Critical Accounting Policies - Revenue Recognition Regulatory Accounting - As a result of our cost-based rate-regulated transmission and distribution operations, our financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate regulated. In accordance with SFAS 71, regulatory assets (deferred expenses) and regulatory liabilities (future revenue reductions or refunds) are recorded to reflect the economic effects of regulation by matching expenses with their recovery through regulated revenues in the same accounting period. When regulatory assets are probable of recovery through regulated rates, we record them as assets on the balance sheet. We test for probability of recovery whenever new events occur, for example a regulatory commission order or passage of new legislation. If we determine that recovery of a regulatory asset is no longer probable, we write off that regulatory asset as a charge against net income. A write off of regulatory assets may also reduce future cash flows since there may be no recovery through regulated rates. Traditional Electricity Supply and Delivery Activities - We recognize revenues on an accrual basis for electricity supply sales and electricity transmission and distribution delivery services. The revenues are recognized in our income statement when the energy is delivered to the customer and include unbilled as well as billed amounts. In general expenses are recorded when incurred. Energy Marketing and Trading Activities - AEP engages in wholesale electricity marketing and trading transactions (trading activities). A portion of the revenues and costs of AEP's trading activities are allocated to CSPCo as a member of the AEP Power Pool. Trading activities involve the purchase and sale of energy under physical forward contracts at fixed and variable prices and buying and selling financial energy contracts which includes exchange traded futures and options and over-the-counter options and swaps. Although trading contracts are generally short-term, there are also long-term trading contracts. We recognize revenues from trading activities generally based on changes in the fair value of energy trading contracts. Recording the net change in the fair value of trading contracts prior to settlement is commonly referred to as mark-to-market (MTM) accounting. It represents the change in the unrealized gain or loss throughout the contract's term. When the contract actually settles, that is, the energy is actually delivered in a sale or received in a purchase or the parties agree to forego delivery and receipt and net settle in cash, the unrealized gain or loss is reversed and the actual realized cash gain or loss is recognized. Therefore, over the trading contract's term an unrealized gain or loss is recognized as the contract's market value changes. When the contract settles the total gain or loss is realized in cash but only the difference between the accumulated unrealized net gains or losses recorded in prior months and the cash proceeds is recognized. Unrealized mark-to-market gains and losses are included in the Balance Sheet as energy trading contract assets or liabilities as appropriate. The majority of our trading activities represent physical forward electricity contracts that are typically settled by entering into offsetting contracts. An example of our trading activities is when, in January, we enter into a forward sales contract to deliver electricity in July. At the end of each month until the contract settles in July, we would record our share of any difference between the contract price and the market price as an unrealized gain or loss. In July when the contract settles, we would realize our share of the gain or loss in cash and reverse the previously recorded unrealized gain or loss. Depending on whether the delivery point for the electricity is in AEP's traditional marketing area or not determines where the contract is reported on CSPCo's income statement. AEP's traditional marketing area is up to two transmission systems from the AEP service territory. Physical forward trading sale contracts with delivery points in AEP's traditional marketing area are included in revenues when the contracts settle. Physical forward trading purchase contracts with delivery points in AEP's traditional marketing area are included in purchased power expense when they settle. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts in AEP's traditional marketing area are included in revenues on a net basis. Physical forward sales contracts for delivery outside of AEP's traditional marketing area are included in nonoperating income when the contract settles. Physical forward purchase contracts for delivery outside of AEP's traditional marketing area are included in nonoperating expenses when the contract settles. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts with delivery points outside of AEP's traditional marketing area are included in nonoperating income on a net basis. Continuing with the above example, assume that later in January or sometime in February through July we enter into an offsetting forward contract to buy electricity in July. If we do nothing else with these contracts until settlement in July and if the volumes, delivery point, schedule and other key terms match then the difference between the sale price and the purchase price represents a fixed value to be realized when the contracts settle in July. If the purchase contract is perfectly matched with the sales contract, we have effectively fixed the profit or loss; specifically it is the difference between the contracted settlement price of the two contracts. Mark-to-market accounting for these contracts will have no further impact on results of operations but will have an offsetting and equal effect on trading contract assets and liabilities. Of course we could also do similar transactions but enter into a purchase contract prior to entering into a sales contract. If the sale and purchase contracts do not match exactly as to volumes, delivery point, schedule and other key terms, then there could be continuing mark-to-market effects on results of operations from recording additional changes in fair values using mark-to-market accounting. Trading of electricity options, futures and swaps, represents financial transactions with unrealized gains and losses from changes in fair values reported net in nonoperating income until the contracts settle. When these financial contracts settle, we record our share of the net proceeds in nonoperating income and reverse to nonoperating income the prior unrealized gain or loss. The fair value of open short-term trading contracts are based on exchange prices and broker quotes. We mark-to-market open long-term trading contracts based mainly on AEP-developed valuation models. These models estimate future energy prices based on existing market and broker quotes and supply and demand market data and assumptions. The fair values determined are reduced by reserves to adjust for credit risk and liquidity risk. Credit risk is the risk that the counterparty to the contract will fail to perform or fail to pay amounts due AEP. Liquidity risk represents the risk that imperfections in the market will cause the price to be less than or more than what the price should be based purely on supply and demand. There are inherent risks related to the underlying assumptions in models used to fair value open long-term trading contracts. AEP has independent controls to evaluate the reasonableness of our valuation models. However, energy markets, especially electricity markets, are imperfect and volatile and unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a contract's term and when contracts settle. Therefore, there could be significant adverse or favorable effects on future results of operations and cash flows if market prices do not correlate with the AEP-developed price models. Volatility in commodities markets affects the fair values of all of our open trading contracts exposing CSPCo to market risk. See "Market Risks" section of MD&A for a discussion of the policies and procedures used to manage exposure to risk from trading activities. Results of Operations Net Income Increases Income before extraordinary item increased by $72 million or 60% in 2001 primarily due to the effect of a court decision related to a corporate owned life insurance (COLI) program recorded in 2000. In February 2001 the U.S. District Court for the Southern District of Ohio ruled against AEP and certain of its subsidiaries, including CSPCo, in a suit over the deductibility of interest claimed in AEP's consolidated tax return related to COLI. In 1998 and 1999 CSPCo paid the disputed taxes and interest attributable to the COLI interest deductions for taxable years 1991-98. The payments were included in Other Property and Investments pending the resolution of this matter. Also contributing to the increase in net income in 2001 was growth in and strong performance by the wholesale business in the first half of 2001 offset in part by the effect of extremely mild weather in November and December combined with weak economic conditions which reduced retail energy sales. Operating Revenues Increase Operating revenues increased 36% in 2001 due to the significant increase in wholesale marketing and trading volume. Changes in the components of operating revenues were as follows: Increase (Decrease) From Previous Year (dollars in millions) Amount % Retail* $ (65.1) (10) Wholesale Marketing and Trading 1,072.1 53 Unrealized MTM 23.1 N.M. Other 0.8 2 -------- Total Marketing and Trading 1,030.9 38 Energy Delivery* 85.2 21 Sales to AEP Affiliates 18.1 37 -------- Total Revenues $1,134.2 36 ======== N.M. = Not Meaningful *Reflects the allocation in 2000 of certain transmission and distribution revenues included in bundled retail rates to energy delivery. The significant increase in wholesale marketing and trading revenues was caused by a 46% volume increase in 2001. The maturing of the Intercontinental Exchange, the development of proprietary tools, and increased staffing of energy traders has resulted in an increase in the number of forward electricity purchase and sales contracts in AEP's traditional marketing area. Operating Expenses Rise Operating expenses increased by 36% in 2001 due primarily to a significant increase in purchased power expense. Changes in the components of operating expenses were: Increase (Decrease) From Previous Year (dollars in millions) Amount % Fuel $ (14.0) (7) Marketing and Trading Purchases 1,089.5 58 AEP Affiliate Purchases 4.4 2 Other Operation Expense (0.4) - Maintenance Expense (7.2) (10) Depreciation and Amortization 27.7 28 Taxes Other Than Income Taxes (11.7) (10) Income Taxes (10.3) (9) -------- Total $1,078.0 36 ======== Fuel costs decreased by $14 million due to a 12.5% decrease in generation partially offset by increased coal prices of 6.3% The increase in marketing and trading purchases is reflective of the increase in trading volume. Reversal of a quality of service regulatory liability accrual and reduced maintenance of overhead distribution lines accounted for the decease in maintenance expense. Depreciation and amortization expense increased significantly due to amortization of transition regulatory assets which began in January 2001. With the implementation of customer choice in Ohio on January 1, 2001, the PUCO approved the Company's plan for recovery of generation-related regulatory assets through frozen transition rates. Concurrent with the start of the transition period, we began amortization of the transition regulatory assets. Depreciation expense also increased due to additional plant investment. The decrease in taxes other than income taxes in 2001 is due to a decrease in property tax rates on generation property partially offset by a new state excise tax. The decrease in income tax expense was primarily due to an unfavorable ruling in AEP's suit against the government over interest deductions claimed relating to AEP's COLI program which was recorded in 2000 offset in part by an increase in pre-tax income. Nonoperating Income and Nonoperating Expense The increase in nonoperating income and nonoperating expense in 2001 was due to a significant increase in the wholesale business trading transactions outside of AEP's traditional marketing area. Interest Charges Decrease Interest charges for 2001 decreased as a result of the recognition in 2000 of deferred interest payments to the IRS related to the COLI disallowances as well as reduced debt in 2001. Extraordinary Loss In 2001 we recorded an extraordinary loss of $30 million net of tax to write-off prepaid Ohio excise taxes stranded by Ohio deregulation (see Note 2, "Extraordinary Items and Cumulative Effect").
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Income Year Ended December 31, --------------------------------------------- 2001 2000 1999 ---- ---- ---- (in thousands) OPERATING REVENUES: Electricity Marketing and Trading $3,749,133 $2,718,204 $2,222,741 Energy Delivery 483,219 398,046 389,280 Sales to AEP Affiliates 67,511 49,365 19,718 ------ ---------- ---------- Total Operating Revenues 4,299,863 3,165,615 2,631,739 --------- --------- --------- OPERATING EXPENSES: Fuel 175,153 189,155 185,511 Purchased Power: Electricity Marketing and Trading 2,958,656 1,869,150 1,467,628 AEP Affiliates 292,199 287,750 199,574 Other Operation 221,342 221,775 190,614 Maintenance 62,454 69,676 65,229 Depreciation and Amortization 127,364 99,640 94,532 Taxes Other Than Income Taxes 111,481 123,223 120,146 Income Taxes 99,037 109,369 85,715 ------ ------- ------ TOTAL OPERATING EXPENSES 4,047,686 2,969,738 2,408,949 --------- --------- --------- OPERATING INCOME 252,177 195,877 222,790 NONOPERATING INCOME 1,334,302 780,159 410,226 NONOPERATING EXPENSES 1,322,641 767,649 410,457 NONOPERATING INCOME TAX EXPENSE (CREDIT) 3,923 7,357 (2,940) INTEREST CHARGES 68,015 80,828 75,229 ------ ------ ------ INCOME BEFORE EXTRAORDINARY ITEM 191,900 120,202 150,270 EXTRAORDINARY LOSS - DISCONTINUANCE OF REGULATORY ACCOUNTING FOR GENERATION - Net of tax (Note 2) (30,024) (25,236) - ------- ------- ---- NET INCOME 161,876 94,966 150,270 PREFERRED STOCK DIVIDEND REQUIREMENTS 1,095 1,783 2,131 ----- ----- ----- EARNINGS APPLICABLE TO COMMON STOCK $160,781 $ 93,183 $148,139 ======== ======== ========
Consolidated Statements of Retained Earnings
Year Ended December 31, --------------------------------------------- 2001 2000 1999 ---- ---- ---- (in thousands) Retained Earnings January 1 $ 99,069 $246,584 $186,441 Net Income 161,876 94,966 150,270 ------- ------ ------- 260,945 341,550 336,711 ------- ------- ------- Deductions: Cash Dividends Declared: Common Stock 82,952 240,600 87,996 Cumulative Preferred Stock - 7% Series 875 1,400 1,750 --- ----- ----- Total Cash Dividends Declared 83,827 242,000 89,746 Capital Stock Expense 1,015 481 381 ----- --- --- Total Deductions 84,842 242,481 90,127 ------ ------- ------ Retained Earnings December 31 $176,103 $ 99,069 $246,584 ======== ======== ========
See Notes to Financial Statements beginning on page L-1. COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Consolidated Balance Sheets December 31, ------------------------ 2001 2000 ---- ---- (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production $1,574,506 $1,564,254 Transmission 401,405 360,302 Distribution 1,159,105 1,096,365 General 146,732 156,534 Construction Work in Progress 72,572 89,339 ------ ------ Total Electric Utility Plant 3,354,320 3,266,794 Accumulated Depreciation 1,377,032 1,299,697 --------- --------- NET ELECTRIC UTILITY PLANT 1,977,288 1,967,097 --------- --------- OTHER PROPERTY AND INVESTMENTS 40,369 39,848 ------ ------ LONG-TERM ENERGY TRADING CONTRACTS 193,915 171,820 ------- ------- CURRENT ASSETS: Cash and Cash Equivalents 12,358 11,600 Accounts Receivable: Customers 41,770 73,711 Affiliated Companies 63,470 49,591 Miscellaneous 16,968 18,807 Allowance for Uncollectible Accounts (745) (659) Fuel - at average cost 20,019 13,126 Materials and Supplies - at average cost 38,984 38,097 Accrued Utility Revenues 7,087 9,638 Energy Trading Contracts 347,198 1,079,704 Prepayments 28,733 46,735 ------ ------ TOTAL CURRENT ASSETS 575,842 1,340,350 ------- --------- REGULATORY ASSETS 262,267 291,553 ------- ------- DEFERRED CHARGES 56,187 77,634 ------ ------ TOTAL $3,105,868 $3,888,302 ========== ========== See Notes to Financial Statements beginning on page L-1. COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES December 31, --------------------- 2001 2000 ---- ---- (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock - No Par Value: Authorized - 24,000,000 Shares Outstanding - 16,410,426 Shares $ 41,026 $ 41,026 Paid-in Capital 574,369 573,354 Retained Earnings 176,103 99,069 ------- ------ Total Common Shareholder's Equity 791,498 713,449 Cumulative Preferred Stock - Subject to Mandatory Redemption 10,000 15,000 Long-term Debt 571,348 899,615 ------- ------- TOTAL CAPITALIZATION 1,372,846 1,628,064 --------- --------- OTHER NONCURRENT LIABILITIES 36,715 47,584 ------ ------ CURRENT LIABILITIES: Long-term Debt Due Within One Year 220,500 - Advances from Affiliates 181,384 88,732 Accounts Payable - General 62,393 89,846 Accounts Payable - Affiliated Companies 83,697 72,493 Taxes Accrued 116,364 162,904 Interest Accrued 10,907 13,369 Energy Trading Contracts 334,958 1,109,682 Other 34,600 60,701 ------ ------ TOTAL CURRENT LIABILITIES 1,044,803 1,597,727 --------- --------- DEFERRED INCOME TAXES 443,722 422,759 ------- ------- DEFERRED INVESTMENT TAX CREDITS 37,176 41,234 ------ ------ LONG-TERM ENERGY TRADING CONTRACTS 157,706 138,073 ------- ------- DEFERRED CREDITS 12,900 12,861 ------ ------ COMMITMENTS AND CONTINGENCIES (Note 8) TOTAL $3,105,868 $3,888,302 ========== ==========
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Cash Flows Year Ended December 31, ----------------------------------------- 2001 2000 1999 ---- ---- ---- (in thousands) OPERATING ACTIVITIES: Net Income $ 161,876 $ 94,966 $ 150,270 Adjustments for Noncash Items: Depreciation and Amortization 128,500 100,182 94,962 Deferred Federal Income Taxes 24,108 (4,063) 10,481 Deferred Investment Tax Credits (4,058) (3,482) (3,994) Deferred Fuel Costs (net) - 5,352 8,889 Mark to Market of Energy Trading Contracts (44,680) (3,393) (2,369) Extraordinary Loss 30,024 25,236 - Change in Certain Current Assets and Liabilities: Accounts Receivable (net) 19,987 (29,737) 5,166 Fuel, Materials and Supplies (7,780) 11,957 (7,777) Accrued Utility Revenues 2,551 38,479 (7,990) Accounts Payable (16,249) 81,284 9,292 Disputed Tax and Interest Related to COLI - 39,483 (2,240) Change in Other Assets (42,066) (121,115) (14,898) Change in Other Liabilities (18,769) 132,441 3,388 ------- ------- ----- Net Cash Flows From Operating Activities 233,444 367,590 243,180 ------- ------- ------- INVESTING ACTIVITIES: Construction Expenditures (132,532) (127,987) (115,321) Proceeds From Sales and Leaseback Transactions and Other 10,841 1,560 1,858 ------ ----- ----- Net Cash Flows Used For Investing Activities (121,691) (126,427) (113,463) -------- -------- -------- FINANCING ACTIVITIES: Change in Advances from Affiliates (net) 92,652 88,732 - Issuance of Affiliated Long-term Debt 200,000 - - Retirement of Preferred Stock (5,000) (10,000) - Retirement of Long-term Debt (314,733) (25,274) (35,523) Change in Short-term Debt (net) - (45,500) (7,000) Dividends Paid on Common Stock (82,952) (240,600) (87,996) Dividends Paid on Cumulative Preferred Stock (962) (1,575) (1,750) ---- ------ ------ Net Cash Flows Used For Financing Activities (110,995) (234,217) (132,269) -------- -------- -------- Net Increase (Decrease) in Cash and Cash Equivalents 758 6,946 (2,552) Cash and Cash Equivalents January 1 11,600 4,654 7,206 ------ ----- ----- Cash and Cash Equivalents December 31 $12,358 $ 11,600 $ 4,654 ======= ======== =======
Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $68,596,000, $68,506,000 and $72,007,000 and for income taxes was $80,485,000, $81,109,000 and $71,809,000 in 2001, 2000 and 1999, respectively. Noncash acquisitions under capital leases were $1,019,000, $10,777,000 and $6,855,000 in 2001, 2000 and 1999, respectively. See Notes to Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Capitalization December 31, ----------------------------- 2001 2000 ---- ---- (in thousands) COMMON SHAREHOLDER'S EQUITY $ 791,498 $ 713,449 ---------- ---------- PREFERRED STOCK: $100 par value - authorized shares 2,500,000 $25 par value - authorized shares 7,000,000 Call Price Shares December 31, Number of Shares Redeemed Outstanding Series 2001 Year Ended December 31, December 31, 2001 - ------ ------------ ---------------------------- ----------------- 2001 2000 1999 ---- ---- ---- Subject to Mandatory Redemption: 7.00% (a) 50,000 100,000 - 100,000 10,000 15,000 ---------- ---------- LONG-TERM DEBT (See Schedule of Long-term Debt): Notes - Affiliated 200,000 First Mortgage Bonds 243,197 537,119 Installment Purchase Contracts 91,220 91,166 Senior Unsecured Notes 147,458 159,318 Junior Debentures 109,973 112,012 Less Portion Due Within One Years (220,500) - ---------- ---------- Total Long-term Debt Excluding Portion Due Within One Year 571,348 899,615 ---------- ---------- TOTAL CAPITALIZATION $1,372,846 $1,628,064 ========== ==========
(a) A sinking fund requires the redemption of 50,000 shares at $100 a share on or before August 1 of each year. The Company has the right, on each sinking fund date, to redeem an additional 50,000 shares which the Company did in August 2000. The sinking fund provisions of the 7% series aggregate $5,000,000 in 2002 and 2003. See Notes to Financial Statements beginning on page L-1. COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Schedule of Long-term Debt First mortgage bonds outstanding were as follows: December 31, -------------------- 2001 2000 ---- ---- (in thousands) % Rate Due 7.25 2002 - October 1 $ 14,000 $ 56,500 7.15 2002 - November 1 6,500 20,000 6.80 2003 - May 1 13,000 45,000 6.60 2003 - August 1 25,000 40,000 6.10 2003 - November 1 5,000 20,000 6.55 2004 - March 1 26,500 50,000 6.75 2004 - May 1 26,000 50,000 8.70 2022 - July 1 2,000 35,000 8.40 2022 - August 1 - 15,000 8.55 2022 - August 1 15,000 15,000 8.40 2022 - August 15 14,000 25,500 8.40 2022 - October 15 13,000 13,000 7.90 2023 - May 1 40,000 50,000 7.75 2023 - August 1 33,000 33,000 7.45 2024 - March 1 - 30,000 7.60 2024 - May 1 11,000 41,000 Unamortized Discount (803) (1,881) -------- -------- Total $243,197 $537,119 ======== ======== First mortgage bonds are secured by first mortgage liens on electric utility plant. Certain indentures relating to the first mortgage bonds contain improvement, maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. Installment purchase contracts have been entered into in connection with the issuance of pollution control revenue bonds by the Ohio Air Quality Development Authority: December 31, 2001 2000 ---- ---- (in thousands) % Rate Due - ------ ----------------- 6-3/8 2020 - December 1 $48,550 $48,550 6-1/4 2020 - December 1 43,695 43,695 Unamortized Discount (1,025) (1,079) ------- ------- Total $91,220 $91,166 ======= ======= Under the terms of the installment purchase contracts, CSPCo is required to pay amounts sufficient to enable the payment of interest on and the principal (at stated maturities and upon mandatory redemptions) of related pollution control revenue bonds issued to finance the construction of pollution control facilities at the Zimmer Plant. Senior unsecured notes outstanding were as follows: December 31, 2001 2000 ---- ---- (in thousands) % Rate Due - ------ ------------------ 6.85 2005 - October 3 $ 36,000 $ 48,000 6.51 2008 - February 1 52,000 52,000 6.55 2008 - June 26 60,000 60,000 Unamortized Discount (542) (682) -------- -------- Total $147,458 $159,318 ======== ======== Notes payable to parent company were as follows: December 31, ---------------------- 2001 2000 ---- ---- (in thousands) % Rate Due Variable 2002 - Sept 25 $200,000 $ - Junior debentures outstanding were as follows: December 31, 2001 2000 ---- ---- (in thousands) % Rate Due - ------ ------------------ 8-3/8 2025 - Sept 30 $ 72,843 $ 75,000 7.92 2027 - March 31 40,000 40,000 Unamortized Discount (2,870) (2,988) -------- -------- Total $109,973 $112,012 ======== ======== Interest may be deferred and payment of principal and interest on the junior debentures is subordinated and subject in right to the prior payment in full of all senior indebtedness of the Company. At December 31, 2001, future annual long-term debt payments are as follows: Amount ------ (in thousands) 2002 $220,500 2003 43,000 2004 52,500 2005 36,000 2006 - Later Years 445,088 Total Principal Amount 797,088 Unamortized Discount (5,240) --------- Total $791,848 ======== COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Index to Notes to Consolidated Financial Statements The notes to CSPCo's financial statements are combined with the notes to financial statements for AEP and its other subsidiary registrants. Listed below are the combined notes that apply to CSPCo. The combined footnotes begin on page L-1. Combined Footnote Reference Significant Accounting Policies Note 1 Extraordinary Items and Cumulative Effect Note 2 Effects of Regulation Note 6 Customer Choice and Industry Restructuring Note 7 Commitments and Contingencies Note 8 Benefit Plans Note 10 Business Segments Note 12 Risk Management, Financial Instruments and Derivatives Note 13 Income Taxes Note 14 Supplementary Information Note 16 Leases Note 18 Lines of Credit and Sale of Receivable Note 19 Unaudited Quarterly Financial Information Note 20 Jointly Owned Electric Utility Plant Note 23 Related Party Transactions Note 24 INDEPENDENT AUDITORS' REPORT To the Shareholders and Board of Directors of Columbus Southern Power Company: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Columbus Southern Power Company and its subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Columbus Southern Power Company and its subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America. Deloitte & Touche LLP Columbus, Ohio February 22, 2002 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Selected Consolidated Financial Data Year Ended December 31, 2001 2000 1999 1998 1997 ---- ---- ---- ---- ---- (in thousands) INCOME STATEMENTS DATA: Operating Revenues $4,803,625 $3,542,084 $2,920,187 $2,435,646 $1,391,917 Operating Expenses 4,643,920 3,576,786 2,811,535 2,269,639 1,184,129 ---------- ---------- ---------- ---------- ---------- Operating Income (Loss) 159,705 (34,702) 108,652 166,007 207,788 Nonoperating Income (Loss) 9,730 9,933 4,530 (839) 4,415 Interest Charges 93,647 107,263 80,406 68,540 65,463 ---------- ---------- ---------- ---------- ---------- Net Income (Loss) 75,788 (132,032) 32,776 96,628 146,740 Preferred Stock Dividend Requirements 4,621 4,624 4,885 4,824 5,736 ---------- ---------- ---------- ---------- ---------- Earnings (Loss) Applicable to Common Stock $ 71,167 $ (136,656) $ 27,891 $ 91,804 $ 141,004 ========== ========== ========== ========== ========== December 31, 2001 2000 1999 1998 1997 ---- ---- ---- ---- ---- (in thousands) BALANCE SHEETS DATA: Electric Utility Plant $4,923,721 $4,871,473 $4,770,027 $4,631,848 $4,514,497 Accumulated Depreciation and Amortization 2,436,972 2,280,521 2,194,397 2,081,355 1,973,937 ---------- ---------- ---------- ---------- ---------- Net Electric Utility Plant $2,486,749 $2,590,952 $2,575,630 $2,550,493 $2,540,560 ========== ========== ========== ========== ========== Total Assets $4,817,008 $5,811,038 $4,576,696 $4,148,523 $3,967,798 ========== ========== ========== ========== ========== Common Stock and Paid-in Capital $ 789,800 $ 789,656 $ 789,323 $ 789,189 $ 789,056 Accumulated Other Comprehensive Income (Loss) (3,835) - - - - Retained Earnings 74,605 3,443 166,389 253,154 278,814 ---------- ---------- ---------- ---------- ---------- Total Common Shareholder's Equity $ 860,570 $ 793,099 $ 955,712 $1,042,343 $1,067,870 ========== ========== ========== ========== ========== Cumulative Preferred Stock: Not Subject to Mandatory Redemption $ 8,736 $ 8,736 $ 9,248 $ 9,273 $ 9,435 Subject to Mandatory Redemption (a) 64,945 64,945 64,945 68,445 68,445 ---------- ---------- ---------- ---------- ---------- Total Cumulative Preferred Stock $ 73,681 $ 73,681 $ 74,193 $ 77,718 $ 77,880 ========== ========== ========== ========== ========== Long-term Debt (a) $1,652,082 $1,388,939 $1,324,326 $1,175,789 $1,049,237 ========== ========== ========== ========== ========== Obligations Under Capital Leases (a) $ 61,933 $ 163,173 $ 187,965 $ 186,427 $ 195,227 ========== ========== ========== ========== ========== Total Capitalization And Liabilities $4,817,008 $5,811,038 $4,576,696 $4,148,523 $3,967,798 ========== ========== ========== ========== ==========
(a) Including portion due within one year. (a) INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Management's Discussion and Analysis of Results of Operations I&M is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to 567,000 retail customers in its service territory in northern and eastern Indiana and a portion of southwestern Michigan. As a member of the AEP Power Pool, I&M shares the revenues and the costs of the AEP Power Pool's wholesale sales to neighboring utilities and power marketers including power trading transactions. I&M also sells wholesale power to municipalities and electric cooperatives. The cost of the AEP System's generating capacity is allocated among the AEP Power Pool members based on their relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity credits. AEP Power Pool members are also compensated for the out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each company's prior twelve month peak demand relative to the total peak demand of all member companies as a basis for sharing revenues and costs. The result of this calculation is each company's member load ratio (MLR) which determines each company's percentage share of revenues and costs. I&M is committed under unit power agreements to purchase all of AEGCo's 50% share of the 2,600 MW Rockport Plant capacity unless it is sold to other utilities. AEGCo is an affiliate that is not a member of the AEP Power Pool. A long-term unit power agreement with an unaffiliated utility expired at the end of 1999 for the sale of 455 MW of AEGCo's Rockport Plant capacity. An agreement between AEGCo and KPCo provides for the sale of 390 MW of AEGCo's Rockport Plant capacity to KPCo through 2004. Therefore, effective January 1, 2000, I&M began purchasing 910 MW of AEGCo's 50% share of Rockport Plant capacity. Critical Accounting Policies - Revenue Recognition Regulatory Accounting - As a cost-based rate-regulated electric public utility company, I&M's consolidated financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate regulated. In accordance with SFAS 71, regulatory assets (deferred expenses) and regulatory liabilities (future revenue reductions or refunds) are recorded to reflect the economic effects of regulation by matching expenses with their recovery through regulated revenues in the same accounting period. When regulatory assets are probable of recovery through regulated rates, we record them as assets on the balance sheet. We test for probability of recovery whenever new events occur, for example a regulatory commission order or passage of new legislation. If we determine that recovery of a regulatory asset is no longer probable, we write off that regulatory asset as a charge against net income. A write off of regulatory assets may also reduce future cash flows since there may be no recovery through regulated rates. Traditional Electricity Supply and Delivery Activities - We recognize revenues on an accrual basis for electricity supply sales and electricity transmission and distribution delivery services. The revenues are recognized in our income statement when the energy is delivered to the customer and include unbilled as well as billed amounts. In general expenses are recorded when incurred. Energy Marketing and Trading Activities - AEP engages in wholesale electricity marketing and trading transactions (trading activities). A portion of the revenues and costs of AEP's trading activities are allocated to I&M as a member of the AEP Power Pool. Trading activities involve the purchase and sale of energy under physical forward contracts at fixed and variable prices and buying and selling financial energy contracts which includes exchange traded futures and options and over-the-counter options and swaps. The majority of trading activities represent physical forward electricity contracts that are typically settled by entering into offsetting physical contracts. Although trading contracts are generally short-term, there are also long-term trading contracts. Accounting standards applicable to trading activities require that changes in the fair value of trading contacts be recognized in revenues prior to settlement and is commonly referred to as mark-to-market (MTM) accounting. Since I&M is a cost-based rate-regulated entity, changes in the fair value of physical forward sale and purchase contracts in AEP's traditional marketing area are deferred as regulatory liabilities (gains) or regulatory assets (losses). The deferral reflects the fact that power sales and purchases are included in regulated rates on a settlement basis. AEP's traditional marketing area is up to two transmission systems from the AEP service territory. The change in the fair value of physical forward sale and purchase contracts outside AEP's traditional marketing area is included in nonoperating income on a net basis. Mark-to-market accounting represents the change in the unrealized gain or loss throughout the contract's term. When the contract actually settles, that is, the energy is actually delivered in a sale or received in a purchase or the parties agree to forego delivery and receipt of electricity and net settle in cash, the unrealized gain or loss is reversed and the actual realized cash gain or loss is recognized in the income statement. Therefore, as the contract's market value changes over the contract's term an unrealized gain or loss is deferred for contracts with delivery points in AEP's traditional marketing area and for contracts with delivery points outside of AEP's traditional marketing area the unrealized gain or loss is recognized as nonoperating income. When the contract settles the total gain or loss is realized in cash and the impact on the income statement depends on whether the contract's delivery points are within or outside of AEP's traditional marketing area. For contracts with delivery points in AEP's traditional marketing area, the total gain or loss realized in cash is recognized in the income statement. Physical forward trading sale contracts with delivery points in AEP's traditional marketing area are included in revenues when the contracts settle. Physical forward trading purchase contracts with delivery points in AEP's traditional marketing area are included in purchased power expense when they settle. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts in AEP's traditional marketing area are deferred as regulatory liabilities (gains) or regulatory assets (losses). For contacts with delivery points outside of AEP's traditional marketing area only the difference between the accumulated unrealized net gains or losses recorded in prior months and the cash proceeds is recognized in the income statement. Physical forward sales contracts for delivery outside of AEP's traditional marketing area are included in nonoperating income when the contract settles. Physical forward purchase contracts for delivery outside of AEP's traditional marketing area are included in nonoperating expenses when the contract settles. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts with delivery points outside of AEP's traditional marketing area are included in nonoperating income on a net basis. Unrealized mark-to-market gains and losses are included in the Balance Sheet as energy trading contract assets or liabilities as appropriate. Trading of electricity options, futures and swaps, represents financial transactions with unrealized gains and losses from changes in fair values reported net in non-operating income until the contracts settle. When these financial contracts settle, we record our share of the net proceeds in non-operating income and reverse to nonoperating income the prior unrealized gain or loss. The fair value of open short-term trading contracts are based on exchange prices and broker quotes. We mark-to-market open long-term trading contracts based mainly on AEP-developed valuation models. These models estimate future energy prices based on existing market and broker quotes and supply and demand market data and assumptions. The fair values determined are reduced by reserves to adjust for credit risk and liquidity risk. Credit risk is the risk that the counterparty to the contract will fail to perform or fail to pay amounts due AEP. Liquidity risk represents the risk that imperfections in the market will cause the price to be less than or more than what the price should be based purely on supply and demand. There are inherent risks related to the underlying assumptions in models used to fair value open long-term trading contracts. AEP has independent controls to evaluate the reasonableness of our valuation models. However, energy markets, especially electricity markets, are imperfect and volatile and unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a contract's term and when contracts settle. Therefore, there could be significant adverse or favorable effects on future results of operations and cash flows if market prices do not correlate with the AEP-developed price models. Volatility in commodities markets affects the fair values of all of our open trading contracts exposing I&M to market risk. See "Market Risks" section of MD&A for a discussion of the policies and procedures used to manage exposure to risk from trading activities. Results of Operations During 2000 both of the Cook Plant nuclear units were successfully restarted after being shutdown in September 1997 due to questions regarding the operability of certain safety systems which arose during a NRC architect engineer design inspection. See discussion in Note 4 of the Notes to Financial Statements. A reduction in other operation and maintenance expense in 2001 reflects the completion of restart work on the Cook Plant and was the primary reason for a $208 million increase in net income. As a result of the costs incurred in 2000 to restart the Cook Plant nuclear units and a disallowance of interest deductions for a corporate owned life insurance (COLI) program, net income declined $165 million in 2000. In February 2001 the U.S. District Court for the Southern District of Ohio ruled against AEP and certain of its subsidiaries, including I&M, in a suit over deductibility of interest claimed in AEP's consolidated tax return related to COLI. In 1998 and 1999 I&M paid the disputed taxes and interest attributable to the COLI interest deductions for the taxable years 1991-98 and deferred them. Operating Revenues Increase Operating revenues increased 36% in 2001 and 21% in 2000 due to increased wholesale marketing and trading sales. The following analyzes the changes in operating revenues: Increase (Decrease) From Previous Year (dollars in millions) 2001 2000 ------------------------------ Amount % Amount % Retail* $ (2.3) N.M. $(88.6) (12) Marketing and Trading 1,210.7 52 564.0 32 Other 5.0 13 (13.0) (26) -------- ------ 1,213.4 40 462.4 18 Energy Delivery* 3.4 1 0.1 N.M. Sales to AEP Affiliates 44.7 21 159.4 313 -------- ------ Total $1,261.5 36 $621.9 21 ======== ====== N.M. = Not Meaningful *Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery. The increase in operating revenues in 2001 and 2000 is primarily due to an increase in wholesale marketing and trading activities. The maturing of the Intercontinental Exchange, the development of proprietary tools, and increased staffing of energy traders have resulted in an increase in the number of forward electricity purchase and sale contracts in AEP's traditional marketing area. A decline in retail revenues partly offset the increase in wholesale marketing and trading revenues. Retail revenues decreased in 2000 when the accrual of power supply recovery revenues ceased at the end of 1999 pursuant to Cook Plant settlement agreements. The accrued power supply recovery revenues are being amortized over a five-year period ending December 31, 2003. I&M increased its sales to AEP affiliates in 2000 when additional electricity became available. The return to service of the Cook Plant units and purchasing more power from AEGCo due to the expiration of AEGCo's contract to sell power to an unaffiliated entity, increased the amount of power I&M could sell to its affiliates in the AEP Power Pool. Operating Expenses Increase Total operating expenses increased 30% in 2001 and 27% in 2000 primarily due to additional purchases of power for marketing and trading and due to the expiration of an AEGCo unit power agreement to sell part of its Rockport Plant generation to an unaffiliated utility. Also contributing to the increase in operating expenses in 2000 was the unfavorable COLI tax ruling and costs related to the extended Cook Plant outage and restart efforts. The changes in the components of operating expenses were: Increase (Decrease) From Previous Year (dollars in millions) 2001 2000 ----------------------------- Amount % Amount % Fuel $ 39.2 19 $ 25.5 14 Marketing and Trading Purchases 1,227.7 59 462.9 29 AEP Affiliate Purchases (27.2) (10) 65.1 32 Other Operation (147.8) (25) 137.5 30 Maintenance (92.6) (42) 84.5 62 Depreciation and Amortization 9.3 6 4.9 3 Taxes Other Than Income Taxes 4.9 8 (5.2) (8) Income Taxes 53.6 N.M. (9.9) (95) ------- ------ Total $1,067.1 30 $765.3 27 ======== ====== N.M. = Not Meaningful The increase in fuel expense in 2001 and 2000 reflects an increase in nuclear generation as the Cook Plant units returned to service following the extended outage. Electricity marketing and trading purchased power expense increased in 2001 and 2000 due to AEP's effort to grow its wholesale marketing and trading business. The decline in purchased power from AEP affiliates in 2001 reflects generation from the Cook Plant replacing purchases from the AEP Power Pool. Purchases from the AEP Power Pool declined 21% in 2001. As a result of the expiration of AEGCo's power sale contract with an unaffiliated utility on December 31, 1999, I&M was obligated to buy more of AEGCo's share of Rockport Plant power. Purchases from AEGCo increased 91% in 2000. The decrease in other operation and maintenance expenses in 2001 was primarily due to the cessation of expenditures to prepare the Cook Plant nuclear units for restart with their return to service in 2000. Other operation and maintenance expenses increased in 2000 primarily due to expenditures to prepare the Cook Plant units for restart. In 1999 the IURC and MPSC approved settlement agreements which allowed the deferral of $200 million of Cook Plant restart costs in 1999 for amortization over five years from 1999 through 2003. As a result, other operation and maintenance expense in 1999 reflected a net deferral of $160 million. See discussion in Note 4 of the Notes to Financial Statements. The increase in depreciation and amortization charges in 2001 reflects increased generation and distribution plant investments and amortization of I&M's share of deferred merger costs. Taxes other than income taxes increased in 2001 due to higher real and personal property tax expense from the effect of a favorable accrual adjustment recorded in December 2000 to match estimated amounts with actual expenses. The decrease in taxes other than income tax in 2000 is primarily attributable to decreases in real and personal property taxes reflecting the favorable accrual adjustment and Indiana gross receipts taxes reflecting an unfavorable accrual adjustment related to the 1998 tax year recorded in 1999 for gross receipts tax. The significant increase in income taxes attributable to operations in 2001 is due to an increase in pre-tax operating income. Income taxes attributable to operations decreased in 2000 due to a decrease in pre-tax operating income. Nonoperating Income and Expenses Increase The increases in nonoperating income and expenses in 2001 and 2000 is primarily due to increased volume of forward electricity trading transactions outside AEP's traditional marketing area. Nonoperating power trading revenues increased 70% in 2001 and 95% in 2000. Nonoperating power trading expenses increased 70% in 2001 and 93% in 2000. Interest Charges The decrease in 2001 interest charges reflects the recognition in 2000 of deferred interest payments to the IRS on disputed income taxes from the disallowance of tax deductions for COLI interest for the years 1991-1998. Interest charges increased in 2000 due to increased borrowings to support expenditures for the Cook Plant restart effort and the recognition of deferred interest payments to the IRS on the disputed taxes.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Income Year Ended December 31, ------------------------------------------ 2001 2000 1999 ---- ---- ---- (in thousands) OPERATING REVENUES: Electricity Marketing and Trading $4,234,176 $3,020,757 $2,558,338 Energy Delivery 314,410 311,019 310,880 Sales to AEP Affiliates 255,039 210,308 50,969 ------- ------- ------ TOTAL OPERATING REVENUES 4,803,625 3,542,084 2,920,187 --------- --------- --------- OPERATING EXPENSES: Fuel 250,098 210,870 185,419 Purchased Power: Electricity Marketing and Trading 3,293,255 2,065,509 1,602,658 AEP Affiliates 238,237 265,475 200,372 Other Operation 451,195 599,012 461,494 Maintenance 127,263 219,854 135,331 Depreciation and Amortization 164,230 154,920 149,988 Taxes other Than Income Taxes 65,518 60,622 65,843 Income Taxes 54,124 524 10,430 ------ --- ------ TOTAL OPERATING EXPENSES 4,643,920 3,576,786 2,811,535 --------- --------- --------- OPERATING INCOME (LOSS) 159,705 (34,702) 108,652 NONOPERATING INCOME 1,474,572 869,895 452,019 NONOPERATING EXPENSES 1,459,799 855,773 446,183 NONOPERATING INCOME TAX EXPENSE 5,043 4,189 1,306 INTEREST CHARGES 93,647 107,263 80,406 ------ ------- ------ NET INCOME (LOSS) 75,788 (132,032) 32,776 PREFERRED STOCK DIVIDEND REQUIREMENTS 4,621 4,624 4,885 ----- ----- ----- EARNINGS (LOSS) APPLICABLE TO COMMON STOCK $ 71,167 $ (136,656) $ 27,891 ======== ========== ========
Consolidated Statements of Comprehensive Income Year Ended December 31, ----------------------------------------- 2001 2000 1999 ---- ---- ---- (in thousands) NET INCOME (LOSS) $75,788 $(132,032) $32,776 OTHER COMPREHENSIVE INCOME (LOSS) Cash Flows Interest Rate Hedge (3,835) - - ------ ------- ---- COMPREHENSIVE INCOME (LOSS) $71,953 $(132,032) $32,776 ======= ========= ======= See Notes to Financial Statements beginning on page L-1. INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Consolidated Balance Sheets December 31, 2001 2000 ---- ---- (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production $2,758,160 $2,708,436 Transmission 957,336 945,709 Distribution 900,921 863,736 General (including nuclear fuel) 233,005 257,152 Construction Work in Progress 74,299 96,440 ------ ------ Total Electric Utility Plant 4,923,721 4,871,473 Accumulated Depreciation and Amortization 2,436,972 2,280,521 --------- --------- NET ELECTRIC UTILITY PLANT 2,486,749 2,590,952 --------- --------- NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR FUEL DISPOSAL TRUST FUNDS 834,109 778,720 ------- ------- LONG-TERM ENERGY TRADING CONTRACTS 215,544 194,554 ------- ------- OTHER PROPERTY AND INVESTMENTS 127,977 131,417 ------- ------- CURRENT ASSETS: Cash and Cash Equivalents 16,804 14,835 Advances to Affiliates 46,309 - Accounts Receivable: Customers 60,864 106,832 Affiliated Companies 31,908 48,706 Miscellaneous 25,398 27,491 Allowance for Uncollectible Accounts (741) (759) Fuel - at average cost 28,989 16,532 Materials and Supplies - at average cost 91,440 84,471 Energy Trading Contracts 399,195 1,222,925 Accrued Utility Revenues 2,072 - Prepayments 6,497 6,066 ----- ----- TOTAL CURRENT ASSETS 708,735 1,527,099 ------- --------- REGULATORY ASSETS 408,927 552,140 ------- ------- DEFERRED CHARGES 34,967 36,156 ------ ------ TOTAL $4,817,008 $5,811,038 ========== ========== See Notes to Financial Statements beginning on page L-1. INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES December 31, ------------ 2001 2000 ---- ---- (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock - No Par Value: Authorized - 2,500,000 Shares Outstanding - 1,400,000 Shares $ 56,584 $ 56,584 Paid-in Capital 733,216 733,072 Accumulated Other Comprehensive Income (Loss) (3,835) - Retained Earnings 74,605 3,443 ------ ----- Total Common Shareholder's Equity 860,570 793,099 Cumulative Preferred Stock: Not Subject to Mandatory Redemption 8,736 8,736 Subject to Mandatory Redemption 64,945 64,945 Long-term Debt 1,312,082 1,298,939 --------- --------- TOTAL CAPITALIZATION 2,246,333 2,165,719 --------- --------- OTHER NONCURRENT LIABILITIES: Nuclear Decommissioning 600,244 560,628 Other 87,025 108,600 ------ ------- TOTAL OTHER NONCURRENT LIABILITIES 687,269 669,228 ------- ------- CURRENT LIABILITIES: Long-term Debt Due Within One Year 340,000 90,000 Advances from Affiliates - 253,582 Accounts Payable - General 90,817 119,472 Accounts Payable - Affiliated Companies 43,956 75,486 Taxes Accrued 69,761 68,416 Interest Accrued 20,691 21,639 Obligations Under Capital Leases 10,840 100,848 Energy Trading and Derivative Contracts 383,714 1,267,981 Other 72,435 97,070 ------ ------ TOTAL CURRENT LIABILITIES 1,032,214 2,094,494 --------- --------- DEFERRED INCOME TAXES 400,531 487,945 ------- ------- DEFERRED INVESTMENT TAX CREDITS 105,449 113,773 ------- ------- DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2 77,592 81,299 ------ ------ LONG-TERM ENERGY TRADING CONTRACTS 175,581 156,343 ------- ------- DEFERRED CREDITS 92,039 42,237 ------ ------ COMMITMENTS AND CONTINGENCIES (Note 8) TOTAL $4,817,008 $5,811,038 ========== ========== See Notes to Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Cash Flows Year Ended December 31, 2001 2000 1999 ---- ---- ---- (in thousands) OPERATING ACTIVITIES: Net Income (Loss) $75,788 $(132,032) $32,776 Adjustments for Noncash Items: Depreciation and Amortization 166,360 163,391 153,921 Amortization of Incremental Nuclear Refueling Outage Expenses (net) 418 5,737 8,480 Amortization (Deferral) of Nuclear Outage Costs (net) 40,000 40,000 (160,000) Deferred Federal Income Taxes (29,205) (125,179) 85,727 Deferred Investment Tax Credits (8,324) (7,854) (8,152) Mark-to-Market of Energy Trading Contracts (19,502) (10,859) (2,602) Unrecovered Fuel and Purchased Power Costs 37,501 37,501 (84,696) Changes in Certain Current Assets And Liabilities: Accounts Receivable (net) 64,841 (25,305) (19,178) Fuel, Materials and Supplies (19,426) 10,743 (12,880) Accrued Utility Revenues (2,072) 44,428 (7,151) Accounts Payable (60,185) 85,056 19,068 Taxes Accrued 1,345 19,446 13,809 Disputed Tax and Interest Related to COLI - 56,856 (3,228) Change in Other Assets (5,871) (68,160) (48,879) Change in Other Liabilities (5,461) 37,668 63,763 ------ ------ ------ Net Cash Flows From Operating Activities 236,207 131,437 30,778 ------- ------- ------ INVESTING ACTIVITIES: Construction Expenditures (91,052) (171,071) (165,331) Buyout of Nuclear Fuel Leases (92,616) - - Other 1,074 587 2,501 ----- --- ----- Net Cash Flows Used For Investing Activities (182,594) (170,484) (162,830) -------- -------- -------- FINANCING ACTIVITIES: Issuance of Long-term Debt 297,656 199,220 247,989 Retirement of Cumulative Preferred Stock - (314) (3,597) Retirement of Long-term Debt (44,922) (148,000) (109,500) Change in Advances from Affiliates (net) (299,891) 253,582 - Change in Short-term Debt (net) - (224,262) 115,562 Dividends Paid on Common Stock - (26,290) (114,656) Dividends Paid on Cumulative Preferred Stock (4,487) (3,368) (5,856) ------ ------ ------ Net Cash Flows From (Used For) Financing Activities (51,644) 50,568 129,942 ------- ------ ------- Net Increase (Decrease) in Cash and Cash Equivalents 1,969 11,521 (2,110) Cash and Cash Equivalents January 1 14,835 3,314 5,424 ------ ----- ----- Cash and Cash Equivalents December 31 $16,804 $ 14,835 $ 3,314 ======= ======== =======
Supplemental Disclosure: Cash paid (received) for interest net of capitalized amounts was $92,140,000,$82,511,000 and $78,703,000 and for income taxes was $100,470,000, $73,254,000 and $(71,395,000) in 2001, 2000 and 1999, respectively. Noncash acquisitions under capital leases were $1,023,000, $22,218,000 and $10,852,000 in 2001, 2000 and 1999, respectively. See Notes to Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Retained Earnings Year Ended December 31, 2001 2000 1999 ---- ---- ---- (in thousands) Retained Earnings January 1 $3,443 $ 166,389 $253,154 Net Income (Loss) 75,788 (132,032) 32,776 ------ -------- ------ 79,231 34,357 285,930 ------ ------ ------- Deductions: Cash Dividends Declared: Common Stock - 26,290 114,656 Cumulative Preferred Stock: 4-1/8% Series 229 230 244 4.56% Series 66 66 66 4.12% Series 72 74 78 5.90% Series 897 897 963 6-1/4% Series 1,203 1,203 1,250 6.30% Series 834 834 834 6-7/8% Series 1,186 1,186 1,238 ----- ----- ----- Total Cash Dividends Declared 4,487 30,780 119,329 Capital Stock Expense 139 134 212 --- --- --- Total Deductions 4,626 30,914 119,541 ----- ------ ------- Retained Earnings December 31 $ 74,605 $ 3,443 $166,389 ======== ======= ========
See Notes to Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Capitalization December 31, ---------------------------- 2001 2000 ---- ---- (in thousands) COMMON SHAREHOLDER'S EQUITY $ 860,570 $ 793,099 ---------- ---------- PREFERRED STOCK: $100 Par Value - Authorized 2,250,000 shares $25 Par Value - Authorized 11,200,000 shares Call Price Shares December 31, Number of Shares Redeemed Outstanding Series 2001 Year Ended December 31, December 31, 2001 - ------ ------------ ------------------------ ----------------- 2001 2000 1999 ---- ---- ---- Not Subject to Mandatory Redemption: 4-1/8% 106.125 - 3,750 97 55,389 5,539 5,539 4.56% 102 - - 150 14,412 1,441 1,441 4.12% 102.728 - 1,375 - 17,556 1,756 1,756 ---------- ---------- 8,736 8,736 ---------- ---------- Subject to Mandatory Redemption: 5.90% (a,b) - - 15,000 152,000 15,200 15,200 6-1/4% (a,b) - - 10,000 192,500 19,250 19,250 6.30% (a,b) - - - 132,450 13,245 13,245 6-7/8% (a,c) - - 10,000 172,500 17,250 17,250 ---------- ---------- 64,945 64,945 ---------- ---------- LONG-TERM DEBT (See Schedule of Long-term Debt): First Mortgage Bonds 264,141 308,976 Installment Purchase Contracts 310,239 309,717 Senior Unsecured Notes 696,144 397,435 Other Long-term Debt 219,947 211,307 Junior Debentures 161,611 161,504 Less Portion Due Within One Year (340,000) (90,000) ---------- ---------- Long-term Debt Excluding Portion Due Within One Year 1,312,082 1,298,939 ---------- ---------- TOTAL CAPITALIZATION $2,246,333 $2,165,719 ========== ==========
(a) Not callable until after 2002. There are no aggregate sinking fund provisions through 2002. Sinking fund provisions require the redemption of 15,000 shares in 2003 and 67,500 shares each year in 2004, 2005 and 2006. The sinking fund provisions of each series subject to mandatory redemption have been met by purchase of shares in advance of the due date. (b) Commencing in 2004 and continuing through 2008 the Company may redeem, at $100 per share, 20,000 shares of the 5.90% series, 15,000 shares of the 6-1/4% series and 17,500 shares of the 6.30% series outstanding under sinking fund provisions at its option and all remaining outstanding shares must be redeemed not later than 2009. Shares previously redeemed may be applied to meet the sinking fund requirement. (c) Commencing in 2003 and continuing through the year 2007, a sinking fund will require the redemption of 15,000 shares each year and the redemption of the remaining shares outstanding on April 1, 2008, in each case at $100 per share. Shares previously redeemed may be applied to meet the sinking fund requirement. See Notes to Financial Statements beginning on page L-1. INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Schedule of Long-term Debt First mortgage bonds outstanding were as follows: December 31, -------------------- 2001 2000 ---- ---- (in thousands) % Rate Due 7.63 2001 - June 1 $ - $ 40,000 7.60 2002 - November 1 50,000 50,000 7.70 2002 - December 15 40,000 40,000 6.10 2003 - November 1 30,000 30,000 8.50 2022 - December 15 75,000 75,000 7.35 2023 - October 1 15,000 20,000 7.20 2024 - February 1 30,000 30,000 7.50 2024 - March 1 25,000 25,000 Unamortized Discount (859) (1,024) -------- -------- $264,141 $308,976 First mortgage bonds are secured by first mortgage liens on electric utility plant. Certain indentures relating to the first mortgage bonds contain improvement, maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. Installment purchase contracts have been entered into, in connection with the issuance of pollution control revenue bonds by governmental authorities as follows: December 31, 2001 2000 ---- ---- (in thousands) % Rate Due - ------ ----------------- City of Lawrenceburg, Indiana: 7.00 2015 - April 1 $ 25,000 $ 25,000 5.90 2019 - November 1 52,000 52,000 City of Rockport, Indiana: (a) 2014 - August 1 50,000 50,000 7.60 2016 - March 1 40,000 40,000 6.55 2025 - June 1 50,000 50,000 (b) 2025 - June 1 50,000 50,000 City of Sullivan, Indiana: 5.95 2009 - May 1 45,000 45,000 Unamortized Discount (1,761) (2,283) -------- -------- $310,239 $309,717 (a) A variable interest rate is determined weekly. The average weighted interest rate was 2.4% for 2001 and 4.5% for 2000. (b) In June 2001 an auction rate was established. Auction rates are determined by standard procedures every 35 days. The auction rate for June through December 2001 ranged from 1.55% to 2.9% and averaged 2.4%. Prior to June 25, 2001, an adjustable interest rate was a daily, weekly, commercial paper or term rate as designated by I&M. A weekly rate was selected which ranged from 1.9% to 4.9% in 2001 and from 2.9% to 5.9% in 2000 and averaged 3.3% during 2001 and 4.2% during 2000. The terms of the installment purchase contracts require I&M to pay amounts sufficient for the cities to pay interest on and the principal (at stated maturities and upon mandatory redemptions) of related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain generating plants. On the variable rate series the principal is payable at the stated maturities or on the demand of the bondholders at periodic interest adjustment dates which occur weekly. The variable rate bonds due in 2014 are supported by a bank letter of credit which expires in 2002. Accordingly, the variable rate installment purchase contracts have been classified for repayment purposes based on the expiration date of the letter of credit. Senior unsecured notes outstanding were as follows: December 31, --------------------- 2001 2000 ---- ---- (in thousands) % Rate Due - ------ ------------------ (a) 2002 - September 3 $200,000 $200,000 6-7/8 2004 - July 1 150,000 150,000 6.125 2006 - December 15 300,000 - 6.45 2008 - November 10 50,000 50,000 Unamortized Discount (3,856) (2,565) -------- -------- $696,144 $397,435 (a) A floating interest rate is determined quarterly. The rate on December 31, 2001 and 2000 was 2.71% and 7.31%, respectively. The average interest rate was 5.1% in 2001 and 7.3% in 2000. Junior debentures outstanding were as follows: December 31, 2001 2000 ---- ---- (in thousands) % Rate Due - ------ ----------------- 8.00 2026 - March 31 $ 40,000 $ 40,000 7.60 2038 - June 30 125,000 125,000 Unamortized Discount (3,389) (3,496) -------- -------- Total $161,611 $161,504 ======== ======== Interest may be deferred and payment of principal and interest on the junior debentures is subordinated and subject in right to the prior payment in full of all senior indebtedness of I&M. At December 31, 2001, future annual long-term debt payments are as follows: Amount ------ (in thousands) 2002 $ 340,000 2003 30,000 2004 150,000 2005 - 2006 300,000 Later Years 841,947 ---------- Total Principal Amount 1,661,947 Unamortized Discount (9,865) ---------- Total $1,652,082 ========== INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Index to Notes to Financial Statements The notes to I&M's financial statements are combined with the notes to financial statements for AEP and its other subisidiary registrants. Listed below are the combined notes that apply to I&M. The combined footnotes begin on page L-1. Combined Footnote Reference Significant Accounting Policies Note 1 Merger Note 3 Nuclear Plant Restart Note 4 Effects of Regulation Note 6 Customer Choice and Industry Restructuring Note 7 Commitments and Contingencies Note 8 Benefit Plans Note 10 Business Segments Note 12 Risk Management, Financial Instruments and Derivatives Note 13 Income Taxes Note 14 Supplementary Information Note 16 Leases Note 18 Lines of Credit and Sale of Receivables Note 19 Unaudited Quarterly Financial Information Note 20 Related Party Transactions Note 24 INDEPENDENT AUDITORS' REPORT To the Shareholders and Board of Directors of Indiana Michigan Power Company: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Indiana Michigan Power Company and its subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of income, comprehensive income, retained earnings and cash flows for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Indiana Michigan Power Company and its subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America. DELOITTE & TOUCHE LLP Columbus, Ohio February 22, 2002 KENTUCKY POWER COMPANY
KENTUCKY POWER COMPANY Selected Financial Data Year Ended December 31, 2001 2000 1999 1998 1997 ---- ---- ---- ---- ---- (in thousands) INCOME STATEMENTS DATA: Operating Revenues $1,659,395 $1,176,867 $918,121 $705,562 $359,543 Operating Expenses 1,611,717 1,127,129 863,446 653,669 312,687 - --------- - --------- - ------- - ------- - ------- Operating Income 47,678 49,738 54,675 51,893 46,856 Nonoperating Income (Loss) 1,248 2,070 (327) (1,726) (464) Interest Charges 27,361 31,045 28,918 28,491 25,646 ---- ------ -- ------ -- ------ -- ------ -- ------ Net Income $ 21,565 $ 20,763 $ 25,430 $ 21,676 $ 20,746 ======== ======== ======== ======== ======== Year Ended December 31, 2001 2000 1999 1998 1997 ---- ---- ---- ---- ---- (in thousands) BALANCE SHEETS DATA: Electric Utility Plant $1,128,415 $1,103,064 $1,079,048 $1,043,711 $1,006,955 Accumulated Depreciation and Amortization 384,104 360,648 340,008 315,546 296,318 ------- ------- ------- ------- ------- Net Electric Utility Plant $744,311 $742,416 $739,040 $728,165 $710,637 ======== ======== ======== ======== ======== Total Assets $1,153,243 $1,509,064 $986,638 $921,847 $886,671 ========== ========== ======== ======== ======== Common Stock and Paid-in Capital $209,200 $209,200 $209,200 $199,200 $179,200 Accumulated Other Comprehensive Income (Loss) (1,903) Retained Earnings 48,833 57,513 67,110 71,452 78,076 ------ ------ ------ ------ ------ Total Common Shareholder's Equity $256,130 $266,713 $276,310 $270,652 $257,276 ======== ======== ======== ======== ======== Long-term Debt (a) $346,093 $330,880 $365,782 $368,838 $341,051 ======== ======== ======== ======== ======== Obligations Under Capital Leases(a) $ 9,583 $ 14,184 $ 15,141 $ 18,977 $ 18,725 ======= ======== ======== ======== ======== Total Capitalization and Liabilities $1,153,243 $1,509,064 $986,638 $921,847 $886,671 ========== ========== ======== ======== ========
(a) Including portion due within one year. KENTUCKY POWER COMPANY Management's Narrative Analysis of Results of Operations KPCo is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power serving 172,000 retail customers in eastern Kentucky. KPCo as a member of the AEP Power Pool shares in the revenues and costs of the AEP Power Pool's wholesale sales to neighboring utility systems and power marketers including power trading transactions. KPCo also sells wholesale power to municipalities. The cost of the AEP Power Pool's generating capacity is allocated among the Pool members based on their relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity credits. AEP Power Pool members are also compensated for their out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each company's prior twelve month peak demand relative to the total peak demand of all member companies as a basis for sharing revenues and costs. The result of this calculation is the member load ratio (MLR) which determines each company's percentage share of AEP Power Pool revenues and costs. Critical Accounting Policies - Revenue Recognition Regulatory Accounting - As a cost-based rate-regulated electric public utility company, KPCo's financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate regulated. In accordance with SFAS 71, regulatory assets (deferred expenses) and regulatory liabilities (future revenue reductions or refunds) are recorded to reflect the economic effects of regulation by matching expenses with their recovery through regulated revenues in the same accounting period. When regulatory assets are probable of recovery through regulated rates, we record them as assets on the balance sheet. We test for probability of recovery whenever new events occur, for example a regulatory commission order or passage of new legislation. If we determine that recovery of a regulatory asset is no longer probable, we write off that regulatory asset as a charge against net income. A write off of regulatory assets may also reduce future cash flows since there may be no recovery through regulated rates. Traditional Electricity Supply and Delivery Activities - We recognize revenues on an accrual basis for electricity supply sales and electricity transmission and distribution delivery services. The revenues are recognized in our income statement when the energy is delivered to the customer and include unbilled as well as billed amounts. In general expenses are recorded when incurred. Energy Marketing and Trading Activities - AEP engages in wholesale electricity marketing and trading transactions (trading activities). A portion of the revenues and costs of AEP's trading activities are allocated to KPCO as a member of the AEP Power Pool. Trading activities involve the purchase and sale of energy under physical forward contracts at fixed and variable prices and buying and selling financial energy contracts which includes exchange traded futures and options and over-the-counter options and swaps. The majority of trading activities represent physical forward electricity contracts that are typically settled by entering into offsetting physical contracts. Although trading contracts are generally short-term, there are also long-term trading contracts. Accounting standards applicable to trading activities require that changes in the fair value of trading contacts be recognized in revenues prior to settlement and is commonly referred to as mark-to-market (MTM) accounting. Since KPCO is a cost-based rate-regulated entity, changes in the fair value of physical forward sale and purchase contracts in AEP's traditional marketing area are deferred as regulatory liabilities (gains) or regulatory assets (losses). AEP's traditional marketing area is up to two transmission systems from the AEP Service territory. The change in the fair value of physical forward sale and purchase contracts outside AEP's traditional marketing area is included in nonoperating income on a net basis. Mark-to-market accounting represents the change in the unrealized gain or loss throughout the contract's term. When the contract actually settles, that is, the energy is actually delivered in a sale or received in a purchase or the parties agree to forego delivery and receipt of electricity and net settle in cash, the unrealized gain or loss is reversed and the actual realized cash gain or loss is recognized in the income statement. Therefore, as the contract's market value changes over the contract's term an unrealized gain or loss is deferred for contracts with delivery points in AEP's traditional marketing area and for contracts with delivery points outside of AEP's traditional marketing area the unrealized gain or loss is recognized as nonoperating income. When the contract settles the total gain or loss is realized in cash and the impact on the income statement depends on whether the contract's delivery points are within or outside of AEP's traditional marketing area. For contracts with delivery points in AEP's traditional marketing area, the total gain or loss realized in cash is recognized in the income statement. Physical forward trading sale contracts with delivery points in AEP's traditional marketing area are included in revenues when the contracts settle. Physical forward trading purchase contracts with delivery points in AEP's traditional marketing area are included in purchased power expense when they settle. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts in AEP's traditional marketing area are deferred as regulatory liabilities (gains) or regulatory assets (losses). For contacts with delivery points outside of AEP's traditional marketing area only the difference between the accumulated unrealized net gains or losses recorded in prior months and the cash proceeds is recognized in the income statement. Physical forward sales contracts for delivery outside of AEP's traditional marketing area are included in nonoperating income when the contract settles. Physical forward purchase contracts for delivery outside of AEP's traditional marketing area are included in nonoperating expenses when the contract settles. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts with delivery points outside of AEP's traditional marketing area are included in nonoperating income on a net basis. Unrealized mark-to-market gains and losses are included in the Balance Sheet as energy trading assets or liabilities as appropriate. Trading of electricity options, futures and swaps, represents financial transactions with unrealized gains and losses from changes in fair values reported net in nonoperating income until the contracts settle. When these financial contracts settle, we record our share of the net proceeds in nonoperating income and reverse to nonoperating income the prior unrealized gain or loss. The fair value of open short-term trading contracts are based on exchange prices and broker quotes. We mark-to-market open long-term trading contracts based mainly on AEP-developed valuation models. These models estimate future energy prices based on existing market and broker quotes and supply and demand market data and assumptions. The fair values determined are reduced by reserves to adjust for credit risk and liquidity risk. Credit risk is the risk that the counterparty to the contract will fail to perform or fail to pay amounts due AEP. Liquidity risk represents the risk that imperfections in the market will cause the price to be less than or more than what the price should be based purely on supply and demand. There are inherent risks related to the underlying assumptions in models used to fair value open long-term trading contracts. AEP has independent controls to evaluate the reasonableness of our valuation models. However, energy markets, especially electricity markets, are imperfect and volatile and unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a contract's term and when contracts settle. Therefore, there could be significant adverse or favorable effects on future results of operations and cash flows if market prices do not correlate with the AEP-developed price models. Volatility in commodities markets affects the fair values of all of our open trading contracts exposing KPCO to market risk. See "Market Risks" section of MD&A for a discussion of the policies and procedures used to manage exposure to risk from trading activities. Net Income Increases Net income increased $802 thousand or 4% in 2001 primarily due to the effect of a court decision related to a corporate owned life insurance (COLI) program recorded in 2000. In February 2001 the U.S. District Court for the Southern District of Ohio ruled against AEP and certain of its subsidiaries, including KPCo, in a suit over deductibility of interest claimed in AEP's consolidated tax return related to COLI. In 1998 and 1999 KPCo paid the disputed taxes and interest attributable to the COLI interest deductions for taxable years 1992-98. The payments were included in Other Property and Investments pending the resolution of this matter. Operating Revenues Increase Operating revenues increased $482.5 million or 41% in 2001 as a result of significant increases in trading activities in AEP's traditional marketing area. Changes in the components of operating revenues were as follows: Increase (Decrease) From Previous Year (dollars in millions) Amount % Retail* $(13.5) (9) Wholesale Marketing and Trading 486.4 57 Other (0.7) (4) ---- Subtotal 472.2 47 ----- Energy Delivery* 9.8 8 Sales to AEP Affiliates 0.5 1 --- Total $482.5 41 ====== *Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery. Retail revenues decreased as a result of mild weather conditions. Usage by residential customers declined in response to warmer temperatures during November and December 2001. Commercial and industrial sales were stable. The increase in wholesale marketing and trading revenues is driven by increased trading volume. The maturing of the Intercontinental Exchange, the development of propriety tools, and increased staffing of energy traders have resulted in an increase in the number of forward electricity purchase and sale contracts in AEP's traditional marketing area. Energy delivery revenues rose largely from providing additional transmission services as a result of increased wholesale marketing and trading transactions and from increased assignment of fees for transmission and distribution delivery services. Operating Expenses Increase Operating expenses increased $484.6 million in 2001 primarily due to increases in purchased power for trading activity. Changes in the components of operating expenses were as follows: Increase (Decrease) From Previous Year) (dollars in millions) Amount % Fuel $ (4.0) (5) Marketing and Trading Purchases 491.4 62 AEP Affiliate Purchases 2.5 2 Other Operation 5.9 11 Maintenance (3.4) (13) Depreciation and Amortization 1.5 5 Taxes Other Than Income Taxes 0.6 8 Income Taxes (9.9) (51) ---- Total $484.6 43 ====== The decrease in fuel expense is a result of sharing profits from the trading of power with customers in accordance with the Kentucky Public Service Commission's fuel clause mechanism. Under this mechanism, the profits from KPCo's portion of AEP's wholesale marketing and trading activities are shared with retail customers. This sharing is recognized through credits to fuel expense, thus reducing fuel expense. Increases in wholesale marketing and trading volume accounted for the significant increase in purchased power expense. The increase in other operation expense is attributable to increased trading incentive compensation expense, reduced AEP transmission equalization credits and expenses for a full year of factoring accounts receivable. Under the AEP East Region Transmission Agreement, KPCo and certain affiliates share the costs associated with the ownership of their transmission system based upon each company's peak demand and investment. An increase in KPCo's peak demand relative to its affiliates' peak demand was the main reason for the decline in transmission equalization credits. Factoring of accounts receivable began in June 2000. In 2001 we incurred a full year of factoring expenses compared with a partial year in 2000. Lower maintenance expense in 2001 is a result of performing significant planned maintenance at the Big Sandy Plant in 2000 for which there was no comparable activity in the current year. Additions to property, plant and equipment accounted for the increase in depreciation expense. These additions included capitalized software and general distribution equipment upgrades and improvements. Taxes other than income taxes rose as a result of increases in real and personal property tax accruals reflecting higher taxable property values. The decrease in income tax expense was primarily due to a decrease in pre-tax book income and the effect of an unfavorable ruling in 2000 in AEP's suit against the government over interest deductions claimed in prior years related to AEP's COLI program. Nonoperating Income and Nonoperating Expenses Increase The increase in nonoperating income and nonoperating expenses was due to an increase in nonregulated electric trading activities outside AEP's traditional marketing area. Interest Charges Decrease The decline in interest expense was due to the effect of recognizing in 2000 previously deferred interest payments to the IRS related to the COLI disallowances and interest on resultant state income tax deficiencies.
KENTUCKY POWER COMPANY Statements of Income Year Ended December 31, ----------------------------------------- 2001 2000 1999 ---- ---- ---- (in thousands) OPERATING REVENUES: Electricity Marketing and Trading $1,485,846 $1,013,700 $744,706 Energy Delivery 131,183 121,346 129,113 Sales to AEP Affiliates 42,366 41,821 44,302 ------ ------ ------ TOTAL REVENUES 1,659,395 1,176,867 918,121 --------- --------- ------- OPERATING EXPENSES: Fuel 70,635 74,638 84,369 Purchased Power: Electricity Marketing and Trading 1,279,556 788,102 567,902 AEP Affiliates 130,204 127,707 84,000 Other Operation 59,175 53,325 52,468 Maintenance 22,444 25,866 21,452 Depreciation and Amortization 32,491 31,028 29,221 Taxes Other Than Income Taxes 7,854 7,251 8,091 Income Taxes 9,358 19,212 15,943 ----- ------ ------ TOTAL OPERATING EXPENSES 1,611,717 1,127,129 863,446 --------- --------- ------- OPERATING INCOME 47,678 49,738 54,675 NONOPERATING INCOME 569,603 334,950 156,783 NONOPERATING EXPENSES 567,679 331,751 157,276 NONOPERATING INCOME TAX EXPENSE (CREDIT) 684 1,129 (166) INTEREST CHARGES 27,361 31,045 28,918 ------ ------ ------ NET INCOME $ 21,565 $ 20,763 $ 25,430 ======== ======== ========
Statements of Comprehensive Income Year Ended December 31, ----------------------------------------- 2001 2000 1999 ---- ---- ---- (in thousands) NET INCOME $21,565 $20,763 $25,430 OTHER COMPREHENSIVE INCOME (LOSS) Cash Flow Interest Rate Hedge (1,903) - - ------ ---- ---- COMPREHENSIVE INCOME $19,662 $20,763 $25,430 ======= ======= =======
Statements of Retained Earnings Year Ended December 31, ------------------------------------- 2001 2000 1999 ---- ---- ---- (in thousands) RETAINED EARNINGS JANUARY 1 $57,513 $67,110 $71,452 NET INCOME 21,565 20,763 25,430 CASH DIVIDENDS DECLARED 30,245 30,360 29,772 ------ ------ ------ RETAINED EARNINGS DECEMBER 31 $48,833 $57,513 $67,110 ======= ======= =======
See Notes to Financial Statements Beginning on Page L-1. KENTUCKY POWER COMPANY Balance Sheets December 31, ------------------------ 2001 2000 ---- ---- (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production $271,070 $271,107 Transmission 374,116 360,563 Distribution 402,537 387,499 General 65,059 67,476 Construction Work in Progress 15,633 16,419 ------ ------ Total Electric Utility Plant 1,128,415 1,103,064 Accumulated Depreciation and Amortization 384,104 360,648 ------- ------- NET ELECTRIC UTILITY PLANT 744,311 742,416 ------- ------- OTHER PROPERTY AND INVESTMENTS 6,492 6,559 ----- ----- LONG-TERM ENERGY TRADING CONTRACTS 77,972 76,503 ------ ------ CURRENT ASSETS: Cash and Cash Equivalents 1,947 2,270 Accounts Receivable: Customers 20,036 34,555 Affiliated Companies 16,012 22,119 Miscellaneous 3,333 6,419 Allowance for Uncollectible Accounts (264) (282) Fuel - at average cost 12,060 4,760 Materials and Supplies - at average cost 15,766 15,408 Accrued Utility Revenues 5,395 6,500 Energy Trading Contracts 139,605 480,739 Prepayments 1,314 766 ---------- --- TOTAL CURRENT ASSETS 215,204 573,254 ------- ------- REGULATORY ASSETS 97,692 98,515 ------ ------ DEFERRED CHARGES 11 572 11,817 ------ ------ TOTAL $1,153,243 $1,509,064 ========== ========== See Notes to Financial Statements beginning on page L-1. KENTUCKY POWER COMPANY December 31, ------------------------ 2001 2000 ---- ---- (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock - Par Value $50: Authorized - 2,000,000 Shares Outstanding - 1,009,000 Shares $ 50,450 $ 50,450 Paid-in Capital 158,750 158,750 Accumulated Other Comprehensive Income (Loss) (1,903) - Retained Earnings 48,833 57,513 ------ ------ Total Common Shareholder's Equity 256,130 266,713 Long-term Debt 251,093 270,880 ---------- ------- TOTAL CAPITALIZATION 507,223 537,593 ------- ------- OTHER NONCURRENT LIABILITIES 11,929 18,348 ------ ------ CURRENT LIABILITIES: Long-term Debt Due Within One Year 95,000 60,000 Advances from Affiliates 66,200 47,636 Accounts Payable - General 24,050 32,043 Accounts Payable - Affiliated Companies 22,557 37,506 Customer Deposits 4,461 4,389 Taxes Accrued 10,305 11,885 Interest Accrued 5,269 5,610 Energy Trading and Derivative Contracts 144,364 494,086 Other 12,296 14,517 ------ ------ Total CURRENT LIABILITIES 384,502 707,672 ------- ------- DEFERRED INCOME TAXES 168,304 165,935 ------- ------- DEFERRED INVESTMENT TAX CREDITS 10,405 11,656 ------ ------ LONG-TERM ENERGY TRADING CONTRACTS 63,412 61,478 ------ ------ DEFERRED CREDITS 7,468 6,382 ----- ----- COMMITMENTS AND CONTINGENCIES (Note 8) TOTAL $1,153,243 $1,509,064 ========== ========== See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY Statements of Cash Flows Year Ended December 31, ----------------------------------------- 2001 2000 1999 ---- ---- ---- (in thousands) OPERATING ACTIVITIES: Net Income $ 21,565 $20,763 $25,430 Adjustments for Noncash Items: Depreciation and Amortization 32,491 31,034 29,228 Deferred Income Taxes 6,293 3,765 2,596 Deferred Investment Tax Credits (1,251) (1,252) (1,292) Deferred Fuel Costs (net) (4,707) 2,948 828 Mark-to-Market of Energy Trading Contracts (1,454) (4,376) (863) Change in Certain Current Assets and Liabilities: Accounts Receivable (net) 23,694 (20,930) (6,618) Fuel, Materials and Supplies (7,658) 8,386 (7,014) Accrued Utility Revenues 1,105 7,237 (177) Accounts Payable (22,942) 39,883 4,935 Taxes Accrued (1,580) 2,025 2,604 Disputed Tax and Interest Related to COLI - 5,943 (567) Change in Other Assets (2,762) 62,653 11,547 Change in Other Liabilities (9,446) (62,702) (13,837) ------ ------- ------- Net Cash Flows From Operating Activities 33,348 95,377 46,800 ------ ------ ------ INVESTING ACTIVITIES: Construction Expenditures (37,206) (36,209) (44,339) Proceeds From Sales of Property 216 266 168 --- --- --- Net Cash Flows Used For Investing Activities (36,990) (35,943) (44,171) ------- ------- ------- FINANCING ACTIVITIES: Capital Contributions from Parent Company - - 10,000 Issuance of Long-term Debt 75,000 69,685 79,740 Retirement of Long-term Debt (60,000) (105,000) (83,307) Change in Short-term Debt (net) - (39,665) 19,315 Change in Advances From Affiliates (net) 18,564 47,636 - Dividends Paid (30,245) (30,360) (29,772) ------- ------- ------- Net Cash Flows From (Used For) Financing Activities 3,319 (57,704) (4,024) ----- ------- ------ Net Increase (Decrease) in Cash and Cash Equivalents (323) 1,730 (1,395) Cash and Cash Equivalents January 1 2,270 540 1,935 ----- --- ----- Cash and Cash Equivalents December 31 $1,947 $ 2,270 $ 540 ====== ======= =====
Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $27,090,000, $28,619,000 and $29,845,000 and for income taxes was $7,549,000, $7,923,000 and $12,050,000 in 2001, 2000 and 1999, respectively. Noncash acquisitions under capital leases were $817,000, $2,817,000 and $2,219,000 in 2001, 2000 and 1999, respectively. See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY Statements of Capitalization December 31, ------------------------ 2001 2000 ---- ---- (in thousands) COMMON SHAREHOLDER'S EQUITY $256,130 $266,713 -------- -------- LONG-TERM DEBT (See Schedule of Long-term Debt): First Mortgage Bonds 59,383 119,341 Senior Unsecured Notes 147,625 147,490 Notes Payable 100,000 25,000 Junior Debentures 39,085 39,049 Less Portion Due Within One Year (95,000) (60,000) ------- ------- Long-term Debt Excluding Portion Due Within One Year 251,093 270,880 ------- ------- TOTAL CAPITALIZATION $507,223 $537,593 ======== ========
See Notes to Financial Statements beginning on page L-1. KENTUCKY POWER COMPANY Schedule of Long-term Debt First mortgage bonds outstanding were as follows: December 31, -------------------- 2001 2000 ---- ---- (in thousands) % Rate Due 8.95 2001 - May 10 $ - $ 20,000 8.90 2001 - May 21 - 40,000 6.65 2003 - May 1 15,000 15,000 6.70 2003 - June 1 15,000 15,000 6.70 2003 - July 1 15,000 15,000 7.90 2023 - June 1 14,500 14,500 Unamortized Discount (117) (159) -------- -------- $ 59,383 $119,341 ======== ======== First mortgage bonds are secured by first mortgage liens on electric utility plant. Certain indentures relating to the first mortgage bonds contain improvement, maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. Senior unsecured notes outstanding were as follows: December 31, 2001 2000 ---- ---- (in thousands) % Rate Due - ------ ------------------ (a) 2002 - November 19 $ 70,000 $ 70,000 6.91 2007 - October 1 48,000 48,000 6.45 2008 - November 10 30,000 30,000 Unamortized Discount (375) (510) -------- -------- 147,625 147,490 Less Portion Due Within One Year 70,000 - -------- -------- Total $ 77,625 $147,490 ======== ======== (a) A floating interest rate is determined monthly. The rate on December 31, 2001 was 4.3% and on December 31, 2000 was 7.4%. Notes payable to parent company were as follows: December 31, 2001 2000 ---- ---- (in thousands) % Rate Due 4.336 2003 - May 15 $15,000 $ - 6.501 2006 - May 15 60,000 - ------- ------ $75,000 $ - ======= ====== Notes payable to banks outstandings were as follows: December 31, 2001 2000 ---- ---- (in thousands) % Rate Due 7.45 2002 - September 20 $25,000 $25,000 ======= ======= Junior debentures outstanding were as follows: December 31, 2001 2000 ---- ---- (in thousands) % Rate Due 8.72 2025 - June 30 $40,000 $40,000 Unamortized Discount (915) (951) ------- ------- Total $39,085 $39,049 ======= ======= Interest may be deferred and payment of principal and interest on the junior debentures is subordinated and subject in right to the prior payment in full of all senior indebtedness of the Company. At December 31, 2001, future annual long-term debt payments are as follows: Amount ------ (in thousands) 2002 $ 95,000 2003 60,000 2004 - 2005 - 2006 60,000 Later Years 132,500 -------- Total Principal Amount 347,500 Unamortized Discount 1,407 -------- Total $346,093 ======== KENTUCKY POWER COMPANY Index to Notes to Financial Statements The notes to KPCo's financial statements are combined with the notes to financial statements for AEP and its other subisidiary registrants. Listed below are the combined notes that apply to KPCo. The combined footnotes begin on page L-1. Combined Footnote Reference Significant Accounting Policies Note 1 Merger Note 3 Effects of Regulation Note 6 Commitments and Contingencies Note 8 Benefit Plans Note 10 Business Segments Note 12 Risk Management, Financial Instruments and Derivatives Note 13 Income Taxes Note 14 Leases Note 18 Lines of Credit and Sale of Receivables Note 19 Unaudited Quarterly Financial Information Note 20 Related Party Transactions Note 24 INDEPENDENT AUDITORS' REPORT To the Shareholder and Board of Directors of Kentucky Power Company: We have audited the accompanying balance sheets and statements of capitalization of Kentucky Power Company as of December 31, 2001 and 2000, and the related statements of income, comprehensive income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such financial statements present fairly, in all material respects, the financial position of Kentucky Power Company as of December 31, 2001 and 2000, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America. DELOITTE & TOUCHE LLP Columbus, Ohio February 22, 2002 OHIO POWER COMPANY AND SUBSIDIARIES
OHIO POWER COMPANY AND SUBSIDIARIES Selected Consolidated Financial Data Year Ended December 31, 2001 2000 1999 1998 1997 ---- ---- ---- ---- ---- (in thousands) INCOME STATEMENTS DATA: Operating Revenues $6,262,402 $4,992,100 $4,196,893 $3,572,125 $1,965,818 Operating Expenses 6,021,692 4,765,273 3,908,064 3,282,753 1,689,425 --------- --------- --------- --------- --------- Operating Income 240,710 226,827 288,829 289,372 276,393 Nonoperating Income (Loss) 18,686 (5,004) 7,000 588 14,822 Interest Charges 93,603 119,210 83,672 80,035 82,526 ------ ------- ------ ------ ------ Income Before Extraordinary Item 165,793 102,613 212,157 209,925 208,689 Extraordinary Loss (18,348) (18,876) - - - ------- ------- ---- ---- ---- Net Income 147,445 83,737 212,157 209,925 208,689 Preferred Stock Dividend Requirements 1,258 1,266 1,417 1,474 2,647 ----- ----- ----- ----- ----- Earnings Applicable To Common Stock $146,187 $ 82,471 $210,740 $208,451 $206,042 ======== ======== ======== ======== ======== Year Ended December 31, 2001 2000 1999 1998 1997 ---- ---- ---- ---- ---- (in thousands) BALANCE SHEETS DATA: Electric Utility Plant $5,390,576 $5,577,631 $5,400,917 $5,257,841 $5,155,797 Accumulated Depreciation 2,452,571 2,764,130 2,621,711 2,461,376 2,349,995 --------- --------- --------- --------- --------- Net Electric Utility Plant $2,938,005 $2,813,501 $2,779,206 $2,796,465 $2,805,802 ========== ========== ========== ========== ========== Total Assets $4,916,067 $6,242,557 $4,677,209 $4,344,680 $4,163,202 ========== ========== ========== ========== ========== Common Stock and Paid-in Capital $783,684 $783,684 $783,577 $783,536 $783,497 Accumulated Other Comprehensive Income (Loss) (196) Retained Earnings 401,297 398,086 587,424 587,500 590,151 ------- ------- ------- ------- ------- Total Common Shareholder's Equity $1,184,785 $1,181,770 $1,371,001 $1,371,036 $1,373,648 ========== ========== ========== ========== ========== Cumulative Preferred Stock: Not Subject to Mandatory Redemption $ 16,648 $ 16,648 $ 16,937 $ 17,370 $ 17,542 Subject to Mandatory Redemption (a) 8,850 8,850 8,850 11,850 11,850 ----- ----- ----- ------- ------ Total Cumulative Preferred Stock $ 25,498 $ 25,498 $ 25,787 $ 29,220 $ 29,392 ======== ======== ======== ======== ======== Long-term Debt (a) $1,203,841 $1,195,493 $1,151,511 $1,084,928 $1,095,226 ========== ========== ========== ========== ========== Obligations Under Capital Leases (a) $ 80,666 $116,581 $136,543 $142,635 $157,487 ======== ======== ======== ======== ======== Total Capitalization and Liabilities $4,916,067 $6,242,557 $4,677,209 $4,344,680 $4,163,202 ========== ========== ========== ========== ==========
(a) Including portion due within one year. OHIO POWER COMPANY AND SUBSIDIARIES Management's Discussion and Analysis of Results of Operations OPCo is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to 698,000 retail customers in northwestern, east central, eastern and southern sections of Ohio. OPCo supplies electric power to the AEP Power Pool and shares the revenues and costs of the AEP Power Pool's wholesale sales to neighboring utility systems and power marketers including power trading transactions. OPCo also sells wholesale power to municipalities and cooperatives. The cost of the AEP Power Pool's generating capacity is allocated among Pool members based on their relative peak demands and generating reserves through the payment of capacity charges or the receipt of capacity credits. AEP Power Pool members are also compensated for their out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each company's prior twelve month peak demand relative to the total peak demand of all member companies as a basis for sharing revenues and costs. The result of this calculation is the member load ratio (MLR) which determines each company's percentage share of AEP Power Pool revenues and costs. Critical Accounting Policies - Revenue Recognition Regulatory Accounting - As a result of our cost-based rate-regulated transmission and distribution operations, our financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate regulated. In accordance with SFAS 71, regulatory assets (deferred expenses) and regulatory liabilities (future revenue reductions or refunds) are recorded to reflect the economic effects of regulation by matching expenses with their recovery through regulated revenues in the same accounting period. When regulatory assets are probable of recovery through regulated rates, we record them as assets on the balance sheet. We test for probability of recovery whenever new events occur, for example a regulatory commission order or passage of new legislation. If we determine that recovery of a regulatory asset is no longer probable, we write off that regulatory asset as a charge against net income. A write off of regulatory assets may also reduce future cash flows since there may be no recovery through regulated rates. Traditional Electricity Supply and Delivery Activities - We recognize revenues on an accrual basis for electricity supply sales and electricity transmission and distribution delivery services. The revenues are recognized in our income statement when the energy is delivered to the customer and include unbilled as well as billed amounts. In general expenses are recorded when incurred. Energy Marketing and Trading Activities - AEP engages in wholesale electricity marketing and trading transactions (trading activities). A portion of the revenues and costs of AEP's trading activities are allocated to OPCo as a member of the AEP Power Pool. Trading activities involve the purchase and sale of energy under physical forward contracts at fixed and variable prices and buying and selling financial energy contracts which includes exchange traded futures and options and over-the-counter options and swaps. Although trading contracts are generally short-term, there are also long-term trading contracts. We recognize revenues from trading activities generally based on changes in the fair value of energy trading contracts. Recording the net change in the fair value of trading contracts prior to settlement is commonly referred to as mark-to-market (MTM) accounting. It represents the change in the unrealized gain or loss throughout the contract's term. When the contract actually settles, that is, the energy is actually delivered in a sale or received in a purchase or the parties agree to forego delivery and receipt of electricity and net settle in cash, the unrealized gain or loss is reversed and the actual realized cash gain or loss is recognized. Therefore, over the trading contract's term an unrealized gain or loss is recognized as the contract's market value changes. When the contract settles the total gain or loss is realized in cash but only the difference between the accumulated unrealized net gains or losses recorded in prior months and the cash proceeds is recognized. Unrealized mark-to-market gains and losses are included in the Balance Sheet as energy trading contract assets or liabilities as appropriate. The majority of our trading activities represent physical forward electricity contracts that are typically settled by entering into offsetting contracts. An example of our trading activities is when, in January, we enter into a forward sales contract to deliver electricity in July. At the end of each month until the contract settles in July, we would record our share of any difference between the contract price and the market price as an unrealized gain or loss. In July when the contract settles, we would realize our share of the gain or loss in cash and reverse the previously recorded unrealized gain or loss. Depending on whether the delivery point for the electricity is in AEP's traditional marketing area or not determines where the contract is reported on OPCo's income statement. AEP's tradititonal marketing area is up to two transmission systems from the AEP service territory. Physical forward trading sale contracts with delivery points in AEP's traditional marketing area are included in revenues when the contracts settle. Physical forward trading purchase contracts with delivery points in AEP's traditional marketing area are included in purchased power expense when they settle. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts in AEP's traditional marketing area are included in revenues on a net basis. Physical forward sales contracts for delivery outside of AEP's traditional marketing area are included in nonoperating income when the contract settles. Physical forward purchase contracts for delivery outside of AEP's traditional marketing area are included in nonoperating expenses when the contract settles. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts with delivery points outside of AEP's traditional marketing area are included in nonoperating income on a net basis. Continuing with the above example, assume that later in January or sometime in February through July we enter into an offsetting forward contract to buy electricity in July. If we do nothing else with these contracts until settlement in July and if the volumes, delivery point, schedule and other key terms match then the difference between the sale price and the purchase price represents a fixed value to be realized when the contracts settle in July. If the purchase contract is perfectly matched with the sales contract, we have effectively fixed the profit or loss; specifically it is the difference between the contracted settlement price of the two contracts. Mark-to-market accounting for these contracts will have no further impact on results of operations but will have an offsetting and equal effect on trading contract assets and liabilities. Of course we could also do similar transactions but enter into a purchase contract prior to entering into a sales contract. If the sale and purchase contracts do not match exactly as to volumes, delivery point, schedule and other key terms, then there could be continuing mark-to-market effects on results of operations from recording additional changes in fair values using mark-to-market accounting. Trading of electricity options, futures and swaps, represents financial transactions with unrealized gains and losses from changes in fair values reported net in nonoperating income until the contracts settle. When these financial contracts settle, we record our share of the net proceeds in nonoperating income and reverse to nonoperating income the prior unrealized gain or loss. The fair value of open short-term trading contracts are based on exchange prices and broker quotes. We mark-to-market open long-term trading contracts based mainly on AEP-developed valuation models. These models estimate future energy prices based on existing market and broker quotes and supply and demand market data and assumptions. The fair values determined are reduced by reserves to adjust for credit risk and liquidity risk. Credit risk is the risk that the counterparty to the contract will fail to perform or fail to pay amounts due AEP. Liquidity risk represents the risk that imperfections in the market will cause the price to be less than or more than what the price should be based purely on supply and demand. There are inherent risks related to the underlying assumptions in models used to fair value open long-term trading contracts. AEP has independent controls to evaluate the reasonableness of our valuation models. However, energy markets, especially electricity markets, are imperfect and volatile and unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a contract's term and when contracts settle. Therefore, there could be significant adverse or favorable effects on future results of operations and cash flows if market prices do not correlate with the AEP-developed price models. Volatility in commodities markets affects the fair values of all of our open trading contracts exposing OPCo to market risk. See "Market Risks" section of MD&A for a discussion of the policies and procedures used to manage exposure to risk from trading activities. Results of Operations Income before extraordinary item increased $63 million or 62% in 2001 primarily due to the effect of a court decision related to a corporate owned life insurance (COLI) program recorded in 2000. In February 2001 the U.S. District Court for the Southern District of Ohio ruled against AEP and certain of its subsidiaries, including OPCo, in a suit over deductibility of interest claimed in AEP's consolidated tax returns related to COLI. In 1998 and 1999 OPCo paid the disputed taxes and interest attributable to the COLI interest deductions for taxable years 1991-98. The payments were included in Other Property and Investments pending the resolution of this matter. Net income was also favorably impacted by the growth in and strong performance by the wholesale business. The favorable effects of the COLI decision and wholesale business were offset in part by the commencement of the amortization of transition regulatory assets in 2001, the effect of mild winter weather and the recent economic downturn. Income before extraordinary item decreased $110 million or 52% in 2000 due predominantly to the unfavorable COLI decision. Operating Revenues Operating revenues increased 25% in 2001 and 19% in 2000 because of the significant increase in wholesale marketing and trading volume. The changes in the components of revenues were as follows: Increase (Decrease) From Previous Year (Dollars in Millions) 2001 2000 ----------------------------- Amount % Amount % ------ - ------ - Retail* $ (66.0) (8) $(135.7) (15) Wholesale Marketing and Trading 1,294.0 42 738.0 32 Unrealized MTM 32.6 N.M. (10.3) N.M. Other (4.3) (5) 2.8 4 -------- ------- Total Marketing and Trading 1,256.3 32 594.8 18 Energy Delivery* 85.1 18 7.4 2 Sale to AEP Affiliates (71.1)(12) 193.0 50 -------- ------- Total $1,270.3 25 $ 795.2 19 ======== ======= * Reflects for 2000 the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery. The increase in operating revenues in 2001 and 2000 resulted from increased marketing and trading volume (32% in 2001 and 21% in 2000). The maturing of the Intercontinental Exchange, the development of proprietory tools, and increased staffing of energy traders has resulted in an increase in the number of forward electricity purchase and sale contracts in AEP's traditional marketing area. Sales to AEP affiliates decreased in 2001 because an affiliate was able to supply more power to the Power Pool from two nuclear units that returned to service in June and December 2000. As a result of one of OPCo's major industrial customers deciding not to continue its power purchase agreement, OPCo was able to deliver additional power to the power pool in 2000. This accounted for the increase in sales to AEP affiliates in 2000. Operating Expenses Operating expenses increased by 26% in 2001 mostly due to a significant increase in wholesale trading purchases and the amortization of transition regulatory assets partly offset by decreases in fuel expense and income taxes. Operating expenses increased by 22% in 2000 mostly due to increases in fuel expense, wholesale trading purchases, other operation expense and income taxes. Changes in the components of operating expenses were as follows: Increase (Decrease) From Previous Year (dollars in millions) 2001 2000 ---- ---- Amount % Amount % Fuel $ (85.4) (11) $ 84.3 12 Marketing and Trading Purchases 1,327.7 46 597.6 26 AEP Affiliate Purchases 11.8 23 29.9 143 Other Operation (4.0) (1) 80.2 25 Maintenance 18.1 15 3.4 3 Depreciation and Amortization 84.0 54 6.9 5 Taxes Other Than Income Taxes (9.7) (6) 5.3 3 Income Taxes (86.1) (46) 49.6 36 -------- ------ Total Operating Expenses $1,256.4 26 $857.2 22 ======== ====== Fuel expense decreased 11% in 2001 mainly due to a 9% decrease in net generation because of decreased sales to the AEP Power Pool caused by an affiliate's two nuclear units returning to service. Fuel expense increased in 2000 due to increases in generation and the average cost of fuel consumed reflecting shutdown costs included in the cost of coal delivered from affiliated mining operations. Marketing and trading purchases expense increased substantially in 2001 and 2000 due to increases in trading volume. The increases in purchased power from AEP affiliates were due to a significnt increase in AEP Power Pool transactions in 2001 and 2000. Other operation expense increased in 2000 mainly due to increased power generation costs. Increased emission allowance consumption and allowance prices and increased costs of AEP's growing power marketing and trading operation, including trader incentive compensation, accounted for the increase in power generation costs. The increase in emission allowance usage and prices resulted from the stricter air quality standards of Phase II of the 1990 Clean Air Act Amendments which became effective on January 1, 2000. Maintenance expense increased in 2001 mainly due to boiler repairs at Amos, Cardinal, Kammer, Mitchell, Muskingum and Sporn plants, and boiler inspections at the Amos and Cardinal plants. The commencement of amortization of transition regulatory assets in connection with the transition to customer choice and market-based pricing of retail electricity supply under Ohio deregulation accounted for the significant increase in depreciation and amortization expense in 2001. The decrease in taxes other than income taxes in 2001 was due to a decrease in property tax expense reflecting a reduction in rates on generation property under the Ohio Restructuring law partially offset by a new state excise tax. Income taxes decreased in 2001 due to an unfavorable ruling in AEP's suit against the government over interest deductions claimed relating to AEP's COLI program, which was recorded in 2000 and a decrease in pre-tax book income. The increase in income tax expense in 2000 was primarily due to the unfavorable ruling relating to AEP's COLI program. Nonoperating Income and Nonoperating Expense The increases in nonoperating income and nonoperating expenses in 2001 and 2000 were due to an increase in trading transactions outside of the AEP System's traditional marketing area. Interest Charges The major reason for the decrease in interest expense in 2001 was the recognition in 2000 of deferred interest payments to the IRS related to COLI disallowances. The increase in interest expense in 2000 was due to the recognition of deferred interest payments related to the COLI disallowance. Extraordinary Loss In the second quarter of 2001 an extraordinary loss of $18 million net of tax was recorded to write-off prepaid Ohio excise taxes stranded by Ohio deregulation. In 2000 the application of regulatory accounting for generation under SFAS 71 was discontinued which resulted in an after tax extraordinary loss of $19 million.
OHIO POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Income Year Ended December 31, -------------------------------------------- 2001 2000 1999 ---- ---- ---- (in thousands) OPERATING REVENUES: Electricity Marketing and Trading $5,198,323 $3,942,066 $3,347,219 Energy Delivery 552,713 467,587 460,182 Sales to AEP Affiliates 511,366 582,447 389,492 ------- ------- ------- TOTAL OPERATING REVENUES 6,262,402 4,992,100 4,196,893 --------- --------- --------- OPERATING EXPENSES: Fuel 686,568 771,969 687,672 Purchased Power: Electricity Marketing and Trading 4,225,124 2,897,461 2,299,909 AEP Affiliates 62,585 50,741 20,864 Other Operation 403,404 407,375 327,132 Maintenance 142,878 124,735 121,299 Depreciation and Amortization 239,982 155,944 149,055 Taxes Other Than Income Taxes 159,778 169,527 164,213 Income Taxes 101,373 187,521 137,920 ------- ------- ------- TOTAL OPERATING EXPENSES 6,021,692 4,765,273 3,908,064 --------- --------- --------- OPERATING INCOME 240,710 226,827 288,829 NONOPERATING INCOME 1,880,294 1,208,437 630,295 NONOPERATING EXPENSES 1,863,988 1,195,283 628,723 NONOPERATING INCOME TAX EXPENSE (CREDIT) (2,380) 18,158 (5,428) INTEREST CHARGES 93,603 119,210 83,672 ------ ------- ------ INCOME BEFORE EXTRAORDINARY ITEM 165,793 102,613 212,157 EXTRAORDINARY LOSS - DISCONTINUANCE OF REGULATORY ACCOUNTING FOR GENERATION - Net of tax (See Note 2) (18,348) (18,876) - ------- ------- ---- NET INCOME 147,445 83,737 212,157 PREFERRED STOCK DIVIDEND REQUIREMENTS 1,258 1,266 1,417 ----- ----- ----- EARNINGS APPLICABLE TO COMMON STOCK $146,187 $ 82,471 $210,740 ======== ======== ========
Consolidated Statements of Comprehensive Income Year Ended December 31, ----------------------- 2001 2000 1999 ---- ---- ---- NET INCOME $147,445 $83,737 $212,157 OTHER COMPREHENSIVE INCOME (LOSS) Foreign Currency Exchange Rate Hedge (196) - - ---- ---- ---- COMPREHENSIVE INCOME $147,249 $83,737 $212,157 ======== ======= ========
The common stock of the Company is wholly owned by AEP. See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY AND SUBSIDIARIES Consolidated Balance Sheets December 31, ------------------------- 2001 2000 ---- ---- (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production $3,007,866 $2,764,155 Transmission 891,283 870,033 Distribution 1,081,122 1,040,940 General (including mining assets at December 31, 2000) 245,232 707,417 Construction Work in Progress 165,073 195,086 ------- ------- Total Electric Utility Plant 5,390,576 5,577,631 Accumulated Depreciation and Amortization 2,452,571 2,764,130 --------- --------- NET ELECTRIC UTILITY PLANT 2,938,005 2,813,501 --------- --------- OTHER PROPERTY AND INVESTMENTS 62,303 109,124 ------ ------- LONG-TERM ENERGY TRADING CONTRACTS 263,734 255,938 ------- ------- CURRENT ASSETS: Cash and Cash Equivalents 8,848 31,393 Advances to Affiliates - 92,486 Accounts Receivable: Customers 84,694 139,732 Affiliated Companies 148,563 126,203 Miscellaneous 20,409 39,046 Allowance for Uncollectible Accounts (1,379) (1,054) Fuel - at average cost 84,724 82,291 Materials and Supplies - at average cost 88,768 96,053 Accrued Utility Revenues - 264 Energy Trading Contracts 472,246 1,608,298 Prepayments and Other 20,865 32,882 ------ ------ TOTAL CURRENT ASSETS 927,738 2,247,594 ------- --------- REGULATORY ASSETS 644,625 714,710 ------- ------- DEFERRED CHARGES 79,662 101,690 ------ ------- TOTAL $4,916,067 $6,242,557 ========== ==========
See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY AND SUBSIDIARIES December 31, ------------------------ 2001 2000 ---- ---- (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock - No Par Value: Authorized - 40,000,000 Shares Outstanding - 27,952,473 Shares $321,201 $321,201 Paid-in Capital 462,483 462,483 Accumulated Other Comprehensive Income (Loss) (196) - Retained Earnings 401,297 398,086 ------- ------- Total Common Shareholder's Equity 1,184,785 1,181,770 Cumulative Preferred Stock: Not Subject to Mandatory Redemption 16,648 16,648 Subject to Mandatory Redemption 8,850 8,850 Long-term Debt 1,203,841 1,077,987 --------- --------- TOTAL CAPITALIZATION 2,414,124 2,285,255 --------- --------- OTHER NONCURRENT LIABILITIES 130,386 542,017 ------- ------- CURRENT LIABILITIES: Long-term Debt Due Within One Year - 117,506 Advances From Affiliates 300,213 - Accounts Payable - General 134,418 179,691 Accounts Payable - Affiliated Companies 176,520 121,360 Customer Deposits 5,452 39,736 Taxes Accrued 126,770 223,101 Interest Accrued 17,679 20,458 Obligations Under Capital Leases 16,405 32,716 Energy Trading Contracts 456,047 1,652,953 Other 87,070 151,934 ------ ------- Total CURRENT LIABILITIES 1,320,574 2,539,455 --------- --------- DEFERRED INCOME TAXES 797,889 621,941 ------- ------- DEFERRED INVESTMENT TAX CREDITS 21,925 25,214 ------ ------ LONG-TERM ENERGY TRADING CONTRACTS 214,487 205,670 ------- ------- DEFERRED CREDITS 16,682 23,005 ------ ------ COMMITMENTS AND CONTINGENCIES (Note 8) TOTAL $4,916,067 $6,242,557 ========== ==========
See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Cash Flows Year Ended December 31, --------------------------------------- 2001 2000 1999 ---- ---- ---- (in thousands) OPERATING ACTIVITIES: Net Income $ 147,445 $83,737 $ 212,157 Adjustments for Noncash Items: Depreciation, Depletion and Amortization 252,123 200,350 193,780 Deferred Income Taxes 215,833 (65,956) 3,666 Deferred Investment Tax Credits (3,289) (3,399) (3,458) Deferred Fuel Costs (net) - (56,869) (76,978) Extraordinary Loss 18,348 18,876 - Mark to Market of Energy Trading Contracts (59,833) (5,614) (4,234) Change in Certain Current Assets and Liabilities: Accounts Receivable (net) 51,640 51,430 (49,309) Fuel, Materials and Supplies 4,852 46,645 (60,500) Accrued Utility Revenues 264 45,311 (2,074) Accounts Payable 9,887 56,069 9,195 Disputed Tax and Interest Related to COLI - 110,494 (6,272) Accumulated Provisions - Noncurrent (392,026) 145,573 66,573 Taxes Accrued (96,331) 60,919 (776) Customer Deposits (34,284) 31,540 (3,763) Change in Other Assets 79,831 (439,448) (67,515) Change in Other Liabilities (107,704) 359,640 127,288 -------- ------- ------- Net Cash Flows From Operating Activities 86,756 639,298 337,780 ------ ------- ------- INVESTING ACTIVITIES: Construction Expenditures (344,571) (254,016) (193,870) Proceeds From Sales of Property and Other 16,778 6,354 5,900 Investment in Coal Companies (32,115) - - ------- ---- ---- Net Cash Flows Used For Investing Activities (359,908) (247,662) (187,970) -------- -------- -------- FINANCING ACTIVITIES: Issuance of Long-term Debt 300,000 74,748 222,308 Change in Advances From Affiliates (net) 392,699 (92,486) - Retirement of Cumulative Preferred Stock - (182) (3,392) Retirement of Long-term Debt (297,858) (30,663) (158,638) Change in Short-term Debt (net) - (194,918) 71,913 Dividends Paid on Common Stock (142,976) (271,813) (210,813) Dividends Paid on Cumulative Preferred Stock (1,258) (1,262) (1,420) ------ ------ ------ Net Cash Flows Used For Financing Activities 250,607 (516,576) (80,042) ------- -------- ------- Net Increase (Decrease) in Cash and Cash Equivalents (22,545) (124,940) 69,768 Cash and Cash Equivalents January 1 31,393 156,333 86,565 ------ ------- ------ Cash and Cash Equivalents December 31 $ 8,848 $31,393 $ 156,333 ======= ======= =========
Supplemental Disclosure: Cash paid (received) for interest net of capitalized amounts was $94,747,000, $87,120,000 and $78,739,000 and for income taxes was $(22,417,000), $142,710,000 and $94,606,000 in 2001, 2000 and 1999, respectively. Noncash acquisitions under capital leases were $2,380,000, $17,005,000 and $28,561,000 in 2001, 2000 and 1999, respectively. See Notes to Financial Statements beginning on page L-1. OHIO POWER COMPANY AND SUBSIDIARIES Consolidated Statement of Retained Earnings Year Ended December 31, --------------------------------------- 2001 2000 1999 ---- ---- ---- (in thousands) Retained Earnings January 1 $398,086 $587,424 $587,500 Net Income 147,445 83,737 212,157 ------- -- ------ - ------- 545,531 671,161 799,657 ------- - ------- - ------- Deductions: Cash Dividends Declared: Common Stock 142,976 271,813 210,813 Cumulative Preferred Stock: 4.08% Series 58 59 61 4.20% Series 96 96 97 4.40% Series 139 139 142 4-1/2% Series 439 442 460 5.90% Series 428 428 472 6.02% Series 66 66 156 6.35% Series 32 32 32 -- ------ -- ------ -- Total Dividends 144,234 273,075 212,233 ------- - ------- - ------- Retained Earnings December 31 $401,297 $398,086 $587,424 ======== ======== ======== See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Capitalization December 31, ----------------------------- 2001 2000 ---- ---- (in thousands) COMMON SHAREHOLDER'S EQUITY $1,184,785 $1,181,770 ---------- ---------- PREFERRED STOCK: $100 par value - authorized shares 3,762,403 $25 par value - authorized shares 4,000,000 Call Price Shares December 31, Par Number of Shares Redeemed Outstanding Series(a) 2001 Value Year Ended December 31, December 31, 2001 - ------ ------------ ----- --------------------------- ----------------- 2001 2000 1999 ---- ---- ---- Not Subject to Mandatory Redemption: 4.08% $103 $100 - - 373 14,595 1,460 1,460 4.20% 103.20 100 - 276 - 22,824 2,282 2,282 4.40% 104 100 - 432 330 31,512 3,151 3,151 4-1/2% 110 100 - 2,181 3,631 97,546 9,755 9,755 ------ ------ 16,648 16,648 ------ ------ Subject to Mandatory Redemption: 5.90% (b) - $100 - - 10,000 72,500 7,250 7,250 6.02% (c) - 100 - - 20,000 11,000 1,100 1,100 6.35% (c) - 100 - - - 5,000 500 500 ------ ------ 8,850 8,850 ------ ------ LONG-TERM DEBT (See Schedule of Long-term Debt): First Mortgage Bonds 141,544 316,294 Installment Purchase Contracts 233,235 233,130 Senior Unsecured Notes 396,962 471,583 Notes Payable to Affiliated Company 300,000 - Notes Payable - 30,000 Junior Debentures 132,100 131,980 Other Long-term Debt - 12,506 Less Portion Due Within One Year - (117,506) ---------- ---------- Long-term Debt Excluding Portion Due Within One Year 1,203,841 1,077,987 ---------- ---------- TOTAL CAPITALIZATION $2,414,124 $2,285,255 ========== ==========
(a) The series subject to mandatory redemption are not callable until after 2002. The sinking fund provisions of each series subject to mandatory redemption have been met by purchase of shares in advance of the due date. (b) Commencing in 2004 and continuing through the year 2008, a sinking fund for the 5.90% cumulative preferred stock will require the redemption of 22,500 shares each year and the redemption of the remaining shares outstanding on January 1, 2009, in each case at $100 per share. Shares previously redeemed may be applied to meet sinking fund requirements. (c) Commencing in 2003 and continuing through 2007 cumulative preferred stock sinking funds will require the redemption of 20,000 shares each year of the 6.02% series and 15,000 shares each year of the 6.35% series, in each case at $100 per share. All remaining outstanding shares must be redeemed in 2008. Shares previously redeemed may be applied to meet the sinking fund requirements. See Notes to Financial Statements beginning on page L-1. OHIO POWER COMPANY AND SUBSIDIARIES Schedule of Long-term Debt First mortgage bonds outstanding were as follows: December 31, -------------------- 2001 2000 ---- ---- (in thousands) % Rate Due 6.75 2003 - April 1 $ 29,850 $ 38,850 6.55 2003 - October 1 27,315 32,135 6.00 2003 - November 1 12,500 25,000 6.15 2003 - December 1 20,000 50,000 8.80 2022 - February 10 5,000 50,000 7.75 2023 - April 1 5,000 40,000 7.375 2023 - October 1 20,250 40,000 7.10 2023 - November 1 12,000 20,000 7.30 2024 - April 1 10,000 21,500 Unamortized Discount (371) (1,191) -------- -------- Total $141,544 $316,294 ======== ======== First mortgage bonds are secured by first mortgage liens on electric utility plant. Certain indentures relating to the first mortgage bonds contain improvement, maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. Installment purchase contracts have been entered into in connection with the issuance of pollution control revenue bonds by governmental authorities as follows: December 31, 2001 2000 ---- ---- (in thousands) % Rate Due Mason County, West Virginia: 5.45% 2016 - December 1 $ 50,000 $ 50,000 Marshall County, West Virginia: 5.45% 2014 - July 1 50,000 50,000 5.90% 2022 - April 1 35,000 35,000 6.85% 2022 - June 1 50,000 50,000 Ohio Air Quality Development 5.15% 2026 - May 1 50,000 50,000 Unamortized Discount (1,765) (1,870) -------- -------- Total $233,235 $233,130 ======== ======== Under the terms of the installment purchase contracts, OPCo is required to pay amounts sufficient to enable the payment of interest on and the principal (at stated maturities and upon mandatory redemptions) of related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants. Senior unsecured notes outstanding were as follows: December 31, -------------------- 2001 2000 ---- ---- (in thousands) % Rate Due - ------ ------------------ (a) 2001 - May 16 $ - $ 75,000 6.75 2004 - July 1 100,000 100,000 7.00 2004 - July 1 75,000 75,000 6.73 2004 - November 1 48,000 48,000 6.24 2008 - December 4 37,225 37,225 7-3/8 2038 - June 30 140,000 140,000 Unamortized Discount (3,263) (3,642) -------- -------- Total $396,962 $471,583 ======== ======== (a) Redeemed on 5/16/01. Notes payable to parent company were as follows: December 31, 2001 2000 ---- ---- (in thousands) % Rate Due 4.336% 2003 - May 15 $ 60,000 $ - 6.501% 2006 - May 15 240,000 - -------- ------ Total $300,000 $ - ======== ====== Notes payable outstanding were as follows: December 31, 2001 2000 ---- ---- (in thousands) % Rate Due 6.20 2001 - January 31 $ - $ 5,000 6.20 2001 - January 31 - 7,000 6.20 2001 - January 31 - 18,000 ------- ------- Total $ - $30,000 ======= ======= Junior debentures outstanding were as follows: December 31, 2001 2000 ---- ---- (in thousands) % Rate Due - ------ ----------------- 8.16 2025 - September 30 $ 85,000 $ 85,000 7.92 2027 - March 31 50,000 50,000 Unamortized Discount (2,900) (3,020) -------- -------- Total $132,100 $131,980 ======== ======== Interest may be deferred and payment of principal and interest on the junior debentures is subordinated and subject in right to the prior payment in full of all senior indebtedness of the Company. Finance obligations were entered into by the Company's coal mining subsidiaries for mining facilities and equipment through sale and leaseback transactions. In accordance with SFAS 98, the transactions did not qualify as sales and leasebacks for accounting purposes and therefore are shown as other long-term debt. The remaining long-term debt obligation was paid off in the first quarter of 2001. At December 31, 2001, future annual long-term debt payments are as follows: Amount ------ (in thousands) 2002 $ - 2003 149,665 2004 223,000 2005 - 2006 240,000 Later Years 599,475 ---------- Total Principal Amount 1,212,140 Unamortized Discount 8,299 ---------- Total $1,203,841 ========== OHIO POWER COMPANY AND SUBSIDIARIES Index to Notes to Consolidated Financial Statements The notes to OPCo's financial statements are combined with the notes to financial statements for AEP and its other subisidiary registrants. Listed below are the combined notes that apply to OPCo. The combined footnotes begin on page L-1. Combined Footnote Reference Significant Accounting Policies Note 1 Extraordinary Items and Cumulative Effect Note 2 Effects of Regulation Note 6 Customer Choice and Industry Restructuring Note 7 Commitments and Contingencies Note 8 Acquisitions and Dispositions Note 9 Benefit Plans Note 10 Business Segments Note 12 Risk Management, Financial Instruments and Derivatives Note 13 Income Taxes Note 14 Supplementary Information Note 16 Leases Note 18 Lines of Credit and Sale of Receivables Note 19 Unaudited Quarterly Financial Information Note 20 Related Party Transactions Note 24 INDEPENDENT AUDITORS' REPORT To the Shareholders and Board of Directors of Ohio Power Company: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Ohio Power Company and its subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of income, comprehensive income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Ohio Power Company and its subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America. DELOITTE & TOUCHE LLP Columbus, Ohio February 22, 2002 PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES Selected Consolidated Financial Data Year Ended December 31, 2001 2000 1999 1998 1997 ---- ---- ---- ---- ---- (in thousands) INCOME STATEMENTS DATA: Operating Revenues $2,201,249 $1,430,019 $749,390 $780,159 $712,690 Operating Expenses 2,104,261 1,333,350 650,677 665,085 630,666 --------- --------- ------- ------- ------- Operating Income 96,988 96,669 98,713 115,074 82,024 Nonoperating Income (Loss) 20 8,974 946 (91) 1,649 Interest Charges 39,249 38,980 38,151 38,074 37,218 ------ ------ ------ ------ ------ Net Income 57,759 66,663 61,508 76,909 46,455 Preferred Stock Dividend Requirements 213 212 212 213 364 Gain On Reacquired Preferred Stock - - - - 4,211 ---- ---- ---- ---- ----- Earnings Applicable to Common Stock $ 57,546 $ 66,451 $ 61,296 $ 76,696 $ 50,302 ======== ======== ======== ======== ======== December 31, 2001 2000 1999 1998 1997 ---- ---- ---- ---- ---- (in thousands) BALANCE SHEETS DATA: Electric Utility Plant $2,695,099 $2,604,670 $2,459,705 $2,391,722 $2,339,908 Accumulated Depreciation and Amortization 1,184,443 1,150,253 1,114,255 1,082,081 1,031,322 --------- --------- --------- --------- --------- Net Electric Utility Plant $1,510,656 $1,454,417 $1,345,450 $1,309,641 $1,308,586 ========== ========== ========== ========== ========== Total Assets $1,917,897 $2,138,333 $1,524,726 $1,470,939 $1,464,562 ========== ========== ========== ========== ========== Common Stock and Paid-in Capital $337,230 $337,230 $337,230 $337,230 $337,230 Retained Earnings 142,994 137,688 139,237 142,941 135,245 ------- ------- ------- ------- ------- Total Common Shareholder's Equity $480,224 $474,918 $476,467 $480,171 $472,475 ======== ======== ======== ======== ======== Cumulative Preferred Stock: Not Subject to Mandatory Redemption $ 5,283 $ 5,283 $ 5,286 $ 5,287 $ 5,287 ======= ======= ======= ======= ======= Preferred Securities of Subsidiary Trust $ 75,000 $ 75,000 $ 75,000 $ 75,000 $ 75,000 ======== ======== ======== ======== ======== Long-term Debt (a) $451,129 $470,822 $384,516 $384,064 $438,703 ======== ======== ======== ======== ======== Total Capitalization and Liabilities $1,917,897 $2,138,333 $1,524,726 $1,470,939 $1,464,562 ========== ========== ========== ========== ==========
(a) Including portion due within one year. PUBLIC SERVICE COMPANY OF OKLAHOMA Management's Narrative Analysis of Results of Operations PSO is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to approximately 502,000 retail customers in eastern and southwestern Oklahoma. PSO also sells electric power at wholesale to other utilities, municipalities and rural electric cooperatives. Wholesale power marketing and trading activities are conducted on PSO's behalf by AEP. PSO, along with the other AEP electric operating subsidiaries, shares in the revenues and costs of AEP's wholesale sales to and forward trades with other utility systems and power marketers. Critical Accounting Policies - Revenue Recognition Regulatory Accounting - As a cost-based rate-regulated electric public utility company, PSO's consolidated financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate regulated. In accordance with SFAS 71, regulatory assets (deferred expenses) and regulatory liabilities (future revenue reductions or refunds) are recorded to reflect the economic effects of regulation by matching expenses with their recovery through regulated revenues in the same accounting period. When regulatory assets are probable of recovery through regulated rates, we record them as assets on the balance sheet. We test for probability of recovery whenever new events occur, for example a regulatory commission order or passage of new legislation. If we determine that recovery of a regulatory asset is no longer probable, we write off that regulatory asset as a charge against net income. A write off of regulatory assets may also reduce future cash flows since there may be no recovery through regulated rates. Traditional Electricity Supply and Delivery Activities - We recognize revenues on an accrual basis for electricity supply sales and electricity transmission and distribution delivery services. The revenues are recognized in our income statement when the energy is delivered to the customer and include unbilled as well as billed amounts. In general expenses are recorded when incurred. Energy Marketing and Trading Activities - AEP engages in wholesale electricity marketing and trading transactions (trading activities). A portion of the revenues and costs of AEP's trading activities are allocated to PSO. Trading activities allocated to PSO involve the purchase and sale of energy under physical forward contracts at fixed and variable prices. Although trading contracts are generally short-term, there are also long-term trading contracts. Accounting standards applicable to trading activities require that changes in the fair value of trading contracts be recognized in revenues prior to settlement and is commonly referred to as mark-to-market (MTM) accounting. Since PSO is a cost-based rate-regulated entity,whose revenues are based on settled transaction, unrealized changes in the fair value of physical forward sale and purchase contracts are deferred as regulatory liabilities (gains) or regulatory assets (losses). Mark-to-market accounting represents the change in the unrealized gain or loss throughout the contract's term. When the contract actually settles, that is, the energy is actually delivered in a sale or received in a purchase or the parties agree to forego delivery and receipt and net settle in cash, the unrealized gain or loss is reversed and the actual realized cash gain or loss is recognized in the income statement. Therefore, as the contract's market value changes over the contract's term an unrealized gain or loss is deferred as a regulatory liability or a regulatory asset. When the contract settles the total gain or loss is realized in cash and recognized in the income statement. Physical forward trading sale contracts are included in revenues when the contracts settle. Physical forward trading purchase contracts are included in purchased power expense when they settle. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts are deferred as regulatory liabilities (gains) or regulatory assets (losses). Unrealized mark-to-market gains and losses are included in the Balance Sheet as energy trading contract assets or liabilities as appropriate. The fair value of open short-term trading contracts are based on exchange prices and broker quotes. We mark-to-market open long-term trading contracts based mainly on AEP-developed valuation models. These models estimate future energy prices based on existing market and broker quotes and supply and demand market data and assumptions. The fair values determined are reduced by reserves to adjust for credit risk and liquidity risk. Credit risk is the risk that the counterparty to the contract will fail to perform or fail to pay amounts due AEP. Liquidity risk represents the risk that imperfections in the market will cause the price to be less than or more than what the price should be based purely on supply and demand. There are inherent risks related to the underlying assumptions in models used to fair value open long-term trading contracts. AEP has independent controls to evaluate the reasonableness of our valuation models. However, energy markets, especially electricity markets, are imperfect and volatile and unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a contract's term and when contracts settle. Therefore, there could be significant adverse or favorable effects on future results of operations and cash flows if market prices do not correlate with the AEP-developed price models. Volatility in commodities markets affects the fair values of all of our open trading contracts exposing PSO to market risk. See "Market Risks" section of MD&A for a discussion of the policies and procedures used to manage exposure to risk from trading activities. Results of Operations Net income decreased $8.9 million or 13.4% in 2001 due primarily due to the effect of a gain on the sale of a minority interest in Scientech, Inc. recorded in year 2000. Operating Revenues The 54% increase in operating revenues for the year resulted from increased trading volumes of the wholesale electric marketing and trading business. The increase in revenues is primarily attributable to our sharing in AEP's power marketing and trading operations. Revenues also increased as a result of favorable fuel-related revenues associated with the Oklahoma fuel clause recovery mechanism. Increase From Previous Year Amount % (dollars in millions) - --------------------- Retail* $ 49.1 8 Wholesale Marketing and Trading 675.3 124 Other 7.9 41 ------ Total Marketing and Trading 732.3 63 Energy Delivery* 16.8 7 Sales to AEP Affiliates 22.1 151 ------ Total Revenues $771.2 54 ====== *Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery. Revenues from retail customers increased primarily as a result of an increase in fuel-related revenues. Rising prices for natural gas used for generation and higher purchased power prices accounted for the increase in fuel-related revenues. The Oklahoma fuel clause recovery mechanism provides for the accrual of fuel-related revenues until reviewed and approved for billing to customers by the Oklahoma Corporation Commission. The accrual of additional fuel and purchased power revenues is offset by increases in fuel and purchased power expenses. As a result, accrued fuel-related revenues do not impact results of operations. The increase in wholesale electric marketing and trading revenues is attributable to PSO's sharing in the AEP System's power marketing and trading operations for a full year. In June 2000 as a result of a merger with CSW, PSO started sharing in the AEP System's power marketing and trading transactions. Operating Expenses Increase Operating expenses were $770.9 million more in 2001 than in 2000 largely as a result of increased fuel and purchased power expenses. Changes in the components of operating expenses were as follows: Increase From Previous Year Amount % (dollars in millions) - --------------------- Fuel $ 58.5 15 Marketing and Trading Purchases 669.0 119 Affiliated Purchases 18.5 30 Other Operation 18.2 15 Maintenance 0.3 N.M. Depreciation and Amortization 3.8 5 Taxes Other Than Income Taxes (1.2) (4) Income Taxes 3.8 12 ------ Total $770.9 58 ------ N.M. = Not Meaningful Fuel expense increased primarily from the recovery of fuel cost due to regulated recovery mechanisms offset in part by a 4% decrease in generation. The increase in purchased power expense was primarily attributable to our participation in AEP's power marketing and trading activities for a full year. Other operation expenses increased due mainly to a true-up adjustment in 2000 under a FERC-approved Transmission Coordination Agreement and a full year of our share of incentive compensation for power trading. Depreciation expense increased due to investment relating to repowering Northeast Station Units 1 and 2. The increase in income tax expense was primarily due to adjustments associated with prior year tax returns offset in part by a decrease in pre-tax book income. Nonoperating Income Nonoperating income decreased primarily from the effect of a gain recorded in 2000 on the sale of PSO's minority interest in Scientech, Inc. Scientech provides services, systems and instruments, which describe, regulate, monitor and enhance the safety and reliability of power plant operations and their environmental impact.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES Consolidated Statements of Income Year Ended December 31, ----------------------------------------- 2001 2000 1999 ---- ---- ---- (in thousands) OPERATING REVENUES: Electricity Marketing and Trading $1,902,601 $1,170,247 $479,346 Energy Delivery 261,877 245,124 256,327 Sales to AEP Affiliates 36,771 14,648 13,717 ------ ------ ------ TOTAL OPERATING REVENUES 2,201,249 1,430,019 749,390 --------- --------- ------- OPERATING EXPENSES: Fuel 461,470 402,933 269,316 Purchased Power: Electricity Marketing and Trading 1,230,694 561,709 40,274 AEP Affiliates 79,251 60,788 34,619 Other Operation 139,927 121,697 121,896 Maintenance 46,188 45,858 45,809 Depreciation and Amortization 80,245 76,418 74,736 Taxes Other Than Income Taxes 31,973 28,688 30,520 Income Taxes 34,513 35,259 33,507 ------ ------ ------ TOTAL OPERATING EXPENSES 2,104,261 1,333,350 650,677 --------- --------- ------- OPERATING INCOME 96,988 96,669 98,713 NONOPERATING INCOME 2,112 8,807 2,580 NONOPERATING EXPENSES 1,740 1,139 3,849 NONOPERATING INCOME TAX EXPENSE (CREDIT) 352 (1,306) (2,215) INTEREST CHARGES 39,249 38,980 38,151 ------ ------ ------ NET INCOME 57,759 66,663 61,508 PREFERRED STOCK DIVIDEND REQUIREMENTS 213 212 212 --- --- --- EARNINGS APPLICABLE TO COMMON STOCK $ 57,546 $ 66,451 $ 61,296 ======== ======== ========
Consolidated Statements of Retained Earnings Year Ended December 31, ----------------------------------------- 2001 2000 1999 ---- ---- ---- (in thousands) BEGINNING OF PERIOD $137,688 $139,237 $142,941 NET INCOME 57,759 66,663 61,508 DEDUCTIONS: Cash Dividends Declared: Common Stock 52,240 68,000 65,000 Preferred Stock 213 212 212 --- --- --- BALANCE AT END OF PERIOD $142,994 $137,688 $139,237 ======== ======== ======== See Notes to Financial Statements beginning on page L-1. PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES Consolidated Balance Sheets December 31, ------------ 2001 2000 ---- ---- (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production $1,034,711 $914,096 Transmission 427,110 396,695 Distribution 972,806 938,053 General 203,572 206,731 Construction Work in Progress 56,900 149,095 ------ ------- Total Electric Utility Plant 2,695,099 2,604,670 Accumulated Depreciation and Amortization 1,184,443 1,150,253 --------- --------- NET ELECTRIC UTILITY PLANT 1,510,656 1,454,417 --------- --------- OTHER PROPERTY AND INVESTMENTS 41,020 38,211 ------ ------ LONG-TERM ENERGY TRADING CONTRACTS 55,215 52,275 ------ ------ CURRENT ASSETS: Cash and Cash Equivalents 5,795 11,301 Accounts Receivable: Customers 31,144 60,424 Affiliated Companies 10,905 3,453 Allowance for Uncollectible Accounts (44) (467) Fuel - at LIFO cost 21,559 28,113 Materials and Supplies - at average cost 36,785 29,642 Under-recovered Fuel Costs - 43,267 Energy Trading Contracts 162,200 378,911 Prepayments 2,368 1,559 ----- ----- TOTAL CURRENT ASSETS 270,712 556,203 ------- ------- REGULATORY ASSETS 35,004 29,338 ------ ------ DEFERRED CHARGES 5,290 7,889 ----- ----- TOTAL $1,917,897 $2,138,333 ========== ========== See Notes to Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES December 31, ----------------------- 2001 2000 ---- ---- (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock - $15 Par Value: Authorized Shares: 11,000,000 Issued Shares: 10,482,000 Outstanding Shares: 9,013,000 $157,230 $157,230 Paid-in Capital 180,000 180,000 Retained Earnings 142,994 137,688 ------- ------- Total Common Shareholder's Equity 480,224 474,918 ------- ------- Cumulative Preferred Stock Not Subject To Mandatory Redemption 5,283 5,283 PSO-Obligated, Mandatorily Redeemable Preferred Securities of Subsidiary Trust Holding Solely Junior Subordinated Debentures of PSO 75,000 75,000 Long-term Debt 345,129 450,822 ------- ------- TOTAL CAPITALIZATION 905,636 1,006,023 ------- --------- CURRENT LIABILITIES: Long-term Debt Due Within One Year 106,000 20,000 Advances from Affiliates 123,087 81,120 Accounts Payable - General 72,759 104,379 Accounts Payable - Affiliated Companies 40,857 64,556 Customer Deposits 21,041 19,294 Over-Recovered Fuel 8,720 - Taxes Accrued 18,150 1,659 Interest Accrued 7,298 8,336 Energy Trading Contracts 167,658 385,809 Other 12,296 12,137 ------ ------ TOTAL CURRENT LIABILITIES 577,866 697,290 ------- ------- DEFERRED INCOME TAXES 296,877 312,060 ------- ------- DEFERRED INVESTMENT TAX CREDITS 33,992 35,783 ------ ------ REGULATORY LIABILITIES AND DEFERRED CREDITS 56,203 35,292 ------ ------ LONG-TERM ENERGY TRADING CONTRACTS 47,323 51,885 ------ ------ TOTAL $1,917,897 $2,138,333 ========== ==========
See Notes to Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES Consolidated Statements of Cash Flows Year Ended December 31, ---------------------------------------- 2001 2000 1999 ---- ---- ---- (in thousands) OPERATING ACTIVITIES: Net Income $57,759 $66,663 $61,508 Adjustments for Noncash Items: Depreciation and Amortization 80,245 76,418 74,736 Deferred Income Taxes (17,751) 25,453 14,521 Deferred Investment Tax Credits (1,791) (1,791) (1,791) Changes in Certain Assets and Liabilities: Accounts Receivable (net) 21,405 (28,826) (1,668) Fuel, Materials and Supplies (589) 677 (8,985) Other Property and Investments (2,809) 7,994 (2,108) Accounts Payable (55,319) 89,330 (8,000) Taxes Accrued 16,491 (16,821) (4,615) Fuel Recovery 51,987 (36,798) (21,709) Transmission Coordination Agreement Settlement - (15,063) 15,063 Changes in Other Assets (9,150) 4,452 10,227 Changes in Other Liabilities 9,381 (6,073) (15,736) ----- ------ ------- Net Cash Flows From Operating Activities 149,859 165,615 111,443 ------- ------- ------- INVESTING ACTIVITIES: Construction Expenditures (124,520) (176,851) (103,122) Other Items (359) - (8,659) ---- ---- ------ Net Cash Flows Used For Investing Activities (124,879) (176,851) (111,781) -------- -------- -------- FINANCING ACTIVITIES: Issuance of Long-term Debt - 105,625 33,232 Retirement of Long-term Debt (20,000) (20,000) (33,700) Change in Advances From Affiliates (net) 41,967 1,951 63,277 Dividends Paid on Common Stock (52,240) (68,000) (65,000) Dividends Paid on Cumulative Preferred Stock (213) (212) (212) ---- ---- ---- Net Cash Flows (used For) From Financing Activities (30,486) 19,364 (2,403) ------- ------ ------ Net Increase (Decrease) in Cash and Cash Equivalents (5,506) 8,128 (2,741) Cash and Cash Equivalents January 1 11,301 3,173 5,914 ------ ---- ----- ---- ----- Cash and Cash Equivalents December 31 $ 5,795 $11,301 $ 3,173 ======= ======= =======
Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $38,250,000, $33,732,000 and $37,081,000 and for income taxes was $38,653,000, $25,786,000 and $23,871,000 in 2001, 2000 and 1999, respectively. See Notes to Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES Consolidated Statements of Capitalization December 31, -------------------------- 2001 2000 ---- ---- (in thousands) COMMON SHAREHOLDER'S EQUITY $ 480,224 $ 474,918 ---------- ---------- PREFERRED STOCK: Cumulative $100 par value - authorized shares 700,000, redeemable at the option of PSO upon 30 days notice. Call Price Shares December 31, Number of Shares Redeemed Outstanding Series 2001 Year Ended December 31, December 31, 2001 - ------ ------------ ---------------------------- ----------------- 2001 2000 1999 ---- ---- ---- Not Subject to Mandatory Redemption: 4.00% $105.75 - 25 9 44,606 4,460 4,460 4.24% 103.19 - - - 8,069 807 807 Premium 16 16 ---------- ---------- 5,283 5,283 ---------- ---------- TRUST PREFERRED SECURITIES PSO-obligated, mandatorily redeemable preferred securities of subsidiary trust holding solely Junior Subordinated Debentures of PSO, 8.00%, due April 30, 2037 75,000 75,000 ---------- ---------- LONG-TERM DEBT (See Schedule of Long-term Debt): First Mortgage Bonds 297,772 317,465 Installment Purchase Contracts 47,357 47,357 Senior Unsecured Notes 106,000 106,000 Less Portion Due Within One Year (106,000) (20,000) ---------- ---------- Long-term Debt Excluding Portion Due Within One Year 345,129 450,822 ---------- ---------- TOTAL CAPITALIZATION $ 905,636 $1,006,023 ========== ==========
See Notes to Financial Statements beginning on page L-1. PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES Schedule of Long-term Debt First mortgage bonds outstanding were as follows: December 31, 2001 2000 (in thousands) % Rate Due 5.91 2001 - March 1 $ - $6,000 6.02 2001 - March 1 - 5,000 6.02 2001 - March 1 - 9,000 6.25 2003 - April 1 35,000 35,000 7.25 2003 - July 1 65,000 65,000 7.38 2004 - December 1 50,000 50,000 6.50 2005 - June 1 50,000 50,000 7.38 2023 - April 1 100,000 100,000 Unamortized Discount (2,228) (2,535) -- ------ -- ------ $297,772 $317,465 First mortgage bonds are secured by first mortgage liens on electric utility plant. Certain indentures relating to the first mortgage bonds contain improvement, maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. Installment purchase contracts have been entered into in connection with the issuance of pollution control revenue bonds by governmental authorities as follows: December 31, 2001 2000 (in thousands) % Rate Due Oklahoma Environmental Finance Authority (OEFA): 5.90 2007 - December 1 $ 1,000 $ 1,000 Oklahoma Development Finance Authority (ODFA): 4.875 2014 - June 1 33,700 33,700 Red River Authority of Texas: 6.00 2020 - June 1 12,660 12,660 Unamortized Discount (3) (3) ----- ----- Total $47,357 $47,357 ======= ======= Under the terms of the installment purchase contracts, PSO is required to pay amounts sufficient to enable the payment of interest on and the principal (at stated maturities and upon mandatory redemptions) of related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants. Senior unsecured notes outstanding were as follows: December 31, 2001 2000 (in thousands) % Rate Due (a) 2002 - November 21 $106,000 $106,000 ======== ======== (a) A floating interest rate is determined monthly. The rate on December 31, 2001 and 2000 was 2.775% and 7.376%. At December 31, 2001, future annual long-term debt payments are as follows: Amount ------ (in thousands) 2002 $106,000 2003 100,000 2004 50,000 2005 50,000 2006 - Later Years 147,360 ------- Total Principal Amount 453,360 Unamortized Discount (2,231) ------ Total $451,129 ======== PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES Index to Notes to Consolidated Financial Statements The notes to PSO's financial statements are combined with the notes to financial statements for AEP and its other subisidiary registrants. Listed below are the combined notes that apply to PSO. The combined footnotes begin on page L-1. Combined Footnote Reference Significant Accounting Policies Note 1 Merger Note 3 Rate Matters Note 5 Effects of Regulation Note 6 Customer Choice and Industry Restructuring Note 7 Commitments and Contingencies Note 8 Benefit Plans Note 10 Business Segments Note 12 Risk Management, Financial Instruments and Derivatives Note 13 Income Taxes Note 14 Leases Note 18 Lines of Credit and Sale of Receivables Note 19 Unaudited Quarterly Financial Information Note 20 Trust Preferred Securities Note 21 Jointly Owned Electric Utility Plant Note 23 Related Party Transactions Note 24 INDEPENDENT AUDITORS' REPORT To the Shareholders and Board of Directors of Public Service Company of Oklahoma: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Public Service Company of Oklahoma and subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of income, retained earnings, and cash flows for the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. The consolidated financial statements of the Company for the year ended December 31, 1999, before the restatement described in Note 3 to the consolidated financial statements, were audited by other auditors whose report, dated February 25, 2000, expressed an unqualified opinion on those statements. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such 2001 and 2000 consolidated financial statements present fairly, in all material respects, the financial position of Public Service Company of Oklahoma and subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America. We also audited the adjustments described in Note 3 that were applied to restate the 1999 consolidated financial statements to give retroactive effect to the conforming change in the method of accounting for vacation pay accruals. In our opinion, such adjustments are appropriate and have been properly applied. DELOITTE & TOUCHE LLP Columbus, Ohio February 22, 2002 SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Selected Consolidated Financial Data Year Ended December 31, 2001 2000 1999 1998 1997 ---- ---- ---- ---- ---- (in thousands) INCOME STATEMENTS DATA: Operating Revenues $2,574,448 $1,682,726 $971,527 $952,952 $939,869 Operating Expenses 2,428,241 1,554,448 824,465 802,274 800,396 --------- --------- ------- ------- ------- Operating Income 146,207 128,278 147,062 150,678 139,473 Nonoperating Income (Loss) 741 3,851 (1,965) 2,451 4,029 Interest Charges 57,581 59,457 58,892 55,135 50,536 ------ ------ ------ ------ ------ Income Before Extraordinary Item 89,367 72,672 86,205 97,994 92,966 Extraordinary Loss - - (3,011) - - ---- ---- ------ ---- ---- Net Income 89,367 72,672 83,194 97,994 92,966 Preferred Stock Dividend Requirements 229 229 229 705 2,467 Gain (Loss) on Reacquired Preferred Stock - - - (856) 1,819 ---- ---- ---- ---- ----- Earnings Applicable to Common Stock $ 89,138 $ 72,443 $ 82,965 $ 96,433 $ 92,318 ======== ======== ======== ======== ======== December 31, 2001 2000 1999 1998 1997 ---- ---- ---- ---- ---- (in thousands) BALANCE SHEETS DATA: Electric Utility Plant $3,460,764 $3,319,024 $3,231,431 $3,157,911 $3,081,443 Accumulated Depreciation and Amortization 1,550,618 1,457,005 1,384,242 1,317,057 1,225,865 --------- --------- --------- --------- --------- Net Electric Utility Plant $1,910,146 $1,862,019 $1,847,189 $1,840,854 $1,855,578 ========== ========== ========== ========== ========== Total Assets $2,496,600 $2,657,956 $2,106,215 $2,081,454 $2,134,618 ========== ========== ========== ========== ========== Common Stock and Paid-in Capital $380,660 $380,660 $380,660 $380,660 $380,660 Retained Earnings 308,915 293,989 283,546 296,581 320,148 ------- ------- ------- ------- ------- Total Common Shareholder's Equity $689,575 $674,649 $664,206 $677,241 $700,808 ======== ======== ======== ======== ======== Preferred Stock $ 4,704 $ 4,704 $ 4,706 $ 4,707 $ 30,639 ======= ======= ======= ======= ======== Trust Preferred Securities $110,000 $110,000 $110,000 $110,000 $110,000 ======== ======== ======== ======== ======== Long-term Debt (a) $645,283 $645,963 $541,568 $587,673 $589,980 ======== ======== ======== ======== ======== Total Capitalization and Liabilities $2,496,600 $2,657,956 $2,106,215 $2,081,454 $2,134,618 ========== ========== ========== ========== ==========
(a) Including portion due within one year. SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Management's Discussion and Analysis of Results of Operations SWEPCo is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to approximately 431,000 retail customers in northeastern Texas, northwestern Louisiana, and western Arkansas. SWEPCo also sells electric power at wholesale to other utilities, municipalities and rural electric cooperatives. Wholesale power marketing and trading activities are conducted on SWEPCo's behalf by AEP. SWEPCo, along with the other AEP electric operating subsidiaries, shares in the revenues and costs of AEP's wholesale sales to and forward trades with other utility systems and power marketers. Critical Accounting Policies - Revenue Recognition Regulatory Accounting - Our financial statements reflect the actions of regulators since our electricity supply sales in the Louisiana jurisdiction and our transmission and distribution operations our cost-based rate-regulated. As a result of the regulators' actions our financial statements can recognize revenues and expenses in different time periods than enterprises that are not rate regulated. In accordance with SFAS 71, regulatory assets (deferred expenses) and regulatory liabilities (future revenue reductions or refunds) are recorded to reflect the economic effects of regulation by matching expenses with their recovery through regulated revenues in the same accounting period. Traditional Electricity Supply and Delivery Activities - We recognize revenues on an accrual basis for electricity supply sales and electricity transmission and distribution delivery services. The revenues are recognized in our income statement when the energy is delivered to the customer and include unbilled as well as billed amounts. In general expenses are recorded when incurred. When regulatory assets are probable of recovery through regulated rates, we record them as assets on the balance sheet. We test for probability of recovery whenever new events occur, for example a regulatory commission order or passage of new legislation. If we determine that recovery of a regulatory asset is no longer probable, we write off that regulatory asset as a charge against net income. A write off of regulatory assets may also reduce future cash flows since there may be no recovery through regulated rates. Energy Marketing and Trading Activities - AEP engages in wholesale electricity marketing and trading transactions (trading activities). A portion of the revenues and costs of AEP's trading activities are allocated to SWEPCo. Trading activities allocated to SWEPCo involve the purchase and sale of energy under physical forward contracts at fixed and variable prices. Although trading contracts are generally short-term, there are also long-term trading contracts. We generally recognize revenues from trading activities based on changes in the fair value of energy trading contracts. Recording the net change in the fair value of trading contracts as revenues prior to settlement is commonly referred to as mark-to-market (MTM) accounting. It represents the change in the unrealized gain or loss throughout the contract's term. When the contract actually settles, that is, the energy is actually delivered in a sale or received in a purchase or the parties agree to forego delivery and receipt and net settle in cash, the unrealized gain or loss is reversed out of revenues and the actual realized cash gain or loss is recognized in revenues for a sale or in purchased power expense for a purchase. Therefore, over the trading contract's term an unrealized gain or loss is recognized as the contract's market value changes. When the contract settles the total gain or loss is realized in cash but only the difference between the accumulated unrealized net gains or losses recorded in prior months and the cash proceeds is recognized. Unrealized mark-to-market gains and losses are included in the Balance Sheet as energy trading contract assets or liabilities as appropriate. Our trading activities represent physical forward electricity contracts that are typically settled by entering into offsetting contracts. An example of our trading activities is when, in January, we enter into a forward sales contract to deliver electricity in July. At the end of each month until the contract settles in July, we would record any difference between the contract price and the market price as an unrealized gain or loss in revenues. In July when the contract settles, we would realize the gain or loss in cash and reverse to revenues the previously recorded unrealized gain or loss. Prior to settlement, the change in the fair value of physical forward sale and purchase contracts is included in revenues on a net basis. Upon settlement of a forward trading contract, the amount realized is included in revenues for a sales contract and realized costs are included in purchased power expense for a purchase contract with the prior change in unrealized fair value reversed in revenues. Continuing with the above example, assume that later in January or sometime in February through July we enter into an offsetting forward contract to buy electricity in July. If we do nothing else with these contracts until settlement in July and if the volumes, delivery point, schedule and other key terms match then the difference between the sale price and the purchase price represents a fixed value to be realized when the contracts settle in July. If the purchase contract is perfectly matched with the sales contract, we have effectively fixed the profit or loss; specifically it is the difference between the contracted settlement price of the two contracts. Mark-to-market accounting for these contracts will have no further impact on results of operations but will have an offsetting and equal effect on trading contract assets and liabilities. Of course we could also do similar transactions but enter into a purchase contract prior to entering into a sales contract. If the sale and purchase contracts do not match exactly as to volumes, delivery point, schedule and other key terms, then there could be continuing mark-to-market effects on revenues from recording additional changes in fair values using mark-to-market accounting. The fair value of open short-term trading contracts are based on exchange prices and broker quotes. We mark-to-market open long-term trading contracts based mainly on AEP-developed valuation models. These models estimate future energy prices based on existing market and broker quotes and supply and demand market data and assumptions. The fair values determined are reduced by reserves to adjust for credit risk and liquidity risk. Credit risk is the risk that the counterparty to the contract will fail to perform or fail to pay amounts due AEP. Liquidity risk represents the risk that imperfections in the market will cause the price to be less than or more than what the price should be based purely on supply and demand. There are inherent risks related to the underlying assumptions in models used to fair value open long-term trading contracts. AEP has independent controls to evaluate the reasonableness of our valuation models. However, energy markets, especially electricity markets, are imperfect and volatile and unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a contract's term and when contracts settle. Therefore, there could be significant adverse or favorable effects on future results of operations and cash flows if market prices do not correlate with the AEP-developed price models. Volatility in commodities markets affects the fair values of all of our open trading and derivative contracts exposing SWEPCo to market risk. See "Market Risks" section of MD&A for a discussion of the policies and procedures used to manage exposure to risk from trading activities. Results of Operations Net income increased $16.7 million or 23% for the year resulting from the favorable impact of our sharing in AEP's power marketing and trading activities for a full year. The $10.5 million or 13% decrease in net income in 2000 is due to increased operating expenses. Operating Revenues The significant increase in 2001 operating revenues resulted from increased trading volumes of the wholesale business and a full year of our participation in AEP's power marketing and trading operations since the merger in June 2000. Operating revenues significantly increased in 2000 due to the post merger sharing of AEP's power marketing and trading sales, and offset an unfavorable revenue adjustment in 1999 as a result of FERC's approval of a transmission coordination agreement. The transmission coordination agreement provides the means by which the AEP West electric operating companies plan, operate and maintain their separate transmission assets as a single system. The agreement also establishes the method by which these companies allocate transmission revenues received under open access transmission tariffs. The following analyzes the changes in operating revenues: Increase (Decrease) From Previous Year (dollars in millions) 2001 2000 ---- ---- Amount % Amount % Retail* $ 14.3 3 $ 29.9 6 Wholesale Marketing and Trading 822.3 111 622.9 N.M. Mark to Market 15.5 N.M. (4.7) N.M. Other 35.4 113 8.5 37 ------ ------ Total Marketing and Trading 887.5 70 656.6 106 Energy Delivery* (11.9) (3) 45.6 15 Sales to AEP Affiliates 16.1 26 9.0 17 ------ ------ Total Revenues $891.7 53 $711.2 73 ====== ====== N.M. = Not Meaningful * Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery. The significant increase in wholesale revenues in 2001 and 2000 is attributable to SWEPCo's participation in AEP's power marketing and trading operations after the merger of CSW and AEP. Revenues also increased in 2000 because of additional fuel and purchased power revenues and a rise in sales volume caused by warmer summer temperatures. The increase in fuel and purchased power revenues reflects rising prices for natural gas used for generation and related higher costs for purchased power. The Texas and Arkansas fuel clause recovery mechanisms provide for the accrual of fuel-related revenues until reviewed and approved for billing to customers by the regulator. The accrual of additional fuel-related revenues is generally offset by increases in fuel and purchased power expenses. As a result fuel-related revenues do not impact results of operations. Since SWEPCo became a subsidiary of AEP as a result of the merger in June 2000, SWEPCo shares in the AEP System's power marketing and trading transactions with other entities. Trading transactions involve the purchase and sale of substantial amounts of electricity. Operating Expenses Increase Total operating expenses increased 56% in 2001 and 89% for 2000. These increases are mainly attributable to our sharing in AEP's power marketing and trading activities since the merger in June 2000. The changes in the components of operating expenses were: Increase (Decrease) From Previous Year (dollars in millions) 2001 2000 ---- ---- Amount % Amount % Fuel $(41.2) (8) $119.2 31 Electricity Marketing and Trading Purchases 840.4 135 593.1 N.M. Affiliated Purchases 27.9 N.M. 5.8 77 Other Operation 14.3 9 17.2 12 Maintenance (.4) N.M. 10.9 17 Depreciation and Amortization 14.9 14 (4.2) (4) Taxes Other Than Income Taxes 2.0 4 N.M. N.M. Income Taxes 15.9 60 (12.0) (31) ------ ------ Total $873.8 56 $730.0 89 ====== ====== N.M. = Not Meaningful Fuel expense decreased in 2001 from lower natural gas prices and a mild summer resulting in a reduction in generation. Fuel expense increased in 2000 due to an increase in the average unit cost of fuel as a result of an increase in the spot market price for natural gas and an increase in generation to meet the rise in demand for electricity. The major increases in purchased power expense in 2001 and 2000 were primarily caused by our sharing in AEP's power marketing and trading activities. Due to the acquisition of Dolet Hills mining operation in June 2001, other operation expense increased for the year. Other operation expense increased in 2000 due primarily to increased regulatory and consulting expenses. Maintenance expense increased in 2000 as a result of costs to restore service and make repairs following a severe ice storm. Depreciation and amortization expense increased in 2001 due primarily to an increase in excess earnings accruals under the Texas restructuring legislation and the acquisition of Dolet Hills mining operation. The increase in 2001 income tax expense was primarily due to an increase in pre-tax book income. The decrease in income tax expense attributable to operations in 2000 was primarily due to a decrease in pre-tax operating income. Nonoperating Expense The decrease in nonoperating expense in 2000 was due to the effect of a 1999 write off of acquisition expenses following CSW's decision not to continue to pursue the acquisition of Cajun Electric Power Cooperatives non-nuclear assets.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Income Year Ended December 31, ----------------------------------------- 2001 2000 1999 ---- ---- ---- (in thousands) OPERATING REVENUES: Electricity Marketing and Trading $2,162,207 $1,274,652 $618,040 Energy Delivery 333,004 344,950 299,369 Sales to AEP Affiliates 79,237 63,124 54,118 ------ ------ ------ TOTAL OPERATING REVENUES 2,574,448 1,682,726 971,527 --------- --------- ------- OPERATING EXPENSES: Fuel 457,613 498,805 379,597 Purchased Power: Electricity Marketing and Trading 1,463,377 622,970 29,820 AEP Affiliates 41,250 13,338 7,551 Other Operation 173,831 159,459 142,385 Maintenance 74,677 75,123 64,241 Depreciation and Amortization 119,543 104,679 108,831 Taxes Other Than Income Taxes 55,834 53,830 53,783 Income Taxes 42,116 26,244 38,257 ------ ------ ------ TOTAL OPERATING EXPENSES 2,428,241 1,554,448 824,465 --------- --------- ------- OPERATING INCOME 146,207 128,278 147,062 NONOPERATING INCOME 4,512 5,487 2,550 NONOPERATING EXPENSES 3,229 3,112 9,341 NONOPERATING INCOME TAX EXPENSE (CREDIT) 542 (1,476) (4,826) INTEREST CHARGES 57,581 59,457 58,892 ------ ------ ------ INCOME BEFORE EXTRAORDINARY ITEM 89,367 72,672 86,205 EXTRAORDINARY LOSS (net of tax of $1,621,000) - - (3,011) ---- ---- ------ NET INCOME 89,367 72,672 83,194 PREFERRED STOCK DIVIDEND REQUIREMENTS 229 229 229 --- --- --- EARNINGS APPLICABLE TO COMMON STOCK $ 89,138 $ 72,443 $ 82,965 ======== ======== ======== Consolidated Statements of Retained Earnings BALANCE AT BEGINNING OF PERIOD $293,989 $283,546 $296,581 NET INCOME 89,367 72,672 83,194 DEDUCTIONS: Cash Dividends Declared: Common Stock 74,212 62,000 96,000 Preferred Stock 229 229 229 --- --- --- BALANCE AT END OF PERIOD $308,915 $293,989 $283,546 ======== ======== ========
See Notes to Financial Statements beginning on page L-1. SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Consolidated Balance Sheets December 31, ----------------------- 2001 2000 ---- ---- (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production $1,429,356 $1,414,527 Transmission 538,749 519,317 Distribution 1,042,523 1,001,237 General 376,016 325,948 Construction Work in Progress 74,120 57,995 ------ ------ Total Electric Utility Plant 3,460,764 3,319,024 Accumulated Depreciation and Amortization 1,550,618 1,457,005 --------- --------- NET ELECTRIC UTILITY PLANT 1,910,146 1,862,019 --------- --------- OTHER PROPERTY AND INVESTMENTS 43,000 39,627 ------ ------ LONG-TERM ENERGY TRADING CONTRACTS 63,372 62,605 ------ ------ CURRENT ASSETS: Cash and Cash Equivalents 5,415 1,907 Accounts Receivable: Customers 42,326 42,310 Affiliated Companies 20,573 11,419 Allowance for Uncollectible Accounts (89) (911) Fuel Inventory - at average cost 52,212 40,024 Materials and Supplies - at average cost 32,527 25,137 Under-recovered Fuel Costs 2,501 35,469 Energy Trading Contracts 186,159 453,781 Prepayments 18,716 16,780 ------ ------ TOTAL CURRENT ASSETS 360,340 625,916 ------- ------- REGULATORY ASSETS 51,989 57,082 ------ ------ DEFERRED CHARGES 67,753 10,707 ------ ------ TOTAL $2,496,600 $2,657,956 ========== ========== See Notes to Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES December 31, ----------------------- 2001 2000 ---- ---- (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock - $18 Par Value: Authorized - 7,600,000 Shares Outstanding - 7,536,640 Shares $135,660 $135,660 Paid-in Capital 245,000 245,000 Retained Earnings 308,915 293,989 ------- ------- Total Common Shareholder's Equity 689,575 674,649 Preferred Stock 4,704 4,704 SWEPCO-Obligated, Mandatorily Redeemable Preferred Securities of Subsidiary Trust Holding Solely Junior Subordinated Debentures of SWEPCO 110,000 110,000 Long-term Debt 494,688 645,368 ------- ------- TOTAL CAPITALIZATION 1,298,967 1,434,721 --------- --------- OTHER NONCURRENT LIABILITIES 34,997 11,290 ------ ------ CURRENT LIABILITIES: Long-term Debt Due Within One Year 150,595 595 Advances from Affiliates 123,609 16,823 Accounts Payable - General 71,810 107,747 Accounts Payable - Affiliated Companies 37,469 36,021 Customer Deposits 19,880 16,433 Taxes Accrued 36,522 11,224 Interest Accrued 13,631 13,198 Energy Trading Contracts 192,318 462,043 Other 26,166 15,064 ------ ------ TOTAL CURRENT LIABILITIES 672,000 679,148 ------- ------- DEFERRED INCOME TAXES 369,781 399,204 ------- ------- DEFERRED INVESTMENT TAX CREDITS 48,714 53,167 ------ ------ REGULATORY LIABILITIES AND DEFERRED CREDITS 17,828 18,288 ------ ------ LONG-TERM ENERGY TRADING CONTRACTS 54,313 62,138 ------ ------ COMMITMENTS AND CONTINGENCIES (Note 8) TOTAL $2,496,600 $2,657,956 ========== ==========
See Notes to Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Cash Flows Year Ended December 31, ---------------------------------------- 2001 2000 1999 ---- ---- ---- (in thousands) OPERATING ACTIVITIES: Net Income $89,367 $72,672 $83,194 Adjustments for Noncash Items: Depreciation and Amortization 119,543 104,679 108,831 Deferred Income Taxes (31,396) 14,653 (17,347) Deferred Investment Tax Credits (4,453) (4,482) (4,565) Mark-to-Market of Energy Trading Contracts (3,472) 4,677 - Changes in Certain Assets and Liabilities: Accounts Receivable (net) (9,992) (1,254) (11,134) Fuel, Materials and Supplies (19,578) 22,103 (21,891) Accounts Payable (34,489) 43,962 (12,953) Taxes Accrued 25,298 (13,150) 1,185 Transmission Coordination Agreement Settlement - (24,406) 24,406 Fuel Recovery 32,968 (38,357) (2,490) Change in Other Assets 856 57,418 24,500 Change in Other Liabilities 4,958 (36,887) (15,769) ----- ------- ------- Net Cash Flows From Operating Activities 169,610 201,628 155,967 ------- ------- ------- INVESTING ACTIVITIES: Construction Expenditures (111,725) (120,671) (111,019) Purchase of Dolet Hills Mining Operations (85,716) - - Other (411) 446 (4,167) ---- ---- ------ Net Cash Flows Used For Investing Activities (197,852) (120,225) (115,186) -------- -------- -------- FINANCING ACTIVITIES: Issuance of Long-term Debt - 149,360 - Redemption of Preferred Stock - (1) (1) Retirement of Long-term Debt (595) (45,595) (46,144) Change in Advances From Affiliates (net) 106,786 (124,074) 100,192 Dividends Paid on Common Stock (74,212) (62,000) (96,000) Dividends Paid on Cumulative Preferred Stock (229) (229) (229) ---- ---- ---- Net Cash Flows From (Used For) Financing Activities 31,750 (82,539) (42,182) ------ ------- ------- Net Increase (Decrease) in Cash and Cash Equivalents 3,508 (1,136) (1,401) Cash and Cash Equivalents January 1 1,907 3,043 4,444 ----- ----- ----- Cash and Cash Equivalents December 31 $ 5,415 $ 1,907 $ 3,043 ======= ======= =======
Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $51,126,000, $51,111,000 and $55,254,000 and for income taxes was $49,901,000, $27,994,000 and $55,677,000 in 2001, 2000, and 1999, respectively. See Notes to Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Capitalization December 31, ----------------------------- 2001 2000 ---- ---- (in thousands) COMMON SHAREHOLDER'S EQUITY $ 689,575 $ 674,649 ---------- ---------- PREFERRED STOCK: $100 par value - authorized shares 1,860,000 Call Price Shares December 31, Number of Shares Redeemed Outstanding Series 2001 Year Ended December 31, December 31, 2001 - ------ ------------ ---------------------------- ----------------- 2001 2000 1999 ---- ---- ---- Not Subject to Mandatory Redemption: 4.28% $103.90 - - - 7,386 739 739 4.65% $102.75 - - 1 1,907 190 190 5.00% $109 - 12 2 37,715 3,771 3,771 Premium 4 4 ---------- ---------- 4,704 4,704 ---------- ---------- TRUST PREFERRED SECURITIES SWEPCo-obligated, mandatorily redeemable preferred securities of subsidiary trust holding solely Junior Subordinated Debentures of SWEPCo, 7.875%, due April 30, 2037 110,000 110,000 ---------- ---------- LONG-TERM DEBT (See Schedule of Long-term Debt): First Mortgage Bonds 315,449 315,477 Installment Purchase Contracts 179,834 180,486 Senior Unsecured Notes 150,000 150,000 Less Portion Due Within One Year (150,595) (595) ---------- ---------- Long-term Debt Excluding Portion Due Within One Year 494,688 645,368 ---------- ---------- TOTAL CAPITALIZATION $1,298,967 $1,434,721 ========== ==========
See Notes to Financial Statements beginning on page L-1. SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Schedule of Long-term Debt First mortgage bonds outstanding were as follows: December 31, -------------------- 2001 2000 ---- ---- (in thousands) % Rate Due 6-5/8 2003 - February 1 $ 55,000 $ 55,000 7-3/4 2004 - June 1 40,000 40,000 6.20 2006 - November 1 5,650 5,795 6.20 2006 - November 1 1,000 1,000 7.00 2007 - September 1 90,000 90,000 7-1/4 2023 - July 1 45,000 45,000 6-7/8 2025 - October 1 80,000 80,000 Unamortized Discount (1,201) (1,318) -------- -------- $315,449 $315,477 First mortgage bonds are secured by first mortgage liens on electric utility plant. Certain indentures relating to the first mortgage bonds contain improvement, maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. Installment purchase contracts have been entered into in connection with the issuance of pollution control revenue bonds by governmental authorities as follows: December 31, 2001 2000 ---- ---- (in thousands) % Rate Due - ------ ----------------- DeSoto County: 7.60 2019 - January 1 $ 53,500 $ 53,500 Sabine: 6.10 2018 - April 1 81,700 81,700 Titus County: 6.90 2004 - November 1 12,290 12,290 6.00 2008 - January 1 13,070 13,520 8.20 2011 - August 1 17,125 17,125 Unamortized Premium 2,149 2,351 -------- -------- $179,834 $180,486 Under the terms of the installment purchase contracts, SWEPCo is required to pay amounts sufficient to enable the payment of interest on and the principal (at stated maturities and upon mandatory redemptions) of related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants. Senior unsecured notes outstanding were as follows: December 31, 2001 2000 ---- ---- (in thousands) % Rate Due - ------ ------------------ (a) 2002 - March 1 $150,000 $150,000 ======== ======== (a) A floating interest rate is determined monthly. The rate on December 31, 2001 and 2000 was 2.311% and 6.97%. At December 31, 2001, future annual long-term debt payments are as follows: Amount ------ (in thousands) 2002 $150,595 2003 55,595 2004 52,885 2005 595 2006 6,520 Later Years 378,145 -------- Total Principal Amount 644,335 Unamortized Premium 948 -------- Total $645,283 ======== SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Index to Notes to Consolidated Financial Statements The notes to SWEPCo's financial statements are combined with the notes to financial statements for AEP and its other subisidiary registrants. Listed below are the combined notes that apply to SWEPCo. The combined footnotes begin on page L-1. Combined Footnote Reference Significant Accounting Policies Note 1 Extraordinary Items and Cumulative Effect Note 2 Merger Note 3 Rate Matters Note 5 Effects of Regulation Note 6 Customer Choice and Industry Restructuring Note 7 Commitments and Contingencies Note 8 Acquistions and Dispositions Note 9 Benefit Plans Note 10 Business Segments Note 12 Risk Management, Financial Instruments and Derivatives Note 13 Income Taxes Note 14 Leases Note 18 Lines of Credit and Sale of Receivables Note 19 Unaudited Quarterly Financial Information Note 20 Trust Preferred Securities Note 21 Jointly Owned Electric Utility Plant Note 23 Related Party Transactions Note 24 INDEPENDENT AUDITORS' REPORT To the Shareholders and Board of Directors of Southwestern Electric Power Company: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Southwestern Electric Power Company and subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of income, retained earnings, and cash flows for the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. The consolidated financial statements of the Company for the year ended December 31, 1999, before the restatement described in Note 3 to the consolidated financial statements, were audited by other auditors whose report, dated February 25, 2000, expressed an unqualified opinion on those statements. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such 2001 and 2000 consolidated financial statements present fairly, in all material respects, the financial position of Southwestern Electric Power Company and subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America. We also audited the adjustments described in Note 3 that were applied to restate the 1999 consolidated financial statements to give retroactive effect to the conforming change in the method of accounting for vacation pay accruals. In our opinion, such adjustments are appropriate and have been properly applied. DELOITTE & TOUCHE LLP Columbus, Ohio February 22, 2002 WEST TEXAS UTILITIES COMPANY
WEST TEXAS UTILITIES COMPANY Selected Financial Data Year Ended December 31, 2001 2000 1999 1998 1997 ---- ---- ---- ---- ---- (in thousands) INCOME STATEMENTS DATA: Operating Revenues $1,064,271 $759,562 $445,709 $424,953 $397,779 Operating Expenses 1,030,881 707,221 391,910 365,677 353,195 --------- ------- ------- ------- ------- Operating Income 33,390 52,341 53,799 59,276 44,584 Nonoperating Income (Loss) 2,195 (1,675) 2,488 2,712 1,463 Interest Charges 23,275 23,216 24,420 24,263 24,570 ------ ------ ------ ------ ------ Income Before Extraordinary Item 12,310 27,450 31,867 37,725 21,477 Extraordinary Loss - - (5,461) - - ---- --- ------ ---- ---- Net Income 12,310 27,450 26,406 37,725 21,477 Preferred Stock Dividend Requirements 104 104 104 104 144 --- --- --- --- --- Gain on Reacquired Preferred Stock - - - - 1,085 ---- ---- ---- ---- ----- Earnings Applicable to Common Stock $ 12,206 $ 27,346 $ 26,302 $ 37,621 $ 22,418 ======== ======== ======== ======== ======== December 31, 2001 2000 1999 1998 1997 ---- ---- ---- ---- ---- (in thousands) BALANCE SHEETS DATA: Electric Utility Plant $1,260,872 $1,229,339 $1,182,544 $1,146,582 $1,108,845 Accumulated Depreciation and Amortization 546,162 515,041 495,847 473,503 441,281 ------- ------- ------- ------- ------- Net Electric Utility Plant $714,710 $714,298 $686,697 $673,079 $667,564 ======== ======== ======== ======== ======== Total Assets $923,420 $1,087,411 $861,205 $819,446 $826,858 ======== ========== ======== ======== ======== Common Stock and Paid-in Capital $139,450 $139,450 $139,450 $139,450 $139,450 Retained Earnings 105,970 122,588 113,242 114,940 117,319 ------- ------- ------- ------- ------- Total Common Shareholder's Equity $245,420 $262,038 $252,692 $254,390 $256,769 ======== ======== ======== ======== ======== Cumulative Preferred Stock: Not Subject to Mandatory Redemption $ 2,482 $ 2,482 $ 2,482 $ 2,482 $ 2,483 ======= ======= ======= ======= ======= Long-term Debt (a) $255,967 $255,843 $303,686 $303,518 $303,351 ======== ======== ======== ======== ======== Total Capitalization And Liabilities $923,420 $1,087,411 $861,205 $819,446 $826,858 ======== ========== ======== ======== ========
(a) Including portion due within one year. WEST TEXAS UTILITIES COMPANY Management's Narrative Analysis of Results of Operations WTU is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power and provides electric power to approximately 189,000 retail customers in west and central Texas. WTU also sells electric power at wholesale to other utilities, municipalities and rural electric cooperatives. Wholesale power marketing and trading activities are conducted on WTU's behalf by AEP. WTU, along with the other AEP electric operating subsidiaries, shares in the revenues and costs of AEP's wholesale sales to and forward trades with other utility systems and power marketers. Critical Accounting Policies - Revenue Recognition Regulatory Accounting - As a result of our cost-based rate-regulated transmission and distribution operations, our financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate regulated. In accordance with SFAS 71, regulatory assets (deferred expenses) and regulatory liabilities (future revenue reductions or refunds) are recorded to reflect the economic effects of regulation by matching expenses with their recovery through regulated revenues in the same accounting period. When regulatory assets are probable of recovery through regulated rates, we record them as assets on the balance sheet. We test for probability of recovery whenever new events occur, for example a regulatory commission order or passage of new legislation. If we determine that recovery of a regulatory asset is no longer probable, we write off that regulatory asset as a charge against net income. A write off of regulatory assets may also reduce future cash flows since there may be no recovery through regulated rates. Traditional Electricity Supply and Delivery Activities - We recognize revenues on an accrual basis for electricity supply sales and electricity transmission and distribution delivery services. The revenues are recognized in our income statement when the energy is delivered to the customer and include unbilled as well as billed amounts. In general expenses are recorded when incurred. Energy Marketing and Trading Activities - AEP engages in wholesale electricity marketing and trading transactions (trading activities). A portion of the revenues and costs of AEP's trading activities are allocated to WTU. Trading activities allocated to WTU involve the purchase and sale of energy under physical forward contracts at fixed and variable prices. Although trading contracts are generally short-term, there are also long-term trading contracts. We recognize revenues from trading activities generally based on changes in the fair value of energy trading contracts. Recording the net change in the fair value of trading contracts as revenues prior to settlement is commonly referred to as mark-to-market (MTM) accounting. It represents the change in the unrealized gain or loss throughout the contract's term. When the contract actually settles, that is, the energy is actually delivered in a sale or received in a purchase or the parties agree to forego delivery and receipt of electricity and net settle in cash, the unrealized gain or loss is reversed out of revenues and the actual realized cash gain or loss is recognized in revenues for a sale or in purchased power expense for a purchase. Therefore, over the trading contract's term an unrealized gain or loss is recognized as the contract's market value changes. When the contract settles the total gain or loss is realized in cash but only the difference between the accumulated unrealized net gains or losses recorded in prior months and the cash proceeds is recognized. Unrealized mark-to-market gains and losses are included in the Balance Sheet as energy trading contract assets or liabilities as appropriate. Our trading activities represent physical forward electricity contracts that are typically settled by entering into offsetting contracts. An example of our trading activities is when, in January, we enter into a forward sales contract to deliver electricity in July. At the end of each month until the contract settles in July, we would record our share of any difference between the contract price and the market price as an unrealized gain or loss in revenues. In July when the contract settles, we would realize our share of the gain or loss in cash and reverse to revenues the previously recorded unrealized gain or loss. Prior to settlement, the change in the fair value of physical forward sale and purchase contracts is included in revenues on a net basis. Upon settlement of a forward trading contract, the amount realized is included in revenues for a sales contract and realized costs are included in purchased power expense for a purchase contract with the prior change in unrealized fair value reversed in revenues. Continuing with the above example, assume that later in January or sometime in February through July we enter into an offsetting forward contract to buy electricity in July. If we do nothing else with these contracts until settlement in July and if the volumes, delivery point, schedule and other key terms match, then the difference between the sale price and the purchase price represents a fixed value to be realized when the contracts settle in July. If the purchase contract is perfectly matched with the sales contract, we have effectively fixed the profit or loss; specifically it is the difference between the contracted settlement price of the two contracts. Mark-to-market accounting for these contracts will have no further impact on results of operations but will have an offsetting and equal effect on trading contract assets and liabilities. Of course we could also do similar transactions but enter into a purchase contract prior to entering into a sales contract. If the sale and purchase contracts do not match exactly as to volumes, delivery point, schedule and other key terms, then there could be continuing mark-to-market effects on revenues from recording additional changes in fair values using mark-to-market accounting. The fair value of open short-term trading contracts are based on exchange prices and broker quotes. We mark-to-market open long-term trading contracts based mainly on AEP-developed valuation models. These models estimate future energy prices based on existing market and broker quotes and supply and demand market data and assumptions. The fair values determined are reduced by reserves to adjust for credit risk and liquidity risk. Credit risk is the risk that the counterparty to the contract will fail to perform or fail to pay amounts due AEP. Liquidity risk represents the risk that imperfections in the market will cause the price to be less than or more than what the price should be based purely on supply and demand. There are inherent risks related to the underlying assumptions in models used to fair value open long-term trading contracts. AEP has independent controls to evaluate the reasonableness of our valuation models. However, energy markets, especially electricity markets, are imperfect and volatile and unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a contract's term and when contracts settle. Therefore, there could be significant adverse or favorable effects on future results of operations and cash flows if market prices do not correlate with the AEP-developed price models. Volatility in commodities markets affects the fair values of all of our open trading contracts exposing WTU to market risk. See "Market Risks" section of MD&A for a discussion of the policies and procedures used to manage exposure to risk from trading activities. Results of Operations Income before extraordinary items decreased $15.1 million or 55% during 2001, due mostly to a significant increase in other operation expense. The significant increase in other operation expense is partially due to the effect of a 2001 increase in energy delivery's transmission expenses that resulted from new prices for the Electric Reliability Council of Texas (ERCOT) transmission grid. Other operation expense also increased due to the effect of a favorable adjustment made in 2000 related to a FERC-approved Transmission Coordination Agreement. Operating Revenues Operating revenues increased 40% in 2001, as the result of increased trading volumes of AEP's wholesale business. This increase in revenues is attributable to our sharing in AEP's power marketing and trading transactions since the merger of AEP and CSW in June 2000. Changes in the components of operating revenues were as follows: Increase (Decrease) From Previous Year (dollars in millions) Amount % - ---------------------- ------ - Retail* $ (3.1) (2) Wholesale Electric Marketing and Trading 301.9 91 Unrealized MTM 6.3 N.M. Other 6.8 18 ------ Total Marketing and Trading 311.9 55 Energy Delivery* (7.2) (4) ------ Total Revenues $304.7 40 ====== *Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery. Revenues from retail customers decreased slightly in 2001 due to milder than normal summer and winter weather. The significant increase in wholesale marketing and trading revenues is attributable to WTU's increased sharing in AEP's power marketing and trading operations. Since WTU became a subsidiary of AEP as the result of the merger in June 2000, WTU shares in AEP's power marketing and trading transactions. Trading involves the sale and purchase of substantial amounts of electricity to and from non-affiliated parties. Operating Expenses Due mostly to an increase in purchased power expense, operating expenses were $323.7 million or 46% higher than 2000. Charges in the components of operating expenses were as follows: Increase (Decrease) From Previous Year (dollars in millions) Amount % - ---------------------- ------ - Fuel $ (6.0) (3) Marketing and Trading Purchases 321.6 125 Affiliate Purchases (1.1) (2) Other Operation 18.2 20 Maintenance 1.1 5 Depreciation and Amortization (4.5) (8) Taxes Other Than Income Taxes 3.0 12 Income Taxes (8.6) (58) ------ Total $323.7 46 ====== Fuel expense decreased in 2001 due to a decrease in generation offset in part by an increase in the average spot market price for natural gas. The decrease in generation reflects milder than normal summer and winter weather. The significant increase in electricity marketing and trading purchases is the result of our full year of sharing in AEP's power marketing and trading activities. Other operation expense increased from the prior year primarily due to the effect of two items. First, energy delivery's transmission expenses increased as a result of new prices for the ERCOT transmission grid. The increase in other operation expense is also attributable to a favorable adjustment made in 2000 related to the FERC-approved Transmission Coordination Agreement. An increase in maintenance expense is the result of an overhaul in 2001 of the Oklaunion Power Plant. Due to the recordation of increased accruals in 2000 for estimated excess earnings under the Texas Legislation, depreciation and amortization expense decreased during 2001. The increase in taxes other than income taxes is the result of an increase in Texas franchise tax assessments and an increase in the Texas PUCT benefit assessment tax, a new tax in the state of Texas. Income taxes decreased in 2001, reflecting a decrease in pre-tax income. Nonoperating Income Nonoperating income increased $2.7 million due to an increase in interest income earned on under-recovered fuel during 2001. Nonoperating Expense The decrease in nonoperating expenses is mainly due to the effect of a loss provision that was recorded in 2000 for the termination of merchandise sales and the cost of phasing out the merchandising sales programs.
WEST TEXAS UTILITIES COMPANY Statements of Income Year Ended December 31, ------------------------------------------ 2001 2000 1999 ---- ---- ---- (in thousands) OPERATING REVENUES Electricity Marketing and Trading $ 876,554 $ 564,704 $256,033 Energy Delivery 169,036 176,204 174,909 Sales to AEP Affiliates 18,681 18,654 14,767 ---------- ---------- ------ Total Operating Revenues 1,064,271 759,562 445,709 --------- ------- ------- OPERATING EXPENSES: Fuel 177,140 183,154 123,348 Purchased Power: Electricity Marketing and Trading 578,193 256,578 34,941 AEP Affiliates 56,656 57,773 26,591 Other Operation 111,263 93,078 94,290 Maintenance 22,343 21,241 19,604 Depreciation and Amortization 50,705 55,172 50,789 Taxes Other Than Income Taxes 28,319 25,321 28,268 Income Taxes 6,262 14,904 14,079 ----- ------ ------ TOTAL OPERATING EXPENSES 1,030,881 707,221 391,910 --------- ------- ------- OPERATING INCOME 33,390 52,341 53,799 NONOPERATING INCOME 12,199 9,530 14,515 NONOPERATING EXPENSES 10,695 12,664 11,169 NONOPERATING INCOME TAX EXPENSE (CREDIT) (691) (1,459) 858 INTEREST CHARGES 23,275 23,216 24,420 ------ ------ ------ INCOME BEFORE EXTRAORDINARY ITEMS 12,310 27,450 31,867 EXTRAORDINARY LOSS (net of tax of $2,941,000) - - (5,461) ---- ---- ------ NET INCOME 12,310 27,450 26,406 PREFERRED STOCK DIVIDEND REQUIREMENTS 104 104 104 --- --- --- EARNINGS APPLICABLE TO COMMON STOCK $ 12,206 $ 27,346 $ 26,302 ======== ======== ======== Statements of Retained Earnings BEGINNING OF PERIOD $122,588 $113,242 $114,940 NET INCOME 12,310 27,450 26,406 DEDUCTIONS: Cash Dividends Declared: Common Stock 28,824 18,000 28,000 Preferred Stock 104 104 104 --- --- --- BALANCE AT END OF PERIOD $105,970 $122,588 $113,242 ======== ======== ========
See Notes to Financial Statements beginning on page L-1. WEST TEXAS UTILITIES COMPANY Balance Sheets December 31, ------------------------ 2001 2000 ---- ---- (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production $443,508 $431,793 Transmission 250,023 235,303 Distribution 431,969 416,587 General 112,797 110,832 Construction Work in Progress 22,575 34,824 ------ ------ Total Electric Utility Plant 1,260,872 1,229,339 Accumulated Depreciation and Amortization 546,162 515,041 ------- ------- NET ELECTRIC UTILITY PLANT 714,710 714,298 ------- ------- OTHER PROPERTY AND INVESTMENTS 24,933 23,154 ------ ------ LONG-TERM ENERGY TRADING CONTRACTS 21,532 20,804 ------ ------ CURRENT ASSETS: Cash and Cash Equivalents 2,454 6,941 Accounts Receivable: Customers 18,720 36,217 Affiliated Companies 8,656 16,095 Allowance for Uncollectible Accounts (196) (288) Fuel - at average cost 8,307 12,174 Materials and Supplies - at average cost 11,190 10,510 Under-recovered Fuel Costs 32,791 68,107 Energy Trading Contracts 63,252 150,793 Prepayments 966 851 --- --- TOTAL CURRENT ASSETS 146,140 301,400 ------- ------- REGULATORY ASSETS 13,659 24,808 ------ ------ DEFERRED CHARGES 2,446 2,947 ----- ----- TOTAL $923,420 $1,087,411 ======== ========== See Notes to Financial Statements beginning on page L-1. WEST TEXAS UTILITIES COMPANY December 31, ----------------------- 2001 2000 ---- ---- (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock - $25 Par Value: Authorized - 7,800,000 Shares Outstanding - 5,488,560 Shares $137,214 $137,214 Paid-in Capital 2,236 2,236 Retained Earnings 105,970 122,588 ------- ------- Total Common Shareholder's Equity 245,420 262,038 Cumulative Preferred Stock Not Subject to Mandatory Redemption 2,482 2,482 Long-term Debt 220,967 255,843 ------- ------- TOTAL CAPITALIZATION 468,869 520,363 ------- ------- CURRENT LIABILITIES: Long-term Debt Due Within One Year 35,000 - Advances from Affiliates 50,448 58,578 Accounts Payable - General 33,782 45,562 Accounts Payable - Affiliated Companies 11,388 42,212 Customer Deposits 4,191 2,659 Taxes Accrued 17,358 18,901 Interest Accrued 1,244 3,717 Energy Trading Contracts 65,414 153,539 Other 12,001 7,906 ------ ----- TOTAL CURRENT LIABILITIES 230,826 333,074 ------- ------- DEFERRED INCOME TAXES 145,049 157,038 ------- ------- DEFERRED INVESTMENT TAX CREDITS 22,781 24,052 ------ ------ LONG-TERM ENERGY TRADING CONTRACTS 18,455 20,648 ------ ------ REGULATORY LIABILITIES AND DEFERRED CREDITS 37,440 32,236 ------ ------ COMMITMENTS AND CONTINGENCIES (Note 8) TOTAL $923,420 $1,087,411 ======== ========== See Notes to Financial Statements beginning on page L-1.
WEST TEXAS UTILITIES COMPANY Statements of Cash Flows Year Ended December 31, --------------------------------------- 2001 2000 1999 ---- ---- ---- (in thousands) OPERATING ACTIVITIES: Net Income $ 12,310 $27,450 $26,406 Adjustments for Noncash Items: Depreciation and Amortization 50,705 55,172 50,789 Deferred Federal Income Taxes (11,891) 8,164 12,026 Deferred Investment Tax Credits (1,271) (1,271) (1,275) Extraordinary Loss - Discontinuance of SFAS 71 - - 5,461 Mark-to-Market of Energy Trading Contracts (1,818) 1,871 - CHANGES IN CERTAIN ASSETS AND LIABILITIES: Accounts Receivable (net) 24,844 (1,445) (18,890) Fuel, Materials and Supplies 3,187 8,478 (3,785) Accounts Payable (42,604) 28,393 7,229 Taxes Accrued (1,543) 6,443 2,427 Fuel Recovery 35,316 (53,841) (10,101) Transmission Coordination Agreement Settlement - 15,465 (15,465) Change in Other Assets (1,519) 3,361 5,615 Change in Other Liabilities 6,644 (3,962) 2,205 ----- ------ ----- Net Cash Flows From Operating Activities 72,360 94,278 62,642 ------ ------ ------ INVESTING ACTIVITIES: Construction Expenditures (39,662) (64,477) (49,443) Other (127) - (3,832) ---- ---- ------ Net Cash Used For Investing Activities (39,789) (64,477) (53,275) ------- ------- ------- FINANCING ACTIVITIES: Retirement of Long-term Debt - (48,000) - Change in Advances From Affiliates (net) (8,130) 37,170 16,835 Dividends Paid on Common Stock (28,824) (18,000) (28,000) Dividends Paid on Cumulative Preferred Stock (104) (104) (105) ---- ---- ---- Net Cash Used For Financing Activities (37,058) (28,934) (11,270) ------- ------- ------- Net Increase (Decrease) in Cash and Cash Equivalents (4,487) 867 (1,903) Cash and Cash Equivalents at Beginning of Period 6,941 6,074 7,977 ----- ----- ----- Cash and Cash Equivalents at End of Period $2,454 $ 6,941 $ 6,074 ====== ======= =======
Supplemental Disclosure: Cash paid (received) for interest net of capitalized amounts was $19,279,000, $19,088,000 and $17,577,000 and for income taxes was $21,997,000, $(906,000) and $3,309,000 in 2001, 2000 and 1999, respectively. See Notes to Financial Statements beginning on page L-1.
WEST TEXAS UTILITIES COMPANY Statements of Capitalization December 31, --------------------------- 2001 2000 ---- ---- (in thousands) COMMON SHAREHOLDER'S EQUITY $245,420 $262,038 -------- -------- PREFERRED STOCK: $100 par value - authorized shares 810,000 Call Price Shares December 31, Number of Shares Redeemed Outstanding Series 2001 Year Ended December 31, December 31, 2001 - ------ ------------ ---------------------------- ----------------- 2001 2000 1999 ---- ---- ---- Not Subject to Mandatory Redemption: 4.40% $107 - 1 2 23,672 2,367 2,367 Premium 115 115 -------- -------- 2,482 2,482 -------- -------- LONG-TERM DEBT (See Schedule of Long-term Debt): First Mortgage Bonds 211,657 211,533 Installment Purchase Contracts 44,310 44,310 Less Portion Due Within One Year (35,000) - -------- -------- Long-term Debt Excluding Portion Due Within One Year 220,967 255,843 -------- -------- TOTAL CAPITALIZATION $468,869 $520,363 ======== ========
See Notes to Financial Statements beginning on page L-1. WEST TEXAS UTILITIES COMPANY Schedule of Long-term Debt First mortgage bonds outstanding were as follows: December 31, -------------------- 2001 2000 ---- ---- (in thousands) % Rate Due 7-3/4 2007 - June 1 $ 25,000 $ 25,000 6-7/8 2002 - October 1 35,000 35,000 7 2004 - October 1 40,000 40,000 6-1/8 2004 - February 1 40,000 40,000 6-3/8 2005 - October 1 72,000 72,000 Unamortized Discount (343) (467) -------- -------- $211,657 $211,533 First mortgage bonds are secured by first mortgage liens on electric utility plant. Certain indentures relating to the first mortgage bonds contain improvement, maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. Installment purchase contracts have been entered into, in connection with the issuance of pollution control revenue bonds by governmental authorities as follows: December 31, 2001 2000 ---- ---- (in thousands) % Rate Due Red River Authority of Texas: 6 2020 - June 1 $44,310 $44,310 ======= ======= Under the terms of the installment purchase contracts, WTU is required to pay amounts sufficient to enable the payment of interest on and the principal (at stated maturities and upon mandatory redemptions) of related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants. At December 31, 2001, future annual long-term debt payments are as follows: Amount ------ (in thousands) 2002 $ 35,000 2003 - 2004 80,000 2005 72,000 2006 - Later Years 69,310 -------- Principal Amount 256,310 Unamortized Discount (343) -------- Total $255,967 ======== WEST TEXAS UTILITIES COMPANY Index to Notes to Financial Statements The notes to WTU's financial statements are combined with the notes to financial statements for AEP and its other subisidiary registrants. Listed below are the combined notes that apply to WTU. The combined footnotes begin on page L-1. Combined Footnote Reference Significant Accounting Policies Note 1 Extraordinary Items and Cumulative Effect Note 2 Merger Note 3 Rate Matters Note 5 Effects of Regulation Note 6 Customer Choice and Industry Restructuring Note 7 Commitments and Contingencies Note 8 Benefit Plans Note 10 Business Segments Note 12 Risk Management, Financial Instruments and Derivatives Note 13 Income Taxes Note 14 Leases Note 18 Lines of Credit and Sale of Receivables Note 19 Unaudited Quarterly Financial Information Note 20 Jointly Owned Electric Utility Plant Note 23 Related Party Transactions Note 24 INDEPENDENT AUDITORS' REPORT To the Shareholders and Board of Directors of West Texas Utilities Company: We have audited the accompanying balance sheets and statements of capitalization of West Texas Utilities Company as of December 31, 2001 and 2000, and the related statements of income, retained earnings, and cash flows for the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. The financial statements of the Company for the year ended December 31, 1999, before the restatement described in Note 3 to the financial statements, were audited by other auditors whose report, dated February 25, 2000, expressed an unqualified opinion on those statements. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such 2001 and 2000 financial statements present fairly, in all material respects, the financial position of West Texas Utilities Company as of December 31, 2001 and 2000, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America. We also audited the adjustments described in Note 3 that were applied to restate the 1999 financial statements to give retroactive effect to the conforming change in the method of accounting for vacation pay accruals. In our opinion, such adjustments are appropriate and have been properly applied. DELOITTE & TOUCHE LLP Columbus, Ohio February 22, 2002 NOTES TO FINANCIAL STATEMENTS The notes to financial statements that follow are a combined presentation for AEP and its subsidiary registrants. The following list of footnotes shows the registrant to which they apply: 1. Significant Accounting Policies AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU 2. Extraordinary Items and Cumulative Effect AEP, APCo, CPL, CSPCo, OPCo, SWEPCo, WTU 3. Merger AEP, CPL, I&M, KPCo, PSO, SWEPCo, WTU 4. Nuclear Plant Restart AEP, I&M 5. Rate Matters AEP, APCo, CPL, PSO, SWEPCo, WTU 6. Effects of Regulation AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU 7. Customer Choice and Industry Restructuring AEP, APCo, CPL, CSPCo, I&M, OPCo, PSO, SWEPCo, WTU 8. Commitments and Contingencies AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU 9. Acquisitions and Dispositions AEP, OPCo, SWEPCo 10. Benefit Plans AEP, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU 11. Stock-Based Compensation AEP 12. Business Segments AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU 13. Risk Management, Financial AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, Instruments and Derivatives OPCo, PSO, SWEPCo, WTU 14. Income Taxes AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU 15. Basic and Diluted Earnings Per Share AEP 16. Supplementary Information AEP, APCo, CSPCo, I&M, OPCo 17. Power, Distribution and Communications Projects AEP 18. Leases AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU 19. Lines of Credit and Sale of Receivables AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU 20. Unaudited Quarterly Financial Information AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU 21. Trust Preferred Securities AEP, CPL, PSO, SWEPCo 22. Minority Interest in Finance Subsidiary AEP 23. Jointly Owned Electric Utility Plant CPL, CSPCo, PSO, SWEPCo, WTU 24. Related Party Transactions AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU 1. Significant Accounting Policies: Business Operations - AEP's principal business conducted by its eleven domestic electric utility operating companies is the generation, transmission and distribution of electric power. Nine of AEP's eleven domestic electric utility operating companies, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU, are SEC registrants. AEGCo is a domestic generating company wholly-owned by AEP that is an SEC registrant. These companies are subject to regulation by the FERC under the Federal Power Act and follow the Uniform System of Accounts prescribed by FERC. They are subject to further regulation with regard to rates and other matters by state regulatory commissions. AEP also engages in wholesale marketing and trading of electricity, natural gas and to a lesser extent coal, oil, natural gas liquids and emission allowances in the United States and Europe. In addition the Company's domestic operations includes non-regulated independent power and cogeneration facilities, coal mining and intra-state midstream natural gas operations in Louisiana and Texas. International operations include regulated supply and distribution of electricity and other non-regulated power generation projects in the United Kingdom, Australia, Mexico, South America and China. The Company also operates domestic barging, provides energy services worldwide and furnishes communications related services domestically. Rate Regulation - AEP is subject to regulation by the SEC under the PUHCA. The rates charged by the domestic utility subsidiaries are approved by the FERC and the state utility commissions. The FERC regulates wholesale electricity operations and transmission rates and the state commissions regulate retail rates. The prices charged by foreign subsidiaries located in the UK, Australia, China, Mexico and Brazil are regulated by the authorities of that country and are generally subject to price controls. Principles of Consolidation - AEP's consolidated financial statements include AEP Co., Inc. and its wholly-owned and majority-owned subsidiaries consolidated with their wholly-owned or substantially controlled subsidiaries. The consolidated financial statements for APCo, CPL, CSPCo, I&M, OPCo, PSO and SWEPCo include the registrant and its wholly-owned subsidiaries. Significant intercompany items are eliminated in consolidation. Equity investments not substantially controlled that are 50% or less owned are accounted for using the equity method with their equity earnings included in Other Income for AEP and nonoperating income for the registrant subsidiaries. Basis of Accounting - As the owner of cost-based rate-regulated electric public utility companies, AEP Co., Inc.'s consolidated financial statements reflect the actions of regulators that result in the recognition of revenues and expenses in different time periods than enterprises that are not rate regulated. In accordance with SFAS 71, "Accounting for the Effects of Certain Types of Regulation," regulatory assets (deferred expenses) and regulatory liabilities (future revenue reductions or refunds) are recorded to reflect the economic effects of regulation by matching expenses with their recovery through regulated revenues. Application of SFAS 71 for the generation portion of the business was discontinued as follows: in Ohio by OPCo and CSPCo in September 2000, in Virginia and West Virginia by APCo in June 2000, in Texas by CPL, WTU, and SWEPCo in September 1999 and in Arkansas by SWEPCo in September 1999. See Note 7, "Customer Choice and Industry Restructuring" for additional information. Use of Estimates - The preparation of these financial statements in conformity with generally accepted accounting principles necessarily includes the use of estimates and assumptions by management. Actual results could differ from those estimates. Property, Plant and Equipment - Domestic electric utility property, plant and equipment are stated at original cost of the acquirer. Property, plant and equipment of the non-regulated domestic operations and other investments are stated at their fair market value at acquisition plus the original cost of property acquired or constructed since the acquisition, less disposals. Additions, major replacements and betterments are added to the plant accounts. For cost-based rate regulated operations retirements from the plant accounts and associated removal costs, net of salvage, are deducted from accumulated depreciation. The costs of labor, materials and overheads incurred to operate and maintain plant are included in operating expenses. Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization - - AFUDC is a noncash nonoperating income item that is capitalized and recovered through depreciation over the service life of domestic regulated electric utility plant. It represents the estimated cost of borrowed and equity funds used to finance construction projects. The amounts of AFUDC for 2001, 2000 and 1999 were not significant. Effective with the discontinuance of the application of SFAS 71 regulatory accounting for domestic generating assets in Arkansas, Ohio, Texas, Virginia and West Virginia and for other non-regulated operations, interest is capitalized during construction in accordance with SFAS 34, "Capitalization of Interest Costs." The amounts of interest capitalized were not material in 2001, 2000, and 1999. Depreciation, Depletion and Amortization - Depreciation of property, plant and equipment is provided on a straight-line basis over the estimated useful lives of property, other than coal-mining property, and is calculated largely through the use of composite rates by functional class as follows: Annual Composite Functional Class Depreciation Rates of Property Ranges 2001 Production: Steam-Nuclear 2.5% to 3.4% Steam-Fossil-Fired 2.5% to 4.5% Hydroelectric- Conventional and Pumped Storage 1.9% to 3.4% Transmission 1.7% to 3.1% Distribution 2.7% to 4.2% Other 1.8% to 15.0% Annual Composite Functional Class Depreciation Rates of Property Ranges 2000 Production: Steam-Nuclear 2.8% to 3.4% Steam-Fossil-Fired 2.3% to 4.5% Hydroelectric- Conventional and Pumped Storage 1.9% to 3.4% Transmission 1.7% to 3.1% Distribution 3.3% to 4.2% Other 2.5% to 7.3% Annual Composite Functional Class Depreciation Rates of Property Ranges 1999 Production: Steam-Nuclear 2.8% to 3.4% Steam-Fossil-Fired 3.2% to 5.0% Hydroelectric- Conventional and Pumped Storage 1.9% to 3.4% Transmission 1.7% to 2.7% Distribution 2.8% to 4.2% Other 2.0% to 20.0%
The following table provides the annual composite depreciation rates generally used by the AEP registrant subsidiaries for the years 2001, 2000 and 1999 which were as follows: Nuclear Steam Hydro Transmission Distribution General ------- ----- ----- ------------ ------------ ------- AEGCo - % 3.5% - % - % - % 2.8% APCo - 3.4 2.9 2.2 3.3 3.1 CPL 2.5 2.5 1.9 2.3 3.5 4.0 CSPCo - 3.2 - 2.3 3.6 3.2 I&M 3.4 4.5 3.4 1.9 4.2 3.8 KPCo - 3.8 - 1.7 3.5 2.5 OPCo - 3.4 2.7 2.3 4.0 2.7 PSO - 2.7 - 2.3 3.4 6.0 SWEPCo - 3.4 - 2.7 3.6 4.5 WTU - 2.8 - 3.1 3.3 6.6
Depreciation, depletion and amortization of coal-mining assets is provided over each asset's estimated useful life or the estimated life of the mine, whichever is shorter, and is calculated using the straight-line method for mining structures and equipment. The units-of-production method is used to amortize coal rights and mine development costs based on estimated recoverable tonnages at a current average rate of $3.46 per ton in 2001, $5.07 per ton in 2000 and $2.32 per ton in 1999. These costs are included in the cost of coal charged to fuel expense. Cash and Cash Equivalents - Cash and cash equivalents include temporary cash investments with original maturities of three months or less. Inventory - Except for CPL, PSO and WTU, the regulated domestic utility companies value fossil fuel inventories using a weighted average cost method. CPL, PSO and WTU, utilize the LIFO method to value fossil fuel inventories. For those domestic utilities whose generation is unregulated, inventory of coal and oil is carried at the lower of cost or market. Coal mine inventories are also carried at the lower of cost or market. Natural gas inventories are marked-to-market if held in connection with trading operations. Any non-trading gas inventory is carried at the lower of cost or market. Accounts Receivable - AEP Credit Inc. (formerly CSW Credit) factors accounts receivable for the domestic utility subsidiaries and certain non-affiliated utilities. On December 31, 2001 AEP Credit, Inc. entered into a sale of receivables agreement with a group of banks and commercial paper conduits. This transaction constitutes a sale of receivables in accordance with SFAS 140, allowing the receivables to be taken off of the companies balances sheet. See Note 19 for further details. Foreign Currency Translation - The financial statements of subsidiaries outside the U.S. which are included in AEP's consolidated financial statements are measured using the local currency as the functional currency and translated into U.S. dollars in accordance with SFAS 52 "Foreign Currency Translation". Assets and liabilities are translated to U.S. dollars at year-end rates of exchange and revenues and expenses are translated at monthly average exchange rates throughout the year. Currency translation gain and loss adjustments are recorded in shareholders' equity as "Accumulated Other Comprehensive Income (Loss)". The non-cash impact of the changes in exchange rates on cash, resulting from the translation of items at different exchange rates is shown on AEP's Consolidated Statement of Cash Flows in "Effect of Exchange Rate Change on Cash." Actual currency transaction gains and losses are recorded in income. Deferred Fuel Costs - The cost of fuel consumed is charged to expense when the fuel is burned. Where applicable under governing state regulatory commission retail rate orders, fuel cost over or under-recoveries are deferred as regulatory liabilities or regulatory assets in accordance with SFAS 71. These deferrals generally are amortized when refunded or billed to customers in later months with the regulator's review and approval. The amount of deferred fuel costs under fuel clauses for AEP was $139 million at December 31, 2001 and $407 million at December 31, 2000. See also Note 6 "Effects of Regulation". We are protected from fuel cost changes in Kentucky for KPCo, the SPP area of Texas, Louisiana and Arkansas for SWEPCo, Oklahoma for PSO and Virginia for APCo. Where fuel clauses have been eliminated due to the transition to market pricing, (Ohio effective January 1, 2001 and in the Texas ERCOT area effective January 1, 2002) changes in fuel costs impact earnings. In other state jurisdictions, (Indiana, Michigan and West Virginia) where fuel clauses have been frozen or suspended for a period of years, fuel cost changes also impact earnings currently. This is also true for certain of AEP's Independent Power Producer generating units that do not have long-term contracts for their fuel supply. See Note 5, "Rate Matters" and Note 7, "Customer Choice and Industry Restructuring" for further information about fuel recovery. Revenue Recognition - We recognize revenues from foreign and domestic generation, transmission and distribution of electricity, domestic gas pipeline and storage services, other energy supply related business activities, as well as domestic barging, telecommunications and related services. The revenues associated with these activities are recorded when earned as physical commodities are delivered to contractual meter points or services are provided. These revenues also include the accrual of earned, but unbilled and/or not yet metered revenues. Such revenues are based on contract prices or tariffs and presented on a gross basis consistent with generally accepted accounting principles and industry practice. Revenue recognition for energy marketing and trading transactions is further discussed within the Energy Marketing and Trading Transactions section below. The Company follows EITF 98-10 and marks to market energy trading activities, which includes the net change in fair value of open trading contracts in earnings. Mark-to-market gains and losses on open contracts and net settlements of financial contracts (see below) are included in revenues on a net basis. The net basis of reporting for open contracts is permitted by EITF 98-10 and for settled financial contracts is consistent with industry practice. Settled physical forward trading transactions are reported on a gross basis, as permitted by EITF 98-10. Management believes that the gross basis of reporting for settled physical forward trading contracts is a better indication of the scope and significance of energy trading activities to the Company. Energy Marketing and Trading Transactions - AEP engages in wholesale electricity and natural gas marketing and trading transactions (trading activities). Trading activities inolve the purchase and sale of energy under forward contracts at fixed and variable prices and the trading of financial energy contracts which includes exchange futures and options and over-the-counter options and swaps. Although trading contracts are generally short-term, there are long-term trading contracts. The majority of trading activities represent forward electricity and gas contracts that are typically settled by entering into offsetting physical contracts. Forward trading sale contracts are included in AEP's revenues when the contracts settle. Forward trading purchase contracts are included in AEP's fuel and purchased energy expenses when they settle. Prior to settlement the change in fair values of forward sale and purchase contracts are included in AEP's revenues. All of the registrant subsidiaries except AEGCo participate in AEP's wholesale marketing and trading of electricity. APCo, CSPCo, I&M, KPCo and OPCo record forward electricity trading sale contracts in operating revenues when the contracts settle for contracts with delivery points in AEP's traditional marketing area and in nonoperating income for forward electricity trading sale contracts outside AEP's traditional marketing area. APCo, CSPCo, I&M, KPCo and OPCo record forward electricity trading purchase contracts in purchased power expense when the contracts settle for contracts with delivery points in AEP's traditional marketing area and in nonoperating expense for forward electricity trading purchase contracts outside AEP's traditional marketing area. CPL, PSO, SWEPCo and WTU record revenues from forward electricity trading sale contracts in operating revenues. CPL, PSO, SWEPCo and WTU record purchased power expense for forward electricity trading purchase contracts when they settle. APCo, CSPCo and OPCo account for open forward electricity sale and purchase contracts on a mark-to-market basis and include the mark-to-market change in operating revenues for open contracts in AEP's traditional marketing area and in nonoperating income for open contracts beyond AEP's traditional marketing area. I&M and KPCo account for open forward electricity sale and purchase contracts on a mark-to-market basis and defer the mark-to-market change as regulatory assets or liabilities for those open contracts in AEP's traditional marketing area and include the mark-to-market change in nonoperating income for open contracts beyond AEP's traditional marketing area. CPL, PSO, SWEPCo and WTU account for open forward electricity sale and purchase contracts on a mark-to-market basis. CPL includes the mark-to-market change for open electricity trading contracts in revenues. PSO defers as regulatory assets or liabilities the mark-to-market change for open forward electricity trading contracts that are included in cost of service on a settlement basis for ratemaking purposes. SWEPCo and WTU include the jurisdictional share of the mark-to-market change in revenues for open electricity trading contracts for those jurisdictions that are not subject to SFAS 71 cost based rate regulation and defer as regulatory assets or liabilities the jurisdictional share of the mark-to-market change for open contracts that are included in cost of service on a settlement basis for ratemaking purposes. Trading purchases and sales through electricity and gas options, futures and swaps, represent financial transactions with the net proceeds reported in AEP's revenues at fair value upon entering the contracts. APCo, CSPCo, I&M, KPCo and OPCo share in AEP's trading sales and purchases through electricity options, futures and swaps, which represent financial transactions. Changes in fair values of these financial contracts are reported net in nonoperating income. When these contracts settle, the net proceeds are recorded in nonoperating income and the prior unrealized gain or loss in reversed. Recording of the net changes in fair value of open trading contracts is commonly referred to a mark-to-market accounting. All open contracts from trading activities are marked to market in accordance with EITF 98-10. Except as noted above, the net mark-to-market (change in fair value) amount included in results of operations on a net discounted basis. The fair values of open short-term trading contracts are based on exchange prices and broker quotes. Open long-term trading contracts are marked to market based mainly on AEP developed valuation models. The valuation models produce an extimated fair value for open long-term trading contracts. The short-term and long-term fair values are present valued and reduced by appropriate reserves for counterparty credit risks and liquidity risk. The models are derived from internally assessed market prices with the exception of the NYMEX gas curve, where we use daily settled prices. Bid/ask price curves are developed for inclusion in the model based on broker quotes and other available market data. The curves are within the range between the bid and ask price. The end of the month liquidity reserve is based on the difference in price between the price curve and the bid side of the bid ask if we have a long position and the ask side if we have a short position. This provides for a conservative valuation net of the reserves. The use of these models to fair value open trading contracts has inherent risks relating to the underlying assumptions employed by such models. Independent controls are in place to evaluate the reasonableness of the price curve models. Significant adverse or favorable effects on future results of operations and cash flows could occur if market risks, at the time of settlement, do not correlate with AEP developed price models. The effect on AEP's Consolidated Statements of Income of marking to market open electricity trading contracts in AEP's regulated jurisdictions is deferred as regulatory assets or liabilities since these transactions are included in cost of service on a settlement basis for ratemaking purposes. Unrealized mark-to-market gains and losses from trading activities whether deferred or recognized in revenues are part of Energy Trading and Derivative Contracts assets or liabilities as appropriate. Hedging and Related Activities - In order to mitigate the risks of market price and interest rate fluctuations, AEP's foreign subsidiaries, SEEBOARD and CitiPower, utilize interest swaps, and currency swaps to hedge such market fluctuations. Changes in the market value of these swaps are deferred until the gain or loss is realized on the underlying hedged asset, liability or commodity. To qualify as a hedge, these transactions must be designated as a hedge and changes in their fair value must correlate with changes in the price and interest rate movement of the underlying asset, liability or commodity. This in effect reduces AEP's exposure to the effects of market fluctuations related to price and interest rates. AEP, APCo, CSPCo, I&M, and OPCo enter into contracts to manage the exposure to unfavorable changes in the cost of debt to be issued. These anticipatory debt instruments are entered into in order to manage the change in interest rates between the time a debt offering is initiated and the issuance of the debt (usually a period of 60 days). Gains or losses from these transactions are deferred and amortized over the life of the debt issuance with the amortization included in interest charges. There were no such forward contracts outstanding at December 31, 2001 or 2000. See Note 13 - "Risk Management, Financial Instruments and Derivatives" for further discussion of the accounting for risk management transactions. Levelization of Nuclear Refueling Outage Costs - In order to match costs with regulated revenues, incremental operation and maintenance costs associated with periodic refueling outages at I&M's Cook Plant are deferred and amortized over the period beginning with the commencement of an outage and ending with the beginning of the next outage. Maintenance Costs - Maintenance costs are expensed as incurred except where SFAS 71 requires the recordation of a regulatory asset to match the expensing of maintenance costs with their recovery in cost based regulated revenues. See below for an explanation of costs deferred in connection with an extended outage at I&M's Cook Plant. Amortization of Cook Plant Deferred Restart Costs - Pursuant to settlement agreements approved by the IURC and the MPSC to resolve all issues related to an extended outage of the Cook Plant, I&M deferred $200 million of incremental operation and maintenance costs during 1999. The deferred amount is being amortized to expense on a straight-line basis over five years from January 1, 1999 to December 31, 2003. I&M amortized $40 million in 2001, 2000 and 1999 leaving $80 million as an SFAS 71 regulatory asset at December 31, 2001 on the Consolidated Balance Sheets of AEP and I&M. Other Income and Other Expenses - Other Income includes equity earnings of non-consolidated subsidiaries, gains on dispositions of property, interest and dividends, an allowance for equity funds used during construction (explained above) and various other non-operating and miscellaneous income. Other Expenses includes losses on dispositions of property, miscellaneous amortization, donations and various other non-operating and miscellaneous expenses. Income Taxes - The AEP System follows the liability method of accounting for income taxes as prescribed by SFAS 109, "Accounting for Income Taxes." Under the liability method, deferred income taxes are provided for all temporary differences between the book cost and tax basis of assets and liabilities which will result in a future tax consequence. Where the flow-through method of accounting for temporary differences is reflected in regulated revenues (that is, deferred taxes are not included in the cost of service for determining regulated rates for electricity), deferred income taxes are recorded and related regulatory assets and liabilities are established in accordance with SFAS 71 to match the regulated revenues and tax expense. Investment Tax Credits - Investment tax credits have been accounted for under the flow-through method except where regulatory commissions have reflected investment tax credits in the rate-making process on a deferral basis. Investment tax credits that have been deferred are being amortized over the life of the regulated plant investment. Excise Taxes - AEP and its subsidiary registrants, as an agent for a state or local government, collect from customers certain excise taxes levied by the state or local government upon the customer. These taxes are not recorded as revenue or expense, but only as a pass-through billing to the customer to be remitted to the government entity. Excise tax collections and payments related to taxes imposed upon the customer are not presented in the income statement. Debt and Preferred Stock - Gains and losses from the reacquisition of debt used to finance domestic regulated electric utility plant are generally deferred and amortized over the remaining term of the reacquired debt in accordance with their rate-making treatment. If debt associated with the regulated business is refinanced, the reacquisition costs attributable to the portions of the business that are subject to cost based regulatory accounting under SFAS 71 are generally deferred and amortized over the term of the replacement debt commensurate with their recovery in rates. Gains and losses on the reacquisition of debt for operations not subject to SFAS 71 are reported as a component of net income. Debt discount or premium and debt issuance expenses are deferred and amortized over the term of the related debt, with the amortization included in interest charges. Where rates are regulated redemption premiums paid to reacquire preferred stock of the domestic utility subsidiaries are included in paid-in capital and amortized to retained earnings commensurate with their recovery in rates. The excess of par value over costs of preferred stock reacquired is credited to paid-in capital and amortized to retained earnings consistent with the timing of its inclusion in rates in accordance with SFAS 71. Goodwill and Intangible Assets - The amount of acquisition cost in excess of the fair value allocated to tangible and identifiable intangible assets obtained through an acquisition accounted for as a purchase combination is recorded as goodwill on AEP's consolidated balance sheet. Goodwill recognized in connection with purchase combinations acquired after June 30, 2001 was determined in accordance with SFAS 141 "Business Combinations." (see also Note 9, "Acquisitions and Dispositions"). For goodwill associated with purchase combinations before July 1, 2001, amortization is on a straight-line basis generally over 40 years except for the portion of goodwill associated with gas trading and marketing activities which is being amortized on a straight-line basis over 10 years. Accumulated amortization of goodwill was $199 million and $166 million at December 31, 2001 and 2000, respectively. In accordance with SFAS 142, "Goodwill and Other Intangible Assets," goodwill acquired after June 30, 2001 is not subject to amortization. The amortization of goodwill which predates July 1, 2001 ceased on December 31, 2001. SFAS 142 requires that other intangible assets be separately identified and if they have finite lives they must be amortized over that life. Other intangible assets of $441 million net of accumulated amortization of $38 million at December 31, 2001 are included in other assets and represent retail and wholesale distribution licenses for CitiPower operating franchises which are currently being amortized on a straight-line basis over 20 and 40 years, respectively. Also SFAS 142 provides that goodwill and other intangible assets with indefinite lives be tested for impairment annually and not be subjected to amortization. For AEP's goodwill recognized prior to July 1, 2001 and other intangible assets, these requirements will apply beginning January 1, 2002. For the year 2001, the amortization of goodwill reduced AEP's net income by $50 million. AEP is still evaluating the impact of adopting the impairment tests required by SFAS 142. Nuclear Trust Funds - Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions have allowed us to collect through rates to fund future decommissioning and spent fuel disposal liabilities. By rules or orders, the state jurisdictional commissions (Indiana, Michigan and Texas) and the FERC established investment limitations and general risk management guidelines to protect their ratepayers' funds and to allow those funds to earn a reasonable return. In general, limitations include: o Acceptable investments (rated investment grade or above) o Maximum percentage invested in a specific type of investment o Prohibition of investment in obligations of the applicable company or its affiliates. Trust funds are maintained for each regulatory jurisdiction and managed by investment managers, who must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested in order to optimize the after-tax earnings of the Trust, giving consideration to liquidity, risk, diversification, and other prudent investment objectives. Securities held in trust funds for decommissioning nuclear facilities and for the disposal of spent nuclear fuel are included in Other Assets at market value in accordance with SFAS 115, "Accounting for Certain Investments in Debt and Equity Securities." Securities in the trust funds have been classified as available-for-sale due to their long-term purpose. In accordance with SFAS 71, unrealized gains and losses from securities in these trust funds are not reported in equity but result in adjustments to the liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the spent nuclear fuel disposal trust funds in accordance with their treatment in rates. Comprehensive Income - Comprehensive income is defined as the change in equity (net assets) of a business enterprise during a period from transactions and other events and circumstances from non-owner sources. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. Comprehensive income has two components, net income and other comprehensive income. There were no material differences between net income and comprehensive income for AEGCo, CPL, CSPCo, PSO, SWEPCo and WTU. Components of Other Comprehensive Income - Other comprehensive income is included on the balance sheet in the equity section. The following table provides the components that comprise the balance sheet amount in Accumulated Other Comprehensive Income for AEP. December 31, Components 2001 2000 1999 - ----------------------------------------------------------- (millions) Foreign Currency Adjustments $(113) $ (99) $ 20 Unrealized Losses On Securities - - (20) Unrealized Gain on Hedged Derivatives (3) - - Minimum Pension (10) (4) (4) --- -- -- Liability $(126) $(103) $ (4) ===== ===== ==== Accumulated Other Comprehensive Income for AEP registrant subsidiaries as of December 31, 2001, is shown in the following table. Registrant subsidiary balances for Accumulated Other Comprehensive Income for the two years ended December 31, 2000 and 1999 were zero. December 31, Components 2001 - --------------------------------------------- (thousands) Foreign Currency Rate Hedge APCo $ (340) I&M (3,835) KPCo (1,903) OPCo (196) Segment Reporting - The AEP System has adopted SFAS No. 131, which requires disclosure of selected financial information by business segment as viewed by the chief operating decision-maker. See Note 12 "Business Segments" for further discussion and details regarding segments. Common Stock Options - AEP follows Accounting Principles Board Opinion 25 to account for stock options. Compensation expense is not recognized at the date of grant or when exercised, because the exercise price of stock options awarded under the stock option plan equals the market price of the underlying stock on the date of grant. EPS - AEP's basic earnings per share is determined based upon the weighted average number of common shares outstanding during the years presented. Diluted earnings per share for AEP is based upon the weighted average number of common shares and stock options outstanding during the years presented. Basic and diluted EPS are the same in 2001, 2000 and 1999. AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, and WTU are wholly-owned subsidiaries of AEP and are not required to report EPS. Reclassification - Certain prior year financial statement items have been reclassified to conform to current year presentation. Such reclassification had no impact on previously reported net income. Certain settled forward energy transactions of the trading operation were reclassified from a net to a gross basis of presentation in order to better reflect the scope and nature of the AEP System's energy sales and purchases. All financially net settled trading transactions, such as swaps, futures, and unexercised options, and all marked-to-market values on open trading contracts continue to be reported on a net basis, reflecting the financial nature of these transactions. As applicable, prior year amounts of realized physical purchases from settled purchase trading contracts were reclassified from revenues to purchased power expense to present the prior period on a comparable gross basis. 2. Extraordinary Items and Cumulative Effect: Extraordinary Items - Extraordinary items were recorded for the discontinuance of regulatory accounting under SFAS 71 for the generation portion of the business in the Ohio, Virginia, West Virginia, Texas and Arkansas state jurisdictions. See Note 7 "Customer Choice and Industry Restructuring" for descriptions of the restructuring plans and related accounting effects. OPCo and CSPCo recognized an extraordinary loss for stranded Ohio Public Utility Excise Tax (commonly known as the Gross Receipts Tax - GRT) net of allowable Ohio coal credits during the quarter ended June 30, 2001. This loss resulted from regulatory decisions in connection with Ohio deregulation which stranded the recovery of the GRT. Effective with the liability affixing on May 1, 2001, CSPCo and OPCo recorded an extraordinary loss under SFAS 101. Both Ohio companies have appealed to the Ohio Supreme Court the PUCO order on Ohio restructuring that the Ohio companies believe failed to provide for recovery for the final year of the GRT. The Ohio Supreme Court decision is expected in 2002. In October 2001 CPL reacquired $101 million of pollution control bonds in advance of their maturity. Since these pollution control bonds were used to finance generation assets, a loss of $2 million after tax was recorded. The following table shows the components of the extraordinary items reported on the consolidated statements of income: Year Ended December 31, 2001 2000 1999 ---- ---- ---- (in millions) Extraordinary Items: Discontinuance of Regulatory Accounting for Generation: Ohio Jurisdiction (Net of Tax of $20 million in 2001 and $35 Million in 2000) $(48) $(44) $ - Virginia and West Virginia Jurisdictions (Inclusive of Tax Benefit of $8 Million) - 9 - Texas and Arkansas Jurisdictions (Net of Tax of $5 Million) - - (8) Loss on Reacquired Debt (Net of Tax of $1 Million in 2001 and $3 Million in 1999) (2) - (6) ---- ---- ---- Extraordinary Items $(50)$(35) $(14) ==== ==== ==== Cumulative Effect of Accounting Change - The FASB's Derivative Implementation Group (DIG) issued accounting guidance under SFAS 133 for certain derivative fuel supply contracts with volumetric optionality and derivative electricity capacity contracts. This guidance, effective in the third quarter of 2001, concluded that fuel supply contracts with volumetric optionality cannot qualify for a normal purchase or sale exclusion from mark-to-market accounting and provided guidance for determining when electricity capacity contracts can qualify as a normal purchase or sale. Predominantly all of AEP's fuel supply contracts for coal and gas and contracts for electricity capacity, which are recorded on a settlement basis, do not meet the criteria of a financial derivative instrument or qualify as a normal purchase or sale. Therefore, AEP's contracts are generally exempt from the DIG guidance described above. Beginning July 1, 2001, the effective date of the DIG guidance, certain of AEP's fuel supply contracts with volumetric optionality that qualify as financial derivative instruments are marked to market with any gain or loss recognized in the income statement. The effect of initially adopting the DIG guidance at July 1, 2001, for AEP is a favorable earnings mark-to-market effect of $18 million, net of tax of $2 million, is reported as a cumulative effect of an accounting change on the income statement. 3. Merger: On June 15, 2000, AEP merged with CSW so that CSW became a wholly-owned subsidiary of AEP. Under the terms of the merger agreement, approximately 127.9 million shares of AEP Common Stock were issued in exchange for all the outstanding shares of CSW Common Stock based upon an exchange ratio of 0.6 share of AEP Common Stock for each share of CSW Common Stock. Following the exchange, former shareholders of AEP owned approximately 61.4 percent of the corporation, while former CSW shareholders owned approximately 38.6 percent of the corporation. The merger was accounted for as a pooling of interests. Accordingly, AEP's consolidated financial statements give retroactive effect to the merger, with all periods presented as if AEP and CSW had always been combined. Certain reclassifications have been made to conform the historical financial statement presentation of AEP and CSW. The following table sets forth revenues, extraordinary items and net income previously reported by AEP and CSW and the combined amounts shown in the accompanying financial statements for 1999: Year Ended December 31, 1999 ---- (in millions) Revenues: AEP $19,229 CSW 5,516 ------- AEP After Pooling $24,745 ======= Extraordinary Items: AEP $ - CSW (14) ---- AEP After Pooling $(14) ==== Net Income: AEP $520 CSW 455 Conforming Adjustment (3) ---- AEP After Pooling $972 ==== The combined financial statements include an adjustment to conform CSW's accounting for vacation pay accruals with AEP's accounting. The effect of the conforming adjustment was to reduce net assets by $16 million at December 31, 1999 and reduce net income by $3 million for the year ended December 31, 1999. The following table shows the vacation accrual conforming adjustment for CSW's registrant utility subsidiaries: Net Income Reductions Net Asset Year Ended Reduction at December 31, December 31, 1999 1999 ----------------- ---- (in millions) CPL $5.3 $0.7 PSO 2.8 1.1 SWEPCo 4.5 0.5 WTU 2.6 0.4 In connection with the merger, $21 million ($14 million after tax) and $203 million ($180 million after tax) of non-recoverable merger costs were expensed in 2001 and 2000. Such cost included transaction and transition costs not recoverable from ratepayers. Also included in the merger costs were non-recoverable change in control payments. Merger transaction and transition costs of $51 million recoverable from ratepayers were deferred pursuant to state regulator approved settlement agreements through December 31, 2001. The deferred merger costs are being amortized over five to eight year recovery periods, depending on the specific terms of the settlement agreements, with the amortization ($8 million and $4 million for the years 2001 and 2000) included in depreciation and amortization expense. The following tables show the deferred merger cost and amortization expense of the applicable subsidiary registrants: Amortization Merger Cost Expense for the Deferral at Year Ended December 31, 2000 December 31, 2000 ----------------- ----------------- (in millions) CPL $14.4 $1.3 I&M 6.9 0.7 KPCo 2.5 0.3 PSO 7.9 0.5 SWEPCo 6.1 0.5 WTU 4.2 0.4 Amortization Merger Cost Expense for the Deferral at Year Ended December 31, 2001 December 31, 2001 ----------------- ----------------- (in millions) CPL $11.8 $2.6 I&M 9.1 1.7 KPCo 3.2 0.6 PSO 6.6 1.2 SWEPCo 5.0 1.1 WTU 3.5 0.8 Merger transition costs are expected to continue to be incurred for several years after the merger and will be expensed or deferred for amortization as appropriate. As hereinafter summarized, the state settlement agreements provide for, among other things, a sharing of net merger savings with certain regulated customers over periods of up to eight years through rate reductions which began in the third quarter of 2000. Summary of key provisions of Merger Rate Agreements: State/Company Ratemaking Provisions - ------------- --------------------- Texas - CPL, SWEPCo $221 million rate reduction WTU over 6 years. No base rate increases for 3 years post merger. Indiana - I&M $67 million rate reduction over 8 years. Extension of base rate freeze until January 1, 2005. Requires additional annual deposits of $6 million to the nuclear decommissioning trust fund for the years 2001 through 2003. Michigan - I&M Customer billing credits of approximately $14 million over 8 years. Extension of base rate freeze until January 1, 2005. Kentucky - KPCo Rate reductions of approximately $28 million over 8 years. No base rate increases for 3 years post merger. Oklahoma - PSO Rate reductions of approximately $28 million over 5 years. No base rate increase before January 1, 2003. Arkansas - SWEPCo Rate reductions of $6 million over 5 years. Louisiana - SWEPCo Rate reductions of $18 million over 8 years. Base rate cap until June 2005. If actual merger savings are significantly less than the merger savings rate reductions required by the merger settlement agreements in the eight-year period following consummation of the merger, future results of operations, cash flows and possibly financial condition could be adversely affected. The current annual dividend rate per share of AEP common stock is $2.40. The dividends per share reported on the statements of income for 2000 and 1999 represent pro forma amounts and are based on AEP's historical annual dividend rate of $2.40 per share. If the dividends per share reported for prior periods were based on the sum of the historical dividends declared by AEP and CSW, the annual dividend rate would be $2.60 per combined share for the year ended December 31, 1999. See Note 8, "Commitments and Contingencies" for information on a recent court decision concerning the merger. 4. Nuclear Plant Restart: I&M completed the restart of both units of the Cook Plant in 2000. Cook Plant is a 2,110 MW two-unit plant owned and operated by I&M under licenses granted by the NRC. I&M shut down both units of the Cook Plant in September 1997 due to questions regarding the operability of certain safety systems that arose during a NRC architect engineer design inspection. Settlement agreements in the Indiana and Michigan retail jurisdictions that address recovery of Cook Plant related outage costs were approved in 1999. The IURC approved a settlement agreement that resolved all matters related to the recovery of replacement energy fuel costs and all outage/restart costs and related issues during the extended outage of the Cook Plant. The MPSC approved a settlement agreement for two open Michigan power supply cost recovery reconciliation cases that resolved all issues related to the Cook Plant extended outage. The settlement agreements allowed: o deferral of $200 million of non-fuel restart-related nuclear operation and maintenance expense for amortization over five years ending December 31, 2003, o deferral of certain unrecovered fuel and power supply costs for amortization over five years ending December 31, 2003, o a freeze in base rates through December 31, 2003 and a fixed fuel recovery charge through March 1, 2004 in the Indiana jurisdiction, and o a freeze in base rates and fixed power supply costs recovery factors until January 1, 2004 for the Michigan jurisdiction. The amounts of restart costs charged to other operation and maintenance expenses were as follows: Year Ended December 31, 2001 2000 1999 ---- ---- ---- Costs Incurred $ 1 $297 $ 289 Deferred Pursuant to Settlement Agreements - - (200) Amortization of Deferrals 40 40 40 - -- -- -- --- -- Charged to O&M Expense $41 $337 $ 129 === ==== ===== At December 31, 2001 and 2000, deferred restart costs of $80 million and $120 million, respectively, remained in regulatory assets to be amortized through 2003. Also pursuant to the settlement agreements, accrued fuel-related revenues of $38 million in 2001 and 2000 and $37 million in 1999 were amortized. At December 31, 2001 and 2000, fuel-related revenues of $75 million and $113 million, respectively, were included in regulatory assets and will be amortized through December 31, 2003 for both jurisdictions. The amortization of restart costs and fuel-related revenues deferred under Indiana and Michigan retail jurisdictional settlement agreements will adversely affect results of operations through December 31, 2003 when the amortization period ends. The annual amortization of restart cost and fuel-related revenue deferrals is $78 million. 5. Rate Matters: Texas Jurisdictional Fuel Filings - AEP's Texas electric operating companies experienced significant natural gas price increases in the second half of 2000 and early 2001 which resulted in under-recovery of fuel costs and the need to seek increases in fuel rates and surcharges to recover these under-recoveries. During 2001 gas price declines and PUCT-approved fuel rate and fuel surcharge increases resulted in lower unrecovered fuel balances for SWEPCo and WTU and an overrecovered balance for CPL at the end of 2001. Fuel recovery for Texas utilities is a multi-step procedure. When fuel costs change, utilities file with the PUCT for authority to adjust fuel factors. If a utility's prior fuel factors result in an over- or under-recovery of fuel, the utility will also request a surcharge factor to refund or collect that amount. While fuel factors are intended to recover all fuel-related costs, final settlement of these accounts are subject to reconciliation and approval by the PUCT. Fuel reconciliation proceedings determine whether fuel costs incurred and collected during the reconciliation period were reasonable and necessary. All fuel costs incurred since the prior reconciliation date are subject to PUCT review and approval. If material amounts are determined to be unreasonable and ordered to be refunded to customers, results of operations and cash flows would be negatively impacted. According to Texas Restructuring Legislation, fuel cost in the Texas jurisdiction after 2001 will no longer be subject to PUCT review and reconciliation. During 2002 CPL and WTU will file final fuel reconciliations with the PUCT to reconcile their fuel costs through the period ending December 31, 2001. The ultimate recovery of deferred fuel balances at December 31, 2001 will be decided as part of their 2004 true-up proceedings. If the final under-recovered fuel balances or any amounts incurred but not yet reconciled are disallowed, it would have a negative impact on results of operations and cash flows. In October 2001 the PUCT delayed the start of customer choice in the SPP area of Texas. All of SWEPCo's Texas service territory and a small portion of WTU's service territory are in the SPP. SWEPCo's fuel cost recovery procedures will continue until competition begins. SWEPCo will continue to set fuel factors and determine final fuel costs in fuel reconciliation proceedings during the SPP delay period. The PUCT has ruled that WTU fuel factors in the SPP area will be based upon the price to beat fuel factors offered by the WTU retail electric provider in the ERCOT portion of WTU's service territory. The PUCT has initiated a proceeding to determine the most appropriate method to reconcile fuel costs in WTU's SPP area. The following table lists the status of Texas jurisdictional reconciliation, fuel cost subject to reconciliation and under(over)-recovered fuel balances: Fuel cost subject to reconciliation Reconciliation at December 31, 2001 completed through Company CPL June 30, 1998 $1.6 billion SWEPCo December 31, 1999 314 million WTU June 30, 2000 303 million Under (Over) -recovered fuel balances at Company December 31, 2001 CPL $(58) million SWEPCo 7 million WTU 34 million During 2001 CPL, SWEPCo and WTU requested and received approval to increase their fuel rates. In orders issued in 2001 the PUCT delayed consideration of fuel surcharges for CPL and WTU to recover their underrecovered fuel until the 2004 true-up proceedings. CPL's net underrecovered position was eliminated between the order date and year end 2001 as gas prices declined. For SWEPCo the PUCT deferred $6.8 million of Texas jurisdictional unrecovered fuel for consideration in a future proceeding. Under Texas restructuring, newly organized retail electric providers will make sales to consumers beginning January 1, 2002. These sales will be at fixed rates during a transition period from 2002 through 2006. However, the fuel cost component of a retail electric providers' fixed rates will be subject to prospective adjustment twice a year based upon changes in a natural gas price index. As part of the preparation for customer choice, CPL, SWEPCo and WTU filed their proposed fuel factors to be implemented as part of the fixed rates effective January 1, 2002. Fuel factors approved for CPL's and WTU's retail electric providers were effective January 1, 2002. Due to the SPP area competition delay, SWEPCo's proceeding was postponed. WTU Fuel Filings - In December 2000 WTU filed with the PUCT an application to reconcile fuel costs. During the reconciliation period of July 1, 1997 through June 30, 2000, WTU incurred $348 million of Texas jurisdiction eligible fuel and fuel-related expenses. In February 2002 the PUCT approved WTU's fuel cost for the reconciliation period except for a disallowance of less than $50,000. Texas Transmission Rates - On June 28, 2001, the Supreme Court of Texas ruled that the transmission pricing mechanism created by the PUCT in 1996 was invalid. The court upheld an appeal filed by unaffiliated Texas utilities that the PUCT exceeded its statutory authority to set such rates for the period January 1, 1997 through August 31, 1999. Effective September 1, 1999, the legislature granted this authority to the PUCT. CPL and WTU were not parties to the case. However, the companies' transmission sales and purchases were priced using the invalid rates. It is unclear what action the PUCT will take to respond to the court's ruling. If the PUCT changes rates retroactively, the result could have a material impact on results of operations and cash flows for CPL and WTU. FERC Wholesale Fuel Complaints - In May 2000 certain WTU wholesale customers filed a complaint with FERC alleging that WTU had overcharged them through the fuel adjustment clause for certain purchased power costs related to 1999 unplanned outages at WTU's Oklaunion generation station. In November 2001 certain WTU wholesale customers filed an additional complaint at FERC asserting that since 1997 WTU had billed wholesale customers for not only the 1999 Oklaunion outage costs, but also certain additional costs that are not permissible under the fuel adjustment clause. In December 2001 FERC issued an order requiring WTU to refund, with interest, amounts associated with the May 2000 complaint that were previously billed to wholesale customers. The effects of this order were recorded in 2001 and management believes that as of December 31, 2001, it has fully provided for that over billing. In response to the November 2001 complaint, management is working to determine amounts of additional costs inappropriately billed to wholesale customers, which could result in refunds, with interest. At this time, management is unable to predict the negative impact this complaint will have on future results of operations, cash flow and financial condition. FERC Transmission Rates - In November 2001 FERC issued an order requiring CPL, PSO, SWEPCo and WTU to submit revised open access transmission tariffs, and calculate and issue refunds for overcharges from January 1, 1997. The order resulted from a remand by an appeals court of a tariff compliance filing order issued in November 1998 that had been appealed by certain customers. CPL and WTU recorded refund provisions of $1.7 million and $0.7 million, respectively, including interest in 2001 for this order. PSO and SWEPCo recorded $100,000 each for this order making the AEP total $2.6 million. West Virginia - On June 2, 2000, the WVPSC approved a Joint Stipulation between APCo and other parties related to base rates and ENEC recoveries. The Joint Stipulation allows for recovery of regulatory assets including any generation-related regulatory assets through the following provisions: o Frozen transition rates and a wires charge of 0.5 mills per KWH. o The retention, as a regulatory liability, on the books of a net cumulative deferred ENEC over-recovery balance of $66 million to be used to offset the cost of deregulation when generation is deregulated in WV. o The retention of net merger savings prior to December 31, 2004 resulting from the merger of AEP and CSW. o A 0.5 mills per KWH wires charge for departing customers provided for in the WV Restructuring Plan (see Note 7 "Customer Choice and Industry Restructuring" for discussion of the WV Restructuring Plan) Management expects that the approved Joint Stipulation, plus the provisions of pending restructuring legislation will, if the legislation becomes effective, provide for the recovery of existing regulatory assets, other stranded costs and the cost of deregulation in WV. 6. Effects of Regulation: In accordance with SFAS 71 the consolidated financial statements include regulatory assets (deferred expenses) and regulatory liabilities (deferred revenues) recorded in accordance with regulatory actions in order to match expenses and revenues from cost-based rates in the same accounting period. Regulatory assets are expected to be recovered in future periods through the rate-making process and regulatory liabilities are expected to reduce future cost recoveries. Among other things, application of SFAS 71 requires that the AEP System's regulated rates be cost-based and the recovery of regulatory assets be probable. Management has reviewed all the evidence currently available and concluded that the requirements to apply SFAS 71 continue to be met for all electric operations in Indiana, Kentucky, Louisiana, Michigan, Oklahoma and Tennessee. When the generation portion of the Company's business in Arkansas, Ohio, Texas, Virginia and WV no longer met the requirements to apply SFAS 71, net regulatory assets were written off for that portion of the business unless they were determined to be recoverable as a stranded cost through regulated distribution rates or wire charges in accordance with SFAS 101 and EITF 97-4. In the Ohio and WV jurisdictions generation-related regulatory assets that are recoverable through transition rates have been transferred to the distribution portion of the business and are being amortized as they are recovered through charges to regulated distribution customers. As discussed in Note 7, "Customer Choice and Industry Restructing" the Virginia SCC ordered the generation-related regulatory assets in the Virginia jurisdiction to remain with the generation portion of the business. Generation-related regulatory assets in the Virginia jurisdiction are being amortized concurrent with their recovery through capped rates. In the Texas jurisdiction generation-related regulatory assets that have been tentatively approved for recovery through securitization have been classified as "regulatory assets designated for securitization." (See Note 7 "Customer Choice and Industry Restructuring" for further details.) AEP's recognized regulatory assets and liabilities are comprised of the following at: December 31, 2001 2000 (in millions) Regulatory Assets: Amounts Due From Customers For Future Income Taxes $814 $914 Transition - Regulatory Assets 847 963 Regulatory Assets Designated for Securitization 959 953 Deferred Fuel Costs 139 407 Unamortized Loss on Reacquired Debt 99 113 Cook Plant Restart Costs 80 120 DOE Decontamination and Decommissioning Assessment 31 35 Other 193 193 --- --- Total Regulatory Assets $3,162 $3,698 ====== ====== Regulatory Liabilities: Deferred Investment Tax Credits $491 $528 Other 393 208 --- --- Total Regulatory Liabilities $884 $736 ==== ====
The recognized regulatory assets and liabilities for the registrant subsidiaries are of two types: those earning a return and those not earning a return. Items not earning a return have their recovery period end date indicated. Regulatory assets and liabilities are comprised of the following items: AEGCo APCo ----------------------------- ---------------------------- Recovery Recovery 2001 2000 Period 2001 2000 Period ---- ---- -------- ---- ---- -------- (in thousands) Regulatory Assets: Amounts Due From Customers For Future Income Taxes $(22,725) $(23,996) Note 1 $189,794 $217,540 Note 1 Transition - Regulatory Assets Virginia 46,981 55,523 Jun. 2007 Transition - Regulatory Assets West Virginia 127,998 135,946 Jun. 2011 Deferred Fuel Costs 11,732 14,669 Unamortized Loss on Reacquired Debt 5,207 5,504 Note 2 10,421 11,676 Note 2 Deferred Storm Damage 6 1,244 Apr. 2002 Other 71,890 11,152 Note 3 --------- -------- -------- -------- Total Regulatory Assets $(17,518) $(18,492) $458,822 $447,750 ========= ========= ======== ======== Regulatory Liabilities: Deferred Investment Tax Credits $56,304 $59,718 $ 38,328 $ 43,093 WV Rate Stabilization 75,601 75,601 Other 61,552 2,614 ------- ------- -------- -------- Total Regulatory Liabilities $56,304 $59,718 $175,481 $121,308 ======= ======= ======== ========
Note 1: This amount fluctuates from month to month and has no fixed recovery period. Note 2: Unamortized loss on reacquired debt varies in its recovery period for each registrant and ranges from one to thirty-seven years recovery period across all registrants. Note 3: Other may include items not earning a return and would have various recovery periods.
CPL CSPCo ----------------------------- ---------------------------- Recovery Recovery 2001 2000 Period 2001 2000 Period ---- ---- -------- ---- ---- -------- (in thousands) Regulatory Assets: Amounts Due From Customers For Future Income Taxes $200,496 $ 206,930 Note 1 $ 28,361 $ 31,853 Note 1 Transition - Regulatory Assets 223,830 247,852 Dec. 2008 Excess Earnings (62,852) (39,700) Regulatory Assets - Designated For Securitization 959,294 953,249 Deferred Fuel Costs (57,762) 127,295 - - Unamortized Loss on Reacquired Debt 11,180 12,773 Note 2 7,010 8,340 Note 2 DOE Decontamination and Decommissioning Assessment 3,170 3,622 Dec. 2004 Other 11,961 18,815 Note 3 3,066 3,508 Note 3 ---------- ---------- -------- -------- Total Regulatory Assets $1,065,487 $1,282,984 $262,267 $291,553 ========== ========== ======== ======== Regulatory Liabilities: Deferred Investment Tax Credits $122,893 $128,100 $37,176 $41,234 Other 31 11,510 -------- -------- ------- ------- Total Regulatory Liabilities $122,893 $128,100 $37,207 $52,744 ======== ======== ======= =======
Note 1: This amount fluctuates from month to month and has no fixed recovery period. Note 2: Unamortized loss on reacquired debt varies in its recovery period for each registrant and ranges from one to thirty-seven years recovery period across all registrants. Note 3: Other may include items not earning a return and would have various recovery periods.
I&M KPCo ----------------------------- ---------------------------- Recovery Recovery 2001 2000 Period 2001 2000 Period ---- ---- -------- ---- ---- -------- (in thousands) Regulatory Assets: Amounts Due From Customers For Future Income Taxes $171,605 $229,466 Note 1 $83,027 $85,926 Note 1 Deferred Fuel Costs 75,002 112,503 Dec. 2003 1,542 - Feb. 2002 Unamortized Loss on Reacquired Debt 16,255 17,740 Note 2 51 459 Note 2 Cook Plant Restart Costs 80,000 120,000 Dec. 2003 DOE Decontamination and Decommissioning Assessment 27,784 31,744 Dec. 2008 Other 38,281 40,687 Note 3 13,073 12,130 Note 3 --------- -------- ------- ------- Total Regulatory Assets $408,927 $552,140 $97,693 $98,515 ========= ========= ======= ======= Regulatory Liabilities: Deferred Investment Tax Credits $105,449 $113,773 $10,405 $11,656 Other 52,479 9,930 6,551 3,172 -------- -------- ------- ------- Total Regulatory Liabilities $157,928 $123,703 $16,956 $14,828 ======== ======== ======= =======
Note 1: This amount fluctuates from month to month and has no fixed recovery period. Note 2: Unamortized loss on reacquired debt varies in its recovery period for each registrant and ranges from one to thirty-seven years recovery period across all registrants. Note 3: Other may include items not earning a return and would have various recovery periods.
OPCo PSO ----------------------------- ---------------------------- Recovery Recovery 2001 2000 Period 2001 2000 Period ---- ---- -------- ---- ---- -------- (in thousands) Regulatory Assets: Amounts Due From Customers For Future Income Taxes $186,740 $180,602 Note 1 $(26,085) $(28,652) Note 1 Transition - Regulatory Assets 442,707 517,851 Dec. 2007 Deferred Fuel Costs 11,732 43,267 Unamortized Loss on Reacquired Debt 5,502 6,106 Note 2 12,321 13,600 Note 2 Other 9,676 10,151 Note 3 11,707 15,738 Note 3 --------- -------- -------- --------- Total Regulatory Assets $644,625 $714,710 $ 9,675 $ 43,953 ========= ======== ======== ========= Regulatory Liabilities: Deferred Investment Tax Credits $21,925 $25,214 $33,992 $35,783 Other 1,237 10,994 31,858 2,015 ------- ------- ------- ------- Total Regulatory Liabilities $23,162 $36,208 $65,850 $37,798 ======= ======= ======= =======
Note 1: This amount fluctuates from month to month and has no fixed recovery period. Note 2: Unamortized loss on reacquired debt varies in its recovery period for each registrant and ranges from one to thirty-seven years recovery period across all registrants. Note 3: Other may include items not earning a return and would have various recovery periods.
SWEPCo WTU ----------------------------- ---------------------------- Recovery Recovery 2001 2000 Period 2001 2000 Period ---- ---- -------- ---- ---- -------- (in thousands) Regulatory Assets: Amounts Due From Customers For Future Income Taxes $16,553 $14,558 Note 1 $(13,591)$(13,493) Note 1 Deferred Fuel Costs 7,384 35,469 36,872 67,655 Unamortized Loss on Reacquired Debt 19,726 22,626 Note 2 8,198 11,204 Note 2 Other 15,711 19,898 Note 3 5,460 13,604 Note 3 ------- ------- -------- -------- Total Regulatory Assets $59,374 $92,551 $ 36,939 $ 78,970 ======= ======== ======== ======== Regulatory Liabilities: Deferred Investment Tax Credits $48,714 $53,167 $22,781 $24,052 Excess Earnings 500 17,300 15,100 Other 15,454 8,140 5,700 - ------- ------- ------- ------- Total Regulatory Liabilities $64,168 $61,807 $45,781 $39,152 ======= ======= ======= =======
Note 1: This amount fluctuates from month to month and has no fixed recovery period. Note 2: Unamortized loss on reacquired debt varies in its recovery period for each registrant and ranges from one to thirty-seven years recovery period across all registrants. Note 3: Other may include items not earning a return and would have various recovery periods. 7. Customer Choice and Industry Restructuring: Prior to 2001 customer choice/industry restructuring legislation was passed in Ohio, Texas, Virginia and Michigan allowing retail customers to select alternative generation suppliers. Customer choice began on January 1, 2001 in Ohio and on January 1, 2002 in Michigan, Virginia and in the ERCOT area of Texas. AEP's subsidiaries operate in both the ERCOT and SPP areas of Texas. Legislation enacted in Oklahoma, Arkansas and WV to allow retail customers to choose their electricity supplier is not yet effective. In 2001 Oklahoma delayed implementation of customer choice indefinitely. Arkansas delayed the start of customer choice until as late as October 2005. The Arkansas Commission has recommended further delays of the start date or repeal of the restructuring legislation. Before West Virginia's choice plan can be effective, tax legislation must be passed to continue consistent funding for state and local government. No further legislation has been passed related to restructuring in Arkansas or West Virginia. In general, state restructuring legislation provides for a transition from cost-based rate regulated bundled electric service to unbundled cost-based rates for transmission and distribution service and market pricing for the supply of electricity with customer choice of supplier. Ohio Restructuring - Affecting AEP, CSPCo and OPCo Customer choice of electricity supplier and restructuring began on January 1, 2001, under the Ohio Act. During 2001 alternative suppliers registered and were approved by the PUCO as required by the Ohio Act. At January 1, 2002, virtually all customers continue to receive supply service from CSPCo and OPCo with a legislatively required residential generation rate reduction of 5%. All customers continue to be served by CSPCo and OPCo for transmission and distribution services. The Ohio Act provides for a five-year transition period to move from cost based rates to market pricing for electric generation supply services. It granted the PUCO broad oversight responsibility for promulgation of rules for competitive retail electric generation service, approval of a transition plan for each electric utility company and addressed certain major transition issues including unbundling of rates and the recovery of stranded costs including regulatory assets and transition costs. The Ohio Act made several changes in the taxation of electric companies. Effective January 1, 2001 the assessment percentage for property taxes on all electric company property other than transmission and distribution was lowered from 100% to 25%. The assessment percentage applicable to transmission and distribution property remains at 88%. Also, electric companies were exempted from the excise tax based on receipts. To make up for these tax reductions electric distribution companies became subject to a new KWH based excise tax. Since electric companies no longer paid the gross receipts tax, they became liable, as of January 1, 2002 for the corporation franchise tax and municipal income taxes. In preparation for the January 1, 2001 start of the transition period, CSPCo and OPCo filed a transition plan in December 1999. After negotiations with interested parties including the PUCO staff, the PUCO approved a stipulation agreement for CSPCo's and OPCo's transition plans. The approved plans included, among other things, recovery of generation-related regulatory assets over seven years for OPCo and over eight years for CSPCo through frozen transition rates for the first five years of the recovery period and through a wires charge for the remaining years. At December 31, 2000, the amount of regulatory assets to be amortized as recovered was $518 million for OPCo and $248 million for CSPCo. The stipulation agreement required the PUCO to consider implementation of a gross receipts tax credit rider as the parties could not reach an agreement. As of May 1, 2001, electric distribution companies became subject to an excise tax based on KWH sold to Ohio customers. The last tax year for which Ohio electric utilities will pay the excise tax based on gross receipts is May 1, 2001 through April 30, 2002. As required by law, the gross receipts tax is paid in advance of the tax year for which the utility exercises its privilege to conduct business. CSPCo and OPCo treat the tax payment as a prepaid expense and amortized it to expense during the tax year. Following a hearing on the gross receipts tax issue, the PUCO determined that there was no duplicate tax overlap period. The PUCO ordered the gross receipts tax credit rider to be effective May 1, 2001 instead of May 1, 2002 as proposed by the companies. This order reduced CSPCo's and OPCo's revenues by approximately $90 million. CSPCo's and OPCo's request for rehearing of the gross receipts tax issue was also denied by the PUCO. A decision on an appeal of this issue to the Ohio Supreme Court is pending. As described in Note 2, the PUCO's denial of the request for recovery of the final year's gross receipts tax and the tax liability affixing on May 1, 2001 stranded the prepaid asset. As a result, an extraordinary loss was recorded in 2001. One of the intervenors at the hearings for approval of the settlement agreement (whose request for rehearing was denied by the PUCO) filed with the Ohio Supreme Court for review of the settlement agreement. During 2001 that intervenor withdrew from competing in Ohio. The Court dismissed the intervenor's appeal. CSPCo's and OPCo's fuel costs were no longer subject to PUCO fuel clause recovery proceedings beginning January 1, 2001. The elimination of fuel clause recoveries in Ohio subjects AEP, CSPCo and OPCo to risk of fuel market price variations and could adversely affect their results of operations and cash flows. Virginia Restructuring - Affecting AEP and APCo In Virginia, choice of electricity supplier for retail customers began on January 1, 2002 under its restructuring law. A finding by the Virginia SCC that an effective competitive market exists would be required to end the transition period. The restructuring law provides an opportunity for recovery of just and reasonable net stranded generation costs. The mechanisms in the Virginia law for net stranded cost recovery are: a capping of rates until as late as July 1, 2007, and the application of a wires charge upon customers who depart the incumbent utility in favor of an alternative supplier prior to the termination of the rate cap. Capped rates are the rates in effect at July 1, 1999 if no rate change request was made by the utility. APCo did not request new rates; therefore, its current rates are its capped rates. Virginia's restructuring law does not permit the Virginia SCC to change generation rates during the transition period except for changes in fuel costs, changes in state gross receipts taxes, or to address financial distress of the utility. The Virginia restructuring law also requires filings to be made that outline the functional separation of generation from transmission and distribution and a rate unbundling plan. On January 3, 2001, APCo filed its corporate separation plan and rate unbundling plan with the Virginia SCC. The Virginia SCC approved settlement agreements that resolved most issues except the assignment of generation-related regulatory assets among functionally separated generation, transmission and distribution organizations. The Virginia SCC determined that generation-related regulatory assets and related amortization expense should be assigned to APCo's generation function. Presently, capped rates are sufficient to recover generation-related regulatory assets. Therefore, management determined that recovery of APCo's generation-related regulatory assets remains probable. APCo will not collect a wires charge in 2002 per the settlement agreements. The settlement agreements and related Virginia SCC order addressed functional separation leaving decisions related to corporate separation for later consideration. The Virginia SCC order approving the settlement agreements requires several compliance filings, including a fuel/replacement power cost report during an extended outage of an affiliate's nuclear plant. Management is unable to predict the outcome of the Virginia SCC's review of APCo's compliance filings. Texas Restructuring - Affecting AEP, CPL, SWEPCo and WTU On January 1, 2002, customer choice of electricity supplier began in the ERCOT area of Texas. Customer choice has been delayed in other areas of Texas including the SPP area. All of SWEPCo's Texas service territory and a small portion of WTU's service territory are located in the SPP. CPL operates entirely in the ERCOT area of Texas. Texas restructuring legislation, among other things: o provides for the recovery of regulatory assets and other stranded costs through securitization and non-bypassable wires charges; o requires reductions in NOx and sulfur dioxide emissions; o freezes rates until January 1, 2002; o provides for an earnings test for each of the three years of the rate freeze period (1999 through 2001) which will reduce stranded cost recoveries or if there is no stranded cost provides for a refund or their use to fund certain capital expenditures; o requires each utility to structurally unbundle into a retail electric provider, a power generation company and a transmission and distribution utility; o provides for certain limits for ownership and control of generating capacity by companies; o provides for elimination of the fuel clause reconciliation process beginning January 1, 2002; and o provides for a 2004 true-up proceeding to determine recovery of stranded costs including final fuel recovery balances, net regulatory assets, certain environmental costs, accumulated excess earnings and other issues. Under the Texas Legislation, delivery of electricity continues to be the responsibility of the local electric transmission and distribution utility company at regulated prices. Each electric utility was required to submit a plan to structurally unbundle its business activities into a retail electric provider, a power generation company, and a transmission and distribution utility. In 2000 CPL, SWEPCo and WTU filed and the PUCT approved business separation plans. The business separation plans provided for CPL and WTU to establish separate companies and divide their integrated utility operations and assets into a power generation company, a transmission and distribution utility and a retail electric provider. In February 2002 the PUCT approved amendments to SWEPCo's plan. The amended plan separates SWEPCo's Texas jurisdictional transmission and distribution assets and operations into two new regulated transmission and distribution subsidiaries. In addition, a retail electric provider was established by SWEPCo to provide retail electric service to SWEPCo's Texas jurisdictional customers. Until competition commences in the SPP, SWEPCo's assets will not be separated and the SWEPCo retail electric provider will not commence operation. Due to the SPP area delay in the start of competition, only CPL's and WTU's retail electric providers commenced operations on January 1, 2002. Operations for CPL, SWEPCo and WTU have been functionally separated. Under the Texas Legislation, electric utilities are allowed to recover stranded generation costs including generation-related regulatory assets. The stranded costs can be refinanced through securitization (a financing structure designed to provide lower financing costs than are available through conventional financings). In 1999 CPL filed with the PUCT to securitize $1.27 billion of its retail generation-related regulatory assets and $47 million in other qualified restructuring costs. The PUCT authorized the issuance of up to $797 million of securitization bonds ($949 million of generation-related regulatory assets and $33 million of qualified refinancing costs offset by $185 million of customer benefits for accumulated deferred income taxes). Four parties appealed to the Supreme Court of Texas which upheld the PUCT's securitization order. CPL issued its securitization bonds in February 2002. CPL included regulatory assets not approved for securitization in its request for recovery of $1.1 billion of stranded costs. The $1.1 billion request included $800 million of STP costs included in property, plant and equipment-electric on the Consolidated Balance Sheets. These STP costs had previously been identified as excess cost over market (ECOM) by the PUCT for regulatory purposes. They are earning a lower return and being amortized on an accelerated basis for rate-making purposes. After hearings on the issue of stranded costs, the PUCT ruled in October 2001 that its current estimate of CPL's stranded costs was negative $615 million. CPL disagrees with the ruling. The ruling indicated that CPL's costs were below market after securitization of regulatory assets. Management believes CPL has a positive stranded cost exclusive of securitized regulatory assets. The final amount of CPL's stranded costs including regulatory assets and ECOM will be established by the PUCT in the 2004 true-up proceeding. If CPL's total stranded costs determined in the 2004 true-up are less than the amount of securitized regulatory assets, the PUCT can implement an offsetting credit to transmission and distribution rates. The PUCT ruled that prior to the 2004 true-up proceeding, no adjustments would be made to the amount of regulatory costs authorized by the PUCT to be securitized. However, the PUCT also ruled that excess earnings for the period 1999-2001 should be refunded through distribution rates to the extent of any over-mitigation of stranded costs represented by negative ECOM. In 2001 the PUCT issued an order requiring CPL to reduce distribution rates by $54.8 million plus accrued interest over a five-year period beginning January 1, 2002 in order to return estimated excess earnings for 1999, 2000 and 2001. The Texas Legislation intended that excess earnings reduce stranded costs. Final stranded cost amounts and the treatment of excess earnings will be determined in the 2004 true-up proceeding. Currently the PUCT estimates that CPL will have no stranded costs and has ordered the rate reduction to return excess earnings. Since CPL expensed excess earnings amounts in 1999, 2000 and 2001, the order has no additional effect on reported net income but will reduce cash flows for the five year refund period. The amount to be refunded is recorded as a regulatory liability. Management believes that CPL will have stranded costs in 2004, and that the current treatment of excess earnings will be amended at that time. CPL has appealed the PUCT's estimate of stranded costs and refund of excess earnings to the Travis County District Court. Unaffiliated parties also appealed the PUCT's refund order contending the entire $615 million of negative stranded costs should be refunded presently. Management is unable to predict the outcome of this litigation. An unfavorable ruling would have a negative impact on results of operations, cash flows and possibly financial condition. The Texas Legislation allows for several alternative methods to be used to value stranded costs in the final 2004 true-up proceeding including the sale or exchange of generation assets, the issuance of power generation company stock to the public or the use of an ECOM model. To the extent that the final 2004 true-up proceeding determines that CPL should recover additional stranded costs, the additional amount recoverable can also be securitized. The Texas Legislation provides for an earnings test each year of the 1999 through 2001 rate freeze period. For CPL, any earnings in excess of the most recently approved cost of capital in its last rate case must be applied to reduce stranded costs. Companies without stranded costs, including SWEPCo and WTU, must pay any excess earnings to customers, invest them in improvements to transmission or distribution facilities or invest them to improve air quality at generating facilities. The Texas Legislation requires PUCT approval of the annual earnings test calculation. The PUCT issued a final order for the 1999 earnings test in February 2001 and adjustments to the accrued 1999 and 2000 excess earnings were recorded in results of operations in the fourth quarter of 2000. After adjustments the 1999 excess earnings for CPL and WTU were $24 million and $1 million, respectively. SWEPCo had no excess earnings in 1999. The PUCT issued a final order in September 2001 for the 2000 excess earnings. CPL's, SWEPCo's and WTU's excess 2000 earnings were $23 million, $1 million and $17 million, respectively. An estimate of 2001 excess earnings of $8 million for CPL, $2 million for SWEPCo and none for WTU has been recorded and will be adjusted, if necessary, in 2002 when the PUCT issues its final order regarding 2001 excess earnings. Due to the companies' disagreement with the PUCT, its staff and the Office of Public Utility Counsel related to the proper determination of 2000 excess earnings, the companies filed in district court in October 2001 seeking judicial review of the PUCT's determination of excess earnings. A decision from the court is not expected until later in 2002. Beginning January 1, 2002, fuel costs will not be subject to PUCT fuel reconciliation proceedings for CPL and WTU's ERCOT customers. Consequently, CPL and WTU will file a final fuel reconciliation with the PUCT to reconcile their fuel costs through the period ending December 31, 2001. Due to the delay of competition for the SPP area, SWEPCo, which operates in the SPP area, continues to record and request recovery of fuel costs under the Texas fuel reconciliation proceeding. For WTU's SPP area customers, the PUCT will determine a method to reconcile their fuel costs beginning in 2002 (see Note 5 "Rate Matters"). Final unrecovered deferred fuel balances at December 31, 2001 will be included in each company's 2004 true-up proceeding. If the final fuel balances or any amount incurred but not yet reconciled are not recovered, they could have a negative impact on results of operations. The elimination of the fuel clause recoveries in 2002 in the ERCOT area of Texas will subject AEP and the retail electric providers of CPL and WTU to greater risks of fuel market price increases and could adversely affect future results of operations beginning in 2002. The affiliated retail electric providers of CPL, SWEPCo and WTU are required by the Texas Legislation to offer residential and small commercial customers (with a peak usage of less than 1000 KW) a price-to-beat rate until January 1, 2007. In December 2001 the PUCT approved price-to-beat rates for CPL's and WTU's retail electric providers. Customers with a peak usage of more than 1000 KW are subject to market rates. The Texas restructuring legislation provides for the price to beat to be adjusted up to two times annually to reflect changes in fuel and purchased energy costs using a natural gas price index. Due to the delay in the start of competition in the SPP areas of Texas, several issues are pending before the PUCT. These issues impact SWEPCo's and WTU's Texas SPP operations. WTU's Texas SPP operations are estimated to be less than 5% of WTU's total operations. West Virginia Restructuring - Affecting AEP and APCo In 2000 the WVPSC issued an order approving an electricity restructuring plan which the WV Legislature approved by joint resolution. The joint resolution provides that the WVPSC cannot implement the plan until the legislature makes tax law changes necessary to preserve the revenues of state and local governments. Since the WV Legislature has not passed the required tax law changes, the restructuring plan has not become effective. AEP subsidiaries, APCo and WPCo, provide electric service in WV. The WV restructuring plan provides for: o deregulation of generation assets o separation of the generation, transmission and distribution businesses o a transition period with capped and fixed rates for up to 13 years o establishment of a rate stabilization deferred liability balance of $81 million ($76 million by APCo and $5 million by WPCo) by the end of year ten of the transition period. APCo's Joint Stipulation, discussed in Note 5 "Rate Matters" and approved by the WVPSC in 2000 in connection with a base rate filing, provides additional mechanisms to recover transition generation-related regulatory assets. In order for customer choice to become effective in WV, the WV Legislature must enact tax legislation. Management is unable to predict the timing of the passage of such legislation. Arkansas Restructuring - Affecting AEP and SWEPCo In 1999 Arkansas enacted legislation to restructure its electric utility industry. Major provisions of the legislation as amended are: o retailcompetition delayed until as late as October 2005; o transmission facilities must be operated by an ISO if owned by a company which also owns generating facilities; o rates will be frozen for one to three years; o market power issues will be addressed by the Arkansas Commission; and o an annual progress report to the Arkansas General Assembly on the development of competition in electric markets and its impact on retail customers is required. Based on recommendations in the annual progress report filed by the Arkansas Commission, the Arkansas General Assembly passed and the Governor signed legislation in 2001 changing the start date of electric retail competition to October 1, 2003, and providing the Arkansas Commission with authority to delay that date for up to an additional two years. The Arkansas Commission in December 2001 recommended further delays of the start date or repeal of the restructuring legislation. Discontinuance of the Application of SFAS 71 Regulatory Accounting in Arkansas, Ohio, Texas, Virginia and West Virginia - Affecting AEP, APCo, CPL, CSPCo, OPCo, SWEPCo and WTU The enactment of restructuring legislation and the ability to determine transition rates, wires charges and any resultant gain or loss under restructuring legislation in Arkansas, Ohio, Texas, Virginia and West Virginia enabled AEP and certain subsidiaries to discontinue regulatory accounting under SFAS 71 for the generation portion of their business in those states. Under the provisions of SFAS 71, regulatory assets and regulatory liabilities are recorded to reflect the economic effects of regulation by matching expenses with related regulated revenues. The discontinuance of the application of SFAS 71 in Arkansas, Ohio, Texas, Virginia and West Virginia in accordance with the provisions of SFAS 101 and EITF Issue 97-4 resulted in recognition of extraordinary gains or losses in 2000 and 1999. The discontinuance of SFAS 71 can require the write-off of regulatory assets and liabilities related to the deregulated operations, unless their recovery is provided through cost-based regulated rates to be collected in a portion of operations which continues to be rate regulated. Additionally, a company must determine if any plant assets are impaired when they discontinue SFAS 71 accounting. At the time the companies discontinued SFAS 71, the analysis showed that there was no accounting impairment of generation assets. Prior to 1999, all of the domestic electric utility subsidiaries' financial statements reflected the economic effects of regulation under the requirements of SFAS 71. As a result of deregulation of generation, the application of SFAS 71 for the generation portion of the business in Arkansas, Ohio, Texas, Virginia and West Virginia was discontinued. Remaining generation-related regulatory assets will be amortized as they are recovered under terms of transition plans. Management believes that substantially all generation-related regulatory assets and stranded costs will be recovered under terms of the transition plans. If future events including the 2004 true-up proceeding in Texas were to make their recovery no longer probable, the Company would write-off the portion of such regulatory assets and stranded costs deemed unrecoverable as a non-cash extraordinary charge to earnings. If any write-off of regulatory assets or stranded costs occurred, it could have a material adverse effect on future results of operations, cash flows and possibly financial condition. Michigan Restructuring - Affecting AEP and I&M On June 5, 2000, the Michigan Legislation became law. Its major provisions, which were effective immediately, applied only to electric utilities with one million or more retail customers. I&M, AEP's electric operating subsidiary doing business in Michigan, has less than one million customers in Michigan. Consequently, I&M was not immediately required to comply with the Michigan Legislation. The Michigan Legislation gives the MPSC broad power to issue orders to implement retail customer choice of electric supplier no later than January 1, 2002 including recovery of regulatory assets and stranded costs. In compliance with MPSC orders, on June 5, 2001, I&M filed its proposed unbundled rates, open access tariffs and terms of service. On October 11, 2001, the MPSC approved a settlement agreement which generally approved I&M's June 5, 2001 filing except for agreed upon modifications. In accordance with the settlement agreement, I&M agreed that recovery of implementation costs and regulatory assets would be determined in future proceedings. The settlement agreement did not modify the procedure for review of decom-missioning costs recoveries. Customer choice commenced for I&M's Michigan customers on January 1, 2002. Effective with that date the rates on I&M's Michigan customers' bills for retail electric service were unbundled to allow customers the opportunity to evaluate the cost of generation service for comparison with other offers. I&M's total rates in Michigan remain unchanged and reflect cost of service. At this time, none of I&M's customers have elected to change suppliers and no competing suppliers are active in I&M's Michigan service territory. Management has concluded that as of December 31, 2001 the requirements to apply SFAS 71 continue to be met since I&M's rates for generation in Michigan continue to be cost-based regulated. As a result I&M has not yet dis-continued regulatory accounting under SFAS 71. Oklahoma Restructuring - Affecting AEP and PSO Under Oklahoma restructuring legislation passed in 1997 retail open access and customer choice was scheduled to begin by July 1, 2002. In June 2001 the Oklahoma Governor signed into law a bill to delay, indefinitely, the implementation of the transition to customer choice and market based pricing under restructuring legislation. Consequently, PSO, the AEP subsidiary doing business in Oklahoma, will remain rate-regulated until further legislation passes and continues the application of SFAS 71 regulatory accounting. 8. Commitments and Contingencies: Construction and Other Commitments - The AEP System has substantial construction commitments to support its operations. Aggregate construction expenditures for 2002-2004 for consolidated domestic and foreign operations are estimated to be $5.4 billion. The following table shows the estimated construction expenditures of the subsidiary registrants for 2002 - 2004: (in millions) AEGCo $171.9 APCo 815.5 CPL 573.1 CSPCo 408.7 I&M 556.9 KPCo 223.3 OPCo 1,008.0 PSO 364.9 SWEPCo 321.4 WTU 169.6 APCo, AEP's subsidiary which operates in Virginia and West Virginia, has been seeking regulatory approval to build a new high voltage transmission line for over a decade. Through December 31, 2001 we had invested approximately $40 million in this effort. If the required regulatory approvals are not obtained and the line is not constructed, the $40 million investment would be written off adversely affecting future results of operations and cash flows. Long-term contracts to acquire fuel for electric generation have been entered into for various terms, the longest of which extends to the year 2014 for the AEP System. The expiration date of the longest fuel contract is 2006 for APCo, 2005 for CSPCo, 2014 for I&M, 2004 for KPCo, 2012 for OPCo, 2014 for PSO, 2006 for SWEPCo and 2006 for WTU. The contracts provide for periodic price adjustments and contain various clauses that would release the subsidiaries from their obligations under certain force majeure conditions. The AEP System has contracted to sell approximately 1,300 MW of capacity domestically on a long-term basis to unaffiliated utilities. Certain of these contracts totaling 250 MW of capacity are unit power agreements requiring the delivery of energy only if the unit capacity is available. The power sales contracts expire from 2002 to 2012. In connection with a lignite mining contract for its Henry W. Pirkey Power Plant, SWEPCo has agreed under certain conditions, to assume the obligations of the mining contractor. The contractor's actual obligation outstanding at December 31, 2001 was $75 million. As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo has agreed to provide guarantees of mine reclamation in the amount of $85 million. Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by a third party miner. At December 31, 2001 the cost to reclaim the mine is estimated to be approximately $36 million. AEP, through certain subsidiaries, has entered into agreements with an unrelated, unconsolidated special purpose entity (SPE) to develop, construct, finance and lease a power generation facility. The SPE will own the power generation facility and lease it to an AEP consolidated subsidiary after construction is completed. The lease will be accounted for as an operating lease with the payment obligations included in the lease footnote. Payments under the operating lease are expected to commence in the first quarter of 2004. AEP will in turn sublease the facility to an unrelated industrial company which will both use the energy produced by the facility and sell excess energy. Another affiliate of AEP has agreed to purchase the excess energy from the subleasee for resale. The SPE has an aggregate financing commitment from equity and debt participants (Investors) of $427 million. AEP, in its role as construction agent for the SPE, is responsible for completing construction by December 31, 2003. In the event the project is terminated before completion of construction, AEP has the option to either purchase the project for 100% of project costs or terminate the project and make a payment to the Lessor for 89.9% of project costs. The term of the operating lease between the SPE and the AEP subsidiary is five years with multiple extension options. If all extension options are exercised the total term of the lease would be 30 years. AEP's lease payments to the SPE are sufficient to provide a return to the Investors. At the end of the first five-year lease term or any extension, AEP may renew the lease at fair market value subject to Investor approval; purchase the facility at its original construction cost; or sell the facility, on behalf of the SPE, to an independent third party. If the project is sold and the proceeds from the sale are insufficient to repay the Investors, AEP may be required to make a payment to the Lessor of up to 85% of the project's cost. AEP has guaranteed a portion of the obligations of its subsidiaries to the SPE during the construction and post-construction periods. As of December 31, 2001, project costs subject to these agreements totaled $168 million, and total costs for the completed facility are expected to be approximately $450 million. Since the lease is accounted for as an operating lease for financial accounting purposes, neither the facility nor the related obligations are reported on AEP's balance sheets. The lease is a variable rate obligation indexed to three-month LIBOR. Consequently as market interest rates increase, the payments under this operating lease will also increase. Annual payments of approximately $12 million represent future minimum payments under the first five-year lease term calculated using the indexed LIBOR rate of 2.85% at December 31, 2001. OPCo has entered into a purchased power agreement to purchase electricity produced by an unaffiliated entity's three-unit natural gas fired plant that is under construction. The first unit is anticipated to be completed in October 2002 and the agreement will terminate 30 years after the third unit begins operation. Under the terms of the agreement OPCo has the options to run the plant until December 31, 2005 taking 100% of the power generated. For the remainder of the 30 year contract term, OPCo will pay the variable costs to generate the electricity it purchases which could be up to 20% of the plant's capacity. The estimated fixed payments through December 2005 are $55 million. Nuclear Plants - Affecting AEP, CPL and I&M I&M owns and operates the two-unit 2,110 MW Cook Plant under licenses granted by the NRC. CPL owns 25.2% of the two-unit 2,500 MW STP. STPNOC operates STP on behalf of the joint owners under licenses granted by the NRC. The operation of a nuclear facility involves special risks, potential liabilities, and specific regulatory and safety requirements. Should a nuclear incident occur at any nuclear power plant facility in the U.S., the resultant liability could be substantial. By agreement I&M and CPL are partially liable together with all other electric utility companies that own nuclear generating units for a nuclear power plant incident at any nuclear plant in the U.S. In the event nuclear losses or liabilities are underinsured or exceed accumulated funds and recovery in rates is not possible, results of operations, cash flows and financial condition would be adversely affected. Nuclear Incident Liability - Affecting AEP, CPL and I&M The Price-Anderson Act establishes insurance protection for public liability arising from a nuclear incident at $9.5 billion and covers any incident at a licensed reactor in the U.S. Commercially available insurance provides $200 million of coverage. In the event of a nuclear incident at any nuclear plant in the U.S., the remainder of the liability would be provided by a deferred premium assessment of $88 million on each licensed reactor in the U.S. payable in annual installments of $10 million. As a result, I&M could be assessed $176 million per nuclear incident payable in annual installments of $20 million. CPL could be assessed $44 million per nuclear incident payable in annual installments of $5 million as its share of a STPNOC assessment. The number of incidents for which payments could be required is not limited. Insurance coverage for property damage, decommissioning and decontamination at the Cook Plant and STP is carried by I&M and STPNOC in the amount of $1.8 billion each. Cook Plant and STPNOC jointly purchase $1 billion of excess coverage for property damage, de-commissioning and decontamination. Additional insurance provides coverage for extra costs resulting from a prolonged accidental outage. I&M and STPNOC utilize an industry mutual insurer for the placement of this insurance coverage. Participation in this mutual insurer requires a contingent financial obligation of up to $36 million for I&M and $3 million for CPL which is assessable if the insurer's financial resources would be inadequate to pay for losses. SNF Disposal - Affecting AEP, CPL, and I&M Federal law provides for government responsibility for permanent SNF disposal and assesses nuclear plant owners fees for SNF disposal. A fee of one mill per KWH for fuel consumed after April 6, 1983 at Cook Plant and STP is being collected from customers and remitted to the U.S. Treasury. Fees and related interest of $220 million for fuel consumed prior to April 7, 1983 at Cook Plant have been recorded as long-term debt. I&M has not paid the government the Cook Plant related pre-April 1983 fees due to continued delays and uncertainties related to the federal disposal program. At December 31, 2001, funds collected from customers towards payment of the pre-April 1983 fee and related earnings thereon are in external funds and approximate the liability. CPL is not liable for any assessments for nuclear fuel consumed prior to April 7, 1983 since the STP units began operation in 1988 and 1989. Decommissioning and Low Level Waste Accumulation Disposal - Affecting AEP, CPL and I&M Decommissioning costs are accrued over the service lives of the Cook Plant and STP. The licenses to operate the two nuclear units at Cook Plant expire in 2014 and 2017. After expiration of the licenses, Cook Plant is expected to be decommissioned through dismantlement. The estimated cost of decommissioning and low level radioactive waste accumulation disposal costs for Cook Plant ranges from $783 million to $1,481 million in 2000 nondiscounted dollars. The wide range is caused by variables in assumptions including the estimated length of time SNF may need to be stored at the plant site subsequent to ceasing operations. This, in turn, depends on future developments in the federal government's SNF disposal program. Continued delays in the federal fuel disposal program can result in increased decommissioning costs. I&M is re-covering estimated Cook Plant decommissioning costs in its three rate-making jurisdictions based on at least the lower end of the range in the most recent decommissioning study at the time of the last rate proceeding. The amount recovered in rates for decommissioning the Cook Plant and deposited in the external fund was $27 million in 2001 and $28 million in 2000 and 1999. The licenses to operate the two nuclear units at STP expire in 2027 and 2028. After expiration of the licenses, STP is expected to be decommissioned using the decontamination method. CPL estimates its portion of the costs of decommissioning STP to be $289 million in 1999 nondiscounted dollars. CPL is accruing and recovering these decommissioning costs through rates based on the service life of STP at a rate of $8 million per year. Decommissioning costs recovered from customers are deposited in external trusts. In 2001 and 2000 I&M deposited in its decommissioning trust an additional $12 million and $6 million, respectively, related to special regulatory commission approved funding for decommissioning of the Cook Plant. Trust fund earnings increase the fund assets and the recorded liability and decrease the amount needed to be recovered from ratepayers. Decommissioning costs including interest, unrealized gains and losses and expenses of the trust funds are recorded in other operation expense for Cook Plant. For STP, nuclear decommissioning costs are recorded in other operation expense, interest income of the trusts are recorded in nonoperating income and interest expense of the trust funds are included in interest charges. On the AEP Consolidated Balance Sheets, nuclear decommissioning trust assets are included in other assets and a corresponding nuclear decommissioning liability is included in other noncurrent liabilities. On CPL's balance sheets, the nuclear decommissioning liability of $99 million is included in electric utility plant-accumulated depreciation and amortization. At December 31, 2001 and 2000, the decommissioning liability for Cook Plant and STP combined totals $699 million and $654 million, respectively. Shareholders' Litigation - Affecting AEP On December 21, 2001, the U.S. District Court for the Southern District of Ohio dismissed a class action lawsuit against AEP and four former or present officers. The class consisted of all persons and entities who purchased or otherwise acquired AEP common stock between July 25, 1997 and June 25, 1999. The complaint alleged that the defendants knowingly violated federal securities laws by disseminating materially false and misleading statements related to the extended Cook Plant outage. Municipal Franchise Fee Litigation - Affecting AEP and CPL In 2001 CPL settled litigation regarding municipal franchise fees in Texas. CPL paid $11 million to settle the litigation and be released from any further liability. The City of San Juan, Texas had filed a class action suit in 1996 seeking $300 million in damages. Texas Base Rate Litigation - Affecting AEP and CPL In 2001 the Texas Supreme Court denied CPL's request to review a case resulting from a 1997 PUCT base rate order. The Court also denied CPL's rehearing request. The primary issues were: o the classification of $800 million of invested capital in STP as ECOM and assigning it a lower return on equity than other generation property; o and an $18 million disallowance of an affiliate service billings. Lignite Mining Agreement Litigation - Affecting AEP and SWEPCo In 2001 SWEPCo settled ongoing litigation concerning lignite mining in Louisiana. Since 1997 SWEPCo has been involved in litigation concerning the mining of lignite from jointly owned lignite reserves. SWEPCo and CLECO are each a 50% owner of Dolet Hills Power Station Unit 1 and jointly own lignite reserves in the Dolet Hills area of northwestern Louisiana. Under terms of a settlement, SWEPCo purchased an unaffiliated mine operator's interest in the mining operations and related debt and other obligations for $86 million. Federal EPA Complaint and Notice of Violation - Affecting AEP, APCo, CSPCo, I&M, and OPCo Since 1999 AEP, APCo, CSPCo, I&M, and OPCo have been involved in litigation regarding generating plant emissions under the Clean Air Act. Federal EPA and a number of states alleged that AEP System companies and eleven unaffiliated utilities modified certain units at coal fired generating plants in violation of the Clean Air Act. Federal EPA filed complaints against AEP subsidiaries in U.S. District Court for the Southern District of Ohio. A separate lawsuit initiated by certain special interest groups was consolidated with the Federal EPA case. The alleged modification of the generating units occurred over a 20 year period. Under the Clean Air Act, if a plant undertakes a major modification that directly results in an emissions increase, permitting requirements might be triggered and the plant may be required to install additional pollution control technology. This requirement does not apply to activities such as routine maintenance, replacement of degraded equipment or failed components, or other repairs needed for the reliable, safe and efficient operation of the plant. The Clean Air Act authorizes civil penalties of up to $27,500 per day per violation at each generating unit ($25,000 per day prior to January 30, 1997). In March 2001 the District Court ruled claims for civil penalties based on activities that occurred more than five years before the filing date of the complaints cannot be imposed. There is no time limit on claims for injunctive relief. In February 2001 the government filed a motion requesting a determination that four projects undertaken on units at Sporn, Cardinal and Clinch River plants do not constitute "routine maintenance, repair and replacement" as used in the Clean Air Act. Management believes its maintenance, repair and replacement activities were in conformity with the Clean Air Act and intends to vigorously pursue its defense. In January 2002 the U.S. Court of Appeals for the 11th Circuit ruled that TVA may pursue its court challenge of a Federal EPA administrative order charging similar violations to those in the complaints against AEP and other utilities. Management is unable to estimate the loss or range of loss related to the contingent liability for civil penalties under the Clear Air Act proceedings and unable to predict the timing of resolution of these matters due to the number of alleged violations and the significant number of issues yet to be determined by the Court. In the event the AEP System companies do not prevail, any capital and operating costs of additional pollution control equipment that may be required as well as any penalties imposed would adversely affect future results of operations, cash flows and possibly financial condition unless such costs can be recovered through regulated rates, and where states are deregulating generation, unbundled transition period generation rates, stranded cost wires charges and future market prices for electricity. In December 2000 Cinergy Corp., an unaffiliated utility, which operates certain plants jointly owned by CSPCo, reached a tentative agreement with Federal EPA and other parties to settle litigation regarding generating plant emissions under the Clean Air Act. Negotiations are continuing between the parties in an attempt to reach final settlement terms. Cinergy's settlement could impact the operation of Zimmer Plant and W.C. Beckjord Generating Station Unit 6 (owned 25.4% and 12.5%, respectively, by CSPCo). Until a final settlement is reached, CSPCo will be unable to determine the settlement's impact on its jointly owned facilities and its results of operations and cash flows. NOx Reductions - Affecting AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo and SWEPCo Federal EPA issued a NOx Rule requiring substantial reductions in NOx emissions in a number of eastern states, including certain states in which the AEP System's generating plants are located. The NOx Rule has been upheld on appeal. The compliance date for the NOx Rule is May 31, 2004. The NOx Rule required states to submit plans to comply with its provisions. In 2000 Federal EPA ruled that eleven states, including states in which AEGCo's, APCo's, CSPCo's, I&M's, KPCo's and OPCo's generating units are located, failed to submit approvable compliance plans. Those states could face stringent sanctions including limits on construction of new sources of air emissions, loss of federal highway funding and possible Federal EPA takeover of state air quality management programs. AEP subsidiaries and other utilities requested that the D.C. Circuit Court review this ruling. In 2000 Federal EPA also adopted a revised rule (the Section 126 Rule) granting petitions filed by certain northeastern states under the Clean Air Act. The rule imposes emissions reduction requirements comparable to the NOx Rule beginning May 1, 2003, for most of AEP's coal-fired generating units. Affected utilities including certain AEP operating companies, petitioned the D.C. Circuit Court to review the Section 126 Rule. After review, the D.C. Circuit Court instructed Federal EPA to justify the methods it used to allocate allowances and project growth for both the NOx Rule and the Section 126 Rule. AEP subsidiaries and other utilities requested that the D.C. Circuit Court vacate the Section 126 Rule or suspend its May 2003 compliance date. On August 24, 2001, the D.C. Circuit Court issued an order tolling the compliance schedule until Federal EPA responds to the Court's remand. Federal EPA has announced that it intends to adopt May 31, 2004, as the compliance date for the Section 126 Rule when it finalizes the NOx budgets for both rules. In 2000 the Texas Natural Resource Conservation Commission adopted rules requiring significant reductions in NOx emissions from utility sources, including CPL and SWEPCo. The compliance date is May 2003 for CPL and May 2005 for SWEPCo. During 2001 selective catalytic reduction (SCR) technology to reduce NOx emissions on OPCo's Gavin Plant commenced operations. Construction of SCR technology at certain other AEP generating units continues with completion scheduled in 2002 through 2006. Our estimates indicate that compliance with the NOx Rule, the Texas Natural Resource Conservation Commission rule and the Section 126 Rule could result in required capital expenditures of approximately $1.6 billion of which approximately $450 million has been spent through December 31, 2001 for the AEP System. Estimated compliance costs and amounts spent by registrant subsidiaries are as follows: Estimated Amount Spent Compliance Cost (in millions) AEGCo $125 $ - APCo 365 130 CPL 57 4 CSPCo 106 1 I&M 202 - KPCo 140 13 OPCo 606 277 SWEPCo 28 21 Since compliance costs cannot be estimated with certainty, the actual cost to comply could be significantly different than the preliminary estimates depending upon the compliance alternatives selected to achieve reductions in NOx emissions. Unless any capital and operating costs of additional pollution control equipment are recovered from customers, they will have an adverse effect on results of operations, cash flows and possibly financial condition. Merger Litigation - On January 18, 2002, the U.S. Court of Appeals for the District of Columbia ruled that the SEC failed to prove that the June 15, 2000 merger of AEP with CSW meets the requirements of the PUHCA and sent the case back to the SEC for further review. Specifically, the court told the SEC to revisit its conclusion that the merger met PUHCA requirements that utilities be "physically interconnected" and confined to a "single area or region." In its June 2000 approval of the merger, the SEC agreed with AEP that the companies' systems are integrated because they have transmission access rights to a single high-voltage line through Missouri and also met the PUCHA's single region requirement because it is now technically possible to centrally control the output of power plants across many states. In its ruling, the appeals court said that the SEC failed to explain its conclusions that the transmission integration and single region requirements are satisfied. Management believes that the merger meets the requirements of the PUHCA and expects the matter to be resolved favorably. Enron Bankruptcy - Affecting AEP, APCo, CSPCo, I&M, KPCo and OPCo At the date of Enron's bankruptcy AEP had open trading contracts and trading accounts receivables and payables with Enron. In addition, on June 1, 2001, we purchased Houston Pipe Line from Enron and entered into a lease arrangement with a subsidiary of Enron for a gas storage facility. At the date of Enron's bankruptcy various HPL related contingencies and indemnities remained unsettled. In the fourth quarter of 2001 AEP provided $47 million ($31 million net of tax) for our estimated loss from the Enron bankruptcy. The amounts for certain subsidiary registrants were: Amounts Amounts Net of Registrant Provided Tax -------- -- --- (in millions) APCo $5.2 $3.4 CSPCo 3.2 2.1 I&M 3.4 2.2 KPCo 1.3 0.8 OPCo 4.3 2.8 The amounts provided were based on an analysis of contracts where AEP and Enron are counterparties, the offsetting of receivables and payables, the application of deposits from Enron and management's analysis of the HPL related purchase contingencies and indemnifications. If there are any adverse unforeseen developments in the bankruptcy proceedings, our future results of operations, cash flows and possibly financial condition could be adversely impacted. Other - AEP and its registrant subsidiaries are involved in a number of other legal proceedings and claims. While management is unable to predict the ultimate outcome of these matters, it is not expected that their resolution will have a material adverse effect on results of operations, cash flows or financial condition. 9. Acquisitions and Dispositions: On June 1, 2001, AEP, through a wholly owned subsidiary, purchased Houston Pipe Line Company and Lodisco LLC for $727 million from Enron. The acquired assets include 4,200 miles of gas pipeline, a 30-year $274 million prepaid lease of a gas storage facility and certain gas marketing contracts. The purchase method of accounting was used to record the acquisition. According to APB Opinion No. 16 "Business Combinations" AEP recorded the assets acquired and liabilities assumed at their estimated fair values as determined by the Company's management based on information currently available and on current assumptions as to future operations. Based on a preliminary purchase price allocation the excess of cost over fair value of the net assets acquired was approximately $190 million and is recorded as goodwill. SFAS 142 "Goodwill and Other Intangible Assets" treats goodwill as a non-amortized, non-wasting asset effective January 1, 2002. Therefore, goodwill was amortized for only seven months in 2001 on a straight-line basis over 30 years. The purchase method results in the assets, liabilities and earnings of the acquired operations being included in AEP's consolidated financial statements from the purchase date. SFAS 141 "Business Combinations" apply to all business combinations initiated and consummated after June 30, 2001. AEP also purchased the following assets or acquired the following businesses from July 1, 2001 through December 31, 2001 for an aggregate total of $1,651 million: o SWEPCo, an AEP subsidiary, purchased the Dolet Hills mining operations including existing mine reclamation liabilities at its jointly owned lignite reserves in Louisiana. The purchase resulted from a litigation settlement discussed in Note 8, "Commitments and Contingencies". Management expects the acquisition to have minimal impact on results of operations. o Quaker Coal Company as part of a bankruptcy proceeding settlement and assumed additional liabilities of approximately $58 million. The acquisition includes property, coal reserves, mining operations and royalty interests in Colorado, Kentucky, Ohio, Pennsylvania and West Virginia. AEP will continue to operate the mines and facilities which employ over 800 individuals. o MEMCO Barge Line that adds 1,200 hopper barges and 30 towboats to AEP's existing barging fleet. MEMCO's 450 employees will continue to operate the barge line. MEMCO also adds major barging operations on the Mississippi and Ohio rivers to AEP's barging operations on the Ohio and Kanawha rivers. o 4,000 megawatts of UK coal-fired generation that includes Fiddler's Ferry, a four-unit, 2,000-megawatt station on the River Mersey in northwest England, approximately 200 miles from London and Ferrybridge, a four-unit, 2,000-megawatt station on the River Aire in northeast England, approximately 200 miles from London and related coal stocks. o A 20% equity interest in Caiua, a Brazilian electric operating company which is a subsidiary of Vale. See Note 17, "Power, Distribution and Communications Projects". The Company converted a total of $66 million on an existing loan and accrued interest on that loan into Caiua equity. o Indian Mesa Wind Project consisting of 160 megawatts of wind generation located near Fort Stockton, Texas. o Acquired existing contracts and hired 22 key staff from Enron's London-based international coal trading group. Regarding the 2001 acquisitions management has recorded the assets acquired and liabilities assumed at their estimated fair values in accordance with APB Opinion No. 16 and SFAS 141 as appropriate based on currently available information and on current assumptions as to future operations. Management is in the process of obtaining independent appraisals regarding certain of these acquisitions and evaluating others to refine its determination of fair values. Accordingly the allocation of the purchase prices are subject to revision based on the final determinations. Dispositions In March 2001 CSWE, a subsidiary company, completed the sale of Frontera, a generating plant that the FERC required to be divested in connection with the merger of AEP and CSW. The sale proceeds were $265 million and resulted in an after tax gain of $46 million. In July 2001 AEP, through a wholly owned subsidiary, sold its 50% interest in a 120-megawatt generating plant located in Mexico. The sale resulted in an after tax gain of approximately $11 million. In July 2001 OPCo, an AEP subsidiary, sold coal mines in Ohio and West Virginia and agreed to purchase approximately 34 million tons of coal from the purchaser of the mines through 2008. The sale is expected to have a nominal impact on results of operations and cash flows. In December 2001 AEP completed the sale of its ownership interests in the Virginia and West Virginia PCS (personal communications services) Alliances for stock. AEP recorded a 25% valuation provision on the stock received and is restricted from selling this stock until after January 1, 2003. In addition, the number of shares AEP can sell each month is limited in order to prevent large swings in the stock price. The sales resulted in an after tax gain of approximately $7 million. In December 2000 the Company, through a wholly owned subsidiary, committed to negotiate a sale of its 50% investment in Yorkshire, a U.K. electricity supply and distribution company. As a result a $43 million impairment writedown ($30 million after tax) was recorded in the fourth quarter of 2000 to reflect the net loss from the expected sale in the first quarter of 2001. The impairment writedown is included in Other Income on AEP's Consolidated Statements of Income. On February 26, 2001 an agreement to sell the Company's 50% interest in Yorkshire was signed. On April 2, 2001, following the approval of the buyer's shareholders, the sale was completed without further impact on AEP's consolidated earnings. In December 2000, CSW International, a subsidiary company sold its investment in a Chilean electric company for $67 million. A net loss on the sale of $13 million ($9 million after tax) is included in Other Income, and includes $26 million ($17 million net of tax) of losses from foreign exchange rate changes that were previously reflected in other comprehensive income. In the second quarter of 2000 manage-ment determined that the then existing decline in market value of the shares was other than temporary. As a result the investment was written down by $33 million ($21 million after tax) in June 2000. The total loss from both the write down of the Chilean investment to market in the second quarter and from the sale in the fourth quarter was $46 million ($30 million net of tax). 10. Benefit Plans: In the U.S. AEP sponsors two qualified pension plans and two nonqualified pension plans. Substantially all employees in the U.S., are covered by one or both of the pension plans. OPEB plans are sponsored by the AEP System to provide medical and death benefits for retired employees in the U.S. The foreign pension plans are for employees of SEEBOARD in the U.K. and CitiPower in Australia. The majority of SEEBOARD's employees joined a pension plan that is administered for the U.K.'s electricity industry. The assets of this plan are actuarially valued every three years. SEEBOARD and its participating employees both contribute to the plan. Subsequent to July 1, 1995, new employees were no longer able to participate in that plan and two new pension plans were made available to new employees of SEEBOARD. CitiPower sponsors a defined benefit pension plan that covers all employees. The following tables provide a reconciliation of the changes in the plans' benefit obligations and fair value of assets over the two-year period ending December 31, 2001, and a statement of the funded status as of December 31 for both years:
U.S. Foreign U.S. Pension Plans Pension Plans OPEB Plans ------------------ ---------------- ----------------- 2001 2000 2001 2000 2001 2000 ---- ---- ---- ---- ---- ---- (in millions) Reconciliation of benefit obligation: Obligation at January 1 $3,161 $2,934 $1,179 $1,176 $1,668 $1,365 Service Cost 69 60 12 13 30 29 Interest Cost 232 227 60 64 114 106 Participant Contributions - - 4 5 8 7 Plan Amendments - (71)(a) - - 17 (b) (67) (c) Foreign Currency Translation Adjustment - - (36) (95) - - Actuarial (Gain) Loss 121 218 (62) 80 192 262 Divestures - - - - (287) (d) - Benefit Payments (291) (207) (58) (64) (88) (85) Curtailments - - - - 1 51 (e) ------ ------ ------ ------ ------ ------ Obligation at December 31 $3,292 $3,161 $1,099 $1,179 $1,655 $1,668 ====== ====== ====== ====== ====== ====== Reconciliation of fair value of plan assets: Fair value of plan assets at January 1 $3,911 $3,866 $1,290 $1,405 $704 $668 Actual Return on Plan Assets (182) 250 (131) 55 (31) 2 Company Contributions - 2 7 - 118 112 Participant Contributions - - 4 5 8 7 Foreign Currency Translation Adjustment - - (40) (111) - - Benefit Payments (291) (207) (58) (64) (88) (85) ------ ------ ------ ------ ---- ---- Fair value of plan assets at December 31 $3,438 $3,911 $1,072 $1,290 $711 $704 ====== ====== ====== ====== ==== ==== Funded status: Funded status at December 31 $146 $ 750 $(27) $111 $(944) $(964) Unrecognized Net Transition (Asset) Obligation (15) (23) - - 263 298 Unrecognized Prior-Service Cost (12) (12) 9 10 17 - Unrecognized Actuarial (Gain) Loss 35 (628) 74 (67) 649 448 ---- ----- ---- ---- ----- ----- Prepaid Benefit (Accrued Liability) $154 $ 87 $ 56 $ 54 $ (15) $(218) ==== ===== ==== ==== ===== =====
(a) One of the qualified pension plans converted to the cash balance pension formula from a final average pay formula. (b) Related to the purchase of Houston Pipe Line Company and MEMCO Barge Line. (c) Change to a service-related formula for retirement health care costs and a 50% of pay life insurance benefit for retiree life insurance. (d) Related to the sale of Central Ohio Coal Company, Southern Ohio Coal Company and Windsor Coal Company. (e) Related to the shutdown of Central Ohio Coal Company, Southern Ohio Coal Company and Windsor Coal Company. The following table provides the amounts for prepaid benefit costs and accrued benefit liability recognized in the consolidated balance sheets as of December 31 of both years. The amounts for additional minimum liability, intangible asset and accumulated other comprehensive income for 2000 were recorded in 2001 and the amounts for 2001 will be recorded in 2002.
U.S. Foreign U.S. Pension Plan Pension Plans OPEB Plans ------------------- ---------------- ------------------- 2001 2000 2001 2000 2001 2000 ---- ---- ---- ---- ---- ---- (in millions) Prepaid Benefit Costs $ 205 $ 159 $57 $54 $ 1 $ 3 Accrued Benefit Liability (51) (72) (1) - (16) (221) Additional Minimum Liability (15) (24) - - N/A N/A Intangible Asset 9 14 - - N/A N/A Accumulated Other Comprehensive Income 6 10 - - N/A N/A ----- ----- --- --- ---- ------ Net Asset (Liability) $ 154 $ 87 $56 $54 $(15) $(218) ===== ===== === === ==== ===== Other Comprehensive (Income) Expense Attributable to Change in Additional Pension Liability Recognition $(4) $4 - - N/A N/A === == === === === ====
N/A = Not Applicable Both of the AEP System's nonqualified pension plans had accumulated benefit obligations in excess of plan assets of $40 million and $26 million at December 31, 2001 and $41 million and $26 million at December 31, 2000. There are no plan assets in the nonqualified plans. The AEP System's OPEB plans had accumulated benefit obligations in excess of plan assets of $944 million and $964 million at December 31, 2001 and 2000, respectively. In late December 2001 AEP purchased generation plants in the UK (see Note 9, "Acquisitions and Dispositions"). The purchase included the pension plan of the existing generation plant employees. In connection with the acquisition, a $10 million liability for the accumulated benefit obligation in excess of plan assets was assumed. The following table provides the components of AEP's net periodic benefit cost for the plans for fiscal years 2001, 2000 and 1999:
U.S. Foreign U.S. Pension Plans Pension Plans OPEB Plans -------------------- -------------------- ------------------- 2001 2000 1999 2001 2000 1999 2001 2000 1999 ---- ---- ---- ---- ---- ---- ---- ---- ---- (in millions) Service cost $ 69 $ 60 $ 71 $ 12 $ 13 $ 15 $ 30 $ 29 $ 33 Interest cost 232 227 211 60 64 59 114 106 90 Expected return on plan assets (338) (321) (299) (69) (75) (71) (61) (57) (49) Amortization of transition (asset) obligation (8) (8) (8) - - - 30 41 43 Amortization of prior-service cost - 13 12 1 1 - - - - Amortization of net actuarial (gain) loss (24) (39) (15) - - - 18 4 5 ---- ----- ----- ---- ---- ---- ---- ---- ---- Net periodic benefit cost (credit) (69) (68) (28) 4 3 3 131 123 122 Curtailment loss(a) - - - - - - 1 79 18 ---- ----- ----- ---- ---- ---- ---- ---- ---- Net periodic benefit cost (credit) after curtailments $(69) $ (68) $ (28) $ 4 $ 3 $ 3 $132 $202 $140 ==== ===== ===== ==== ==== ==== ==== ==== ====
(a) Curtailment charges were recognized during 2000 and 1999 for the shutdown of Central Ohio Coal Company, Southern Ohio Coal Company and Windsor Coal Company. The following table provides the net periodic benefit cost (credit) for the plans by the following AEP registrant subsidiaries for fiscal years 2001, 2000 and 1999:
U.S. U.S Pension Plans OPEB Plans ---------------------------- -------------------------- 2001 2000 1999 2001 2000 1999 ---- ---- ---- ---- ---- ---- (in thousands) APCo $(13,645) $(14,047) $(3,925) $22,810 $ 22,139 $19,431 CPL (3,411) (2,986) (4,270) 8,214 6,656 7,595 CSPCo (10,624) (10,905) (4,893) 10,328 9,643 8,623 I&M (7,805) (8,565) (1,259) 15,077 14,155 13,664 KPCo (1,922) (2,075) (393) 2,438 2,364 2,652 OPCo (14,879) (15,041) (4,979) 34,444 116,205 52,518 PSO (2,480) (2,196) (3,129) 6,187 4,277 5,516 SWEPCo (3,051) (2,606) (3,734) 6,399 4,152 4,913 WTU (1,664) (1,585) (2,221) 3,729 2,929 3,377
The weighted-average assumptions as of December 31, used in the measurement of the Company's benefit obligations are shown in the following tables:
U.S. Foreign Pension Plans Pension Plans U.S. OPEB Plans ----------------------- ------------------------- --------------------- 2001 2000 1999 2001 2000 1999 2001 2000 1999 ---- ---- ---- ---- ---- ---- ---- ---- ---- % % % % % % % % % Discount rate 7.25 7.50 8.00 5-5.8 5-5.5 5.5-6 7.25 7.50 8.00 Expected return on plan assets 9.00 9.00 9.00 6.1-7.5 6-7.5 6.5-7.5 8.75 8.75 8.75 Rate of compensation increase 3.7 3.2 3.8 4.0 3.5-4.0 4-4.5 N/A N/A N/A
For OPEB measurement purposes, an 8% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2002. The rate was assumed to decrease gradually each year to a rate of 5% through 2005 and remain at that level thereafter. Assumed health care cost trend rates have a significant effect on the amounts reported for the OPEB health care plans. A 1% change in assumed health care cost trend rates would have the following effects: 1% Increase 1% Decrease (in millions) Effect on total service and interest cost components of net periodic postretirement health care benefit cost $ 18 $(15) Effect on the health care Component of the Accumulated Postretirement Benefit obligation 189 (156) AEP Savings Plans - The AEP Savings Plans are defined contribution plans offered to non-UMWA U.S. employees. The cost for contributions to these plans totaled $55 million in 2001, $37 million in 2000 and $36 million in 1999. Beginning in 2001 AEP's contributions to the plans increased to 4.5% of the initial 6% of employee pay contributed from the previous 3% of the initial 6% of employee base pay contributed. The following table provides the cost for contributions to the savings plans by the following AEP registrant subsidiaries for fiscal years 2001, 2000 and 1999: 2001 2000 1999 ---- ---- ---- (in thousands) APCo $7,031 $3,988 $4,091 CPL 3,046 3,161 3,284 CSPCo 2,789 1,638 1,679 I&M 7,833 4,231 3,996 KPCo 1,016 544 561 OPCo 6,398 3,713 3,744 PSO 2,235 2,306 2,435 SWEPCo 2,776 2,880 2,961 WTU 1,558 1,708 1,766 Other UMWA Benefits - AEP and OPCo provide UMWA pension, health and welfare benefits for certain unionized mining employees, retirees, and their survivors who meet eligibility requirements. The benefits are administered by UMWA trustees and contributions are made to their trust funds. Contributions are expensed as paid as part of the cost of active mining operations and were not material in 2001, 2000 and 1999. 11. Stock-Based Compensation: AEP has a Long-term Incentive Plan under which a maximum of 15,700,000 shares of common stock can be issued to key employees. The plan was adopted in 2000. Under the plan, the exercise price of each option granted equals the market price of AEP's common stock on the date of grant. These options will vest in equal increments, annually, over a three-year period with a maximum exercise term of ten years. CSW maintained a stock option plan prior to the merger with AEP in 2000. Effective with the merger, all CSW stock options outstanding were converted into AEP stock options at an exchange ratio of one CSW stock option for 0.6 of an AEP stock option. The exercise price for each CSW stock option was adjusted for the exchange ratio. The provisions of the CSW stock option plan will continue in effect until all options expire or there are no longer options outstanding. Under the CSW stock option plan, the option exercise price was equal to the stock's market price on the date of grant. The grant vested over three years, one-third on each of the first three anniversary dates of the grant, and expires 10 years after the original grant date. All CSW stock options are fully vested. The following table summarizes share activity in the above plans, and the weighted-average exercise price:
2001 2000 1999 ---- ---- ---- Weighted Weighted Weighted Average Average Average Options Exercise Options Exercise Options Exercise (in thousands) Price (in thousands) Price (in thousands) Price -------------- ----- -------------- ----- -------------- ------ Outstanding at beginning of year 6,610 $36 825 $40 866 $40 Granted 645 $45 6,046 $36 - $ - Exercised (216) $38 (26) $36 (22) $38 Forfeited (217) $37 (235) $39 (19) $43 ----- ---- --- Outstanding at end of year 6,822 $37 6,610 $36 825 $40 ===== ===== === Options Exercisable at end of year 395 $43 588 $41 707 $42 === === ===
The weighted-average grant-date fair value of options granted in 2001 and 2000 was $8.01 and $5.50 per share. There were no options granted in 1999. Shares outstanding under the stock option plan have exercise prices ranging from $35 to $49 and a weighted-average remaining contractual life of 8.5 years. If compensation expense for stock options had been determined based on the fair value at the grant date, net income and earnings per share would have been the pro forma amounts shown below: 2001 2000 1999 ---- ---- ---- Pro forma net income (in millions) $959 $264 $972 Pro forma earnings per Share: Basic $2.98 $0.82 $3.03 Diluted $2.97 $0.82 $3.03 The proceeds received from exercised stock options are included in common stock and paid-in capital. The pro forma amounts are not representative of the effects on reported net income for future years. The fair value of each option award is estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted average assumptions used to estimate the fair value of options granted: 2001 2000 Risk Free Interest Rate 4.87% 5.02% Expected Life 7 years 7 years Expected Volatility 28.40% 24.75% Expected Dividend Yield 6.05% 6.02% 12. Business Segments: In fiscal year 2000, AEP reported the following four business segments: Domestic Electric Utilities; Foreign Energy Delivery; Worldwide Energy Investments; and Other. With this structure, our regulated domestic utility companies were considered single, vertically integrated units, and were reported collectively in the Domestic Electric Utilities segment. In 2001, we moved toward our goal of functionally and structurally segregating our businesses. The ensuing realignment of our operations resulted in our current business segments, Wholesale, Energy Delivery and Other. The business activities of each of these segments are as follows: Wholesale o Generation of electricity for sale to retail and wholesale customers, o Marketing and trading of electricity and gas worldwide. o Gas pipeline and storage services and other energy supply related business Energy Delivery o Domestic electricity transmission o Domestic electricity distribution Other o Foreign electricity generation investments o Foreign electricity distribution and supply investments o Telecommunication services Segment results of operations for the twelve months ended December 31, 2001, 2000 and 1999 are shown below. These amounts include certain estimates and allocations where necessary. We have used Earnings before Interest and Income Taxes (EBIT) as a measure of segment operating performance. The EBIT measure is total operating revenues net of total operating expenses and other routine income and deductions from income. It differs from net income in that it does not take into account interest expense or income taxes. EBIT is believed to be a reasonable gauge of results of operations. By excluding interest and income taxes, EBIT does not give guidance regarding the demand of debt service or other interest requirements, or tax liabilities or taxation rates. The effects of interest expense and taxes on overall corporate performance can be seen in the consolidated income statement.
Energy Reconciling AEP Year Wholesale Delivery Other Adjustments Consolidated - ---- --------- -------- ----- ----------- ------------ (in millions) 2001 Revenues from: External unaffiliated customers $55,929 $ 3,356 $ 1,972 $ - $61,257 Transactions with other operating segments 2,708 20 1,155 (3,883) - Segment EBIT 1,418 986 278 (115) 2,567 Depreciation, depletion and amortization expense 597 632 154 - 1,383 Total assets 31,459 12,455 4,541 (1,174)(a) 47,281 Investments in equity method subsidiaries 242 - 414 - 656 Gross property additions 640 844 348 - 1,832 (a) Reconciling adjustments for Total Assets: Eliminate intercompany balances (1,558) Corporate assets 404 Other (20) ------- (1,174)
2000 Revenues from: External unaffiliated customers $31,437 $ 3,174 $2,095 $ - $36,706 Transactions with other operating segments 1,726 2 750 (2,478) - Segment EBIT 1,006 1,017 358 (322) 2,059 Depreciation, depletion and amortization expense 559 506 188 (3) 1,250 Total assets 32,216 14,876 7,124 (866)(b) 53,350 Investments in equity method subsidiaries 140 - 724 - 864 Gross property additions 493 961 319 - 1,773 (b) Reconciling adjustments for Total Assets: Eliminate intercompany balances (955) Corporate assets 93 Other (4) ------- (866)
1999 Revenues from: External unaffiliated customers $19,543 $3,068 $2,134 $ - $24,745 Transactions with other operating segments 1,038 - 573 (1,611) - Segment EBIT 1,146 1,008 392 (82) 2,464 Depreciation, depletion and amortization expense 565 454 196 (3) 1,212 Total assets 18,408 11,224 6,396 (335)(c) 35,693 Investments in equity method subsidiaries 134 - 755 - 889 Gross property additions 390 815 475 - 1,680 (c) Reconciling adjustments for Total Assets: Eliminate intercompany balances (345) Other 10 ------- (335)
Geographically our business is transacted primarily in the United States and the United Kingdom with other holdings in a small number of other counties. Results of operations by geographic area are as follows: Geographic Areas Revenues - ---------------- --------------------------------------------------------------------- United AEP United States Kingdom Other Foreign Consolidated --------------------------------------------------------------------- (in millions) 2001 $53,650 $7,201 $406 $61,257 2000 34,300 2,011 395 36,706 1999 22,694 1,705 346 24,745
Long-Lived Assets --------------------------------------------------------------------- United AEP United States Kingdom Other Foreign Consolidated --------------------------------------------------------------------- (in millions) 2001 $21,726 $2,158 $659 $24,543 2000 20,463 1,220 710 22,393 1999 19,958 1,124 783 21,865
Of the registrant operating company subsidiaries, all of the registrant subsidiaries except AEGCo have two business segments. The segment results for each of these subsidiaries are reported in the table below. AEGCo has one segment, a wholesale generation business. AEGCo's results of operations are reported in AEGCo's financial statements.
Twelve Months Ended Twelve Months Ended December 31, 2001 December 31, 2000 ----------------- ----------------- Revenues Revenues From From External Segment External Segment Customers EBIT Total Assets Customers EBIT Total Assets --------- ---- --------- ---- (in thousands) (in thousands) Wholesale Segment APCo $6,404,394 $164,844 $2,855,337 $4,512,390 $ 154,525 $3,708,252 CPL 2,848,545 303,926 2,977,504 1,870,689 273,650 3,182,192 CSPCo 3,816,644 232,372 1,987,756 2,767,569 235,860 2,488,513 I&M 4,489,215 117,396 3,318,919 3,231,065 (146,297) 4,003,805 KPCo 1,528,212 4,935 585,847 1,055,521 22,379 766,605 OPCo 5,709,689 240,128 3,156,115 4,524,513 289,084 4,007,722 PSO 1,939,372 52,086 907,165 1,184,895 54,072 1,011,432 SWEPCo 2,241,444 82,409 1,223,334 1,337,776 27,055 1,302,398 WTU 895,235 7,930 396,147 583,358 13,910 466,499 Energy Delivery Segment APCo $595,036 $213,733 $2,252,601 $574,918 $191,560 $2,925,472 CPL 473,182 109,587 2,138,482 478,814 136,069 2,285,492 CSPCo 483,219 130,503 1,118,112 398,046 81,896 1,399,789 I&M 314,410 111,206 1,498,089 311,019 126,241 1,807,233 KPCo 131,183 54,033 567,396 121,346 49,770 742,459 OPCo 552,713 118,261 1,759,952 467,587 138,418 2,234,835 PSO 261,877 79,787 1,010,732 245,124 85,524 1,126,901 SWEPCo 333,004 107,197 1,273,266 344,950 129,842 1,355,558 WTU 169,036 33,226 527,273 176,204 50,201 620,912 Registrant Subsidiaries Company Total APCo $6,999,430 $378,577 $5,107,938 $5,087,308 $346,085 $6,633,724 CPL 3,321,727 413,513 5,115,986 2,349,503 409,719 5,467,684 CSPCo 4,299,863 362,875 3,105,868 3,165,615 317,756 3,888,302 I&M 4,803,625 228,602 4,817,008 3,542,084 (20,056) 5,811,038 KPCo 1,659,395 58,968 1,153,243 1,176,867 72,149 1,509,064 OPCo 6,262,402 358,389 4,916,067 4,992,100 427,502 6,242,557 PSO 2,201,249 131,873 1,917,897 1,430,019 139,596 2,138,333 SWEPCo 2,574,448 189,606 2,496,600 1,682,726 156,897 2,657,956 WTU 1,064,271 41,156 923,420 759,562 64,111 1,087,411
Twelve Months Ended December 31, 1999 Revenues From External Customers Segment EBIT Total Assets (in thousands) Wholesale Segment APCo $3,404,987 $116,907 $2,434,110 CPL 1,032,808 267,165 2,821,449 CSPCo 2,242,459 214,312 1,798,394 I&M 2,609,307 (18,055) 3,153,344 KPCo 789,008 18,569 501,212 OPCo 3,763,711 278,415 3,002,768 PSO 493,063 56,521 721,195 SWEPCo 672,158 95,385 1,032,045 WTU 270,800 25,008 369,457 Energy Delivery Segment APCo $565,660 $208,460 $1,920,290 CPL 449,667 133,172 2,026,401 CSPCo 389,280 93,962 1,011,596 I&M 310,880 142,973 1,423,352 KPCo 129,113 51,556 485,426 OPCo 460,182 149,906 1,674,441 PSO 256,327 74,430 803,531 SWEPCo 299,369 83,143 1,074,170 WTU 174,909 46,216 491,748 Registrant Subsidiaries Company Total APCo $3,970,647 $325,367 $4,354,400 CPL 1,482,475 400,337 4,847,850 CSPCo 2,631,739 308,274 2,809,990 I&M 2,920,187 124,918 4,576,696 KPCo 918,121 70,125 986,638 OPCo 4,196,893 428,321 4,677,209 PSO 749,390 130,951 1,524,726 SWEPCo 971,527 178,528 2,106,215 WTU 445,709 71,224 861,205
13. Risk Management, Financial Instruments and Derivatives: Risk Management We are subject to market risks in our day to day operations. Our risk policies have been reviewed with the Board of Directors, approved by a Risk Management Committee and administered by Chief Risk Officer. The Risk Management Committee establishes risk limits, approves risk policies, assigns responsibilities regarding the oversight and management of risk and monitors risk levels. This committee receives daily, weekly, and monthly reports regarding compliance with policies, limits and procedures. The committee meets monthly and consists of the Chief Risk Officer, Chief Credit Officer, V.P. Market Risk Oversight, and senior financial and operating managers. The risks and related strategies that management can employ are: Risk Description Strategy Price Risk Volatility in Trading and commodity prices hedging Interest Rate Risk Changes in Interest rates Hedging Foreign Exchange Fluctuations in Risk foreign currency rates Hedging Credit Risk Non-performance on contracts Guarantees, with Collateral counterparties We employ physical forward purchase and sale contracts, exchange futures and options, over-the-counter options, swaps, and other derivative contracts to offset price risk where appropriate. However, we engage in trading of electricity, gas and to a lesser degree coal, oil, natural gas liquids, and emission allowances and as a result the Company is subject to price risk. This risk is managed by the management of the trading operations, the Company's Chief Risk Officer and the Risk Management Committee. If the risk from trading activities exceeds certain pre-determined limits, the positions are modified or hedged to reduce the risk to the limits unless specifically approved by the Risk Management Committee. Although we do not hedge all commodity price exposure, manage-ment makes informed risk taking decisions supported by the above described risk management controls. AEP is exposed to risk from changes in the market prices of coal and natural gas used to generate electricity where generation is no longer regulated or where existing fuel clauses are suspended or frozen. The protection afforded by fuel clause recovery mechanisms has either been eliminated by the implementation of customer choice in Ohio (effective January 1, 2001) and in the ERCOT area of Texas (effective January 1, 2002) or frozen by settlement agreements in Indiana, Michigan and West Virginia. To the extent all fuel supply for the generating units in these states are not under fixed price long-term contracts, AEP is subject to market price risk. AEP continues to be protected against market price changes by active fuel clauses in Oklahoma, Arkansas, Louisiana, Kentucky, Virginia and the SPP area of Texas. We employ fair value hedges, cash flow hedges and swaps to mitigate changes in interest rates or fair values on short and long-term debt when management deems it necessary. We do not hedge all interest rate risk. We employ cash flow forward hedge contracts to lock-in prices on transactions denominated in foreign currencies where deemed necessary. International subsidiaries use currency swaps to hedge exchange rate fluctuations in debt transactions denominated in foreign currencies. We do not hedge all foreign currency exposure. Our open trading contracts, including structured transactions, are marked-to-market daily using the price model and price curve(s) corresponding to the instrument. Forwards, futures and swaps are generally valued by subtracting the contract price from the market price and then multiplying the difference by the contract volume and adjusting for net present value and other impacts. Significant estimates in valuing such contracts include forward price curves, volumes, seasonality, weather, and other factors. Forwards and swaps (which are a series of forwards) are valued based on forward price curves which represent a series of projected prices at which transactions can be executed in the market. The forward price curve includes the market's expectations for prices of a delivered commodity at that future date. The forward price curve is developed from the market bid price, which is the highest price which traders are willing to pay for a contract, and the ask or offer price, which is the lowest price traders are willing to receive for selling a contract. Options contracts, consisting primarily of options on forwards and spread options, are valued using models, which are variations on Black-Scholes option models. The market-related inputs are the interest rate curve, the underlying commodity forward price curve, and the implied volatility curve. Option prices or volatilities may be quoted in the market. Significant estimates in valuing these contracts include forward price curves, volumes, and other volatilities. Futures and futures options traded on futures exchanges (primarily oil and gas on Nymex) are valued at the exchange price. Market prices utilized in valuing all forward contracts, OTC options, swaps and structured transactions represent mid-market price, which is the average of the bid and ask prices. These bids and offers come from brokers, on-line exchanges such as the Intercontinental Exchange, and directly from other counterparties. These prices exist for delivery periods and locations being traded or quoted and vary by period, location and commodity. For periods and locations that are not liquid and for which external information is not readily available, management uses the best information available to develop bid and ask prices and forward curves. Electricity and gas markets in particular have primary trading hubs or delivery points/regions and less liquid secondary delivery points. In North American natural gas markets, the primary delivery points are generally traded from Henry Hub, Louisiana. The less liquid gas or power trading points may trade as a spread (based on transportation costs, constraints, etc.) from the nearest liquid trading hub. Also, some commodities trade more often and therefore are more liquid than others. For example, peak electricity is a more liquid product than off-peak electricity. Henry Hub gas trades in monthly blocks for up to 36 months and after that only trades in seasonal or calendar blocks. In the near term, forward price curves for gas have a seasonal shape. They are based on market quotes beyond that. For all these factors, the curve used for valuation is the mid-point. At times bids or offers may not be available due to market events, volatility, constraints, long-dated part of the curve, etc. When this occurs, the Company uses its best judgment to estimate the curve values until actual values are available again. The value used will be based on various factors such as last trade price, recent price trend, product spreads, location spreads (including transportation costs), cross commodity spreads (e.g., heat rate conversion of gas to power), time spreads, cost of carry (e.g., cost of gas storage), marginal production cost, cost of new entrant capacity, and alternative fuel costs. Also, an energy commodity contract's price volatility generally increases as it approaches the delivery month. Spot price volatility (e.g., daily or hourly prices) can cause contract values to change substantially as open positions settle against spot prices. When a portion of a curve has been estimated for a period of time and market changes occur, assumptions are updated to align the company's curve to the market. The fair values determined are reduced by reserves to adjust for credit risk and liquidity risk. Credit risk is based on credit ratings of counterparties and represents the risk that the counterparty to the contract will fail to perform or fail to pay amounts due AEP. Liquidity risk represents the risk that imperfections in the market will cause the price to be less than or more than what the price should be based purely on supply and demand. The liquidity reserve essentially reserves half of the difference between bids and offers for each open position, such that the wider the bid-offer spread (indicating lower liquidity), the greater the reserve. We also mark to market derivatives that are not trading contracts in accordance with generally accepted accounting principles. There may be unique models for these transactions, but the curves the company inputs into the models are the same forward curves, which are described above. We have developed independent controls to evaluate the reasonableness of our valuation models and curves. However, there are inherent risks related to the underlying assumptions in models used to fair value open long-term trading contracts. Therefore, there could be a significant favorable or adverse effect on future results of operations and cash flows if market prices at settlement differ from the price models and curves. AEP limits credit risk by extending unsecured credit to entities based on internal ratings. AEP uses Moody's Investor Service, Standard and Poor's and qualitative and quantitative data to independently assess the financial health of counterparties on an ongoing basis. This data, in conjunction with the ratings information, is used to determine appropriate risk parameters. AEP also requires cash deposits, letters of credit and parental/affiliate guarantees as security from certain below investment grade counterparties in our normal course of business. We trade electricity and gas contracts with numerous counterparties. Since our open energy trading contracts are valued based on changes in market prices of the related commodities, our exposures change daily. We believe that our credit and market exposures with any one counterparty is not material to financial condition at December 31, 2001. At December 31, 2001 less than 5% of the counterparties were below investment grade as expressed in terms of Net Mark to Market Assets. Net Mark to Market Assets represents the aggregate difference (either positive or negative) between the forward market price for the remaining term of the contract and the contractual price. The following table approximates counterparty credit quality and exposure for AEP. Futures, Forward and Counterparty Swap Credit Quality: Contracts Options Total Year Ending December 31, 2001 (in millions) AAA/Exchanges $147 $ - $147 AA 140 4 144 A 304 7 311 BBB 932 34 966 Below Investment Grade 56 23 79 -- -- -- Total $1,579 $68 $1,647 ====== === ====== The counterparty credit quality and exposure for the registrant subsidiaries is generally consistent with that of AEP. We enter into transactions for electricity and natural gas as part of wholesale trading operations. Electric and gas transactions are executed over-the-counter with counterparties or through brokers. Gas transactions are also executed through brokerage accounts with brokers who are registered with the Commodity Futures Trading Commission. Brokers and counterparties require cash or cash related instruments to be deposited on these transactions as margin against open positions. The combined margin deposits at December 31, 2001 and 2000 was $55 million and $95 million. These magin accounts are restricted and therefore are not included in cash and cash equivalents on the Balance Sheet. AEP and its subsidiaries can be subject to further margin requirements should related commodity prices change. The margin deposits at December 31, 2001 for the registrants were: (in thousands) APCo $2,832 CPL 299 CSP 1,736 I&M 1,879 KPCo 698 OPCo 2,862 PSO 247 SWEPCo 299 WTU 99 Financial Derivatives and Hedging In the first quarter of 2001, AEP adopted SFAS 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS 137 and SFAS 138. SFAS 133 requires that entities recognize all derivatives including fair value hedges as either assets or liabilities and measure such derivatives at fair value. Changes in the fair value of derivatives are included in earnings unless designated as a cash flow hedge. This practice is commonly referred to as mark-to-market accounting. Changes in the fair value of derivatives that are designated as effective cash flow hedges are included in other comprehensive income. AEP recorded a favorable transition adjustment to accumu-lated other comprehensive income of $27 million at January 1, 2001 in connection with the adoption of SFAS 133. Derivatives included in the transition adjustment are interest rate swaps, foreign currency swaps and commodity swaps, options and futures. Most of the derivatives identified in the trans-ition adjustment were designated as cash flow hedges and relate to foreign operations. The amounts of net revenue margins (sales less purchases) in 2001, 2000, and 1999 for trading activities were: 2001 2000 1999 ---- ---- ---- (in millions) Net Revenue Margin $609 $435 $91 The amounts of revenues recorded in 2001, 2000 and 1999 for the registrant subsidiaries were: 2001 2000 1999 ---- ---- ---- (in thousands) APCo $78,521 $72,649 $28,970 CPL 15,711 3,385 - CSPCo 51,765 48,142 14,800 I&M 36,089 58,909 16,147 KPCo 12,466 23,417 5,563 OPCo 65,118 73,474 24,389 PSO (2,483) 9,268 - SWEPCo 7,897 6,404 - WTU (1,491) 1,821 - The fair value of open trading contracts that are marked-to-market are based on management's best estimates using over-the-counter quotations and exchange prices for short-term open trading contracts, and Company developed price curves for open long-term trading contracts. The fair values of trading contracts at December 31 are: 2001 2000 ------------------ -------------------- Fair Fair Value Value ----- ----- (in millions) (in millions) Trading Assets Electric Futures and Options-NYMEX $ 11 $ - Physicals 3,588 8,791 Options - OTC 182 215 Swaps 117 164 ------ ------ Total Trading Assets $3,898 $9,170 ====== ====== Gas Futures and Options-NYMEX $ 143 $ - Physicals 238 454 Options - OTC 978 1,266 Swaps 5,646 6,185 ------ ------ Total Trading Assets $7,005 $7,905 ====== ====== Trading Liabilities Electric Futures and Options-NYMEX $ - $ - Physicals (3,382) (8,852) Options - OTC (101) (133) Swaps (126) (144) ------- ------- Total Trading Liabilities $(3,609) $(9,129) ======= ======= Gas Futures and Options- NYMEX $ (92) $ (81) Physicals (80) (419) Options - OTC (1,076) (934) Swaps (5,598) (6,449) ------- ------- Total Trading Liabilities $(6,846) $(7,883) ======= ======= 2001 2000 ------------------ -------------------- Fair Fair Value Value ----- ----- (in thousands) (in thousands) APCo Trading Assets Electric Futures and Options-NYMEX (net) $ - $ - Physicals 801,306 2,234,522 Options - OTC 46,649 59,814 Swaps 34,578 51,470 Trading Liabilities Electric Futures and Options-NYMEX (net) $ - $ - Physicals (748,016) (2,258,596) Options - OTC (21,895) (35,955) Swaps (36,921) (44,855) KPCo Trading Assets Electric Futures and Options-NYMEX (net) $ - $ - Physicals 197,545 530,828 Options - OTC 11,503 14,207 Swaps 8,529 12,227 Trading Liabilities Electric Futures and Options-NYMEX (net) $ - $ - Physicals (190,389) (536,512) Options - OTC (5,372) (8,521) Swaps (9,106) (10,656) 2001 2000 ------------------ -------------------- Fair Fair Value Value ----- ----- (in thousands) (in thousands) I&M Trading Assets Electric Futures and Options-NYMEX (net) $ - $ - Physicals 560,393 1,349,950 Options - OTC 31,397 36,139 Swaps 22,950 31,095 Trading Liabilities Electric Futures and Options-NYMEX (net) $ - $ - Physicals (513,026) (1,371,793) Options - OTC (15,864) (25,807) Swaps (24,505) (27,099) OPCo Trading Assets Electric Futures and Options-NYMEX (net) $ - $ - Physicals 668,142 1,776,259 Options - OTC 38,108 46,731 Swaps 29,730 41,788 Trading Liabilities Electric Futures and Options-NYMEX (net) $ - $ - Physicals (619,756) (1,792,417) Options - OTC (18,227) (29,350) Swaps (32,551) (37,398) CSPCo Trading Assets Electric Futures and Options-NYMEX (net) $ - $ - Physicals 491,290 1,192,203 Options - OTC 28,612 31,918 Swaps 21,211 27,461 Trading Liabilities Electric Futures and Options-NYMEX (net) $ - $ - Physicals (456,613) (1,204,948) Options - OTC (13,403) (19,220) Swaps (22,648) (23,932) 2001 2000 ------------------ -------------------- Fair Fair Value Value ----- ----- (in thousands) (in thousands) CPL Trading Assets Electric Physicals $285,481 $ 542,626 Trading Liabilities Electric Physicals (281,624) (550,817) PSO Trading Assets Electric Physicals 217,415 431,186 Trading Liabilities Electric Physicals (214,981) (437,694) SWEPCo Trading Assets Electric Physicals 249,531 516,385 Trading Liabilities Electric Physicals (246,631) (524,180) WTU Trading Assets Electric Physicals 84,784 171,597 Trading Liabilities Electric Physicals (83,869) (174,187) The FASB's Derivatives Implementation Group (DIG) Issued guidance, effective in the third quarter of 2001, regarding the imple-mentation of SFAS 133 for certain fuel supply contracts with volume optionality and electricity capacity contracts. The guidance concluded that fuel supply contracts with volumetric optionality cannot qualify for a normal purchase or sale exclusion from mark-to-market accounting and provided guidance for determining when electricity capacity con-racts can qualify as normal purchases or sales. Predominantly all of AEP's contracts for coal, gas and electricity, which are recorded on a settlement basis, do not meet the criteria of a financial derivative instrument and qualify as normal purchases or sales. As a result they are exempt from the DIG guidance described above and have not been marked-to-market. Beginning July 1, 2001, the effective date of the DIG guidance, certain of AEP's fuel supply contracts with volumetric optionality that qualify as financial derivative instruments are marked to market with any gain or loss recognized in the income statement. The effect of initially adopting the DIG guidance at July 1, 2001, a favorable earnings mark-to-market effect of $18 million, net of tax, is reported as a cumulative effect of an accounting change on the income statement. Cash flows from both derivative instruments and trading activities are included in net cash flows from operating activities. Certain derivatives may be designated for accounting purposes as a hedge of either the fair value of an asset, liability or firm commitment, or a hedge of the variability of cash flows related to a variable-priced asset, liability, commitment or forecasted trans-action. To qualify for hedge accounting, the relationship between the hedging instrument and the hedged item must be documented to include the risk management objective and strategy for use of the hedge instrument. At the inception of the hedge and on an ongoing basis, the effectiveness of the hedge is assessed as to whether the hedge is highly effective in offsetting changes in fair value or cash flows of the item being hedged. Changes in the fair value that result from ineffectiveness of a hedge under SFAS 133 are recognized currently in earnings through mark-to-market accounting. Changes in the fair value of effective cash flow hedges are reported in accumulated other comprehensive income if documented at inception. Gains and losses from cash flow hedges in other comprehensive income are reclassified to earnings in the accounting periods in which the variability of cash flows of the hedged items affect earnings. Cash flow hedges included in Accumulated Other Comprehensive income on the Balance Sheet at December 31, 2001 are: Hedging Assets Hedging Liabilities Other Comprehensive Income (Loss) After Tax ----------------------- (in millions) Electric $16 $ (6) $ 4 Interest Rate - (21) (12) Foreign Currency - - 5 ---- $ (3) The following table represents the activity in Other Comprehensive Income related to the effect of adopting SFAS 133 for derivative contracts that qualify as cash flow hedges at December 31, 2001: (in millions) AEP consolidated Transition Adjustment, January 1, 2001 $ 27 Changes in fair value (1) Reclasses from OCI to net income (29) --- Accumulated OCI derivative loss, December 31, 2001 $ (3) ==== (in thousands) APCo Transition Adjustment, January 1, 2001 $- Effective portion of changes in fair value (340) Reclasses from OCI to net income - -- Accumulated OCI derivative gain, December 31, 2001 $(340) ===== KPCo Transition Adjustment, January 1, 2001 $(557) Effective portion of changes in fair value (2,348) Reclasses from OCI to net income 1,002 ----- Accumulated OCI derivative gain, December 31, 2001 $(1,903) ======= I&M Transition Adjustment, January 1, 2001 $(317) Effective portion of changes in fair value (5,368) Reclasses from OCI to net income 1,850 ----- Accumulated OCI derivative gain, December 31, 2001 $(3,835) ======= OPCo Transition Adjustment, January 1, 2001 $- Effective portion of changes in fair value (196) Reclasses from OCI to net income - -- Accumulated OCI derivative gain, December 31, 2001 $(196) ===== Approximately $15 million of net losses from cash flow hedges in accumulated other comprehensive income at December 31, 2001 are expected to be reclassified to net income in the next twelve months as the items being hedged settle. The actual amounts reclassified from accumulated other comprehensive income to net income can differ as a result of market price changes. The maximum term for which the exposure to the variability of future cash flows is being hedged is 5 years. We have derivatives under SFAS 133 that do not employ hedge accounting and are not energy trading. The derivative's mark to market value at December 31, 2001 was a $22.7 million asset and a $13.1 million liability. FINANCIAL INSTRUMENTS Market Valuation of Non-Derivative Financial Instrument The book values of cash and cash equivalents, accounts receivable, short-term debt and accounts payable approximate fair value because of the short-term maturity of these instruments. The book value of the pre-April 1983 spent nuclear fuel disposal liability approximates the best estimate of its fair value. The fair values of long-term debt and preferred stock subject to mandatory redemption are based on quoted market prices for the same or similar issues and the current dividend or interest rates offered for instruments with similar maturities. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that we could realize in a current market exchange. The book values and fair values of significant financial instruments for AEP and its registrant subsidiaries December 31, 2001 and 2000 are summarized in the following tables. 2001 2000 Book Value Fair Value Book Value Fair Value ---------- ---------- ---------- ---------- (in millions) (in millions) AEP Consolidated Long-term Debt $12,053 $12,002 $10,754 $10,812 Preferred Stock 95 93 100 98 Trust Preferred Securities 321 320 334 326 (in thousands) (in thousands) AEGCo Long-term Debt $45,000 $45,268 $45,000 $45,000 APCo Long-term Debt $1,556,559 $1,439,531 $1,605,818 $1,601,313 Preferred Stock 10,860 10,860 10,860 10,725 CPL Long-term Debt $1,253,768 $1,278,644 $1,454,559 $1,463,690 Trust Preferred Securities 136,250 135,760 148,500 147,431 CSPCo Long-term Debt $791,848 $802,194 $899,615 $908,620 Preferred Stock 10,000 10,100 15,000 14,892 I&M Long-term Debt $1,652,082 $1,672,392 $1,388,939 $1,377,230 Preferred Stock 64,945 62,795 64,945 63,941 KPCo Long-term Debt $346,093 $350,233 $330,880 $335,408 OPCo Long-term Debt $1,203,841 $1,227,880 $1,195,493 $1,176,367 Preferred Stock 8,850 8,837 8,850 8,780 PSO Long-term Debt $451,129 $462,903 $470,822 $476,964 Trust Preferred Securities 75,000 74,730 75,000 72,180 SWEPCo Long-term Debt $645,283 $656,998 $645,963 $651,586 Trust Preferred Securities 110,000 109,780 110,000 106,700 WTU Long-term Debt $255,967 $266,846 $255,843 $261,315 Other Financial Instruments - Nuclear Trust Funds Recorded at Market Value - The trust investments which are classified as held for sale for decommissioning and SNF disposal, reported in other assets, are recorded at market value in accordance with SFAS 115. At December 31, 2001 and 2000 the fair values of the trust investments were $933 million and $873 million, respectively, and had a cost basis of $839 million and $768 million, respectively. The change in market value in 2001, 2000, and 1999 was a net unrealized holding loss of $11 million, and net unrealized holding gain of $6 million, and $18 million, respectively. 14. Income Taxes: The details of AEP's consolidated income taxes as reported are as follows: Year Ended December 31, ------------------------------ 2001 2000 1999 ---- ---- ---- (in millions) Federal: Current $406 $ 766 $308 Deferred 60 (237) 129 ---- ----- ---- Total 466 529 437 ---- ----- ---- State: Current 61 50 25 Deferred 35 (9) - ---- ----- ----- Total 96 41 25 ---- ----- ---- International: Current 1 6 3 Deferred 6 21 17 ---- ----- ----- Total 7 27 20 ---- ----- ----- Total Income Tax as Reported $569 $ 597 $482 ==== ===== ====
The details of the registrant subsidiaries income taxes as reported are as follows: AEGCo APCo CPL CSPCo I&M Year Ended December 31, 2001 (in thousands) Charged (Credited) to Operating Expenses (net): Current $ 9,126 $ 71,623 $190,671 $ 88,013 $ 107,286 Deferred (6,224) 27,198 (72,568) 14,923 (45,785) Deferred Investment Tax Credits - (3,237) (5,207) (3,899) (7,377) ------- -------- -------- -------- --------- Total 2,902 95,584 112,896 99,037 54,124 ------- -------- -------- -------- --------- Charged (Credited) to Nonoperating Income (net): Current (56) (19,165) (398) (13,803) (10,590) Deferred - 21,832 - 17,885 16,580 Deferred Investment Tax Credits (3,414) (1,528) - (159) (947) ------- -------- -------- -------- --------- Total (3,470) 1,139 (398) 3,923 5,043 ------- -------- -------- -------- --------- Total Income Tax as Reported $ (568) $ 96,723 $112,498 $102,960 $ 59,167 ======= ======== ======== ======== ========= KPCo OPCo PSO SWEPCo WTU Year Ended December 31, 2001 (in thousands) Charged (Credited) to Operating Expenses (net): Current $ 7,726 $(62,298) $ 53,030 $ 77,965 $ 19,424 Deferred 2,812 166,166 (16,726) (31,396) (11,891) Deferred Investment Tax Credits (1,180) (2,495) (1,791) (4,453) (1,271) ------- -------- -------- -------- -------- Total 9,358 101,373 34,513 42,116 6,262 ------- -------- -------- -------- ------- Charged (Credited) to Nonoperating Income (net): Current (2,725) (21,600) 352 542 (691) Deferred 3,481 20,014 - - - Deferred Investment Tax Credits (72) (794) - - - ------- -------- -------- -------- ------- Total 684 (2,380) 352 542 (691) ------- -------- -------- -------- ------- Total Income Tax as Reported $10,042 $ 98,993 $ 34,865 $ 42,658 $ 5,571 ======= ======== ======== ======== ======= AEGCo APCo CPL CSPCo I&M Year Ended December 31, 2000 (in thousands) Charged (Credited) to Operating Expenses (net): Current $ 8,746 $129,165 $ 89,403 $120,494 $ 134,796 Deferred (5,842) 3,838 16,263 (7,746) (126,748) Deferred Investment Tax Credits - (2,947) (5,207) (3,379) (7,524) ------- -------- -------- -------- --------- Total 2,904 130,056 100,459 109,369 524 ------- -------- -------- -------- --------- Charged (Credited) to Nonoperating Income (net): Current (44) 327 (5,073) 3,777 2,950 Deferred - 4,764 - 3,683 1,569 Deferred Investment Tax Credits (3,396) (1,968) - (103) (330) ------- -------- ------- -------- --------- Total (3,440) 3,123 (5,073) 7,357 4,189 ------- -------- ------- -------- --------- Total Income Tax as Reported $ (536) $133,179 $95,386 $116,726 $ 4,713 ======= ======== ======= ======== =========
KPCo OPCo PSO SWEPCo WTU Year Ended December 31, 2000 (in thousands) Charged (Credited) to Operating Expenses (net): Current $17,878 $259,608 $11,597 $16,073 $ 6,774 Deferred 2,521 (70,263) 25,453 14,653 9,401 Deferred Investment Tax Credits (1,187) (1,824) (1,791) (4,482) (1,271) ------- -------- ------- ------- ------- Total 19,212 187,521 35,259 26,244 14,904 ------- -------- ------- ------- ------- Charged (Credited) to Nonoperating Income (net): Current (50) 15,426 (1,306) (1,476) (222) Deferred 1,244 4,307 - - (1,237) Deferred Investment Tax Credits (65) (1,575) - - - ------- ------- ------- ------- -------- Total 1,129 18,158 (1,306) (1,476) (1,459) ------- ------- ------- ------- ------- Total Income Tax as Reported $20,341 $205,679 $33,953 $24,768 $13,445 ======= ======== ======= ======= =======
AEGCo APCo CPL CSPCo I&M Year Ended December 31, 1999 (in thousands) Charged (Credited) to Operating Expenses (net): Current $ 7,713 $69,522 $ 89,112 $79,410 $(67,368) Deferred (5,282) 8,981 19,620 9,737 85,345 Deferred Investment Tax Credits - (2,659) (5,207) (3,432) (7,547) ------- ------- -------- ------- -------- Total 2,431 75,844 103,525 85,715 10,430 ------- ------- -------- ------- -------- Charged (Credited) to Nonoperating Income (net): Current (146) (1,548) (5,604) (3,122) 1,529 Deferred - 4,052 318 744 382 Deferred Investment Tax Credits (3,448) (2,313) - (562) (605) ------- ------- -------- ------- -------- Total (3,594) 191 (5,286) (2,940) 1,306 ------- ------- -------- ------- -------- Total Income Taxes as Reported $(1,163) $76,035 $ 98,239 $82,775 $ 11,736 ======= ======= ======== ======= ========
KPCo OPCo PSO SWEPCo WTU Year Ended December 31, 1999 (in thousands) Charged (Credited) to Operating Expenses (net): Current $14,897 $135,540 $20,777 $ 60,169 $ 3,328 Deferred 2,239 4,205 14,521 (17,347) 12,026 Deferred Investment Tax Credits (1,193) (1,825) (1,791) (4,565) (1,275) ------- -------- ------- -------- ------- Total 15,943 137,920 33,507 38,257 14,079 ------- -------- ------- -------- ------- Charged (Credited) to Nonoperating Income (net): Current (424) (3,256) (2,215) (4,826) 858 Deferred 357 (539) - - - Deferred Investment Tax Credits (99) (1,633) - - - ------- -------- ------- -------- ------- Total (166) (5,428) (2,215) (4,826) 858 ------- -------- ------- -------- ------- Total Income Taxes as Reported $15,777 $132,492 $31,292 $ 33,431 $14,937 ======= ======== ======= ======== =======
The following is a reconciliation for AEP Consolidated of the difference between the amount of federal income taxes computed by multiplying book income before federal income taxes by the statutory tax rate, and the amount of income taxes reported. Year Ended December 31, --------------------------------- 2001 2000 1999 ---- ---- ---- (in millions) Net Income $ 971 $267 $ 972 Extraordinary Items (net of income tax $20 million in 2001, $44 million in 2000 and $8 million in 1999) 50 35 14 Cumulative Effect of Accounting Change (net of income tax $2 million in 2001) (18) - - Preferred Stock Dividends 10 11 19 ------ ---- ------ Income Before Preferred Stock Dividends of Subsidiaries 1,013 313 1,005 Income Taxes 569 597 482 ------ ---- ------ Pre-Tax Income $1,582 $910 $1,487 ====== ==== ====== Income Tax on Pre-Tax Income at Statutory Rate (35%) $554 $319 $520 Increase (Decrease) in Income Tax Resulting from the Following Items: Depreciation 48 77 71 Corporate Owned Life Insurance 4 247 2 Investment Tax Credits (net) (37) (36) (38) Tax Effects of Foreign Operations (27) (29) (54) Merger Transaction Costs - 49 - State Income Taxes 62 26 16 Other (35) (56) (35) ---- ---- ---- Total Income Taxes as Reported $569 $597 $482 ==== ==== ==== Effective Income Tax Rate 36.0% 65.5% 32.5% ==== ==== ==== Shown below is a reconciliation for each AEP registrant subsidiary of the difference between the amount of federal income taxes computed by multiplying book income before federal income taxes by the statutory rate, and the amount of income taxes reported.
AEGCo APCo CPL CSPCo I&M Year Ended December 31, 2001 (in thousands) Net Income (Loss) $7,875 $161,818 $182,278 $161,876 $ 75,788 Extraordinary (Gains) Loss - - 2,509 30,024 - Income Tax Benefit - - - - - Income Taxes (568) 96,723 112,498 102,960 59,167 ------ -------- -------- -------- -------- Pre-Tax Income (Loss) $7,307 $258,541 $297,285 $294,860 $134,955 ====== ======== ======== ======== ======== Income Tax on Pre-Tax Income (Loss) at Statutory Rate (35%) $ 2,557 $ 90,490 $104,050 $103,201 $ 47,234 Increase (Decrease) in Income Tax Resulting from the Following Items: Depreciation 230 2,977 8,477 2,757 21,224 Corporate Owned Life Insurance - 450 - 544 (148) Nuclear Fuel Disposal Costs - - - - (3,292) Allowance for Funds Used During Construction (1,078) - - - (1,606) Rockport Plant Unit 2 Investment Tax Credit 374 - - - - Removal Costs - - - - - Investment Tax Credits (net) (3,414) (4,765) (5,207) (4,058) (8,324) State Income Taxes 1,050 9,613 9,652 5,727 6,137 Other (287) (2,042) (4,474) (5,211) (2,058) ------- -------- -------- -------- -------- Total Income Taxes as Reported $ (568) $ 96,723 $112,498 $102,960 $ 59,167 ======= ======== ======== ======== ======== Effective Income Tax Rate N.M. 37.4% 37.9% 34.9% 43.8% ==== ==== ==== ==== ====
KPCo OPCo PSO SWEPCo WTU Year Ended December 31, 2001 (in thousands) Net Income $21,565 $147,445 $ 57,759 $ 89,367 $12,310 Extraordinary Loss - 18,348 - - - Income Tax Benefit - - - - - Income Taxes 10,042 98,993 34,865 42,658 5,571 ------- -------- -------- -------- ------- Pre-Tax Income $31,607 $264,786 $ 92,624 $132,025 $17,881 ======= ======== ======== ======== ======= Income Tax on Pre-Tax Income at Statutory Rate (35%) $11,062 $ 92,675 $32,418 $ 46,209 $ 6,259 Increase (Decrease) in Income Tax Resulting from the Following Items: Depreciation 1,581 7,972 - - 1,463 Corporate Owned Life Insurance 334 1,852 - - - Nuclear Fuel Disposal Costs - - - - - Allowance for Funds Used During Construction - - - - - Rockport Plant Unit 2 Investment Tax Credit - - - - - Removal Costs (420) - - - - Investment Tax Credits (net) (1,252) (3,289) (1,791) (4,453) (1,271) State Income Taxes 318 9,752 5,137 5,451 1,283 Other (1,581) (9,969) (899) (4,549) (2,163) ------- -------- ------- -------- ------- Total Income Taxes as Reported $10,042 $ 98,993 $34,865 $ 42,658 $ 5,571 ======= ======== ======= ======== ======= Effective Income Tax Rate 31.8% 37.4% 37.6% 32.3% 31.2% ==== ==== ==== ==== ====
AEGCo APCo CPL CSPCo I&M Year Ended December 31, 2000 (in thousands) Net Income (Loss) $7,984 $ 73,844 $189,567 $ 94,966 $(132,032) Extraordinary (Gains) Loss (1,066) 39,384 Income Tax Benefit - (7,872) - (14,148) - Income Taxes (536) 133,179 95,386 116,726 4,713 ------ -------- -------- -------- --------- Pre-Tax Income (Loss) $7,448 $198,085 $284,953 $236,928 $(127,319) ====== ======== ======== ======== ========= Income Tax on Pre-Tax Income (Loss) at Statutory Rate (35%) $ 2,607 $ 69,330 $99,733 $ 82,925 $(44,561) Increase (Decrease) in Income Tax Resulting from the Following Items: Depreciation 452 7,606 7,556 10,529 20,378 Corporate Owned Life Insurance - 54,824 - 29,259 42,587 Nuclear Fuel Disposal Costs - - - - (3,957) Allowance for Funds Used During Construction (1,070) - - - (2,211) Rockport Plant Unit 2 Investment Tax Credit 374 - - - - Removal Costs - (1,197) - - - Investment Tax Credits (net) (3,396) (4,915) (5,207) (3,482) (7,854) State Income Taxes 784 9,950 2,296 89 6,004 Other (287) (2,419) (8,992) (2,594) (5,673) ------- -------- ------- -------- -------- Total Income Taxes as Reported $ (536) $133,179 $95,386 $116,726 $ 4,713 ======= ======== ======= ======== ======== Effective Income Tax Rate N.M. 67.2% 33.5% 49.3% N.M. ==== ==== ==== ==== ====
KPCo OPCo PSO SWEPCo WTU Year Ended December 31, 2000 (in thousands) Net Income $20,763 $ 83,737 $ 66,663 $72,672 $27,450 Extraordinary Loss 40,157 Income Tax Benefit - (21,281) - - - Income Taxes 20,342 205,679 33,953 24,768 13,445 ------- -------- -------- ------- ------- Pre-Tax Income $41,105 $308,292 $100,616 $97,440 $40,895 ======= ======== ======== ======= ======= Income Tax on Pre-Tax Income at Statutory Rate (35%) $14,387 $107,903 $35,216 $ 34,104 $14,313 Increase (Decrease) in Income Tax Resulting from the Following Items: Depreciation 1,827 27,577 - - 1,204 Corporate Owned Life Insurance 5,149 84,453 - - - Nuclear Fuel Disposal Costs - - - - - Allowance for Funds Used During Construction - - - - - Rockport Plant Unit 2 Investment Tax Credit - - - - - Removal Costs (420) - - - - Investment Tax Credits (net) (1,252) (3,398) (1,791) (4,482) (1,271) State Income Taxes 1,597 (1,988) 3,037 1,650 - Other (946) (8,868) (2,509) (6,504) (801) ------- -------- ------- -------- ------- Total Income Taxes as Reported $20,342 $205,679 $33,953 $ 24,768 $13,445 ======= ======== ======= ======== ======= Effective Income Tax Rate 49.5% 66.8% 33.8% 25.4% 32.9% ==== ==== ==== ==== ====
AEGCo APCo CPL CSPCo I&M Year Ended December 31, 1999 (in thousands) Net Income $ 6,195 $120,492 $182,201 $150,270 $32,776 Extraordinary Loss 8,488 Income Tax Benefit - - (2,971) - - Income Taxes (1,163) 76,035 98,239 82,775 11,736 ------- -------- -------- -------- ------- Pre-Tax Income $ 5,032 $196,527 $285,957 $233,045 $44,512 ======= ======== ======== ======== ======= Income Tax on Pre-Tax Income at Statutory Rate (35%) $ 1,762 $ 68,785 $100,085 $ 81,566 $15,580 Increase (Decrease) in Income Tax Resulting from the Following Items: Depreciation 446 12,593 7,981 8,846 19,966 Corporate Owned Life Insurance - - - - 594 Nuclear Fuel Disposal Costs - - - - (3,347) Allowance for Funds Used During Construction (1,069) - - - (2,174) Rockport Plant Unit 2 Investment Tax Credit 374 - - - - Removal Costs - (3,220) - - - Investment Tax Credits (net) (3,448) (4,972) (5,207) (3,994) (8,152) State Income Taxes 467 3,305 6,965 58 (4,635) Other 305 (456) (11,585) (3,701) (6,096) ------- -------- -------- -------- ------- Total Income Taxes as Reported $(1,163) $ 76,035 $ 98,239 $ 82,775 $11,736 ======= ======== ======== ======== ======= Effective Income Tax Rate N.M. 38.7% 34.4% 35.6% 26.4% ==== ==== ==== ==== ====
KPCo OPCo PSO SWEPCo WTU Year Ended December 31, 1999 (in thousands) Net Income $25,430 $212,157 $61,508 $83,194 $26,406 Extraordinary Loss 4,632 8,402 Income Tax Benefit - - - (1,621) (2,941) Income Taxes 15,777 132,492 31,292 33,431 14,937 ------- -------- ------- -------- ------- Pre-Tax Income $41,207 $344,649 $92,800 $119,636 $46,804 ======= ======== ======= ======== ======= Income Tax on Pre-Tax Income at Statutory Rate (35%) $14,423 $120,628 $ 32,480 $ 41,873 $16,382 Increase (Decrease) in Income Tax Resulting from the Following Items: Depreciation 1,843 17,517 - - 1,120 Corporate Owned Life Insurance - 198 - - - Removal Costs (420) - - - - Investment Tax Credits (net) (1,292) (3,458) (1,791) (4,565) (1,275) State Income Taxes 1,809 1,090 3,054 2,924 - Other (586) (3,483) (2,451) (6,801) (1,290) ------- -------- -------- -------- ------- Total Income Taxes as Reported $15,777 $132,492 $ 31,292 $ 33,431 $14,937 ======= ======== ======== ======== ======= Effective Income Tax Rate 38.3% 38.5% 33.8% 28.0% 32.0% ==== ==== ==== ==== ====
The following tables show the elements of the net deferred tax liability and the significant temporary differences for AEP Consolidated and each registrant subsidiary: December 31, -------------------------- 2001 2000 ---- ---- (in millions) Deferred Tax Assets $ 1,248 $ 1,248 Deferred Tax Liabilities (6,071) (6,123) ------- ------- Net Deferred Tax Liabilities $(4,823) $(4,875) ======= ======= Property Related Temporary Differences $(3,963) $(3,935) Amounts Due From Customers For Future Federal Income Taxes (245) (252) Deferred State Income Taxes (160) (251) Transition Regulatory Assets (268) (163) Regulatory Assets Designated for Securitization (332) (332) All Other (net) 145 58 ------- ------- Net Deferred Tax Liabilities $(4,823) $(4,875) ======= =======
AEGCo APCo CPL CSPCo I&M December 31, 2001 (in thousands) Deferred Tax Assets $ 75,856 $ 162,334 $ 130,863 $ 74,767 $ 332,225 Deferred Tax Liabilities (103,831) (865,909) (1,294,658) (518,489) (732,756) --------- --------- ----------- --------- --------- Net Deferred Tax Liabilities $ (27,975) $(703,575) $(1,163,795) $(443,722) $(400,531) ========= ========= =========== ========= ========= Property Related Temporary Differences $ (70,581) $(530,298) $ (808,922) $(323,139) $(306,151) Amounts Due From Customers For Future Federal Income Taxes 9,292 (55,206) (70,174) (9,839) (46,756) Deferred State Income Taxes (3,822) (56,747) - (8,968) (38,015) Translation Regulatory Assets - (34,783) - (78,298) - Net Deferred Gain on Sale and Leaseback-Rockport Plant Unit 2 40,816 - - - 27,157 Accrued Nuclear Decommissioning Expense - - - - 43,707 Deferred Fuel and Purchased Power - - - - (26,270) Deferred Cook Plant Restart Costs - - - - (28,000) Nuclear Fuel - - - - (16,062) Regulatory Assets Designated for Securitization - - (332,198) - - All Other (net) (3,680) (26,541) 47,499 (23,478) (10,141) --------- --------- ----------- --------- --------- Net Deferred Tax Liabilities $ (27,975) $(703,575) $(1,163,795) $(443,722) $(400,531) ========= ========= =========== ========= =========
KPCo OPCo PSO SWEPCo WTU December 31, 2001 (in thousands) Deferred Tax Assets $ 30,927 $ 135,938 $ 59,421 $ 56,189 $ 22,888 Deferred Tax Liabilities (199,231) (933,827) (356,298) (425,970) (167,937) --------- --------- --------- --------- --------- Net Deferred Tax Liabilities $(168,304) $(797,889) $(296,877) $(369,781) $(145,049) ========= ========= ========= ========= ========= Property Related Temporary Differences $(118,147) $(595,974) $(320,900) $(362,884) $(149,309) Amounts Due From Customers For Future Federal Income Taxes (20,215) (61,130) 10,199 (6,441) 4,757 Deferred State Income Taxes (25,267) (18,440) - - - Translation Regulatory Assets - (154,947) - - - Deferred Fuel and Purchased Power - 20,323 - - - Provision for Mine Shutdown Costs - 18,365 - - - All Other (net) (4,675) (6,086) 13,824 (456) (497) --------- --------- --------- --------- --------- Net Deferred Tax Liabilities $(168,304) $(797,889) $(296,877) $(369,781) $(145,049) ========= ========= ========= ========= =========
AEGCo APCo CPL CSPCo I&M December 31, 2000 (in thousands) Deferred Tax Assets $ 81,480 $ 178,487 $ 67,184 $ 88,198 $ 342,900 Deferred Tax Liabilities (114,408) (860,961) (1,309,981) (510,957) (830,845) --------- --------- ----------- --------- --------- Net Deferred Tax Liabilities $ (32,928) $(682,474) $(1,242,797) $(422,759) $(487,945) ========= ========= =========== ========= ========= Property Related Temporary Differences $ (78,113) $(510,950) $ (773,454) $(343,045) $(324,198) Amounts Due From Customers For Future Federal Income Taxes 10,317 (55,085) (72,426) (11,142) (55,218) Deferred State Income Taxes (5,478) (86,351) - - (69,982) Translation Regulatory Asset - (40,554) - (68,817) - Net Deferred Gain on Sale and Leaseback-Rockport Plant Unit 2 42,766 - - - 28,454 Accrued Nuclear Decommissioning Expense - - - - 34,702 Deferred Fuel and Purchased Power - - - - (39,395) Deferred Cook Plant Restart Costs - - - - (42,000) Nuclear Fuel - - - - (28,319) Regulatory Assets Designated for Securitization - - (332,198) - - All Other (net) (2,420) 10,466 (64,719) 245 8,011 --------- --------- ----------- --------- --------- Net Deferred Tax Liabilities $ (32,928) $(682,474) $(1,242,797) $(422,759) $(487,945) ========= ========= =========== ========= =========
KPCo OPCo PSO SWEPCo WTU December 31, 2000 (in thousands) Deferred Tax Assets $ 32,807 $ 330,878 $ 60,010 $ 47,615 $ 16,604 Deferred Tax Liabilities (198,742) (952,819) (372,070) (446,819) (173,642) --------- --------- --------- --------- --------- Net Deferred Tax Liabilities $(165,935) $(621,941) $(312,060) $(399,204) $(157,038) ========= ========= ========= ========= ========= Property Related Temporary Differences $(116,109) $(586,039) $(313,248) $(375,427) $(150,264) Amounts Due From Customers For Future Federal Income Taxes (19,680) (57,759) 11,082 (6,015) 4,723 Deferred State Income Taxes (29,695) (14,282) (36,487) - - Translation Regulatory Asset - (53,149) - - - Deferred Fuel and Purchased Power - (116,224) - - - Provision for Mine Shutdown Costs - 63,995 - - - Postretirement Benefits - 93,306 - - - All Other (net) (451) 48,211 26,593 (17,762) (11,497) --------- --------- --------- --------- --------- Net Deferred Tax Liabilities $(165,935) $(621,941) $(312,060) $(399,204) $(157,038) ========= ========= ========= ========= =========
We have settled with the IRS all issues from the audits of our consolidated federal income tax returns for the years prior to 1991. We have received Revenue Agent's Reports from the IRS for the years 1991 through 1996, and have filed protests contesting certain proposed adjustments. Returns for the years 1997 through 2000 are presently being audited by the IRS. Management is not aware of any issues for open tax years that upon final resolution are expected to have a material adverse effect on results of operations. COLI Litigation - On February 20, 2001, the U.S. District Court for the Southern District of Ohio ruled against AEP in its suit against the United States over deductibility of interest claimed by AEP in its consolidated federal income tax returns related to its COLI program. AEP had filed suit to resolve the IRS' assertion that interest deductions for AEP's COLI program should not be allowed. In 1998 and 1999 the Company paid the disputed taxes and interest attributable to COLI interest deductions for taxable years 1991-98 to avoid the potential assessment by the IRS of additional interest on the contested tax. The payments were included in other assets pending the resolution of this matter. As a result of the U.S. District Court's decision to deny the COLI interest deductions, net income was reduced by $319 million in 2000. The Company has filed an appeal of the U.S. District Court's decision with the U.S. Court of Appeals for the 6th Circuit. The earnings reductions for affected registrant subsidiaries are as follows: (in millions) APCo $ 82 CSPCo 41 I&M 66 KPCo 8 OPCo 118 The Company has not recognized a deferred tax liability for temporary differences related to investments in certain subsidiaries located outside of the United States because such differences are deemed to be essentially permanent in duration. If the investments were sold, the temporary differences may become taxable resulting in a tax liability of approximately $66 million. The Company joins in the filing of a consolidated federal income tax return with its affiliated companies in the AEP System. The allocation of the AEP System's current consolidated federal income tax to the System companies is in accordance with SEC rules under the 1935 Act. These rules permit the allocation of the benefit of current tax losses to the System companies giving rise to them in determing their current tax expense. The tax loss of the System parent company, AEP Co., Inc., is allocated to its subsidiaries with taxable income. With the exception of the loss of the parent company, the method of allocation approximates a separate return result for each company in the consolidated group. 15. Basic and Diluted Earnings Per Share: The calculation of basic and diluted earnings per share is based on the amounts of income and weighted average shares shown in the table below. 2001 2000 1999 ---- ---- ---- (in millions - except per share amounts) Income: - ------ Income before Extraordinary Item and Cumulative Effect $1,003 $302 $986 Extraordinary Losses (net of tax) (50) (35) (14) Cumulative Effect of Accounting Change (net of tax) 18 - - ------ ---- ---- Net Income $ 971 $267 $972 ====== ==== ==== Weighted Average Shares: Average common Shares outstanding 322 322 321 Assumed conversion of stock options (see Note 11) 1 - - --- --- --- Diluted average comon shares outstanding 323 322 321 === === === Basic and Diluted Earnings Per Share: Income before Extraordinary item and cumulative effect $3.11 $ 0.94 $ 3.07 Extraordinary losses (net of tax) (0.16) (0.11) (0.04) Cumulative effect of accounting change (net of tax) 0.06 - - ----- ------ ------ $3.01 $ 0.83 $ 3.03 The assumed conversion of stock options does not affect income for purposes of calculating diluted earnings per share. Basic and diluted EPS are the same in 2001, 2000 and 1999 since the effect on weighted average shares outstanding is little or nil. 16. Supplementary Information:
Year Ended December 31, ----------------------- 2001 2000 1999 ---- ---- ---- (in millions) AEP Consolidated Purchased Power - Ohio Valley Electric Corporation (44.2% owned by AEP System) $127 $86 $64 Cash was paid for: Interest (net of capitalized amounts) $972 $842 $979 Income Taxes $569 $449 $270 Noncash Investing and Financing Activities: Acquisitions under Capital Leases $17 $118 $80 Assumption of Liabilities Related to Acquisitions $171 - - Exchange of Communication Investment for Common Stock $5 - -
The amounts of power purchased by the registrant subsidiaries from Ohio Valley Electric Corporation, which is 44.2% owned by the AEP System, for the years ended December 31, 2001, 2000, and 1999 were: APCo CSPCo I&M OPCo ---- ----- --- ---- (in thousands) Year Ended December 31, 2001 $45,542 $12,626 $20,723 $47,757 Year Ended December 31, 2000 30,998 8,706 15,204 31,134 Year Ended December 31, 1999 21,774 6,006 10,227 25,623 17. Power, Distribution and Communications Projects: Power Projects AEP owns interests of 50% or less in domestic unregulated power plants with a capacity of 1,483 MW located in Colorado, Florida and Texas. In addition to the domestic projects, AEP has equity interests in international power plants totaling 1,788 MW. AEP has other projects in various stages of development. Investments in power projects that are 50% or less owned are accounted for by the equity method and reported in investments in power, distribution and communications projects on the balance sheet. At December 31, 2001, six domestic and four international power projects are accounted for under the equity method. The six domestic projects are combined cycle gas turbines that provide steam to a host commercial customer and are considered Qualifying Facilities (QF) under the Public Utilities Regulatory Policies Act of 1978. The four international power plants are classified as Foreign Utility Companies (FUCO) under the Energy Policies Act of 1992. All of the power projects accounted for under the equity method have unrelated third-party partners. All of the above power projects have project-level financing, which is non-recourse to AEP. AEP or AEP subsidiaries have guaranteed $30 million of domestic partnership obligations for performance under power purchase agreements and for debt service reserves in lieu of cash deposits. AEP has guaranteed $94 million of additional equity for two projects. Distribution Projects We own a 44% equity interest in Vale, a Brazilian electric operating company which was purchased for a total of $149 million. On December 1, 2001 we converted a $66 million note receivable and accrued interest into a 20% equity interest in Caiua (Brazilian electric operating company), a subsidiary of Vale. Vale and Caiua have experienced losses from operations and our investment has been affected by the devaluation of the Brazilian Real. The cumulative equity share of operating and foreign currency translation losses through December 31, 2001 is approximately $46 million and $54 million, respectively, net of tax. The cumulative equity share of operating and foreign currency translation losses through December 31, 2000 is approximately $33 million and $49 million, respectively, net of tax. Both investments are covered by a put option, which, if exercised, requires our partners in Vale to purchase our Vale and Caiua shares at a minimum price equal to the U.S. dollar equivalent of the original purchase price. As a result, management has concluded that the investment carrying amount should not be reduced below the put option value unless it is deemed to be an other than temporary impairment and our partners in Vale are deemed unable to fulfill their responsibilities under the put option. Management has evaluated through an independent third-party, the ability of its Vale partners to fulfill their responsibilities under the put option agreement and has concluded that our partners should be able to fulfill their responsibilities. Management believes that the decline in the value of its investment in Vale in US dollars is not other than temporary. As a result and pursuant to the put option agreement, these losses have not been applied to reduce the carrying values of the Vale and Caiua investments. As a result we will not recognize any future earnings from Vale and Caiua until the operating losses are recovered. Should the impairment of our investment become other than temporary due to our partners in Vale becoming unable to fulfill their responsibilities, it would have an adverse effect on future results of operations. Management will continue to monitor both the status of the losses and of its partners ability to fulfill its obligations under the put. Communication Projects AEP provides telecommunication services to businesses and telecommunication companies through a broadband fiber optic network. AEP's investment in the network include fiber optic cable, electronic equipment and colocation facilities that house the equipment. The investments are both owned and leased with a majority of the leased investments being indefeasible rights of use (IRUs) for fiber optic cable for periods ranging from 20 to 30 years. Telecommunication revenue is accounted for using the accrual method of accounting as service is rendered over the contractual term. Lease obligations related to these investment are included in the lease payment amounts disclosed in the lease note. AEP has a 46.25% ownership interest in a joint venture, AFN networks, LLC (AFN), which is engaged in the operation and construction of a fiber optic network. AFN both owns and leases fiber optic cable and electronic equipment with the majority of leases being IRUs of fiber optic cable for periods ranging from 20 to 25 years. AEP accounts for AFN under the equity method of accounting and has recorded its pro rata share of the losses during the start up phase. AEP has a credit agreement with AFN that enables AFN to borrow up to $91.5 million at market interest rates to finance their construction and operations. The amount available to AFN at December 31, 2001 is $61 million. AEP has a 50% ownership interest in a joint venture, American Fiber Touch, LLC (AFT), that is constructing a fiber optic line from Missouri to Illinois. AEP accounts for AFT under the equity method of accounting and has recorded its pro rata share of the losses of AFT during the start up phase. AEP has recently decided to withdraw from this venture and fully provided for the expected loss in exiting the joint venture in December 2001. 18. Leases: Leases of property, plant and equipment are for periods up to 35 years and require payments of related property taxes, maintenance and operating costs. The majority of the leases have purchase or renewal options and will be renewed or replaced by other leases. Lease rentals for both operating and capital leases are generally charged to operating expenses in accordance with rate-making treatment for regulated operations. Capital leases for non-regulated property are accounted for as if the assets were owned and financed. The components of rental costs are as follows:
AEP AEGCo APCo CPL CSPCo I&M KPCo Year Ended December 31, 2001 (in thousands) Lease Payments on Operating Leases $296,000 $76,262 $ 6,142 $5,948 $ 7,063 $104,574 $1,191 Amortization of Capital Leases 85,000 281 12,099 - 7,206 17,933 2,740 Interest on Capital Leases 22,000 55 3,789 - 2,396 4,424 808 -------- ------- ------- ------ ------- -------- ------ Total Lease Rental Costs $403,000 $76,598 $22,030 $5,948 $16,665 $126,931 $4,739 ======== ======= ======= ====== ======= ======== ====== OPCo PSO SWEPCo WTU Year Ended December 31, 2001 (in thousands) Lease Payments on Operating Leases $63,913 $4,010 $2,277 $1,534 Amortization of Capital Leases 14,443 - - - Interest on Capital Leases 5,818 - - - ------- ------ ------ ------ Total Lease Rental Costs $84,174 $4,010 $2,277 $1,534 ======= ====== ====== ======
AEP AEGCo APCo CPL CSPCo I&M KPCo Year Ended December 31, 2000 (in thousands) Lease Payments on Operating Leases $237,000 $73,858 $ 7,128 $ - $ 7,683 $ 81,446 $1,978 Amortization of Capital Leases 121,000 281 13,900 - 7,776 26,341 3,931 Interest on Capital Leases 38,000 55 3,930 - 2,690 10,908 1,054 -------- ------- ------- ------- ------- -------- ------ Total Lease Rental Costs $396,000 $74,194 $24,958 $ - $18,149 $118,695 $6,963 ======== ======= ======= ======= ======= ======== ====== OPCo PSO SWEPCo WTU Year Ended December 31, 2000 (in thousands) Lease Payments on Operating Leases $51,981 $ - $ - $ - Amortization of Capital Leases 37,280 - - - Interest on Capital Leases 9,584 - - - ------- ------ ------ ------ Total Lease Rental Costs $98,845 $ - $ - $ - ======= ====== ====== ======
AEP AEGCo APCo CPL CSPCo I&M KPCo Year Ended December 31, 1999 (in thousands) Lease Payments on Operating Leases $247,000 $74,269 $ 5,647 $ - $ 5,687 $ 81,611 $ 199 Amortization of Capital Leases 97,000 364 13,749 - 7,427 11,320 4,299 Interest on Capital Leases 35,000 64 4,267 - 2,720 9,338 1,162 -------- ------- ------- ------ ------- -------- ------ Total Lease Rental Costs $379,000 $74,697 $23,663 $ - $15,834 $102,269 $5,660 ======== ======= ======= ====== ======= ======== ====== OPCo PSO SWEPCo WTU Year Ended December 31, 1999 (in thousands) Lease Payments on Operating Leases $ 60,026 $ - $ - $ - Amortization of Capital Leases 35,622 - - - Interest on Capital Leases 9,552 - - - -------- ------ ------ ------ Total Lease Rental Costs $105,200 $ - $ - $ - ======== ====== ====== ======
Property, plant and equipment under capital leases and related obligations recorded on the Consolidated Balance Sheets are as follows: AEP AEGCo APCo CSPCo I&M KPCo OPCo Year Ended December 31, 2001 (in thousands) Property, Plant and Equipment Under Capital Leases Production $ 40,000 $1,983 $ 2,712 $ 6,380 $ 4,826 $ 1,138 $ 22,477 Distribution 177,000 14,593 Other: Mining Assets and Other 722,000 129 82,292 $54,999 86,267 17,658 114,944 -------- ------ ------- ------- -------- ------- -------- Total Property, Plant and Equipment 939,000 2,112 85,004 61,379 105,686 18,796 137,421 Accumulated Amortization 256,000 1,801 38,745 26,044 43,768 9,213 57,429 -------- ------ ------- ------- -------- ------- -------- Net Property, Plant and Equipment Under Capital Leases $683,000 $ 311 $46,259 $35,335 $ 61,918 $ 9,583 $ 79,992 ======== ====== ======= ======= ======== ======= ======== Obligations Under Capital Leases: Noncurrent Liability $356,000 $ 76 $33,928 $27,052 $ 51,093 $ 6,742 $ 64,261 Liability Due Within One Year 95,000 235 12,357 7,835 10,840 2,841 16,405 -------- ------ ------- ------- -------- ------- -------- Total Obligations Under Capital Leases $451,000 $ 311 $46,285 $34,887 $ 61,933 $ 9,583 $ 80,666 ======== ====== ======= ======= ======== ======= ========
AEP AEGCo APCo CSPCo I&M KPCo OPCo Year Ended December 31, 2000 (in thousands) Property, Plant and Equipment Under Capital Leases Production $ 42,000 $2,017 $ 6,276 $ 2 $ 7,023 $ 1,730 $ 24,709 Distribution 151,000 14,595 Other: Nuclear Fuel (net of amortization) 90,000 89,872 Mining Assets and Other 619,000 177 93,437 $68,352 97,383 22,072 200,308 -------- ------ ------- ------- -------- ------- -------- Total Property, Plant and Equipment 902,000 2,194 99,713 68,354 208,873 23,802 225,017 Accumulated Amortization 288,000 1,603 36,553 25,422 45,700 9,618 108,436 -------- ------ ------- ------- -------- ------- -------- Net Property, Plant and Equipment Under Capital Leases $614,000 $ 591 $63,160 $42,932 $163,173 $14,184 $116,581 ======== ====== ======= ======= ======== ======= ======== Obligations Under Capital Leases: Noncurrent Liability $419,000 $ 358 $50,350 $35,199 $ 62,325 $11,091 $ 83,866 Liability Due Within One Year 195,000 233 12,810 7,733 100,848 3,093 32,715 -------- ------ ------- ------- -------- ------- -------- Total Obligations Under Capital Leases $614,000 $ 591 $63,160 $42,932 $163,173 $14,184 $116,581 ======== ====== ======= ======= ======== ======= ========
Properties under operating leases and related obligations are not included in the Consolidated Balance Sheets. CPL, PSO, SWEPCo and WTU do not lease property, plant and equipment under capital leases.
Future minimum lease payments consisted of the following at December 31, 2001: AEP AEGCo APCo CSPCo I&M KPCo OPCo Capital (in thousands) - ------- 2002 $ 96,000 $217 $13,718 $ 8,932 $11,759 $ 3,093 $ 18,516 2003 81,000 132 11,625 7,284 10,028 2,441 17,521 2004 63,000 20 9,371 6,111 7,947 1,824 14,701 2005 49,000 6 6,440 5,248 6,282 1,449 11,520 2006 42,000 1 4,690 3,903 5,335 891 10,305 Later Years 397,000 - 7,613 11,400 17,882 1,548 28,948 -------- ---- ------- ------- ------- ------- -------- Total Future Minimum Lease Payments 728,000 376 53,457 42,878 59,233 11,246 101,511 Less Estimated Interest Element 277,000 65 7,172 7,991 (2,700) 1,663 20,845 -------- ---- ------- ------- ------- ------- -------- Estimated Present Value of Future Minimum Lease Payments $451,000 $311 $46,285 $34,887 $61,933 $ 9,583 $ 80,666 ======== ==== ======= ======= ======= ======= ========
AEP AEGCo APCo CPL CSPCo I&M KPCo (in thousands) Noncancellable Operating Leases 2002 $ 286,000 $ 73,854 $ 3,193 $ 5,948 $ 2,104 $ 82,627 $ 717 2003 271,000 73,854 3,108 5,948 1,991 79,923 691 2004 255,000 73,854 2,402 5,948 1,623 77,104 571 2005 245,000 73,854 2,155 5,948 1,308 75,736 544 2006 243,000 73,854 1,887 5,948 1,279 75,595 398 Later Years 2,671,000 1,181,664 4,563 - 3,198 1,186,678 1,842 ---------- ---------- ------- ------- ------- ---------- ------ Total Future Minimum Lease Payments $3,971,000 $1,550,934 $17,308 $29,740 $11,503 $1,577,663 $4,763 ========== ========== ======= ======= ======= ========== ======
OPCo PSO SWEPCo WTU (in thousands) Noncancellable Operating Leases 2002 $ 62,945 $4,010 $ 2,277 $1,534 2003 62,914 4,010 2,277 1,534 2004 63,323 4,010 2,277 1,534 2005 62,836 4,010 2,277 1,534 2006 63,242 4,010 2,277 1,534 Later Years 244,069 - - - -------- ------ ------- ------ Total Future Minimum Lease Payments $559,329 $20,050 $11,385 $7,670 ======== ======= ======= ====== Operating leases include lease agreements with special purpose entities related to Rockport Plant Unit 2 and the Gavin Plant's flue gas desulfurization system (Gavin Scrubbers). The Rockport Plant lease resulted from a sale and leaseback transaction in 1989. The gain from the sale was deferred and is being amortized over the term of the lease which expires in 2022. The Gavin Scrubber lease expires in 2009. AEP has no ownership interest in the special purpose entities and does not guarantee their debt. The special purpose entities are not consolidated in AEP's financial statements in accordance with applicable accounting standards. As a result, neither the leased plant and equipment nor the debt of the special purpose entities is included on AEP's balance sheet. The future lease payment obligations to the special purpose entities are included in the above table of future minimum lease payments under noncancellable operating leases. 19. Lines of Credit and Sale of Receivables: The AEP System uses short-term debt, primarily commercial paper, to meet fluctuations in working capital requirements and other interim capital needs. AEP has established a money pool to coordinate short-term borrowings for certain subsidiaries, including AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU and also incurs borrowings outside the money pool for other subsidiaries. As of December 31, 2001, AEP had revolving credit facilities totaling $3.5 billion to support its commercial paper program. At December 31, 2001, AEP had $3.2 billion outstanding in short-term borrowings of which $2.9 billion was under these credit facilities. The maximum amount of such short-term borrowings outstanding during the year, which had a weighted average interest rate for the year of 4.95%, was $3.3 billion during March 2001. The registrant subsidiaries incurred interest expense for amounts borrowed from the AEP money pool as follows: Year Ended December 31, ------------------------- 2001 2000 1999 ---- ---- ---- (in millions) AEGCo 0.8 - - APCo 9.8 - - CPL 11.4 16.9 14.1 CSPCo 5.0 1.4 - I&M 13.1 0.8 - KPCo 2.3 - - OPCo 14.6 9.2 - PSO 6.3 7.5 2.0 SWEPCo 3.4 4.2 4.7 WTU 3.1 2.7 0.6 Interest income earned from amounts advanced to the AEP money pool by the registrant subsidiaries were: Year Ended December 31, ------------------------- 2001 2000 1999 ---- ---- ---- (in millions) APCo 1.7 - - CPL 0.1 - - CSPCo 0.8 1.1 - I&M 1.6 9.0 - KPCo 0.1 1.8 - OPCo 8.6 3.4 - SWEPCo 0.1 - 0.1 WTU - - 0.2 Outstanding short-term debt for AEP Consolidated consisted of: December 31, 2001 2000 ---- ---- (in millions) Balance Outstanding: Notes Payable $ 207 $ 193 Commercial paper 2,948 4,140 ------ ------ Total $3,155 $4,333 ====== ====== AEP Credit, which does not participate in the money pool, issued commercial paper on a stand-alone basis up to May 30, 2001. AEP Credit provides low-cost financing for utilities, including both AEP's electric utility operating companies and non-affiliates, through factoring receivables which arise primarily from the sale and delivery of electricity in the ordinary course of business. In January 2002 AEP Credit stopped purchasing accounts receivable from non-affiliated electric utility companies. On May 30, 2001, AEP Credit stopped issuing commercial paper and allowed its $2 billion unsecured revolving credit facility to mature. Funding needs were replaced on May 30, 2001 by a $1.5 billion variable funding note. The variable funding note was, in turn, replaced on December 31, 2001 when AEP Credit entered into a sale of receivables agreement with a group of banks and commercial paper conduits. Under the sale of receivables agreement, AEP Credit sells an interest in the receivables it acquired from its clients to the commercial paper conduits and banks and receives cash. This transaction constitutes a sale of receivables in accordance with SFAS 140 allowing the receivables to be taken off of AEP Credit's balance sheet. AEP has no ownership interest in the commercial paper conduits and does not consolidate these entities in accordance with GAAP. We continue to service the receivables. At December 31, 2001, the banks had a $1.2 billion commitment under the sale of receivables agreement to purchase receivables from AEP Credit of which $1 billion was outstanding. Of the $1 billion of receivables sold, $485 million respresented non-affiliate receivables. The commitment available under the sale of receivables agreement declines to $1.1 billion on January 31, 2002 and to $900 million on February 28, 2002, where it remains until the expiration of the commitment on May 30, 2002. AEP Credit maintains a retained interest in the receivables sold and this interest is pledged as collateral for the collection of the receivables sold. The fair value of the retained interest is based on book value due to the short-term nature of the accounts receivable less an allowance for anticipated uncollectible accounts. At year ended December 31, 2001, AEP Credit had: $ Millions Accounts Receivable Sold 1,045 Accounts Receivable Retained Interest Less Uncollectible Accounts and Pledged as Collateral 143 Deferred Revenue from Servicing Accounts Receivable 5 Loss on Sale of Accounts Receivable 8 Initial Variable Discount Rate 2.28% Retained Interest if 10% Adverse change in Uncollectible Accounts 142 Retained Interest if 20% Adverse change in Uncollectible Accounts 140 Historical loss and delinquency amount for the Customer Accounts Receivable managed portfolio for the year ended December 31, 2001. Face Value December 31, 2001 $ Millions Customer Accounts Receivable Retained $ 626 Miscellaneous Accounts Receivable Retained 1,365 Allowance for Uncollectible Accounts Retained (109) ------ Total Net Balance Sheet Accounts Receivable 1,882 Customer Accounts Receivable Securitized (Affiliate) 560 Customer Accounts Receivable Securitized (Non-Affiliate) 485 ------ Total Accounts Receivable managed $2,927 ====== Net Uncollectible Accounts Written off for the Year Ended December 31, 2001 87 -- Customer Accounts receivable retained and securitized for the domestic electric operating companies are managed by AEP Credit as a pool between affiliate and non-affiliate accounts receivable. Miscellaneous Account Receivable have been fully retained and not securitized. Delinquent Customer Accounts Receivable over 60 days old at December 31, 2001: (in millions) Affiliated $ 92 Non-Affiliated 17 ---- Total $109 ==== Under the factoring arrangement the registrant subsidiaries (excluding AEGCo) sell without recourse certain of their customer accounts receivable and accrued utility revenue balances to AEP Credit and are charged a fee based on AEP Credit financing costs, uncollectible accounts experience for each company's receivables and administrative costs. The costs of factoring customer accounts receivable is reported as an operating expense. At December 31, 2001 the amount of factored accounts receivable and accrued utility revenues for each registrant subsidiary was as follows: Company (in millions) - ------- APCo $ 61 CPL 89 CSPCo 106 I&M 95 KPCo 26 OPCo 100 PSO 43 SWEPCo 47 WTU 23 The fees paid by the registrant subsidiaries to AEP Credit for factoring customer accounts receivable were: Year Ended December 31, ------------------------- 2001 2000 1999 ---- ---- ---- (in millions) APCo $ 5.2 $- $- CPL 14.7 15.7 14.7 CSPCo 15.2 10.8 - I&M 8.5 6.8 - KPCo 2.7 1.9 - OPCo 12.8 8.4 - PSO 9.6 8.3 6.5 SWEPCo 7.4 9.2 9.3 WTU 3.8 4.0 3.5 20. Unaudited Quarterly Financial Information: The unaudited quarterly financial information for AEP Consolidated follows: 2001 Quarterly Periods Ended ------------------------------------------------------- March 31 June 30 Sept. 30 Dec. 31 ---------- ---------- ---------- ---------- (In Millions - Except Per Share Amounts) - ----------------------- Operating Revenues $14,165 $14,528 $18,385 $14,179 Operating Income 601 672 862 260 Income Before Extraordinary Items and Cumulative Effect 266 280 403 54 Net Income 266 232 421 52 Earnings per Share Before Extraordinary Items And Cumulative Effect* 0.83 0.87 1.25 0.17 Earnings per Share** 0.83 0.72 1.31 0.16 2000 Quarterly Periods Ended ------------------------------------------------------- March 31 June 30 Sept. 30 Dec. 31 ---------- ---------- ---------- ---------- (In Millions - Except Per Share Amounts) - ----------------------- Operating Revenues $6,117 $8,137 $11,608 $10,844 Operating Income 428 308 873 395 Income (Loss) Before Extraordinary Items and Cumulative Effect 140 (18) 403 (223) Net Income (Loss) 140 (9) 359 (223) Earnings (Loss) per Share Before Extraordinary Items and Cumulative Effect 0.43 (0.06) 1.25 (0.68) Earnings (Loss) per Share 0.43 (0.03) 1.11 (0.68) * Amounts for 2001 do not add to $3.11 earnings per share before extraordinary items and cumulative effect due to rounding. ** Amounts for 2001 do not add to $3.01 earnings per share due to rounding. The unaudited quarterly financial information for each AEP registrant subsidiary follows:
Quarterly Periods Ended AEGCo APCo CPL CSPCo I&M ----------------- ----- ---- --- ----- --- (in thousands) 2001 March 31 Operating Revenues $60,507 $1,974,127 $603,412 $1,125,573 $1,291,538 Operating Income 1,807 88,152 64,152 51,932 52,698 Income (Loss) Before Extraordinary Items 1,980 61,787 35,031 37,671 32,363 Net Income (Loss) 1,980 61,787 35,031 37,671 32,363 June 30 Operating Revenues $52,217 $1,849,304 $648,499 $1,109,095 $1,259,874 Operating Income 1,882 59,362 82,351 62,894 47,340 Income (Loss) Before Extraordinary Items 2,063 36,419 52,518 47,418 27,374 Net Income (Loss) 2,063 36,419 52,518 21,011 27,374 September 30 Operating Revenues $57,417 $2,017,159 $1,235,941 $1,297,704 $1,402,178 Operating Income 1,615 60,381 112,598 76,920 44,509 Income Before Extraordinary Items 2,051 30,317 83,702 65,318 25,064 Net Income 2,051 30,317 83,702 65,318 25,064 December 31 Operating Revenues $57,407 $1,158,840 $833,875 $767,491 $850,035 Operating Income 1,673 67,091 36,630 60,431 15,158 Income (Loss) Before Extraordinary Items 1,781 33,295 13,536 41,493 (9,013) Net Income (Loss) 1,781 33,295 11,027 37,876 (9,013)
Quarterly Periods Ended KPCo OPCo PSO SWEPCo WTU ----------------- ---- ---- --- ------ --- (in thousands) 2001 March 31 Operating Revenues $459,157 $1,699,665 $356,139 $425,689 $195,006 Operating Income 12,604 64,756 8,340 33,986 5,392 Income Before Extraordinary Items 7,075 53,397 (1,560) 19,869 891 Net Income 7,075 53,397 (1,560) 19,869 891 June 30 Operating Revenues $439,131 $1,627,177 $398,194 $434,795 $192,839 Operating Income 8,364 47,067 21,942 32,649 12,428 Income Before Extraordinary Items 2,742 32,094 11,921 17,784 6,133 Net Income 2,742 10,579 11,921 17,784 6,133 September 30 Operating Revenues $485,820 $1,819,792 $910,428 $1,028,742 $429,623 Operating Income 12,587 69,668 59,914 60,194 17,745 Income Before Extraordinary Items 5,312 51,378 51,069 46,357 14,067 Net Income 5,312 51,378 51,069 46,357 14,067 December 31 Operating Revenues $275,287 $1,115,768 $536,488 $685,222 $246,803 Operating Income 14,123 59,219 6,793 19,378 (2,175) Income (Loss) Before Extraordinary Items 6,436 28,924 (3,670) 5,357 (8,781) Net Income (Loss) 6,436 32,091 (3,670) 5,357 (8,781)
Quarterly Periods Ended AEGCo APCo CPL CSPCo I&M ----------------- ----- ---- --- ----- --- (in thousands) 2000 March 31 Operating Revenues $56,866 $1,021,678 $316,328 $633,305 $708,150 Operating Income 2,395 78,246 38,650 44,124 (15,251) Income Before Extraordinary Items 2,445 47,664 8,139 27,471 (36,553) Net Income 2,445 47,664 8,139 27,471 (36,553) June 30 Operating Revenues $56,928 $1,460,774 $437,911 $928,332 $1,011,706 Operating Income 1,746 58,208 95,717 50,798 (18,599) Income Before Extraordinary Items 1,653 30,240 67,553 35,335 (39,181) Net Income 1,653 39,178 67,553 35,335 (39,181) September 30 Operating Revenues $55,658 $1,538,340 $795,794 $960,837 $1,060,654 Operating Income 2,209 65,750 120,653 83,562 36,056 Income Before Extraordinary Items 1,972 36,112 89,974 65,542 15,190 Net Income 1,972 36,112 89,974 40,306 15,190 December 31 Operating Revenues $59,064 $1,066,516 $799,470 $643,141 $ 761,574 Operating Income 2,074 (1,050) 52,078 17,393 (36,908) Income (Loss) Before Extraordinary Items 1,914 (49,110) 23,901 (8,146) (71,488) Net Income (Loss) 1,914 (49,110) 23,901 (8,146) (71,488)
Quarterly Periods Ended KPCo OPCo PSO SWEPCo WTU ----------------- ---- ---- --- ------ --- (in thousands) 2000 March 31 Operating Revenues $231,454 $1,047,837 $161,329 $207,756 $ 93,335 Operating Income 15,557 65,113 10,860 22,731 9,781 Income Before Extraordinary Items 8,052 46,216 1,165 7,663 3,833 Net Income 8,052 46,216 1,165 7,663 3,833 June 30 Operating Revenues $342,660 $1,436,330 $209,172 $272,409 $130,742 Operating Income 9,456 79,968 24,502 33,296 16,938 Income Before Extraordinary Items 2,449 58,233 14,700 18,786 8,070 Net Income 2,449 58,233 14,700 18,786 8,070 September 30 Operating Revenues $359,296 $1,484,663 $555,236 $573,891 $249,330 Operating Income 13,790 96,652 56,437 61,312 16,565 Income Before Extraordinary Items 6,761 77,061 54,329 47,537 10,670 Net Income 6,761 58,185 54,329 47,537 10,670 December 31 Operating Revenues $243,457 $1,023,270 $504,282 $628,670 $286,155 Operating Income 10,935 (14,906) 4,870 10,939 9,057 Income (Loss) Before Extraordinary Items 3,501 (78,897) (3,531) (1,314) 4,877 Net Income (Loss) 3,501 (78,897) (3,531) (1,314) 4,877
Earnings for the fourth quarter 2001 increased $275 million from the prior year primarily due to the effect of charges recorded in 2000 from a ruling by the IRS disallowing interest deductions from AEP's COLI program and a write down for the proposed sale of Yorkshire. Fourth quarter 2001 earnings were also favorably impacted by the return to service in December 2000 of Unit 1 of the Cook Plant after an extended outage and the receipt of a contract cancellation fee from a non-affiliated factoring client of AEP Credit. 21. Trust Preferred Securities: The following Trust Preferred Securities issued by the wholly-owned statutory business trusts of CPL, PSO and SWEPCo were outstanding at December 31, 2001 and December 31, 2000. They are classified on the balance sheets as Certain Subsidiaries Obligated, Mandatorily Redeemable Preferred Securities of Subsidiary Trusts Holding Solely Junior Subordinated Debentures of Such Subsidiaries. The Junior Subordinated Debentures mature on April 30, 2037. CPL reacquired 490,000 and 60,000 trust preferred units during 2001 and 2000, respectively.
Units issued/ Outstanding Description of At 12/31/01 Underlying ----------- Business Trust Security Amount at December 31, Debentures of Registrant - -------------- -------- ---------------------- ------------------------ 2001 2000 (in millions) CPL Capital I 8.00%, Series A 5,450,000 $136 $149 CPL, $141 million, 8.00%, Series A PSO Capital I 8.00%, Series A 3,000,000 75 75 PSO, $77 million, 8.00%, Series A SWEPCo Capital I 7.875%, Series A 4,400,000 110 110 SWEPCO, $113 million, ---------- --- --- 12,850,000 $321 $334 7.875%, Series A ========== ==== ====
Each of the business trusts is treated as a subsidiary of its parent company. The only assets of the business trusts are the subordinated debentures issued by their parent company as specified above. In addition to the obligations under their subordinated debentures, each of the parent companies has also agreed to a security obligation which represents a full and unconditional guarantee of its capital trust obligation. 22. Minority Interest in Finance Subsidiary: In August 2001, AEP formed Caddis Partners, LLC (Caddis), a consolidated subsidiary, and sold a non-controlling preferred member interest in Caddis to an unconsolidated special purpose entity (Steelhead) for $750 million. Under the provisions of the Caddis formation agreements, the preferred member interest receives quarterly a preferred return equal to an adjusted floating reference rate (4.413% at December 31, 2001). The $750 million received replaces interim funding used to acquire Houston Pipe Line Company in June 2001. The preferred interest is supported by natural gas pipeline assets and $321.4 million of preferred stock issued by an AEP subsidiary to the AEP affiliate which has the managing member interest in Caddis. Such preferred stock is convertible into common stock of AEP upon the occurrence of certain events. AEP can elect not to have the transaction supported by such preferred stock if the preferred interest were reduced by $225 million. In addition, Caddis has the right to redeem the preferred member interest at any time. The initial period of the preferred interest is through August 2006. At the end of the initial period, Caddis will either reset the preferred rate, re-market the preferred member interests to new investors, redeem the preferred member interests, in whole or in part including accrued return, or liquidate in accordance with the provisions of applicable agreements. Steelhead has the right to terminate the transaction and liquidate Caddis upon the occurrence of certain events including a default in the payment of the preferred return. Steelhead's rights include: forcing a liquidation of Caddis and acting as the liquidator, and requiring the conversion of the $321.4 million of AEP subsidiary preferred stock into AEP common stock. If the preferred member interest exercised its rights to liquidate under these conditions, then AEP would evaluate whether to refinance at that time or relinquish the assets that support the preferred member interest. Liquidation of the preferred interest or of Caddis could impact AEP's liquidity. Caddis and the AEP subsidiary which acts as its managing member are each a limited liability company, with a separate existence and identity from its members, and the assets of each are separate and legally distinct from AEP. The results of operations, cash flows and financial position of Caddis and such managing member are consolidated with AEP for financial reporting purposes. The preferred member interest and payments of the preferred return are reported on AEP's income statement and balance sheet as Minority Interest in Finance Subsidiary. 23. Jointly Owned Electric Utility Plant: CPL, CSPCo, PSO, SWEPCo and WTU have generating units that are jointly owned with unaffiliated companies. Each of the participating companies is obligated to pay its share of the costs of any such jointly owned facilities in the same proportion as its ownership interest. Each AEP registrant subsidiary's proportionate share of the operating costs associated with such facilities is included in its statements of income and the investments are reflected in its balance sheets under utility plant as follows:
Company's Share December 31, 2001 2000 -------------------------- --------------------------- Percent Utility Construction Utility Construction of Plant Work Plant Work Ownership in Service in Progress in Service in Progress --------- ------------ ------------- ------------ ------------ (in thousands) (in thousands) CPL: Oklaunion Generating Station (Unit No. 1) 7.8 $ 37,728 $ 318 $ 37,236 $ 395 South Texas Project Generating Station (Units No. 1 and 2) 25.2 2,360,452 41,571 2,373,575 19,292 ---------- ------- ---------- ------- $2,398,180 $41,889 $2,410,811 $19,687 ========== ======= ========== ======== CSP: W.C. Beckjord Generating Station (Unit No. 6) 12.5 $ 14,292 $ 884 $ 14,108 $ 178 Conesville Generating Station (Unit No. 4) 43.5 81,697 494 80,103 261 J.M. Stuart Generating Station 26.0 193,760 27,758 191,875 10,086 Wm. H. Zimmer Generating Station 25.4 704,951 2,634 706,549 5,265 Transmission (a) 61,476 91 61,820 451 ---------- ------- ---------- ------- $1,056,176 $31,861 $1,054,455 $16,241 ========== ======= ========== ======= PSO: Oklaunion Generating Station (Unit No. 1) 15.6 $ 82,646 $ 634 $ 81,185 $ 817 ========== ======= ========== ======== SWEPCo: Dolet Hills Generating Station (Unit No. 1) 40.2 $ 234,747 $ 675 $ 231,442 $ 1,984 Flint Creek Generating Station (Unit No. 1) 50.0 83,953 213 82,899 852 Pirkey Generating Station (Unit No. 1) 85.9 439,430 10,577 437,069 435 ---------- ------- ---------- ------- $ 758,130 $11,465 $ 751,410 $ 3,271 ========== ======= ========== ======== WTU: Oklaunion Generating Station (Unit No. 1) 54.7 $ 279,419 $ 1,651 $ 277,624 $ 3,295 ========== ======= ========== =======
(a) Varying percentages of ownership. The accumulated depreciation with respect to each AEP registrant subsidiary's share of jointly owned facilities is shown below: December 31, 2001 2000 ---- ---- (in thousands) CPL $863,130 $834,722 CSPCo 410,756 389,558 PSO 35,653 33,669 SWEPCo 392,728 367,558 WTU 100,430 98,045 24. Related Party Transactions AEP System Power Pool APCo, CSPCo, I&M, KPCo 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 their 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, KPCo 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. As part of AEP's restructuring settlement agreement filed with FERC, CSPCo and OPCo would no longer be parties to the Interconnection agreement and certain other modifications to its terms would also be made. Power marketing and trading transactions (trading activities) are conducted by the AEP Power Pool and shared among the parties under the Interconnection Agreement. Trading activities involve the purchase and sale of electricity under physical forward contracts at fixed and variable prices and the trading of electricity contracts including exchange traded futures and options and over-the-counter options and swaps. The majority of these transactions represent physical forward contracts in the AEP System's traditional marketing area and are typically settled by entering into offsetting contracts. The regulated physical forward contracts are recorded on a gross basis in the month when the contract settles. In addition, the AEP Power Pool enters into transactions for the purchase and sale of electricity options, futures and swaps, and for the forward purchase and sale of electricity outside of the AEP System's traditional marketing area. CPL, PSO, SWEPCo, WTU and AEP Service Corporation are parties to a Restated and Amended Operating Agreement originally dated as of January 1, 1997 (CSW Operating Agreement). The CSW Operating Agreement requires the operating companies of the west zone to maintain specified annual planning reserve margins and requires the subsidiaries that have capacity in excess of the required margins to make such capacity available for sale to other AEP subsidiaries as capacity commitments. The CSW Operating Agreement also delegates to AEP Service Corporation the authority to coordinate the acquisition, disposition, planning, design and construction of generating units and to supervise the operation and maintenance of a central control center. The CSW Operating Agreement has been accepted for filing and allowed to become effective by FERC. AEP's System Integration Agreement provides for the integration and coordination of AEP's east and west zone operating subsidiaries, joint dispatch of generation within the AEP System, and the distribution, between the two operating zones, of costs and benefits associated with the System's generating plants. It is designed to function as an umbrella agreement in addition to the AEP Interconnection Agreement and the CSW Operating Agreement, each of which will continue to control the distribution of costs and benefits within each zone.
The following table shows the revenues derived from sales to the Pools and direct sales to affiliates for years ended December 31, 2001, 2000 and 1999: APCo CSPCo I&M KPCo OPCo AEGCo Related Party Revenues (in thousands) 2001 Sales to East System Pool $ 91,977 $44,185 $239,277 $34,735 $431,637 $ - Sales to West System Pool 24,892 13,971 15,596 6,117 19,797 - Direct Sales To East Affiliates 54,777 - - - 55,450 227,338 Direct Sales To West Affiliates (3,133) (1,705) (1,905) (744) (2,590) - Other 2,772 11,060 2,071 2,258 7,072 - -------- ------- -------- ------- -------- -------- Total Revenues $171,285 $67,511 $255,039 $42,366 $511,366 $227,338 ======== ======= ======== ======= ======== ======== 2000 Sales to East System Pool $ 81,013 $36,884 $200,474 $36,554 $502,140 $ - Sales to West System Pool 7,697 4,095 4,614 1,829 6,356 - Direct Sales To East Affiliates 59,106 - - - 66,487 227,983 Direct Sales To West Affiliates 4,092 2,262 2,510 972 3,421 - Other 2,770 6,124 2,710 2,466 4,043 - -------- ------- -------- ------- -------- -------- Total Revenues $154,678 $49,365 $210,308 $41,821 $582,447 $227,983 ======== ======= ======== ======= ======== ======== 1999 Sales to East System Pool $ 41,869 $15,136 $50,624 $43,157 $337,699 $ - Direct Sales To East Affiliates 57,201 - - - 50,968 152,559 Other 1,162 4,582 345 1,145 825 - -------- ------- -------- ------- -------- -------- Total Revenues $100,232 $19,718 $50,969 $44,302 $389,492 $152,559 ======== ======= ======= ======= ======== ========
CPL PSO SWEPCo WTU Related Party Revenues (in thousands) 2001 Sales to East System Pool $ - $ 4 $ - $ - Sales to West System Pool 19,865 3,317 8,073 322 Direct Sales To East Affiliates 3,697 2,833 3,238 1,228 Direct Sales To West Affiliates 12,617 30,668 67,930 9,350 Other 5,583 (51) (3) 7,781 ------- ------- ------- ------- Total Revenues $41,762 $36,771 $79,238 $18,681 ======= ======= ======= ======= 2000 Sales to East System Pool $ - $ - $ - $ - Sales to West System Pool 23,421 7,323 5,546 194 Direct Sales To East Affiliates (3,348) (1,990) (3,008) (1,116) Direct Sales To West Affiliates 12,516 21,995 62,178 7,645 Other 5,163 (12,680) (1,592) 11,931 ------- ------- ------- ------- Total Revenues $37,752 $14,648 $63,124 $18,654 ======= ======= ======= ======= 1999 Sales to West System Pool $ 6,124 $ 3,097 $ 4,527 $ 401 Direct Sales To West Affiliates 7,470 7,968 49,542 2,576 Other 14,177 2,652 48 11,790 ------- ------- ------- ------- Total Revenues $27,771 $13,717 $54,117 $14,767 ======= ======= ======= =======
The following table shows the purchased power expense incurred from purchases from the Pools and affiliates for the years ended December 31, 2001, 2000, and 1999: APCo CSPCo I&M KPCo OPCo Related Party Purchases (in thousands) 2001 Purchases from East System Pool $346,582 $292,034 $ 79,030 $ 61,816 $62,350 Purchases from West System Pool 296 165 185 72 235 Direct Purchases from East Affiliates - - 159,022 68,316 - Direct Purchases from West Affiliates - - - - - -------- -------- -------- -------- ------- Total Purchases $346,878 $292,199 $238,237 $130,204 $62,585 ======== ======== ======== ======== ======= 2000 Purchases from East System Pool $355,305 $287,482 $106,644 $ 58,150 $50,339 Purchases from West System Pool 455 260 285 108 390 Direct Purchases from East Affiliates - - 158,537 69,446 - Direct Purchases from West Affiliates 14 8 9 3 12 -------- -------- -------- -------- ------- Total Purchases $355,774 $287,750 $265,475 $127,707 $50,741 ======== ======== ======== ======== ======= 1999 Purchases from East System Pool $130,991 $199,574 $112,350 $19,502 $ 20,864 Direct Purchases from East Affiliates - - 88,022 64,498 - -------- -------- -------- ------- --------- Total Purchases $130,991 $199,574 $200,372 $84,000 $ 20,864 ======== ======== ======== ======= ========
CPL PSO SWEPCo WTU Related Party Purchases (in thousands) 2001 Purchases from East System Pool $ - $ 1,327 $ - $ 4 Purchases from West System Pool 415 5,877 3,810 11,689 Direct Purchases from East Affiliates 12,657 37,445 27,744 4,614 Direct Purchases from West Affiliates 45,569 34,603 9,696 40,349 ------- ------- ------- ------- Total Purchases $58,641 $79,252 $41,250 $56,656 ======= ======= ======= ======= 2000 Purchases from East System Pool $ - $20,100 $ - $ - Purchases from West System Pool 1,696 5,386 4,379 18,444 Direct Purchases from East Affiliates 251 2,117 695 71 Direct Purchases from West Affiliates 30,644 33,185 8,264 39,258 ------- ------- ------- ------- Total Purchases $32,591 $60,788 $13,338 $57,773 ======= ======= ======= ======= 1999 Purchases from West System Pool $ 895 $ 6,992 $1,295 $ 7,266 Direct Purchases from West Affiliates 15,778 27,627 6,256 19,325 ------- ------- ------ ------- Total Purchases $16,673 $34,619 $7,551 $26,591 ======= ======= ====== =======
The above summarized related party revenues and expenses are reported in their entirely, without elimination, and are presented as operating revenues affiliated and purchased power affiliated on the income statement of each AEP Power Pool member. Since all of the above pool members are included in AEP's consolidated results, the above summarized related party transactions are eliminated in total in AEP's consolidated revenues and expenses. AEP System Transmission Pool APCo, CSPCo, I&M, KPCo 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." The following table shows the net (credits) or charges allocated among the parties to the Transmission Agreement during the years ended December 31, 1998, 1999 and 2000: 1999 2000 2001 ---- ---- ---- (in thousands) APCo $ (8,300) $ (3,400) $ (3,100) CSPCo 39,000 38,300 40,200 I&M (43,900) (43,800) (41,300) KPCo (4,300) (6,000) (4,600) OPCo 17,500 14,900 8,800 CPL, PSO, SWEPCo, WTU and AEP Service Corporation are parties to a Transmission Coordination Agreement originally dated as of January 1, 1997 (TCA). The TCA established a coordinating committee, which is charged with the responsibility of overseeing the coordinated planning of the transmission facilities of the west zone operating subsidiaries, including the performance of transmission planning studies, the interaction of such subsidiaries with independent system operators (ISO) and other regional bodies interested in transmission planning and compliance with the terms of the Open Access Transmission Tariff (OATT) filed with the FERC and the rules of the FERC relating to such tariff. Under the TCA, the west zone operating subsidiaries have delegated to AEP Service Corporation the responsibility of monitoring the reliability of their transmission systems and administering the OATT on their behalf. The TCA also provides for the allocation among the west zone operating subsidiaries of revenues collected for transmission and ancillary services provided under the OATT. AEP's System Transmission Integration Agreement provides for the integration and coordination of the planning, operation and maintenance of the transmission facilities of AEP's east and west zone operating subsidiaries. Like the System Integration Agreement, the System Transmission Integration Agreement functions as an umbrella agreement in addition to the AEP Transmission Agreement and the Transmission Coordination Agreement. The System Transmission Integration Agreement contains two service schedules that govern: o The allocation of transmission costs and revenues. o The allocation of third-party transmission costs and revenues and System dispatch costs. The Transmission Integration Agreement anticipates that additional service schedules may be added as circumstances warrant. Unit Power Agreements and Other A unit power agreement between AEGCo and I&M (the I&M Power Agreement) provides for the sale by AEGCo to I&M of all the power (and the energy associated therewith) available to AEGCo at the Rockport Plant. I&M is obligated, whether or not power is available from AEGCo, to pay as a demand charge for the right to receive such power (and as an energy charge for any associated energy taken by I&M) such amounts, as when added to amounts received by AEGCo from any other sources, will be at least sufficient to enable AEGCo to pay all its operating and other expenses, including a rate of return on the common equity of AEGCo as approved by FERC, currently 12.16%. The I&M Power Agreement will continue in effect until the expiration of the lease term of Unit 2 of the Rockport Plant unless extended in specified circumstances. Pursuant to an assignment between I&M and KPCo, and a unit power agreement between KPCo and AEGCo, AEGCo sells KPCo 30% of the power (and the energy associated therewith) available to AEGCo from both units of the Rockport Plant. KPCo 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 KPCo unit power agreement expires on December 31, 2004. APCo and OPCo, jointly own two power plants. The costs of operating these facilities are apportioned between the owners based on ownership interests. Each company's share of these costs is included in the appropriate expense accounts on each company's consolidated statements of income. Each company's investment in these plants is included in electric utility plant on its consolidated balance sheets. I&M provides barging services to AEGCo, APCo and OPCo. I&M records revenues from barging services as nonoperating income. AEGCo, APCo and OPCo record costs paid to I&M for barging services as fuel expense. The amount of affiliated revenues and affiliated expenses were: Year Ended December 31, 2001 2000 1999 ---- ---- ---- Company (in millions) I&M - revenues $30.2 $23.5 $28.1 AEGCo - expense 8.5 8.8 8.5 APCo - expense 11.5 7.8 10.5 OPCo - expense 10.2 6.9 9.1 American Electric Power Service Corporation (AEPSC) provides certain managerial and professional services to AEP System companies. The costs of the services are billed to its affiliated companies by AEPSC on a direct-charge basis, whenever possible, and on reasonable bases of proration for shared services. The billings for services are made at cost and include no compensation for the use of equity capital, which is furnished to AEPSC by AEP Co., Inc. Billings from AEPSC are capitalized or expensed depending on the nature of the services rendered. AEPSC and its billings are subject to the regulation of the SEC under the 1935 Act. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION, CONTINGENCIES AND OTHER MATTERS The following is a combined presentation of management's discussion and analysis of financial condition, contingencies and other matters for AEP and certain of its registrant subsidiaries. Management's discussion and analysis of results of operations for AEP and each of its subsidiary registrants is presented with their financial statements earlier in this document. The following is a list of sections of management's discussion and analysis of financial condition, contingencies and other matters and the registrant to which they apply: Financial Condition AEP, APCo, CPL, I&M, OPCo, SWEPCo Market Risks AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU Industry Restructuring AEP, APCo, CPL, CSPCo, I&M, OPCo, PSO, SWEPCo, WTU Litigation AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU Environmental Concerns and Issues AEP, APCo, CPL, CSPCo, I&M, OPCo, SWEPCo Other Matters AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU Financial Condition - Affecting AEP, APCo, CPL, I&M, OPCo and SWEPCo We measure our financial condition by the strength of the balance sheet and the liquidity provided by cash flows and earnings. Balance sheet capitalization ratios and cash flow ratios are principal determinants of our credit quality. Year-end ratings of AEP's subsidiaries' first mortgage bonds are listed in the following table: Company Moody's S&P Fitch APCo A3 A A- CPL A3 A- A CSPCo A3 A- A I&M Baa1 A- BBB+ KPCo Baa1 A- BBB+ OPCo A3 A- A- PSO A1 A A+ SWEPCO A1 A A+ WTU A2 A- A The ratings at the end of the year for senior unsecured debt are listed in the following table: Company Moody's S&P Fitch AEP Baa1 BBB+ BBB+ AEP Resources* Baa1 BBB+ BBB+ APCo Baa1 BBB+ BBB+ CPL Baa1 BBB+ A- CSPCo A3 BBB+ A- I&M Baa2 BBB+ BBB KPCo Baa2 BBB+ BBB OPCo A3 BBB+ BBB+ PSO A2 BBB+ A SWEPCO A2 BBB+ A o The rating is for a series of senior notes issued with a Support Agreement from AEP. The ratings are presently stable. AEP's commercial paper program has short-term ratings of A2 and P2 by Moody's and Standard and Poor's, respectively. AEP's common equity to total capitalization declined to 33% in 2001 from 34% in 2000. Total capitalization includes long-term debt due within one year, minority interests and short-term debt. Preferred stock at 1% remained unchanged. Long-term debt increased from 47% to 50% while short-term debt decreased from 18% to 13% and minority interest in finance subsidiary increased to 3%. In 2001 and 2000, AEP did not issue any shares of common stock to meet the requirements of the Dividend Reinvestment and Direct Stock Purchase Plan and the Employee Savings Plan. We plan to strengthen the balance sheet in 2002 by issuing AEP common stock and mandatory convertible preferred stock and using the proceeds from asset sales to reduce debt. The issuance of common stock has the potential to dilute future earnings per share but will enhance the equity to capitalization ratio. Rating agencies have become more focused in their evaluation of credit quality as a result of the Enron bankruptcy. They are focusing especially on the composition of the balance sheet (off-balance sheet leases, debt and special purpose financing structures), the cash liquidity profile and the impact of credit quality downgrades on financing transactions. We have worked closely with the agencies to provide them with all the information they need, but we are unable to predict what actions, if any, they may take regarding our current ratings. During 2001 AEP's cash flow from operations was $2.9 billion, including $971 million from net income and $1.5 billion from depreciation, amortization and deferred taxes. Capital expenditures including acquisitions were $4 billion and dividends on common stock were $773 million. Cash from operations less dividends on common stock financed 52% of capital expenditures. During 2001, the proceeds of AEP's $1.25 billion global notes issuance and proceeds from the sale of a UK distribution company and two generating plants provided cash to purchase assets, fund construction, retire debt and pay dividends. Major construction expenditures include amounts for a wind generating facility and emission control technology on several coal-fired generating units (see discussion in Note 8). Asset purchases include HPL, coal mines, a barge line, a wind generating facility and two coal-fired generating plants in the UK. These acquisitions accounted for the increase in total debt in 2001. During the third quarter of 2001, permanent financing was completed for the acquisition of HPL by the issuance of a minority interest which provided $735 million net of expenses (See Note 22 for discussion of the terms). HPL's permanent financing increased funds available for other corporate purposes. Long-term financings for the other acquisitions will be announced as arranged. Long-term funding arrangements for specific assets are often complex and typically not completed until after the acquisition. Earnings for 2001 resulted in a dividend payout ratio of 80%, a considerable improvement over the 289% payout ratio in 2000. The abnormally high ratio in 2000 was the result of the adverse impact on 2000 earnings from the Cook Plant extended outage and related restart expenditures, merger costs and the write-off related to COLI and non-regulated subsidiaries. We expect continued improvement of the payout ratio as a result of earnings growth in 2002. Cash from operations and short-term borrowings provide working capital and meet other short-term cash needs. We generally use short-term borrowings to fund property acquisitions and construction until long-term funding mechanisms are arranged. Some acquisitions of existing business entities include the assumption of their outstanding debt and certain liabilities. Sources of long-term funding include issuance of AEP common stock, minority interest or long-term debt and sale-leaseback or leasing arrange-ments. The domestic electric subsidiaries generally issue short-term debt to provide for interim financing of capital expenditures that exceed internally generated funds and periodically reduce their outstanding short-term debt through issuances of long-term debt and additional capital contributions from their parent company. We operate a money pool and sell accounts receivables to provide liquidity for the domestic electric subsidiaries. Short-term borrowings in the U.S. are supported by two revolving credit agreements. At December 31, 2001, approximately $554 million remained available for short-term borrowings in the US. Subsidiaries that trade energy commodities in Europe have a separate multicurrency revolving loan and letters of credit agreement allowing them to borrow up to 150 million Euros of which 42 million Euros were available on December 31, 2001. In February 2002 they also originated a temporary second line of 50 million Euros for three months which is expected to be replaced with a 150 million Euro line, providing for a total of 300 million Euros. SEEBOARD, Nanyang and Citipower which operate in the UK, China and Australia, respectively, each have independent financing arrangements which provide for borrowing in the local currency. SEEBOARD has a 320 million pound revolving credit agreement it uses for short-term funding purposes. At December 31, 2001, SEEBOARD had 117 million pounds available. Our revolving credit agreements include covenants that require us to maintain specified financial ratios and describe non-performance of certain actions as events of default. At December 31, 2001 we complied with the covenants of these agreements. In general, a default in excess of $50 million under one agreement is considered a default under the other agreements. In the case of a default on payments under these agreements, all amounts outstanding would be immediately payable. The contractual obligations of AEP include amounts reported on the balance sheet and other obligations disclosed in our footnotes. The following table summarizes AEP's contractual cash obligations at December 31, 2001:
Payments Due by Period (in millions) Contractual Cash Obligations Less Than 1 year 2-3 years 4-5 years After 5 years Total - ---------------------------- ---------------- --------- --------- ------------- ----- Long-term Debt $2,300 $2,988 $2,559 $ 4,246 $12,093 Short-term Debt 3,155 - - - 3,155 Trust Preferred Securities - - - 321 321 Minority Interest In Finance Subsidiary (a) - - 750 - 750 Preferred Stock Subject to Mandatory Redemption - 24 4 67 95 Capital Lease Obligations 96 144 91 397 728 Unconditional Purchase Obligations (b) 317 1,658 1,299 3,559 6,833 Noncancellable Operating Leases 286 526 488 2,671 3,971 Other Long-term Obligations (c) 31 30 - - 61 -- -- ---- ---- -- Total Contractual Cash Obligations $6,185 $5,370 $5,191 $11,261 $28,007 ====== ====== ====== ======= =======
(a) The initial period of the preferred interest is through August 2006. At the end of the initial period, the preferred rate may be reset, the preferred member interests may be re-marketed to new investors, the preferred member interests may be redeemed, in whole or in part including accrued return, or the preferred member interest may be liquidated. (b) Represents contractual obligations to purchase coal and natural gas as fuel for electric generation along with related transportation of the fuel. (c) Represents contractual obligations to loan funds to a joint venture accounted for under the equity method. For the subsidiary registrants, please see each registrant's schedules of capitalization and long-term debt included with each registrants' financial statements in sections B through J for the timing of debt payment obligations and the lease footnote (Note 18) in section L for the timing of rent payments. Special purpose entities have been employed for some of the contractual cash obligations reported in the above table. The lease of Rockport Plant Unit 2 and the Gavin Plant's flue gas desulfurization system (Gavin Scrubbers), the permanent financing of HPL and the sale of accounts receivable use special purpose entities. Neither AEP nor any AEP related parties has an ownership interest in the special purpose entities. AEP does not guarantee the debt of these entities. These special purpose entities are not consolidated in AEP's financial statements in accordance with generally accepted accounting principles. As a result, neither the assets nor the debt of the special purpose entities is included on AEP's balance sheet. The future cash obligations payable to the special purpose entities are included in the above table In addition to the amounts disclosed in the contractual cash obligations table above, AEP and certain subsidiaries make commitments in the normal course of business. These commitments include standby letters of credit, guarantees for the payment of obligation performance bonds, and other commitments. AEP's commitments outstanding at December 31, 2001 under these agreements are summarized in the table below:
Amount of Commitment Expiration Per Period (in millions) Other Commercial Commitments Less Than 1 year 2-3 years 4-5 years After 5 years Total - ---------------------------- ---------------- --------- --------- ------------- ----- Standby Letters of Credit $ 101 $ 53 - $36 $ 190 Guarantees 815 161 - 15 991 Construction of Generating and Transmission Facilities for Third Parties (a) 168 540 - - 708 Other Commercial Commitments (b) 6 45 40 24 115 ------ ---- --- --- ------ Total Commercial Commitments $1,090 $799 $40 $75 $2,004 ====== ==== === === ======
(a) As construction agent for third party owners of power plants and transmission facilities, the Company has committed by contract terms to complete construction by dates specified in the contracts. Should the Company default on these obligations, financial payments could be up to 100% of contract value (amount shown in table) or other remedies required by contract terms. (b) Represents estimated future payments for power to be generated at facilities under construction. With the exceptions of SWEPCo's guarantanee of an unaffiliated mine operator's obligations (payable upon their default) of $111 million at December 31, 2001, and OPCo's obligations under a power purchase agreement of $6 million in 2002 and $16 million each year in 2003 through 2005, the obligations in the above table are commitments of AEP and its non-registrant subsidiaries. AEP, through certain subsidiaries, has entered into agreements with an unrelated, unconsolidated special purpose entity (SPE) to develop, construct, finance and lease a power generation facility. The SPE will own the power generation facility and lease it to an AEP consolidated subsidiary after construction is completed. The lease will be accounted for as an operating lease with the payment obligations included in the lease footnote. Payments under the operating lease are expected to commence in the first quarter of 2004. AEP will in turn sublease the facility to an unrelated industrial company which will both use the energy produced by the facility and sell excess energy. Another affiliate of AEP has agreed to purchase the excess energy from the subleasee for resale. The SPE has an aggregate financing commitment from equity and debt participants (Investors) of $427 million. AEP, in its role as construction agent for the SPE, is responsible for completing construction by December 31, 2003. In the event the project is terminated before completion of construction, AEP has the option to either purchase the project for 100% of project costs or terminate the project and make a payment to the Lessor for 89.9% of project costs. The term of the operating lease between the SPE and the AEP subsidiary is five years with multiple extension options. If all extension options are exercised the total term of the lease would be 30 years. AEP's lease payments to the SPE are sufficient to provide a return to the Investors. At the end of the first five-year lease term or any extension, AEP may renew the lease at fair market value subject to Investor approval; purchase the facility at its original construction cost; or sell the facility, on behalf of the SPE, to an independent third party. If the project is sold and the proceeds from the sale are insufficient to repay the Investors, AEP may be required to make a payment to the Lessor of up to 85% of the project's cost. AEP has guaranteed a portion of the obligations of its subsidiaries to the SPE during the construction and post-construction periods. As of December 31, 2001, project costs subject to these agreements totaled $168 million, and total costs for the completed facility are expected to be approximately $450 million. Since the lease is accounted for as an operating lease for financial accounting purposes, neither the facility nor the related obligations are reported on AEP's balance sheets. The lease is a variable rate obligation indexed to three-month LIBOR. Consequently as market interest rates increase, the payments under this operating lease will also increase. Annual payments of approximately $12 million represent future minimum payments under the first five-year lease term calculated using the indexed LIBOR rate of 2.85% at December 31, 2001. The lease payments and the guarantee of construction commitments are included in the Other Commercial Commitments table above. OPCo has entered into a purchased power agreement to purchase electricity pro-duced by an unaffiliated entity's three-unit natural gas fired plant that is under construction. The first unit is anticipated to be completed in October 2002 and the agree-ment will terminate 30 years after the third unit begins operation. Under the terms of the agreement OPCo has the option to run the plant until December 31, 2005 taking 100% of the power generated. For the remainder of the 30 year contract term, OPCo will pay the variable costs to generate the electricity it pur-chases which could be up to 20% of the plant's capacity. The estimated fixed pay-ments through December 2005 are $55 million and are included in the Other Commercial Commitments table shown above. Minority Interest in Finance Subsidiary In August 2001, AEP formed Caddis Partners, LLC (Caddis), a consolidated subsidiary, and sold a non-controlling pre-ferred member interest in Caddis to an unconsolidated special purpose entity (Steelhead) for $750 million. Under the provisions of the Caddis formation agree-ments, the preferred member interest receives quarterly a preferred return equal to an adjusted floating reference rate (4.413% at December 31, 2001). The $750 million received replaced interim funding used to acquire Houston Pipe Line Company in June 2001. The preferred interest is supported by natural gas pipeline assets and $321.4 million of preferred stock issued by an AEP subsidiary to the AEP affiliate which has the managing member interest in Caddis. Such preferred stock is convertible into common stock of AEP upon the occurrence of certain events. AEP can elect not to have the transaction supported by such preferred stock if the preferred interest were reduced by $225 million. In addition, Caddis has the right to redeem the preferred member interest at any time. The initial period of the preferred interest is through August 2006. At the end of the initial period, Caddis will either reset the preferred rate, re-market the preferred member interests to new investors, redeem the preferred member interests, in whole or in part including accrued return, or liquidate in accordance with the provisions of applicable agreements. The credit agreement between Caddis and the AEP subsidiary that acts as its managing member contains covenants that restrict incremental liens and indebtedness, asset sales, investments, acquisitions, and distributions. Financial covenants impose minimum financial ratios. At December 31, 2001, we satisfied all of the financial ratio requirements. In general, a default in excess of $50 million under another agreement is considered a default under this agreement. Steelhead has the right to terminate the transaction and liquidate Caddis upon the occurrence of certain events including a default in the payment of the preferred return. Steelhead's rights include: forcing a liquidation of Caddis and acting as the liquidator, and requiring the conversion of the $321.4 million of AEP subsidiary preferred stock into AEP common stock. If the preferred member interest exercised its rights to liquidate under these conditions, then AEP would evaluate whether to refinance at that time or relinquish the assets that support the preferred member interest. Liquidation of the preferred interest or of Caddis could impact AEP's liquidity. Caddis and the AEP subsidiary which acts as its managing member are each a limited liability company, with a separate existence and identity from its members, and the assets of each are separate and legally distinct from AEP. The results of operations, cash flows and financial position of Caddis and such managing member are consolidated with AEP for financial reporting purposes. The preferred member interest and payments of the preferred return are reported on AEP's income statement and balance sheet as Minority Interest in Finance Subsidiary. Expenditures for domestic electric utility construction are estimated to be $4.6 billion for the next three years. Approximately 100% of those construction expenditures are expected to be financed by internally generated funds. Construction expenditures for the registrant subsidiaries for the next three years excluding AFUDC are: Construction Projected Expenditures Construction Financed with Expenditures Internal Funds (in millions) APCo $ 815.5 92% CPL 573.1 80% I&M 556.9 ALL OPCo 1,008.0 68% SWEPCo 321.4 92% In 1998 SEEBOARD's 80% owned subsidiary, SEEBOARD Powerlink, signed a 30-year contract for $1.6 billion to operate, maintain, finance and renew the high-voltage power distribution network of the London Underground transportation system. SEEBOARD Powerlink will be responsible for distributing high voltage electricity to supply 270 London Underground stations and 250 miles of the rail system's track. SEEBOARD's partners in Powerlink are an international electrical engineering group and an international cable and construction group. Financing Activity AEP issued $1.25 billion of global notes in May 2001 (with intermediate maturities). The proceeds were loaned to regulated and non-regulated subsidiaries. In 2001 CSPCo and OPCo, AEP's Ohio subsidiaries, reacquired $295.5 million and $175.6 million, respectively, of first mortgage bonds in preparation for corporate separation. AEP Credit purchases, without recourse, the accounts receivable of most of the domestic utility operating companies and certain non-affiliated electric utility companies. AEP Credit's financing for the purchase of receivables changed during 2001. Starting December 31, 2001, AEP Credit entered into a sale of receivables agreement. The agreement allows AEP Credit to sell certain receivables and receive cash meeting the requirements of SFAS 140 for the receivables to be removed from the balance sheet. The agreement expires in May 2002 and is expected to be renewed. At December 31, 2001, AEP Credit had $1.0 billion sold under this agreement of which $485 million are non-affiliated receivables. In January 2002, AEP Credit stopped purchasing accounts receivables from non-affiliated electric utility companies. In February 2002 CPL issued $797 million of securitization notes that were approved by the PUCT as part of Texas restructuring to help decrease rates and recover regulatory assets. The proceeds were used to reduce CPL's debt and equity. In 2002 AEP plans to continue restructuring its debt for corporate separation assuming receipt of all necessary regulatory approvals. Corporate separation will require the transfer of assets between legal entities. With corporate separation, a newly created holding company for the unregulated business is expected to issue all debt needed to fund the wholesale business and unregulated generating companies. The size and maturity lengths of the original offering is presently being determined. The regulated holding company is expected to issue the debt needed by the wires companies in Ohio and Texas. The regulated integrated utility companies will continue their current debt structure until the regulatory commissions approve changes. At that time, the regulated holding company may also issue the debt for the regulated companies' funding needs. We have requested credit ratings for the holding companies consistent with our existing credit quality, but we cannot predict what the outcome will be. AEP uses a money pool to meet the short-term borrowings for certain of its subsidiaries, primarily the domestic electric utility operations. Following corporate separation, management will evaluate the advantages of establishing a money pool for the unregulated business subsidiaries. The current money pool which was approved by the appropriate regulatory authorities will continue to service the regulated business subsidiaries. Presently, AEP also funds the short-term debt requirements of other subsidiaries that are not included in the money pool. As of December 31, 2001, AEP had credit facilities totaling $3.5 billion to support its commercial paper program. At December 31, 2001, AEP had $2.9 billion outstanding in short-term borrowing subject to these credit facilities. Market Risks - Affecting AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU As a major power producer and trader of wholesale electricity and natural gas, we have certain market risks inherent in our business activities. These risks include com-modity price risk, interest rate risk, foreign exchange risk and credit risk. They represent the risk of loss that may impact us due to changes in the underlying market prices or rates. Policies and procedures are established to identify, assess, and manage market risk exposures in our day to day operations. Our risk policies have been reviewed with the Board of Directors, approved by a Risk Management Committee and administered by a Chief Risk Officer. The Risk Management Committee establishes risk limits, approves risk policies, assigns responsibilities regarding the oversight and management of risk and monitors risk levels. This committee receives daily, weekly, and monthly reports regarding compliance with policies, limits and procedures. The committee meets monthly and consists of the Chief Risk Officer, Chief Credit Officer, V.P. Market Risk Oversight, and senior financial and operating managers. We use a risk measurement model which calculates Value at Risk (VaR) to measure our commodity price risk. The VaR is based on the variance - covariance method using historical prices to estimate volatilities and correlations and assuming a 95% confidence level and a one-day holding period. Based on this VaR analysis, at December 31, 2001 a near term typical change in commodity prices is not expected to have a material effect on our results of operations, cash flows or financial condition. The following table shows the high, average, and low market risk as measured by VaR at: December 31, 2001 2000 ---- ---- High Average Low High Average Low (in millions) AEP $28 $14 $5 $32 $10 $1 APCo 4 1 - 6 2 - CPL 3 1 - 4 1 - CSPCo 2 1 - 3 1 - I&M 3 1 - 4 1 - KPCo 1 - - 1 - - OPCo 3 1 - 5 2 - PSO 2 1 - 3 1 - SWEPCo 3 1 - 4 1 - WTU 1 1 - 1 - - We also utilize a VaR model to measure interest rate market risk exposure. The interest rate VaR model is based on a Monte Carlo simulation with a 95% confidence level and a one year holding period. The volatilities and correlations were based on three years of weekly prices. The risk of potential loss in fair value attributable to AEP's exposure to interest rates, primarily related to long-term debt with fixed interest rates, was $673 million at December 31, 2001 and $998 million at December 31, 2000. However, since we would not expect to liquidate our entire debt portfolio in a one year holding period, a near term change in interest rates should not materially affect results of operations or consolidated financial position. The following table shows the potential loss in fair value as measured by VaR allocated to the AEP registrant subsidiaries based upon debt outstanding: VaR for Registrant Subsidiaries: December 31, 2001 2000 (in millions) Company AEGCo $5 $4 APCo 100 149 CPL 80 135 CSPCo 60 84 I&M 86 129 KPCo 16 31 OPCo 59 112 PSO 17 44 SWEPCo 36 60 WTU 20 24 AEGCo is not exposed to risk from changes in interest rates on short-term and long-term borrowings used to finance operations since financing costs are recovered through the unit power agreements. AEP is exposed to risk from changes in the market prices of coal and natural gas used to generate electricity where generation is no longer regulated or where existing fuel clauses are suspended or frozen. The protection afforded by fuel clause recovery mechanisms has either been eliminated by the implementation of customer choice in Ohio (effective January 1, 2001 for CSPCo and OPCo) and in the ERCOT area of Texas (effective January 1, 2002 for CPL and WTU) or frozen by settlement agreements in Indiana, Michigan and West Virginia. To the extent the fuel supply of the generating units in these states is not under fixed price long-term contracts AEP is subject to market price risk. AEP continues to be protected against market price changes by active fuel clauses in Oklahoma, Arkansas, Louisiana, Kentucky, Virginia and the SPP area of Texas. We employ physical forward purchase and sale contracts, exchange futures and options, over-the-counter options, swaps, and other derivative contracts to offset price risk where appropriate. However, we engage in trading of electricity, gas and to a lesser degree coal, oil, natural gas liquids, and emission allowances and as a result the Company is subject to price risk. The amount of risk taken by the traders is controlled by the management of the trading operations and the Company's Chief Risk Officer and his staff. When the risk from trading activities exceeds certain pre-determined limits, the positions are modified or hedged to reduce the risk to the limits unless specifically approved by the Risk Management Committee. We employ fair value hedges, cash flow hedges and swaps to mitigate changes in interest rates or fair values on short and long-term debt when management deems it necessary. We do not hedge all interest rate risk. We employ cash flow forward hedge contracts to lock-in prices on transactions denominated in foreign currencies where deemed necessary. International subsidiaries use currency swaps to hedge exchange rate fluctuations in debt denominated in foreign currencies. We do not hedge all foreign currency exposure. AEP limits credit risk by extending unsecured credit to entities based on internal ratings. In addition, AEP uses Moody's Investor Service, Standard and Poor's and qualitative and quantitative data to independently assess the financial health of counterparties on an ongoing basis. This data, in conjunction with the ratings information, is used to determine appropriate risk parameters. AEP also requires cash deposits, letters of credit and parental/affiliate guarantees as security from certain below investment grade counterparties in our normal course of business. We trade electricity and gas contracts with numerous counterparties. Since our open energy trading contracts are valued based on changes in market prices of the related commodities, our exposures change daily. We believe that our credit and market exposures with any one counterparty is not material to financial condition at December 31, 2001. At December 31, 2001 less than 5% of the counterparties were below investment grade as expressed in terms of Net Mark to Market Assets. Net Mark to Market Assets represents the aggregate difference (either positive or negative) between the forward market price for the remaining term of the contract and the contractual price. The following table approximates counterparty credit quality and exposure for AEP. Futures, Forward and Swap Counterparty Contracts Options Total Credit Quality: December 31, 2001 (in millions) AAA/Exchanges $ 147 $- $ 147 AA 140 4 144 A 304 7 311 BBB 932 34 966 Below Investment Grade 23 ------- --- -- 56 79 -- Total $1,579 $68 $1,647 ====== === ====== The counterparty credit quality and exposure for the registrant subsidiaries is generally consistent with that of AEP. We enter into transactions for electricity and natural gas as part of wholesale trading operations. Electric and gas transactions are executed over the counter with counterparties or through brokers. Gas transactions are also executed through brokerage accounts with brokers who are registered with the Commodity Futures Trading Commission. Brokers and counterparties require cash or cash related instruments to be deposited on these transactions as margin against open positions. The combined margin deposits at December 31, 2001 and 2000 was $55 million and $95 million. These margin accounts are restricted and therefore are not included in cash and cash equivalents on the Balance Sheet. We can be subject to further margin requirements should related commodity prices change. We recognize the net change in the fair value of all open trading contracts, a practice commonly called mark-to-market accounting, in accordance with generally accepted accounting principles and include the net change in mark-to-market amounts on a net discounted basis in revenues. Unrealized mark-to-market revenues totaled $257 million in 2001. The fair values of open short-term trading contracts are based on exchange prices and broker quotes. The fair value of open long-term trading contracts are based mainly on Company developed valuation models. The valuation models produce an estimated fair value for open long-term trading contracts. This fair value is present valued and reduced by appropriate reserves for counterparty credit risks and liquidity risk. The models are derived from internally assessed market prices with the exception of the NYMEX gas curve, where we use daily settled prices. Forward price curves are developed for inclusion in the model based on broker quotes and other available market data. The curves are within the range between the bid and ask prices. The end of the month liquidity reserve is based on the difference in price between the price curve and the bid price of the bid ask prices if we have a long position and the ask side if we have a short position. This provides for a conservative valuation net of the reserves. The use of these models to fair value open trading contracts has inherent risks relating to the underlying assumptions employed by such models. Independent controls are in place to evaluate the reasonableness of the price curve models. Significant adverse or favorable effects on future results of operations and cash flows could occur if market risks, at the time of settlement, do not correlate with the Company developed price models. The effect on the Consolidated Statements of Income of marking to market open electricity trading contracts in the Company's regulated jurisdictions is deferred as regulatory assets or liabilities since these transactions are included in cost of service on a settlement basis for ratemaking purposes. Unrealized mark-to-market gains and losses from trading are reported as assets or liabilities. The following table shows net revenues (revenues less fuel and purchased energy expense) and their relationship to the mark-to-market revenues (the change in fair value of open trading contracts). December 31, ------------------ 2001 2000 1999 ---- ---- ---- (in millions) Revenues (including mark- to- market adjustment) $61,257 $36,706 $24,745 Fuel and Purchased Energy Expense 52,753 28,718 17,244 ------- ------- ------- Net Revenues $ 8,504 $ 7,988 $ 7,501 ======= ======= ======= Mark-to-Market Revenues $257 $170 $23 ==== ==== === Percentage of Net Revenues Represented by Mark-to-Market 3% 2% -% == == == The following tables analyze the changes in fair values of trading assets and liabilities. The first table "Net Fair Value of Energy Trading Contracts" shows how the net fair value of energy trading contracts was derived from the amounts included in the balance sheet line item "energy trading and derivative contracts." The next table "Energy Trading Contracts" disaggregates realized and unrealized changes in fair value; identifies changes in fair value as a result of changes in valuation methodologies; and reconciles the net fair value of energy trading contracts at the beginning of the year of $63 million to the end of the year of $448 million. Contracts realized/settled during the period include both sales and purchase contracts. The third table "Energy Trading Contract Maturities" shows exposures to changes in fair values and realization periods over time for each method used to determine fair value. Net Fair Value of Energy Trading Contracts December 31, ------------------- 2001 2000 ---- ---- (in millions) Energy Trading Contracts: Current Asset $ 8,536 $ 15,495 Long-term Asset 2,367 1,552 Current Liability (8,279) (15,671) Long-term Liability (2,176) (1,313) ------- -------- Net Fair Value of Energy Trading Contracts $ 448 $ 63 ======= ======== The net fair value of energy trading contracts includes $257 million at December 31, 2001 and $170 million at December 31, 2000 of unrealized mark-to-market gains that are recognized in the income statement. Also included in the above net fair value of energy trading contracts are option premiums that are deferred until the related contracts settle and the portion of changes in fair values of electricity trading contracts that are deferred for ratemaking purposes.
Energy Trading Contracts AEP Consolidated (in millions) Total Net Fair Value of Energy Trading Contracts at December 31, 2000 $ 63 Gain from Contracts realized/settled during period (352) (a) Fair Value of new open contracts when entered into during period 73 (b) Adjustments for Contracts entered into and settled during period 310 (a) Net option premium payments 24 Change in fair value due to Valuation Methodology changes (1) (c) Changes in market value of contracts 331 (d) ----- Net Fair Value of Energy Trading Contracts at December 31, 2001 $ 448 (e) =====
(a) Gains from Contracts Realized or Otherwise Settled During the Period" include realized gains from energy trading contracts that settled during 2001 that were entered into prior to 2001, as well as during 2001. "Adjustment for Contracts Entered into and Settled During the Period" discloses the realized gains from settled energy trading contracts that were both entered into and closed within 2001 that are included in the total gains of $352 million, but not included in the ending balance of open contracts. (b) The "Fair Value of New Open Contracts When Entered Into during period" represents the fair value of long-term contracts entered into with customers during 2001. The fair value is calculated as of the execution of the contract. Most of the fair value comes from longer term fixed price contracts with customers that seek to limit their risk against fluctuating energy prices. The contract prices are valued against market curves representative of the delivery location. (c) The Company changed its methodology for calculating and reporting load based transactions. The previous methodology estimated a baseload volume based on historical takes and sold a call option for potential load increases from the baseload. The current methodology uses a modified version of a straddle load follow model to estimate the baseload volume and call option volume. This methodogy change more accurately estimates the load volume forecast. The dollar impact on existing deals was a decrease of in fair value of $1.2 million. (d) "Change in market Value of Contracts" represents the fair value change in the trading portfolio due to market fluctuations during the current period. Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc. (e) The net change in the fair value of energy trading contracts for 2001 that resulted in an increase of $385 million ($448 million less $63 million) represents the balance sheet change. The net mark-to-market gain on energy trading contracts of $257 million represents the impact on earnings. The difference is related primarily to regulatory deferrals of certain mark-to-market gains that were recorded as regulatory liabilities and not reflected in the income statement for those companies that operate in regulated jurisdictions, and deferrals of option premiums included in the above analysis, which do not have a mark-to-market income statement impact. Energy Trading Contracts (in thousand) APCo CPL CSPCo Net Fair Value of Energy Trading Contracts at December 31, 2000 $ 7,447 $(8,191) $ 3,769 Loss/(Gain) from Contracts Realized/settled during period (12,478) 4,221 (11,522) Fair Value of new open Contracts when entered into during period 13,441 9,635 8,245 Adjustments for Contracts Entered into and settled during period 40,755 2,602 24,998 Net option premium payments 1,072 - 658 Change in fair value due to Valuation Methodology changes (220) (158) (135) Changes in market value of Contracts 25,684 (4,252) 22,436 -------- ------- -------- Net Fair Value of Energy Trading Contracts at December 31, 2001 $ 75,701 $ 3,857 $ 48,449 ======== ======= ======== Energy Trading Contracts (in thousands) I&M KPCo OPCo Net Fair Value of Energy Trading Contracts at December 31, 2000 $ (6,845) $ 1,678 $ 5,613 Loss/(Gain) from Contracts Realized/settled during period (10,982) (3,298) (10,861) Fair Value of new open Contracts when entered into During period 8,921 3,315 11,213 Adjustments for Contracts Entered into and settled During period 27,049 10,051 34,001 Net option premium payments 712 264 894 Change in fair value due to Valuation Methodology changes (146) (54) (183) Changes in market value of Contracts 42,636 773 24,769 ------- ------- -------- Net Fair Value of Energy Trading Contracts at December 31, 2001 $ 61,345 $12,729 $ 65,446 ======== ======= ======== Energy Trading Contracts (in thousands) PSO SWEPCo WTU Net Fair Value of Energy Trading Contracts at December 31, 2000 $(6,508) $(7,795) $(2,590) Loss/(Gain) from Contracts Realized/settled during period 2,483 2,938 5,881 Fair Value of new open Contracts when entered into During period 7,338 8,422 2,861 Adjustments for Contracts Entered into and settled during period 1,981 2,274 773 Net option premium payments - - - Change in fair value due to Valuation Methodology changes (120) (138) (46) Changes in market value of Contracts (2,740) (2,801) (5,964) ------- ------- ------- Net Fair Value of Energy Trading Contracts at December 31, 2001 $ 2,434 $ 2,900 $ 915 ======= ======= =======
Energy Trading Contract Maturities Fair Value of Contracts at December 31,2001 ------------------------------------------------------------ Maturities ------------------------------------------------------------ (in millions) AEP Consolidated Less than In Excess Total Fair Source of Fair Value 1 year 1-3 years 4-5 years Of 5 years Value - -------------------- ------ --------- --------- ---------- ----- Prices actively quoted (a) $ 46 $ 8 $ - $ - $ 54 Prices provided by other external Sources (b) 152 33 - - 185 Prices based on models and other Valuation methods (c) 13 133 35 28 209 ---- ---- --- --- ---- Total $211 $174 $35 $28 $448 ==== ==== === === ====
Energy Trading Contract Maturities Fair Value of Contracts at December 31,2001 -------------------------------------------------------------- Maturities -------------------------------------------------------------- (in thousands) Less than In Excess Total Fair Source of Fair Value 1 year 1-3 years 4-5 years Of 5 years Value - -------------------- ------ --------- --------- ---------- ----- APCo Other External Sources 13,366 9,588 - - 22,954 Models/Other Valuation 3,215 34,318 8,413 6,801 52,747 ------ ------ ----- ----- ------ Total 16,581 43,906 8,413 6,801 75,701 ====== ====== ===== ===== ====== CPL Other External Sources (5,245) 1,681 - - (3,564) Models/Other Valuation (1,262) 6,016 1,475 1,192 7,421 ------- ----- ----- ----- ------ Total (6,507) 7,697 1,475 1,192 3,857 ======= ===== ===== ===== ====== CSP Other External Sources 9,867 5,872 - - 15,739 Models/Other Valuation 2,373 21,018 5,153 4,166 32,710 ------ ------ ----- ----- ------ Total 12,240 26,890 5,153 4,166 48,449 ====== ====== ===== ===== ====== KEPCo Other External Sources (1,475) 2,361 - - 886 Models/Other Valuation (355) 8,451 2,072 1,675 11,843 ------- ------ ----- ----- ------ Total (1,830) 10,812 2,072 1,675 12,729 ======= ====== ===== ===== ====== I&M Other External Sources 17,237 6,481 - - 23,718 Models/Other Valuation 4,146 23,197 5,687 4,597 37,627 ------ ------ ----- ----- ------ Total 21,383 29,678 5,687 4,597 61,345 ====== ====== ===== ===== ====== OPCo Other External Sources 13,058 7,987 - - 21,045 Models/Other Valuation 3,141 28,587 7,008 5,665 44,401 ------ ------ ----- ----- ------ Total 16,199 36,574 7,008 5,665 65,446 ====== ====== ===== ===== ====== PSO Other External Sources (4,400) 1,280 - - (3,120) Models/Other Valuation (1,058) 4,581 1,123 908 5,554 ------- ----- ----- --- ------ Total (5,458) 5,861 1,123 908 2,434 ======= ===== ===== === ====== SWEPCo Other External Sources (4,965) 1,469 - - (3,496) Models/Other Valuation (1,194) 5,259 1,289 1,042 6,396 ------- ----- ----- ----- ------ Total (6,159) 6,728 1,289 1,042 2,900 ======= ===== ===== ===== ====== WTU Other External Sources (1,743) 499 - - (1,244) Models/Other Valuation (419) 1,786 438 354 2,159 ------- ----- --- --- ------ Total (2,162) 2,285 438 354 915 ======= ===== === === ======
(a) "Prices Actively Quoted" represents the Company's exchange traded futures positions in natural gas. (b) "Prices Provided by Other External Sources" represents the Company's positions in natural gas, power, and coal at points where over-the-counter broker quotes are available. Prices for these various commodities can generally be obtained on the over-the-counter market through 2003. Some prices from external sources are quoted as strips (one bid/ask for Nov-Mar, Apr-Oct, etc). Such transactions have also been included in this category. (c) "Prices Based on Models and Other Valuation Methods" contain the following: the value of the Company's adjustments for liquidity and counterparty credit exposure, the value of contracts not quoted by an exchange or an over-the-counter broker, the value of transactions for which an internally developed price curve was developed as a result of the long dated nature of certain transactions, and the value of certain structured transactions. We have investments in debt and equity securities which are held in nuclear trust funds. The trust investments and their fair value are discussed in Note 13, "Risk Management, Financial Instruments and Derivatives." Financial instruments in these trust funds have not been included in the market risk calculation for interest rates as these instruments are marked-to-market and changes in market value of these instruments are reflected in a corresponding decommissioning liability. Any differences between the trust fund assets and the ultimate liability are expected to be recovered through regulated rates from our regulated customers. Inflation affects our cost of replacing utility plant and the cost of operating and maintaining plant. The rate-making process limits recovery to the historical cost of assets, resulting in economic losses when the effects of inflation are not recovered from customers on a timely basis. However, economic gains that result from the repayment of long-term debt with inflated dollars partly offset such losses. Industry Restructuring In 2000 California's deregulated electricity market suffered problems including high energy prices mainly due to short energy supplies and financial difficulties for retail distribution companies. This energy crisis has highlighted the importance of risk management and has contributed to certain state regulatory and legislative actions which have delayed the start of customer choice and the transition to competitive, market based pricing for retail electricity supply in some of the states in which AEP operates. Seven of the eleven state retail jurisdictions in which the AEP domestic electric utility companies operate have enacted restructuring legislation. In general, the legislation provides for a transition from cost-based regulation of bundled electric service to customer choice and market pricing for the supply of electricity. As legislative and regulatory proceedings evolved, six AEP electric operating companies (APCo, CPL, CSPCo, OPCo, SWEPCo and WTU) doing business in five of the seven states that have passed restructuring legislation have discontinued the application of SFAS 71 regulatory accounting for the generation business. The seven states in various stages of restructuring to transition power generation and supply to market based pricing are Arkansas, Michigan, Ohio, Oklahoma, Texas, Virginia, and West Virginia. AEP has not discontinued its regulatory accounting for its subsidiaries doing business in Michigan and Oklahoma pending the effective implementation of the legislation. Restructuring legislation, the status of the transition plans and the status of the electric utility companies' accounting to comply with the changes in each of AEP's seven state regulatory jurisdictions affected by restructuring legislation is presented in the Note 7 of the Notes to Financial Statements. RTO Formation FERC Order No. 2000 and many of the settlement agreements with the FERC and state regulatory commissions to approve the AEP-CSW Merger have provisions for the transfer of functional control of our transmission system to an RTO. Certain AEP subsidiaries are participating in the formation of the Alliance RTO. Other subsidiaries are a member of ERCOT or SPP. In 2001 the Alliance companies and MISO entered into a settlement addressing transmission pricing and other "seam" issues between the two RTOs. The FERC subsequently expressed its opinion that four large RTO regions serving the continental US would best support competition and reliability of electric service. Certain state regulatory commissions have taken exception to the FERC's RTO actions. Louisiana's commission ordered utilities it regulates, including SWEPCo, to show the advantage of large RTOs to their customers. On December 19, 2001 the FERC approved the proposal of the Midwest ISO for a regional transmission organization and told the Alliance companies, which had submitted a separate RTO proposal, to explore joining the Midwest ISO organization. The FERC's order is intended to facilitate the establishment of a single RTO in the Midwest and to support the establishment of viable, for-profit transmission companies under an RTO umbrella and concluded that the RTO proposed by Alliance companies lacks sufficient scope to exist as a stand-alone RTO and thus directed the Alliance companies to explore how their business plan can be accommodated within the Midwest ISO. Management is unable to predict the outcome of these transmission regulatory actions and proceedings or their impact on the timing and operation of RTOs, AEP's transmission operations or future results of operations and cash flows. Litigation AEP is involved in various litigation. The details of significant litigation contin-gencies are disclosed in Note 8 and summarized below. COLI - Affecting AEP, APCo, CSPCo, I&M, KPCo and OPCo A decision by U.S. District Court for the Southern District of Ohio in February 2001 that denied AEP's deduction of interest claimed on AEP's consolidated federal income tax returns related to its COLI program resulted in a $319 million reduction in net income for 2000. AEP had filed suit to resolve the IRS' assertion that interest deductions for AEP's COLI program should not be allowed. In 1998 and 1999 AEP and the impacted subsidiaries paid the disputed taxes and interest attributable to COLI interest deductions for taxable years 1991-98 for APCo, CSPCo, I&M and OPCo and 1992-98 for KPCo to avoid the potential assessment by the IRS of additional interest on the contested tax. The payments were included in other assets on AEP's balance sheet and other property and investments on the subsidiaries' balance sheets pending the resolution of this matter. AEP has appealed the Court's decision. The earnings reductions for affected registrant subsidiaries are as follows: (in millions) APCo $ 82 CSPCo 41 I&M 66 KPCo 8 OPCo 118 Shareholders' Litigation - Affecting AEP On December 21, 2001, the U.S. District Court for the Southern District of Ohio dismissed a class action lawsuit against AEP and four former or present officers. The complaint alleged violation of federal securities laws by disseminating materially false and misleading statements related to the extended Cook Plant outage. FERC Wholesale Fuel Complaints - Affecting AEP and WTU In November 2001 certain WTU wholesale customers filed a complaint with FERC alleging that WTU has overcharged them since 1997 through the fuel adjustment clause. The customers allege inappropriate costs related to purchased power were included in the fuel adjustment clause. Management is working to compute if any overcharges occurred and is unable to predict their impact on results of operations, cash flow and financial condition. Municipal Franchise Fee Litigation - Affecting AEP and CPL In 2001 CPL paid $11 million to settle class action litigation regarding municipal franchise fees in Texas. The City of San Juan, Texas had filed a class action lawsuit in 1996 seeking $300 million in damages. Texas Base Rate Litigation - Affecting AEP and CPL In 2001 the Texas Supreme Court denied CPL's request for the court to review a 1997 PUCT base rate order. Subsequently the Court also denied CPL's rehearing request. The primary issues CPL requested the Court to review were: o the classification of $800 million of invested capital in STP as ECOM and assigning it a lower return on equity than other generation property; o and an $18 million disallowance of affiliated service billings. Lignite Mining Agreement Litigation - Affecting AEP and SWEPCo In 2001 SWEPCo settled litigation concerning lignite mining in Louisiana. Since 1997 SWEPCo has been involved in litigation concerning the mining of lignite from jointly owned lignite reserves. SWEPCo and CLECO, an unaffiliated utility, are each a 50% owner of the Dolet Hills Power Station Unit 1 and jointly own lignite reserves in the Dolet Hills area of northwestern Louisiana. Under terms of a settlement, SWEPCo purchased an unaffiliated mine operator's interest in the mining operations and related debt and other obligations for $86 million. Merger Litigation - Affecting AEP and all Subsidiary Registrants In January 2002, a federal court ruled that the SEC failed to prove that the June 15, 2000 merger of AEP with CSW meets the requirements of the PUHCA and sent the case back to the SEC for further review. Management believes that the merger meets the requirements of the PUHCA and expects the matter to be resolved favorably. Other - Affecting AEP and all Subsidiary Registrants AEP and its registrant subsidiaries are involved in a number of other legal proceedings and claims. While management is unable to predict the outcome of such litigation, it is not expected that the ultimate resolution of these matters will have a material adverse effect on the results of operations, cash flows or financial condition. Environmental Concerns and Issues The U.S. continues to debate an array of environmental issues affecting the electric utility industry including new emission limitations recommended by the Bush Administration in February 2002. Most of the policies are aimed at reducing air emissions citing alleged impacts of such emissions on public health, sensitive ecosystems or the global climate. AEP and its subsidiaries' policy on the environment continues to be the development and application of long-term economically feasible measures to improve air and water quality, limit emissions and protect the health of employees, customers, neighbors and others impacted by their operations. In support of this policy, AEP and its subsidiaries continue to invest in research through groups like the Electric Power Research Institute and directly through demonstration projects for new technology for the capture and storage of carbon dioxide, mercury, NOx and other emissions. The AEP System intends to continue in a leadership role to protect and preserve the environment while providing vital energy commodities and services to customers at fair prices. AEP and its subsidiaries have a proven record of efficiently producing and delivering electricity and gas while minimizing the impact on the environment. AEP and its subsidiaries have spent billions of dollars to equip their facilities with the latest cost effective clean air and water technologies and to research new technologies. We are proud of our award winning efforts to reclaim our mining properties. The introduction of multi-pollutant control legislation is being discussed by members of Congress and the Bush Administration. The legislation being considered may regulate carbon dioxide, NOx, sulfur dioxide, mercury and other emissions from electric generating plants. Management will continue to support solutions which are based on sound science, economics and demonstrated control technologies. Management is unable to predict the timing or magnitude of additional pollution control laws or regulations. If additional control technology is required on facilities owned by the electric utility companies and their costs were not recoverable from ratepayers or through market based prices or volumes of product sold, they could adversely affect future results of operations and cash flows. The following discussions explains existing control efforts, litigation and other pending matters related to environmental issues for AEP companies. Federal EPA Complaint and Notice of Violation - Affecting AEP, APCo, CSPCo, I&M and OPCo Since 1999 AEP, APCo, CSPCo, I&M and OPCo have been involved in litigation regarding generating plant emissions under the Clean Air Act. Federal EPA, a number of states and certain special interest grups alleged that APCo, CSPCo, I&M and OPCo modified certain generating units over a 20 year period in violation of the Clean Air Act. Under the Clean Air Act, if a plant undertakes a major modification that directly results in an emissions increase, permitting requirements might be triggered and the plant may be required to install additional pollution control technology. This requirement does not apply to activities such as routine maintenance, replacement of degraded equipment or failed components, or other repairs needed for the reliable, safe and efficient operation of the plant. We believe our maintenance, repair and replacement activities were in conformity with the Clean Air Act and intend to vigorously pursue our defense. The Clean Air Act authorizes civil penalties of up to $27,500 per day per violation at each generating unit ($25,000 per day prior to January 30, 1997). In March 2001 the District Court ruled that claims for civil penalties based on activities that occurred more than five years before the filing date of the complaints cannot be imposed. There is no time limit on claims for injunctive relief. Management is unable to estimate a loss or predict the timing of the resolution of these matters due to the number of alleged violations and the significant number of issues yet to be determined by the Court. If we do not prevail, any capital and operating costs of additional pollution control equipment that may be required as well as any penalties imposed would adversely affect future results of operations, cash flows and possibly financial condition. An unaffiliated utility which operates certain plants jointly owned by CSPCo reached a tentative agreement to settle litigation regarding generating plant emissions under the Clean Air Act. Negotiations are continuing and a settlement could impact the operation of Zimmer Plant and W.C. Beckjord Generating Station Unit 6 (owned 25.4% and 12.5%, respectively, by CSPCo). Until a final settlement is reached, CSPCo will be unable to determine the settlement's impact on its jointly owned facilities and its future results of operations and cash flows. NOx Reduction - Affecting AEP, APCo, CPL, I&M, OPCo and SWEPCo Federal EPA issued a NOx rule (the Nox Rule) and granted petitions filed by certain northeastern states (the Section 126 Rule) requiring substantial reductions in NOx emissions in a number of eastern states, including certain states in which the AEP System's generating plants are located. Federal EPA ruled that eleven states, including certain states in which AEP's generating units are located, failed to submit approvable plans to comply with the NOx Rule. This ruling means that those states could face stringent sanctions including limits on construction of new sources of air emissions, loss of federal highway funding and possible Federal EPA takeover of state air quality management programs. A request for the D.C. Circuit Court to review this ruling is pending. The compliance date for the NOx Rule is May 31, 2004. The D.C. Circuit Court instructed Federal EPA to justify methods used to allocate allowances and project growth for both the NOx Rule and the Section 126 Rule. In response to AEP and other utilities request for the D.C. Circuit Court to suspend the May 2003 compliance date of the Section 126 Rule, the D.C. Circuit Court issued an order tolling the compliance schedule until Federal EPA responds to the Court's remand. In April 2000 the Texas Natural Resource Conservation Commission adopted rules requiring significant reductions in NOx emissions from utility sources, including CPL and SWEPCo. The compliance date is May 2003 for CPL and May 2005 for SWEPCo. In 2001 selective catalytic reduction (SCR) technology to reduce NOx emissions on OPCo's Gavin Plant commenced operation. Construction of SCR technology at certain other generating units continues with completion scheduled in 2002 through 2006. Our estimates indicate that compliance with the NOx Rule, the Texas Natural Resource Conservation Commission rule and the Section 126 Rule could result in required capital expenditures of approximately $1.6 billion of which approximately $450 million has been spent for the AEP System. The following table shows the estimated compliance cost and amounts spent for certain of AEP's registrant subsidiaries. Estimated Amounts Compliance Costs Spent ---------------- ------- (in millions) Company APCo $365 $130 CPL 57 4 I&M 202 - OPCo 606 277 SWEPCo 28 21 Since compliance costs cannot be estimated with certainty, the actual cost to comply could be significantly different than the estimates depending upon the compliance alternatives selected to achieve reductions in NOx emissions. Unless any capital and operating costs of additional pollution control equipment are recovered from customers, they will have an adverse effect on future results of operations, cash flows and possibly financial condition. Superfund - Affecting AEP, APCo, CPL, CSPCo, I&M, OPCo and SWEPCo By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically disposed of or treated in captive disposal facilities or are beneficially utilized. In addition, our generating plants and transmission and distribution facilities have used asbestos, PCBs and other hazardous and non-hazardous materials. We are currently incurring costs to safely dispose of these substances. Additional costs could be incurred to comply with new laws and regulations if enacted. Superfund addresses clean-up of hazardous substances at disposal sites and authorized Federal EPA to administer the clean-up programs. As of year-end 2001, subsidiaries of AEP have been named by the Federal EPA as a PRP for five sites. APCo, CSPCo, and OPCo each have one PRP site and I&M has two PRP sites. There are four additional sites for which AEP, APCo, CSPCo, I&M, OPCo and SWEPCo have received information requests which could lead to PRP designation. CPL, OPCo and SWEPCo have also been named a PRP at two sites under state law. Our liability has been resolved for a number of sites with no significant effect on results of operations. In those instances where AEP or its subsidiaries have been named a PRP or defendant, their disposal or recycling activities were in accordance with the then-applicable laws and regulations. Unfortunately, Superfund does not recognize compliance as a defense, but imposes strict liability on parties who fall within its broad statutory categories. While the potential liability for each Superfund site must be evaluated separately, several general statements can be made regarding AEP's and its subsidiaries' potential future liability. Disposal of materials at a particular site is often unsubstantiated and the quantity of materials deposited at a site was small and often nonhazardous. Although liability is joint and several, typically many parties are named as PRPs for each site and several of the parties are financially sound enterprises. Therefore, our present estimates do not anticipate material cleanup costs for identified sites for which we have been declared PRPs. If significant cleanup costs are attributed to AEP or its subsidiaries in the future under Superfund, results of operations, cash flows and possibly financial condition would be adversely affected unless the costs can be recovered from customers. Global Climate Change - Affecting AEP and all Registrant Subsidiaries At the Third Conference of the Parties to the United Nations Framework Convention on Climate Change held in Kyoto, Japan in December 1997 more than 160 countries, including the U.S., negotiated a treaty requiring legally-binding reductions in emissions of greenhouse gases, chiefly carbon dioxide, which many scientists believe are contributing to global climate change. Although the U.S. signed the Kyoto Protocol on November 12, 1998, the treaty was not submitted to the Senate for its advice and consent by President Clinton. In March 2001 President Bush announced his opposition to the treaty and its U.S. ratification. At the Seventh Conference of the Parties in November 2001, the parties finalized the rules, procedures and guidelines required to facilitate ratification of the protocol. The protocol is expected to become effective by 2003. U.S. representatives attended the Seventh Conference but they did not take any positions on issues being negotiated or attempt to block the approval of any issue. AEP does not support the Kyoto Protocol but intends to work with the Bush Administration and U.S. Congress to develop responsible public policy on this issue. Management expects due to President Bush's opposition to legislation mandating greenhouse gas emissions controls, any policies developed and implemented in the near future are likely to encourage voluntary measures to reduce, avoid or sequester such emissions. The acquisition of 4,000 MW of coal-fired generation in the United Kingdom in December 2001 exposes these assets to potential carbon dioxide emission control obligations since the U.K. is expected to be a party to the Kyoto Protocol. Costs for Spent Nuclear Fuel and Decommissioning - Affecting AEP, CPL and I&M I&M, as the owner of the Cook Plant, and CPL, as a partial owner of STP, have a significant future financial commitment to safely dispose of SNF and decommission and decontaminate the plants. The Nuclear Waste Policy Act of 1982 established federal responsibility for the permanent off-site disposal of SNF and high-level radioactive waste. By law CPL and I&M participate in the DOE's SNF disposal program which is described in Note 8 of the Notes to Financial Statements. Since 1983 I&M has collected $288 million from customers for the disposal of nuclear fuel consumed at the Cook Plant. $116 million of these funds have been deposited in external trust funds to provide for the future disposal of SNF and $172 million has been remitted to the DOE. CPL has collected and remitted to the DOE, $49 million for the future disposal of SNF since STP began operation in the late 1980s. Under the provisions of the Nuclear Waste Policy Act, collections from customers are to provide the DOE with money to build a permanent repository for spent fuel. However, in 1996, the DOE notified the companies that it would be unable to begin accepting SNF by the January 1998 deadline required by law. To date DOE has failed to comply with the requirements of the Nuclear Waste Policy Act. As a result of DOE's failure to make sufficient progress toward a permanent repository or otherwise assume responsibility for SNF, AEP on behalf of I&M and STPNOC on behalf of CPL and the other STP owners, along with a number of unaffiliated utilities and states, filed suit in the D.C. Circuit Court requesting, among other things, that the D.C. Circuit Court order DOE to meet its obligations under the law. The D.C. Circuit Court ordered the parties to proceed with contractual remedies but declined to order DOE to begin accepting SNF for disposal. DOE estimates its planned site for the nuclear waste will not be ready until at least 2010. In 1998, AEP and I&M filed a complaint in the U.S. Court of Federal Claims seeking damages in excess of $150 million due to the DOE's partial material breach of its unconditional contractual deadline to begin disposing of SNF generated by the Cook Plant. Similar lawsuits were filed by other utilities. In August 2000, in an appeal of related cases involving other unaffiliated utilities, the U.S. Court of Appeals for the Federal Circuit held that the delays clause of the standard contract between utilities and the DOE did not apply to DOE's complete failure to perform its contract obligations, and that the utilities' suits against DOE may continue in court. AEP's and I&M's suit has been stayed pending further action by the U.S. Court of Federal Claims. As long as the delay in the availability of a government approved storage repository for SNF continues, the cost of both temporary and permanent storage and the cost of decommissioning will continue to increase. In January 2001, I&M and STPNOC, on behalf of STP's joint owners, joined a lawsuit against DOE, filed in November 2000 by unaffiliated utilities, related to DOE's nuclear waste fund cost recovery settlement with PECO Energy Corporation. The settlement allows PECO to skip two payments to the DOE for disposal of SNF due to the lack of progress towards development of a permanent repository for SNF. The companies believe the settlement is unlawful as the settlement would force other utilities to make up any shortfall in DOE's SNF disposal funds. The cost to decommission nuclear plants is affected by both NRC regulations and the delayed SNF disposal program. Studies completed in 2000 estimate the cost to decommission the Cook Plant ranges from $783 million to $1,481 million in 2000 non-discounted dollars. External trust funds have been established with amounts collected from customers to decommission the plant. At December 31, 2001, the total decom-missioning trust fund balance for Cook Plant was $598 million which includes earnings on the trust investments. Studies completed in 1999 for STP estimate CPL's share of decommissioning cost to be $289 million in 1999 non-discounted dollars. Amounts collected from customers to decommission STP have been placed in an external trust. At December 31, 2001, the total decommission-ing trust fund for CPL's share of STP was $99 million which includes earnings on the trust investments. Estimates from the decommissioning studies could continue to escalate due to the uncertainty in the SNF disposal program and the length of time that SNF may need to be stored at the plant site. We will work with regulators and customers to recover the remaining estimated costs of decommissioning Cook Plant and STP. However, AEP's, CPL's and I&M's future results of operations, cash flows and possibly their financial conditions would be adversely affected if the cost of SNF disposal and decommissioning continues to increase and cannot be recovered. AEP and its subsidiaries are exposed to other environmental concerns which are not considered to be material or potentially material at this time. Should they become significant or should any new concerns be uncovered that are material they could have a material adverse effect on results of operations and possibly financial condition. AEP performs environmental reviews and audits on a regular basis for the purpose of identifying, evaluating and addressing environmental concerns and issues. APCo, AEP's subsidiary which operates in Virginia and West Virginia, has been seeking regulatory approval to build a new high voltage transmission line for over a decade. Through December 31, 2001 we have invested approximately $40 million in this effort. If the required regulatory approvals are not obtained and the line is not constructed, the $40 million investment would be written off adversely affecting AEP's and APCo's future results of operations and cash flows. OTHER MATTERS Enron Bankruptcy - Affecting AEP, APCo, CSPCo, I&M, KPCo and OPCo At the date of Enron's bankruptcy AEP had open trading contracts and trading accounts receivables and payables with Enron. In addition, on June 1, 2001, we purchased Houston Pipe Line from Enron and entered into a lease arrangement with a subsidiary of Enron for a gas storage facility. At the date of Enron's bankruptcy various HPL related contingencies and indemnities remained unsettled. In the fourth quarter of 2001 AEP provided $47 million ($31 million net of tax) for our estimated losses from the Enron bankruptcy. The amounts for certain subsidiary registrants were: Amounts Amounts Net of Registrant Provided Tax -------- -- --- (in millions) APCo $5.2 3.4 CSPCo 3.2 2.1 I&M 3.4 2.2 KPCo 1.3 0.8 OPCo 4.3 2.8 The amounts provided were based on an analysis of contracts where AEP and Enron are counterparties, the offsetting of receivables and payables, the application of deposits from Enron and management's analysis of the HPL related purchase contingencies and indemnifications. If there are any adverse unforeseen developments in the bankruptcy proceedings, our future results of operations, cash flows and possibly financial condition could be adversely impacted. International Investments - Affecting AEP We own a 44% equity interest in Vale, a Brazilian electric operating company which was purchased for a total of $149 million. On December 1, 2001 we converted a $66 million note receivable and accrued interest into a 20% equity interest in Caiua (Brazilian electric operating company), a subsidiary of Vale. Vale and Caiua have experienced losses from operations and our investment has been affected by the devaluation of the Brazilian Real. The cumulative equity share of operating and foreign currency translation losses through December 31, 2001 is approximately $46 million and $54 million, respectively net of tax. The cumulative equity share of operating and foreign currency translation losses through December 31, 2000 is approximately $33 million and $49 million, respectively net of tax. Both investments are covered by a put option, which, if exercised, requires our partners in Vale to purchase our Vale and Caiua shares at a minimum price equal to the U.S. dollar equivalent of the original purchase price. As a result, management has concluded that the investment carrying amount should not be reduced below the put option value unless it is deemed to be an other than temporary impairment and our partners in Vale are deemed unable to fulfill their responsibilities under the put option. Management has evaluated through an independent third-party, the ability of its Vale partners to fulfill their responsibilities under the put option agreement and has concluded that our partners should be able to fulfill their responsibilities. Management believes that the decline in the value of its investment in Vale in US dollars is not other than temporary. As a result and pursuant to the put option agreement, these losses have not been applied to reduce the carrying values of the Vale and Caiua investments. As a result we will not recognize any future earnings from Vale and Caiua until the operating losses are recovered. Should the impairment of our investment become other than temporary due to our partners in Vale becoming unable to fulfill their responsibilities, it would have an adverse effect on future results of operations. Management will continue to monitor both the status of the losses and the ability of its partners to fulfill their obligations under the put. Investments Limitations - Affecting AEP Our investment, including guarantees of debt, in certain types of activities is limited by PUHCA. SEC authorization under PUHCA limits us to issuing and selling securities in an amount up to 100% of our average quarterly consolidated retained earnings balance for investment in EWGs and FUCOs. At December 31, 2001, AEP's investment in EWGs and FUCOs was $2.9 billion, including guarantees of debt, compared to AEP's limit of $3.3 billion. SEC rules under PUHCA permit AEP to invest up to 15% of consolidated capitalization (such amount was $3.6 billion at December 31, 2001) in energy-related companies, including marketing and/or trading of electricity, gas and other energy commodities. Our gas trading business and our interest in domestic cogeneration projects are reported as investments under this rule and at December 31, 2001, such investment was $2.2 billion. New Accounting Standards - Affecting AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU The FASB recently issued SFAS 141, "Business Combinations" and SFAS 142, "Goodwill And Other Intangible Assets." SFAS 141 requires that the purchase method of accounting be used to account for all business combinations entered into after June 30, 2001. SFAS 142 requires that goodwill amortization cease and that goodwill and other intangible assets with indefinite lives be tested for impairment upon SFAS 142 implementation and annually thereafter. We must implement these new standards in the first quarter of 2002. Amortization of goodwill and other intangible assets with indefinite lives will cease with our implementation of SFAS 142 beginning January 1, 2002. The amortization of goodwill reduced AEP's net income by $50 million for the twelve months ended December 31, 2001. The registrant subsidiaries did not have any goodwill at December 31, 2001. We are currently in the process of fair valuing our reporting units with goodwill in order to determined potential goodwill impairment. As such we have not yet determined the impact on first quarter 2002 results of operations of adopting the provision of these standards. SFAS 143, "Accounting for Asset Retirement Obligations," will become effective for us beginning January 1, 2003. SFAS 143 established accounting and reporting for legal obligations associated with the retirement of tangible long-lived assets and the related asset retirement costs. We are currently in the process of evaluating the provisions of the standard and determining its impact on future results of operations and financial condition. To the extent AEP or it registrant subsidiaries are regulated entities, we anticipate that the cumulative effect of this accounting change on future results of operations will be significantly offset by a regulatory asset representing the right to recover legal asset retirement obligations (ARO) relative to regulated long lived assets included in rate base. The impact on future results of operations from the implementation of this new standard on non-regulated long lived assets has not yet been determined. We anticipate that the considerable effort to identify all long lived assets with legal ARO and to determine the required discounted legal ARO will take the remainder of 2002. In August 2001 the FASB issued SFAS 144, "Accounting for the Impairment or Disposal of Long-lived Assets" which sets forth the accounting to recognize and measure an impairment loss. This standard replaces the previous standard, SFAS 121, "Accounting for the Long-lived Assets and for Long-lived Assets to be Disposed Of." SFAS 144 will apply to us beginning January 1, 2002. We do not expect that the imple-mentation of SFAS 144 will materially affect results of operations or financial condition. The FASB recently revised its prior guidance related to SFAS 133, "Accounting for Deriviative Instruments and Hedging Activities" with regard to certain power option and forward contracts. The revised guidance states that power contracts, including both forward and option contracts, that include certain qualitative characteristics are considered capacity contracts, and qualify for the normal purchases and normal sales exception from being marked to market even if they are subject to being booked out, or scheduled to be booked out. As normal purchases and sales these open energy contracts are not marked to market. Rather they are accounted for on a settlement basis. Most of AEP's power contracts that are not marked to market as trading transactions do not qualify as derivatives and thus are not subject to the revised guidance. The few contracts that are derivatives qualified for the exception under the previous guidance and will continue to qualify under the new guidance. Common Stock and Dividend Information The quarterly high and low sales prices for AEP common stock and the cash dividends paid per share are shown in the following table: Quarter Ended High Low Dividend March 2001 $48.10 $39.25 $0.60 June 2001 51.20 45.10 0.60 September 2001 48.90 41.50 0.60 December 2001 46.95 39.70 0.60 March 2000 34.94 25.94 0.60 June 2000 38.50 29.44 0.60 September 2000 40.00 29.94 0.60 December 2000 48.94 36.19 0.60 AEP common stock is traded principally on the New York Stock Exchange. At December 31, 2001, AEP had approximately 150,000 shareholders of record. INVESTOR INQUIRIES Investors should direct inquiries to Investor Relations using the toll free number, 1-800-237-2667 or by writing to: Bette Jo Rozsa Managing Director of Investor Relations American Electric Power Service Corporation 28th Floor 1 Riverside Plaza Columbus, OH 43215-2373 FORM 10-K ANNUAL REPORT The Annual Report (Form 10-K) to the Securities and Exchange Commission will be available in April 2001 at no cost to shareholders. Please address requests for copies to: Geoffrey C. Dean Director of Financial Reporting American Electric Power Service Corporation 26th Floor 1 Riverside Plaza Columbus, OH 43215-2373 TRANSFER AGENT AND REGISTRAR OF CUMULATIVE PREFERRED STOCK Equiserve, First Chicago Division P.O. Box 2500 Jersey City, NJ 07303-2500 Phone number: 1-800-328-6955 EX-23 6 x23a.txt (A) DELOITTE & TOUCHE Exhibit 23(a) INDEPENDENT AUDITORS' CONSENT We consent to the incorporation by reference in Registration Statement Nos. 33-49577 and 33-52759 of Central Power and Light Company on Form S-3 of our reports dated February 22, 2002, appearing in and incorporated by reference in this Annual Report on Form 10-K of Central Power and Light Company for the year ended December 31, 2001. /s/ Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio March 28, 2002 EX-23 7 x23b.txt (B) CONSENT OF ARTHUR ANDERSEN LLP Exhibit 23(b) CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation of our report with respect to the Consolidated Financial Statements of Central Power and Light Company dated February 25, 2000, included in this Form 10-K, into Central Power and Light Company's previously filed registration statements on Form S-3 (File Nos. 33-49577 and 33-52759). /s/ Arthur Andersen LLP Dallas, Texas March 28, 2002 EX-24 8 x24.txt Exhibit 24 POWER OF ATTORNEY Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2001 The undersigned directors of the following companies (each respectively the "Company") Company State of Incorporation AEP Generating Company Ohio Appalachian Power Company Virginia Central Power and Light Company Texas Columbus Southern Power Company Ohio Kentucky Power Company Kentucky Ohio Power Company Ohio Public Service Company of Oklahoma Oklahoma Southwestern Electric Power Company Delaware West Texas Utilities Company Texas do hereby constitute and appoint E. LINN DRAPER, JR., ARMANDO A. PENA and SUSAN TOMASKY, and each of them, their attorneys-in-fact and agents, to execute for them, and in their names, and in any and all of their capacities, the Annual Report of the Company on Form 10-K, pursuant to Section 13 of the Securities Exchange Act of 1934, for the fiscal year ended December 31, 2001, and any and all amendments thereto, and to file the same, with all exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform every act and thing required or necessary to be done, as fully to all intents and purposes as the undersigned might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, may lawfully do or cause to be done by virtue hereof. IN WITNESS WHEREOF, the undersigned have signed these presents this 21st day of February, 2002. /s/ E. Linn Draper, Jr. /s/ Thomas V. Shockley, III /s/ Henry W. Fayne /s/ Susan Tomasky /s/ Armando A. Pena /s/ J. H. Vipperman /s/ Robert P. Powers -----END PRIVACY-ENHANCED MESSAGE-----