-----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, Rk8TOAQbmxbJwnYtKQnmZJBum65Zx2GMjF4fa7xw66LlNjB34LC6ex19kdUCTCUO TxWmHpZwLoiB3ewm1ZBpnA== 0000004904-03-000096.txt : 20030320 0000004904-03-000096.hdr.sgml : 20030320 20030320171343 ACCESSION NUMBER: 0000004904-03-000096 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 9 CONFORMED PERIOD OF REPORT: 20021231 FILED AS OF DATE: 20030320 FILER: COMPANY DATA: COMPANY CONFORMED NAME: SOUTHWESTERN ELECTRIC POWER CO CENTRAL INDEX KEY: 0000092487 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 720323455 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-03146 FILM NUMBER: 03610961 BUSINESS ADDRESS: STREET 1: 428 TRAVIS ST CITY: SHREVEPORT STATE: LA ZIP: 71156 BUSINESS PHONE: 3182222141 MAIL ADDRESS: STREET 1: 428 TRAVIS ST CITY: SHREVEPORT STATE: LA ZIP: 71156-0001 10-K 1 module.txt AEP & SUBSIDIARIES - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- UNITED STATES 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, 2002 [ ] 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 13-4922640 Corporation) 0-18135 AEP GENERATING COMPANY (An Ohio Corporation) 31-1033833 0-346 AEP TEXAS CENTRAL COMPANY (A Texas Corporation) 74-0550600 0-340 AEP TEXAS NORTH COMPANY (A Texas Corporation) 75-0646790 1-3457 APPALACHIAN POWER COMPANY (A Virginia Corporation) 54-0124790 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 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 Indicate by check mark whether American Electric Power Company, Inc. is an accelerated filer (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes X No __ Indicate by check mark whether AEP Generating Company, AEP Texas Central Company, AEP Texas North Company, Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company are accelerated filers (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes __ No X AEP Generating Company, AEP Texas North Company, Columbus Southern Power Company, Kentucky Power Company and Public Service Company of Oklahoma 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 AEP Texas Central Company None AEP Texas North Company None American Electric Common Stock, Power Company, Inc. $6.50 par value.................................. New York Stock Exchange 9.25% Equity Units................................. New York Stock Exchange Appalachian Power Company 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 Power Company None 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 Debentures, Series A, Due Power Company 2026............................................. New York Stock Exchange 7.60% Junior Subordinated Deferrable Interest Debentures, Series B, Due 2038.......... New York Stock Exchange 6% Senior Notes, Series D, Due 2032................ New York Stock Exchange Kentucky Power Company 8.72% Junior Subordinated Deferrable Interest Debentures, Series A, Due 2025.......... New York Stock Exchange Ohio Power Company 7 3/8% Senior Notes, Series A, Due 2038............ New York Stock Exchange Public Service Company 6% Senior Notes, Series B, Due 2032................ New York Stock Exchange of Oklahoma 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 Southwestern Electric None Power Company
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
REGISTRANT TITLE OF EACH CLASS ---------- ------------------- AEP Generating Company None AEP Texas Central Company 4.00% Cumulative Preferred Stock, Non-Voting, $100 par value 4.20% Cumulative Preferred Stock, Non-Voting, $100 par value AEP Texas North Company None American Electric Power Company, Inc. None Appalachian Power Company 4.50% Cumulative Preferred Stock, Voting, no 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
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 JUNE 28, 2002 JUNE 28, 2002 ------------------------ ------------------ AEP Generating Company None 1,000 ($1,000 par value) AEP Texas Central Company None 2,211,678 ($25 par value) AEP Texas North Company None 5,488,560 ($25 par value) American Electric Power Company, Inc. $13,560,125,474 338,833,720 ($6.50 par value) Appalachian Power Company None 13,499,500 (no par value) Columbus Southern Power Company None 16,410,426 (no par value) Indiana Michigan Power Company None 1,400,000 (no par value) Kentucky Power Company None 1,009,000 ($50 par value) Ohio Power Company None 27,952,473 (no par value) Public Service Company of Oklahoma None 9,013,000 ($15 par value) Southwestern Electric Power Company None 7,536,640 ($18 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, AEP Texas Central Company, AEP Texas North Company, Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power 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 Part II the fiscal year ended December 31, 2002: AEP Generating Company AEP Texas Central Company AEP Texas North Company American Electric Power Company, Inc. Appalachian Power Company Columbus Southern Power Company Indiana Michigan Power Company Kentucky Power Company Ohio Power Company Public Service Company of Oklahoma Southwestern Electric Power Company Portions of Proxy Statement of American Electric Power Part III Company, Inc. for 2003 Annual Meeting of Shareholders, to be filed within 120 days after December 31, 2002 Portions of Information Statements of the following Part III companies for 2003 Annual Meeting of Shareholders, to be filed within 120 days after December 31, 2002: Appalachian Power Company Ohio Power Company
------------------ THIS COMBINED FORM 10-K IS SEPARATELY FILED BY AEP GENERATING COMPANY, AEP TEXAS CENTRAL COMPANY, AEP TEXAS NORTH COMPANY, AMERICAN ELECTRIC POWER COMPANY, INC., APPALACHIAN POWER COMPANY, COLUMBUS SOUTHERN POWER COMPANY, INDIANA MICHIGAN POWER COMPANY, KENTUCKY POWER COMPANY, OHIO POWER COMPANY, PUBLIC SERVICE COMPANY OF OKLAHOMA AND SOUTHWESTERN ELECTRIC POWER COMPANY. INFORMATION CONTAINED HEREIN RELATING TO ANY INDIVIDUAL REGISTRANT IS FILED BY SUCH REGISTRANT ON ITS OWN BEHALF. EXCEPT FOR AMERICAN ELECTRIC POWER COMPANY, INC., EACH REGISTRANT MAKES NO REPRESENTATION AS TO INFORMATION RELATING TO THE OTHER REGISTRANTS. YOU CAN ACCESS FINANCIAL AND OTHER INFORMATION AT AEP'S WEBSITE. THE ADDRESS IS WWW.AEP.COM. AEP MAKES AVAILABLE, FREE OF CHARGE ON ITS WEBSITE, COPIES OF ITS ANNUAL REPORT ON FORM 10-K, QUARTERLY REPORTS ON FORM 10-Q, CURRENT REPORTS ON FORM 8-K AND AMENDMENTS TO THOSE REPORTS FILED OR FURNISHED PURSUANT TO SECTION 13(A) OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 AS SOON AS REASONABLY PRACTICABLE AFTER FILING SUCH MATERIAL ELECTRONICALLY OR OTHERWISE FURNISHING IT TO THE SEC. - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- TABLE OF CONTENTS
PAGE NUMBER ------ Glossary of Terms........................................................... i Forward-Looking Information................................................. 1 PART I Item 1. Business.................................................... 2 Item 2. Properties.................................................. 26 Item 3. Legal Proceedings........................................... 29 Item 4. Submission of Matters to a Vote of Security Holders......... 30 Executive Officers of the Registrants.................................... 30 PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters....................................... 32 Item 6. Selected Financial Data..................................... 32 Item 7. Management's Discussion and Analysis of Results of Operations and Financial Condition........................ 33 Item 7A. Quantitative and Qualitative Disclosures About Market Risk...................................................... 33 Item 8. Financial Statements and Supplementary Data................. 33 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.................................. 33 PART III Item 10. Directors and Executive Officers of the Registrants......... 33 Item 11. Executive Compensation...................................... 34 Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters................ 34 Item 13. Certain Relationships and Related Transactions.............. 37 PART IV Item 14. Controls and Procedures..................................... 37 Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K....................................................... 37 Signatures.................................................................. 39 Certifications.............................................................. 42 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. AEPES.................................. AEP Energy Services, Inc., a subsidiary of AEP AEP Power Pool......................... APCo, CSPCo, I&M, KPCo and OPCo, as parties to the Interconnection Agreement AEPR................................... AEP Resources, Inc., a subsidiary of AEP AEPSC or Service Corporation........... American Electric Power Service Corporation, a service subsidiary of AEP AEP System or the System............... The American Electric Power System, an integrated electric utility system, owned and operated by AEP's electric utility subsidiaries AEP Utilities.......................... AEP Utilities, Inc., subsidiary of AEP, formerly, Central and South West Corporation 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 CAA.................................... Clean Air Act CAAA................................... Clean Air Act Amendments of 1990 Cardinal Station....................... Generating facility co-owned by Buckeye and OPCo Centrica............................... Centrica U.S. Holdings, Inc., and its affiliates collectively, unaffiliated companies CERCLA................................. Comprehensive Environmental Response, Compensation and Liability Act of 1980 CG&E................................... The Cincinnati Gas & Electric Company, an unaffiliated utility company Cook Plant............................. The Donald C. Cook Nuclear Plant, owned by I&M, located near Bridgman, Michigan CSPCo. ................................ Columbus Southern Power Company, a public utility subsidiary of AEP CSW Operating Agreement................ Agreement, dated January 1, 1997, by and among PSO, SWEPCo, TCC and TNC governing generating capacity allocation 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, KPCo and OPCo ECOM................................... Excess cost over market EMF.................................... Electric and Magnetic Fields EPA.................................... United States Environmental Protection Agency ERCOT.................................. Electric Reliability Council of Texas EWG.................................... Exempt wholesale generator, as defined under PUHCA FERC................................... Federal Energy Regulatory Commission Fitch.................................. Fitch Ratings, Inc. FPA.................................... Federal Power Act FUCO................................... Foreign utility company as defined under PUHCA I&M.................................... Indiana Michigan Power Company, a public utility subsidiary of AEP I&M Power Agreement.................... Unit Power Agreement Between AEGCo and I&M, dated March 31, 1982 Interconnection Agreement.............. Agreement, dated July 6, 1951, by and among APCo, CSPCo, I&M, KPCo and OPCo, defining the sharing of costs and benefits associated with their respective generating plants IURC................................... Indiana Utility Regulatory Commission KPCo. ................................. Kentucky Power Company, a public utility subsidiary of AEP LLWPA.................................. Low-Level Waste Policy Act of 1980 LPSC................................... Louisiana Public Service Commission MECPL.................................. Mutual Energy CPL, L.P., a Texas REP and former AEP affiliate MEWTU.................................. Mutual Energy WTU, L.P., a Texas REP and former AEP affiliate MISO................................... Midwest Independent Transmission System Operator Moody's................................ Moody's Investors Service, Inc.
i
ABBREVIATION OR ACRONYM DEFINITION ----------------------- ---------- MTM.................................... Marked-to-market MW..................................... Megawatt NOx.................................... Nitrogen oxide NPC.................................... National Power Cooperatives, Inc., an unaffiliated corporation NRC.................................... Nuclear Regulatory Commission OASIS.................................. Open Access Same-time Information System OATT................................... Open Access Transmission Tariff, filed with FERC OCC.................................... Corporation Commission of the State of Oklahoma Ohio Act............................... Ohio electric restructuring legislation OPCo. ................................. Ohio Power Company, a public utility subsidiary of AEP OVEC................................... Ohio Valley Electric Corporation, an electric utility company in which AEP and CSPCo together own a 44.2% equity interest PJM.................................... PJM Interconnection, L.L.C. Pro Serv............................... AEP Pro Serv, Inc., a subsidiary of AEP PSO.................................... Public Service Company of Oklahoma, a public utility subsidiary of AEP PTB.................................... Price to beat, as defined by the Texas Act PUCO................................... The Public Utilities Commission of Ohio PUCT................................... Public Utility Commission of Texas PUHCA.................................. Public Utility Holding Company Act of 1935, as amended QF..................................... Qualifying facility, as defined under the Public Utility Regulatory Policies Act of 1978 RCRA................................... Resource Conservation and Recovery Act of 1976, as amended REP.................................... Retail electricity provider Rockport Plant......................... A generating plant, consisting of two 1,300,000-kilowatt coal-fired generating units, near Rockport, Indiana RTO.................................... Regional Transmission Organization SEC.................................... Securities and Exchange Commission S&P.................................... Standard & Poor's Ratings Service SO(2).................................. Sulfur dioxide SO(2) 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 TCC SWEPCo. ............................... Southwestern Electric Power Company, a public utility subsidiary of AEP TCA.................................... Transmission Coordination Agreement dated January 1, 1997 by and among, PSO, SWEPCo, TCC, TNC and AEPSC, which allocates costs and benefits in connection with the operation of the transmission assets of the four public utility subsidiaries TCC.................................... AEP Texas Central Company, formerly Central Power and Light Company, a public utility subsidiary of AEP TEA.................................... Transmission Equalization Agreement dated April 1, 1984 by and among APCo, CSPCo, I&M, KPCo and OPCo, which allocates costs and benefits in connection with the operation of transmission assets Texas Act.............................. Texas electric restructuring legislation TNC.................................... AEP Texas North Company, formerly West Texas Utilities Company, a public utility subsidiary of AEP TVA.................................... Tennessee Valley Authority UCOS................................... Unbundled cost of service Virginia Act........................... Virginia electric restructuring legislation VSCC................................... Virginia State Corporation Commission WVPSC.................................. West Virginia Public Service Commission West Zone Companies of AEP............. PSO, SWEPCo, TCC and TNC
ii FORWARD-LOOKING INFORMATION - -------------------------------------------------------------------------------- This report made by AEP and certain of its subsidiaries contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. Although AEP and each of its subsidiaries believe that their expectations are based on reasonable assumptions, any such statements may be influenced by factors that could cause actual outcomes and results to be materially different from those projected. Among the factors that could cause actual results to differ materially from those in the forward-looking statements are: - Electric load and customer growth. - Abnormal weather conditions - Available sources and costs of fuels. - Availability of generating capacity. - The speed and degree to which competition is introduced to AEP's power generation business. - The ability to recover stranded costs in connection with possible/proposed deregulation of generation. - New legislation and government regulation - Oversight and/or investigation of the energy sector or its participants. - The ability of AEP to successfully control its costs. - The success of acquiring new business ventures and disposing of existing investments that no longer match AEP's corporate profile. - International and country-specific developments affecting AEP's foreign investments, including the disposition of any current foreign investments and potential additional foreign investments. - The economic climate and growth in AEP's service territory and changes in market demand and demographic patterns. - Inflationary trends. - Electricity and gas market prices. - Interest rates. - Liquidity in the banking, capital and wholesale power markets. - Actions of rating agencies. - Changes in technology, including the increased use of distributed generation within AEP's transmission and distribution service territory. - Other risks and unforeseen events, including wars, the effects of terrorism, embargoes and other catastrophic events. 1 PART I - -------------------------------------------------------------------------------- Item 1. BUSINESS - -------------------------------------------------------------------------------- GENERAL OVERVIEW AND DESCRIPTION OF SUBSIDIARIES AEP was incorporated under the laws of the State of New York in 1906 and reorganized in 1925. It is a registered public utility holding company under PUHCA that owns, directly or indirectly, all of the outstanding common stock of its public utility subsidiaries and varying percentages of other subsidiaries. The service areas of AEP's public utility subsidiaries cover 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 public utility subsidiaries are 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 public 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. Restructuring legislation in Michigan, Ohio, Texas and Virginia has caused or will cause AEP public utility subsidiaries in those states to unbundle previously integrated regulated rates for their retail customers. 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 and transportation and handling of fuel. The member companies of the AEP System also obtain certain accounting, administrative, information systems, engineering, financial, legal, maintenance and other services at cost from a common provider, AEPSC. At December 31, 2002, the subsidiaries of AEP had a total of 22,083 employees. AEP, because it is a holding company rather than an operating company, has no employees. The public utility subsidiaries of AEP are: APCo (organized in Virginia in 1926) is engaged in the generation, transmission and distribution of electric power to approximately 925,000 retail customers in the southwestern portion of Virginia and southern West Virginia, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities and other market participants. At December 31, 2002, APCo and its wholly owned subsidiaries had 2,520 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 Virginia Electric and Power Company. APCo has several points of interconnection with TVA and has entered into agreements with TVA under which APCo and TVA interchange and transfer electric power over portions of their respective systems. CSPCo (organized in Ohio in 1937, the earliest direct predecessor company having been organized in 1883) is engaged in the generation, transmission and distribution of electric power to approximately 689,000 retail customers in Ohio, and in supplying and marketing electric power at wholesale to other electric utilities, municipalities and other market participants. At December 31, 2002, CSPCo had 1,171 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. I&M (organized in Indiana in 1925) is engaged in the generation, transmission and distribution of electric power to approximately 571,000 retail customers in northern and eastern Indiana and southwestern Michigan, and in supplying and marketing electric power at wholesale to other electric utility companies, rural electric cooperatives, municipalities and other market participants. At December 31, 2002, I&M had 2,667 employees. Among the principal industries served are primary metals, transportation equipment, electrical and electronic 2 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. KPCo (organized in Kentucky in 1919) is engaged in the generation, transmission and distribution of electric power to approximately 174,000 retail customers in an area in eastern Kentucky, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities and other market participants. At December 31, 2002, KPCo had 412 employees. In addition to its AEP System interconnections, KPCo also is interconnected with the following unaffiliated utility companies: Kentucky Utilities Company and East Kentucky Power Cooperative Inc. KPCo is also interconnected with TVA. Kingsport Power Company (organized in Virginia in 1917) provides electric service to approximately 46,000 retail customers in Kingsport and eight neighboring communities in northeastern Tennessee. Kingsport Power Company does not own any generating facilities. It purchases electric power from APCo for distribution to its customers. At December 31, 2002, Kingsport Power Company had 57 employees. OPCo (organized in Ohio in 1907 and re-incorporated in 1924) is engaged in the generation, transmission and distribution of electric power to approximately 702,000 retail customers in the northwestern, east central, eastern and southern sections of Ohio, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities and other market participants. At December 31, 2002, OPCo had 1,988 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, transmission and distribution of electric power to approximately 505,000 retail customers in eastern and southwestern Oklahoma, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities, rural electric cooperatives and other market participants. At December 31, 2002, PSO had 998 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. In addition to its AEP System interconnections, PSO also is interconnected with Ameren Corporation, Empire District Electric Co., Oklahoma Gas & Electric Co., Southwestern Public Service Co. and Westar Energy Inc. SWEPCo (organized in Delaware in 1912) is engaged in the generation, transmission and distribution of electric power to approximately 437,000 retail customers in northeastern Texas, northwestern Louisiana and western Arkansas, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities, rural electric cooperatives and other market participants. At December 31, 2002, SWEPCo had 1,372 employees. Among the principal industries served by SWEPCo are natural gas and oil production, petroleum 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. In addition to its AEP System interconnections, SWEPCo is also interconnected with CLECO Corp., Empire District Electric Co., Entergy Corp. and Oklahoma Gas & Electric Co. TCC (organized in Texas in 1945) is engaged in the generation, transmission and sale of power to affiliated and non-affiliated entities and the distribution of electric power to approximately 689,000 retail customers through REPs in southern Texas, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities, rural electric cooperatives and other market 3 participants. At December 31, 2002, TCC had 1,248 employees. Among the principal industries served by TCC are oil and gas extraction, food processing, apparel, metal refining, chemical and petroleum refining, plastics, and machinery equipment. In addition to its AEP System interconnections, TCC is a member of ERCOT. TNC (organized in Texas in 1927) is engaged in the generation, transmission and sale of power to affiliated and non-affiliated entities and the distribution of electric power to approximately 189,000 retail customers through REPs in west and central Texas, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities, rural electric cooperatives and other market participants. At December 31, 2002, TNC had 595 employees. The principal industry served by TNC is agriculture. The territory served by TNC also includes several military installations and correctional facilities. In addition to its AEP System interconnections, TNC is a member of ERCOT. Wheeling Power Company (organized in West Virginia in 1883 and reincorporated in 1911) provides electric service to approximately 41,000 retail customers in northern West Virginia. Wheeling Power Company does not own any generating facilities. It purchases electric power from OPCo for distribution to its customers. At December 31, 2002, Wheeling Power Company had 59 employees. AEGCo (organized in Ohio in 1982) is an electric generating company. AEGCo sells power at wholesale to I&M and KPCo. AEGCo has no employees. Service Company Subsidiary AEP also owns a service company subsidiary, AEPSC. AEPSC 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 AEPSC. At December 31, 2002, AEPSC had 6,548 employees. CLASSES OF SERVICE The principal classes of service from which the public utility subsidiaries of AEP derive revenues and the amount of such revenues during the year ended December 31, 2002 are as follows:
AEP SYSTEM(A) APCo CSPCo I&M KPCo ----------- ---------- ---------- ---------- --------- (IN THOUSANDS) Wholesale Business: Residential........................ $ 3,713,000 $ 616,509 $ 533,061 $ 371,329 $ 118,654 Commercial......................... 2,156,000 276,238 442,847 224,843 50,075 Industrial......................... 1,903,000 353,841 138,174 330,428 96,716 Other Retail Customers............. 385,000 80,429 38,018 61,450 16,911 Energy Delivery.................... (3,551,000) (594,089) (492,278) (321,721) (132,054) ----------- ---------- ---------- ---------- --------- Total Retail.................... 4,606,000 732,928 659,822 666,329 150,302 Marketing and Trading-Electricity............. 2,227,000 204,878 134,836 279,705 50,056 Marketing and Trading-Gas.......... 3,021,000 0 0 0 0 Unrealized MTM Income: Electric........................ 136,000 18,089 13,388 0 0 Gas............................. (399,000) 0 0 0 0 Other.............................. 1,397,000 264,486 99,836 259,009 46,271 ----------- ---------- ---------- ---------- --------- Total Wholesale Business........ 10,988,000 1,220,381 907,882 1,205,043 246,629 ----------- ---------- ---------- ---------- --------- Energy Delivery Business: Transmission....................... 922,000 186,960 107,673 118,812 50,381 Distribution....................... 2,629,000 407,129 384,605 202,909 81,673 ----------- ---------- ---------- ---------- --------- Total Energy Delivery........... 3,551,000 594,089 492,278 321,721 132,054 ----------- ---------- ---------- ---------- --------- Total Other Investments......... 16,000 0 0 0 0 ----------- ---------- ---------- ---------- --------- Total Revenues................ $14,555,000 $1,814,470 $1,400,160 $1,526,764 $ 378,683 =========== ========== ========== ========== =========
4
OPCo PSO SWEPCo TCC TNC ---------- --------- ---------- ---------- -------- (IN THOUSANDS) Wholesale Business: Residential........................... $ 475,210 $ 315,711 $ 313,023 $ 49,210 $ 8,651 Commercial............................ 244,943 218,718 212,626 32,518 4,098 Industrial............................ 531,085 162,386 214,622 12,395 2,134 Other Retail Customers................ 71,737 38,998 33,104 3,594 1,638 Energy Delivery....................... (589,673) (275,547) (348,236) (554,547) (73,353) ---------- --------- ---------- ---------- -------- Total Retail....................... 733,302 460,266 425,139 (456,830) (56,832) Marketing and Trading-Electricity..... 219,488 17,394 157,159 811,800 283,883 Marketing and Trading-Gas............. 0 0 0 0 0 Unrealized MTM Income: Electric........................... 25,574 0 (3,686) (8,490) (1,473) Gas................................ 0 0 0 0 0 Other................................. 545,088 40,440 157,872 789,466 151,809 ---------- --------- ---------- ---------- -------- Total Wholesale Business........... 1,523,452 518,100 736,484 1,135,946 377,387 ---------- --------- ---------- ---------- -------- Energy Delivery Business: Transmission.......................... 162,660 63,178 92,076 68,003 25,273 Distribution.......................... 427,013 212,369 256,160 486,544 48,080 ---------- --------- ---------- ---------- -------- Total Energy Delivery.............. 589,673 275,547 348,236 554,547 73,353 ---------- --------- ---------- ---------- -------- Total Other Investments............ 0 0 0 0 0 ---------- --------- ---------- ---------- -------- Total Revenues................... $2,113,125 $ 793,647 $1,084,720 $1,690,493 $450,740 ========== ========= ========== ========== ========
- --------------- (a) Includes revenues of other subsidiaries not shown. Intercompany transactions have been eliminated, including AEGCo's total revenues of $213,281,000 for the year ended December 31, 2002, all of which resulted from its wholesale business, including its marketing and trading of power. REGULATION Except for retail generation sales in Ohio, Virginia and the ERCOT area of Texas, AEP's public utility subsidiaries' retail rates and certain other matters are subject to traditional regulation by the state utility commissions. Retail sales in Michigan, while still regulated, are now made at unbundled rates. Other states in AEP's service territory have also passed restructuring legislation that has not been implemented or has been repealed. See Electric Restructuring and Customer Choice Legislation and Energy Delivery--Regulation--Rates. AEP's subsidiaries are also subject to regulation by the FERC under the FPA. I&M and TCC 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. AEP and its subsidiaries are also subject to the broad regulatory provisions of PUHCA administered by the SEC. FERC Under the FPA, FERC regulates rates for interstate sales at wholesale, transmission of electric power, accounting and other matters, including construction and operation of hydroelectric projects. FERC regulations require AEP to provide open access transmission service at FERC-approved rates. The transmission service regulated by FERC is predominantly wholesale transmission service, which is service not associated with bundled electricity sales to retail customers. FERC also regulates unbundled transmission service to retail customers. Under the FPA, the FERC regulates the sale of power for resale in interstate commerce by (i) approving contracts for wholesale sales to municipal and cooperative utilities and (ii) granting authority to public utilities to sell power at wholesale at market-based rates upon a showing that the seller lacks the ability to improperly influence market prices. AEP has 5 market-rate authority from FERC, under which most of its wholesale marketing activity takes place. In November 2001, the FERC issued an order in connection with its triennial review of AEP's market based pricing authority requiring (i) certain actions by AEP in connection with its sales and purchases within its control area and (ii) posting of information related to generation facility status on AEP's website. AEP has appealed this order, and the FERC has issued an order delaying the effective date of the order. See Note 9 to the consolidated financial statements, entitled Commitments and Contingencies, incorporated by reference in Item 8, for more information on the current status of this proceeding. SEC The provisions of PUHCA, administered by the SEC, regulate many aspects of a registered holding company system, such as the AEP System. PUHCA limits the operations of a registered holding company system 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. 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. The Division of Investment Management of the SEC has recommended the conditional repeal of PUHCA. Under its recommendation, certain oversight authority would be transferred to the FERC. Legislation has since been introduced in numerous sessions of Congress that would repeal PUHCA, but such legislation has not passed. AEP-CSW MERGER On June 15, 2000, CSW (now known as AEP Utilities, Inc.) merged with and into a wholly-owned merger subsidiary of AEP. As a result, CSW became a wholly owned subsidiary of AEP. The four wholly owned public utility subsidiaries of CSW--PSO, SWEPCo, TCC and TNC--became indirect wholly owned public utility subsidiaries of AEP as a result of the merger. The merger was approved by the FERC and the SEC (with respect to PUHCA). On January 18, 2002, the U.S. Court of Appeals for the District of Columbia ruled that the SEC failed to properly explain how the merger met the requirements of PUHCA and remanded the case to the SEC for further review. The court held that the SEC had not adequately explained its conclusions that the merger met PUHCA requirements that the merging entities be "physically interconnected" and that the combined entity was confined to a "single area or region." Management believes that the merger meets the requirements of PUHCA and expects the matter to be resolved favorably. ELECTRIC RESTRUCTURING AND CUSTOMER CHOICE LEGISLATION Certain states in AEP's service area have adopted restructuring or customer choice legislation. In general, this legislation provides for a transition from bundled cost-based rate regulated 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. At a minimum, this legislation allows retail customers to select alternative generation suppliers. Electric restructuring and/or customer choice began on January 1, 2001 in Ohio and on January 1, 2002 in Michigan, Virginia and the ERCOT area of Texas. Electric restructuring in the SPP area of Texas, also scheduled to begin on January 1, 2002, has been delayed by the PUCT. AEP's public utility subsidiaries operate in both the ERCOT and SPP areas of Texas. Implementation of legislation enacted in Oklahoma and West Virginia to allow retail customers to choose their electricity supplier is on hold. In 2001 Oklahoma delayed implementation of customer choice indefinitely. Before West Virginia's choice plan can be effective, tax legislation must be passed to preserve pre-legislation levels of funding for state and local governments. No further legislation has been passed related to restructuring in West Virginia. In February 2003, Arkansas repealed its restructuring legislation. See Note 7 to the consolidated financial statements, entitled Effects of Regulation, incorporated by reference in Item 8, for a discussion of the effect of restructuring and customer choice legislation on accounting procedures. See Management's Discussion 6 and Analysis of Results of Operations and Financial Condition, under the headings entitled Industry Restructuring and Corporate Separation for a discussion of AEP's corporate separation plan filed with the FERC and related settlement agreements with state commissions and other intervenors. Michigan Customer Choice Customer choice commenced for I&M's Michigan customers on January 1, 2002. Rates for retail electric service for I&M's Michigan customers were unbundled (though they continue to be regulated) to allow customers the ability to evaluate the cost of generation service for comparison with other suppliers. At December 31, 2002, none of I&M's Michigan customers had elected to change suppliers and no alternative electric suppliers are registered to compete in I&M's Michigan service territory. Ohio Restructuring The Ohio Act requires vertically integrated electric utility companies that offer competitive retail electric service in Ohio to separate their generating functions from their transmission and distribution functions. Following the market development period (which will terminate no later than December 31, 2005), retail customers will receive distribution and, where applicable, transmission service from the incumbent utility whose distribution rates will be approved by the PUCO and whose transmission rates will be approved by the FERC. See General--Regulation--FERC for a discussion of FERC regulation of transmission rates and Energy Delivery--Regulation--Rates--Ohio for a discussion of the impact of restructuring on distribution rates. CSPCo and OPCo are each presently operating as functionally separated electric utility companies and no longer charge bundled rates for retail electric service. Each has sought and, from certain regulatory authorities, obtained regulatory approval to legally separate its transmission and distribution assets from its generation assets. CSPCo and OPCo are, however, currently determining the regulatory feasibility of complying with restructuring legislation through continued functional separation. Assuming regulatory compliance, it is currently their intention to remain functionally separated. Texas Restructuring The Texas Act substantially amends the regulatory structure governing electric utilities in Texas in order to allow retail electric competition for all customers and requires each utility to separate into (i) a REP, (ii) a power generation company and (iii) a transmission and distribution utility. Upon separation, neither the REP nor the power generation company will be subject to traditional cost of service rate regulation. See Energy Delivery--Regulation-- Rates--Texas for a discussion of the impact of restructuring on rates. SWEPCo, TCC and TNC initially filed a restructuring plan in January 2000 (which they subsequently updated) that the PUCT approved in February 2002. The updated restructuring plan provided for the legal separation of TCC's and TNC's assets in accordance with the Texas Act into (i) an affiliate power generation company, (ii) a transmission and distribution utility and (iii) various REPs, including those subsequently purchased by Centrica (see below). TCC and TNC continue to pursue legal separation as required by the Texas Act. The PUCT has delayed the implementation of the plan for SWEPCo operations within the SPP area of Texas. Under the Texas Act, a REP, which itself cannot own any generation assets, obtains its electricity from power generation companies, EWGs and other generating entities and provides services at generally unregulated rates, except that the prices that may be charged to residential and small commercial customers by REPs affiliated with a utility within the affiliated utility's service area are set by the PUCT until January 1, 2007. This set price is referred to as the "price to beat" rate (PTB). Affiliate REPs are required to offer the PTB rate to all residential and small commercial customers (with a peak usage of less than 1,000 KW) effective January 1, 2002. As described below, AEP sold its affiliate REPs that must provide PTB service. The PTB rate is still relevant to AEP, however, in determining (i) the contingent portion of the sales price of the affiliate REPs AEP sold and (ii) certain of AEP's obligations in the 2004 true-up proceedings. Prior to the start of retail competition in January 2002, AEP formed MECPL and MEWTU to act as affiliate REPs for TCC and TNC respectively. MECPL and MEWTU were sold in December 2002 to Centrica, which assumed all of the rights and obligations of an affiliated REP, including the provision of PTB service and the obligation to provide data necessary for TCC's and TNC's 2004 true-up proceeding. In connection with the sale, TCC and TNC have contracted to supply approximately 90% of MECPL's and 7 MEWTU's respective power requirements relating to former TCC and TNC PTB customers for a two-year period. See Note 12 to the consolidated financial statements, entitled Acquisitions, Distributions and Discontinued Operations, incorporated by reference in Item 8, for more information on the sale of these REPs and AEP's contractual rights and obligations in connection with the sale. The Texas Act also allows certain transmission and distribution utilities whose generation assets were unbundled to recover certain regulatory assets and stranded costs related to their generation assets. For a discussion of (i) regulatory assets and stranded costs subject to recovery by TCC and (ii) rate adjustments made after implementation of restructuring to allow recovery of certain costs by or with respect to TCC and TNC, see Energy Delivery--Regulatory Assets, Stranded Cost Recovery and Certain Post-Restructuring Rate Adjustments. Virginia Restructuring The Virginia Act was enacted in 1999 providing for retail choice of generation suppliers to be phased in over the January 1, 2002 to January 1, 2004 period. The Virginia Act required jurisdictional utilities to unbundle their power supply and energy delivery rates and to file functional separation plans by January 1, 2002. APCo filed its plan and, following VSCC approval of a settlement agreement, now operates in Virginia as a functionally separated electric utility charging unbundled rates for its retail sales of electricity. The settlement agreement addressed functional separation, leaving decisions related to legal separation for later VSCC consideration. FINANCING General AEP's goal is to use cash from operations to fund capital expenditures, dividends and working capital. Short-term debt is used as an interim bridge for timing differences in the need for cash or to fund debt maturities until permanent financing is arranged. It has been the practice of AEP's operating subsidiaries to finance current construction expenditures in excess of available cash from operations by initially incurring short-term debt, 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. In the past, short-term debt has come from AEP's commercial paper program and revolving credit facilities. Proceeds were loaned to the subsidiaries through intercompany notes under the AEP money pool. The recent downgrade of AEP's commercial paper rating by Moody's, described below, may limit AEP's access to commercial paper on terms as favorable as those of recent years. Therefore, AEP may establish commercial paper programs for certain of its public utility subsidiaries and AEP Utilities. Certain public utility subsidiaries of AEP also sell accounts receivable to provide liquidity. AEP's revolving credit agreements (which backstop the commercial paper program) 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, 2002, 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. AEP's subsidiaries have also utilized, and expect to continue to utilize, additional financing arrangements, such as leasing arrangements, including the leasing of utility assets and coal mining and transportation equipment and facilities. Credit Ratings The rating agencies have been conducting credit reviews of AEP and its registrant subsidiaries. The agencies are also reviewing many companies in the energy sector due to issues that impact the entire industry. In February 2003 Moody's completed its review of AEP and its rated subsidiaries. The results of that review were downgrades of the following ratings for unsecured debt: AEP from Baa2 to Baa3, APCo from Baa1 to Baa2, TCC from Baa1 to Baa2, PSO from A2 to Baa1, SWEPCo from A2 to Baa1. TNC, which had no senior unsecured notes outstanding at the time of the ratings action, had its mortgage bond debt downgraded from A2 to A3. AEP's commercial paper was also concurrently downgraded from P-2 to P-3. The completion of this review was a culmination of earlier ratings action in 2002 that had included a downgrade of AEP from Baa1 to Baa2. With the completion of the reviews, Moody's has placed AEP and its rated subsidiaries on stable outlook. 8 In March 2003 S&P completed its review of AEP and its rated subsidiaries. The results of that review were downgrades of the ratings for unsecured debt for AEP and its rated subsidiaries from BBB+ to BBB. AEP's commercial paper rating was affirmed at A-2. With the completion of the reviews, S&P has placed AEP and its rated subsidiaries on stable outlook. In March 2003 Fitch completed its review of AEP. The result of that review was a downgrade of AEP's unsecured debt rating from BBB+ to BBB. AEP's commercial paper rating was affirmed at F-2. With the completion of the reviews, Fitch has placed AEP and its rated subsidiaries on stable outlook. See Management's Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters, incorporated by reference in Item 7, under the heading entitled Financial Condition for additional information with respect to AEP's credit ratings, liquidity and specific financing activities. ENVIRONMENTAL AND OTHER MATTERS General AEP's subsidiaries are currently 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. The environmental issues that are potentially material to the AEP system include: - The CAA and CAAA and state laws and regulations (including State Implementation Plans) that require compliance, obtaining permits and reporting as to air emissions. - Litigation with the federal and certain state governments and certain special interest groups regarding whether modifications to or maintenance of certain coal-fired generating plants required additional permitting or pollution control technology. See Management's Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters under the heading entitled Federal EPA Complaint and Notice of Violation and Note 9 to the consolidated financial statements entitled Commitments and Contingencies, incorporated by reference in Items 7 and 8 respectively for further information. - Rules issued by the EPA and certain states that require substantial reductions in NOx emissions. The compliance dates for these rules range from 2003 to 2005. AEP is installing (or has installed) emission control technology and is taking other measures to comply with required reductions. See Management's Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters and Note 9 to the consolidated financial statements entitled Commitments and Contingencies, incorporated by reference in Items 7 and 8 respectively, under the heading entitled NOx Reductions for further information. - CERCLA, which imposes upon owners and previous owners of sites, as well as transporters and generators of hazardous material disposed of at such sites, costs for environmental remediation. AEP does not, however, anticipate that any of its currently identified CERCLA-related issues will result in material costs or penalties to the AEP System. See Management's Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters, incorporated by reference in Item 7, under the heading entitled Superfund for further information. - The Federal Clean Water Act, which prohibits the discharge of pollutants into waters of the United States except pursuant to appropriate permits. There are, however, no matters material to the AEP System currently pending under the Clean Water Act. - Solid and hazardous waste laws and regulations, which govern the management and disposal of certain wastes. The majority of solid waste created from the combustion of coal and fossil fuels is fly ash and other coal combustion byproducts, which the EPA has determined are not hazardous waste governed subject to RCRA. 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. AEP's subsidiaries will confront several new environmental policies and regulations over the next decade with the potential for substantial control costs and premature retirement of some generating plants. These could include (i) new or additional controls on sulfur dioxide, NOx and mercury emissions from future laws or regulations, or the possibility of an 9 adverse decision in the new source review litigation; (ii) a new Clean Water Act rule to reduce fish and other aquatic organisms killed at once-through cooled power plants; (iii) finalization and implementation of more stringent water quality-based permit limits; and (iv) a possible future requirement to reduce carbon dioxide emissions. See Management's Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters, incorporated by reference in Item 7, under the heading entitled Environmental Concerns and Issues for information on current environmental issues. AEP expects costs related to environmental controls to eventually be reflected in some jurisdictions in the rates of AEP's public utility subsidiaries. In Michigan, Ohio, Texas and Virginia, those costs may not be recoverable if future market prices for electricity generated by plants in those jurisdictions are insufficient to permit AEP to recover such costs. 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 of these costs. There can be no assurance that these costs will be recovered. AEP's international operations are subject to environmental regulation 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 named as parties to various legal claims, actions, complaints or other proceedings related to environmental matters. AEP's UK generation facilities will be subject to additional environmental constraints in 2008 (which become more stringent after 2015) because they are subject to regulation governing large combustion plants. In the fourth quarter of 2002, AEP decided not to install certain emission control technology on its Fiddler's Ferry and Ferrybridge generation facilities in 2008. This decision and its legal and regulatory consequences will result in a significant reduction in the estimated economic life of those facilities. The cost of complying with applicable environmental laws, regulations and rules is expected to be material to the AEP System. See Management's Discussion and Analysis of Results of Operations and Management's Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters and Note 9 to the consolidated financial statements entitled Commitments and Contingencies, incorporated by reference in Items 7 and 8, respectively, for further information with respect to environmental matters. Environmental Expenditures Expenditures related to generation facility compliance with air and water quality standards during 2001 and 2002 and the current estimate for 2003 are shown below. Substantial expenditures in addition to the amounts set forth below may be required by the System in future years in connection with the modification and addition of facilities at generating plants for environmental quality controls in order to comply with air and water quality standards which have been or may be adopted. Future expenditures could be significantly greater if litigation regarding whether AEP properly installed emission control equipment on its plants is resolved against AEP. See Note 9 to the consolidated financial statements, entitled Commitments and Contingencies, incorporated by reference in Item 8, for more information regarding this litigation and environmental expenditures in general.
2001 2002 2003 ACTUAL ACTUAL ESTIMATE -------- -------- -------- (IN THOUSANDS) AEGCo................ $ 3,500 $ 1,200 $ 11,200 APCo................. 99,200 108,400 65,700 CSPCo................ 22,500 25,400 39,300 I&M.................. 700 1,200 18,500 KPCo................. 11,200 110,600 39,900 OPCo................. 125,300 110,300 53,100 PSO.................. 400 1,200 100 SWEPCo............... 9,200 3,400 9,000 TCC.................. 2,500 600 0 TNC.................. 800 1,900 0 -------- -------- -------- AEP System........... $275,300 $364,200 $236,800 ======== ======== ========
Electric and Magnetic Fields EMF are 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 10 EMF and health effects, none has produced any conclusive evidence that EMF does or does not cause adverse health effects. 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 customers. WHOLESALE OPERATIONS GENERAL AEP conducts its wholesale business operations through its public utility subsidiaries (through which AEP also conducts its energy delivery operations), AEPES, AEPR and Pro Serv. Wholesale operations use and manage the following assets: - Power generation facilities (or interests therein) owned by AEP's public utility and other subsidiaries; - Natural gas pipeline, storage and processing facilities; - Coal mines and related facilities; and - Barge, rail and other fuel transportation related assets. Wholesale operations include the following activities: - Through AEP's public utility subsidiaries, the generation and sale of power (i) to retail customers at unbundled or bundled rates regulated at least in part by state public utility commissions and (ii) at wholesale at rates regulated, in certain instances, by the FERC. - Trading and marketing energy commodities in transactions predominantly limited to risk management around assets used or managed by AEP's wholesale operations, including electric power, natural gas, natural gas liquids, oil, coal, and SO(2) allowances in North America and, where applicable, Europe. Electric power transactions in the United States are conducted principally through AEP's public utility subsidiaries. Other energy commodity and allowances transactions are conducted through AEPES and AEPR. - Entering into 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. - Through Pro Serv, providing engineering, construction, project management and other consulting services for energy-related projects. In October 2002 AEP announced its plans to reduce the exposure to energy trading markets and to downsize the trading and wholesale marketing operations. It is expected that in the future power trading and marketing operations will be smaller in scope and size, will generally be limited to risk management around AEP's assets and, accordingly, focused in those regions in which AEP owns assets. POWER GENERATION General Power generation accounts for the majority of wholesale operations revenue. In 2002, on an as-reported basis, power generation revenue included the following components: (i) 63% from retail sales at predominantly regulated rates; (ii) 33% from power marketing transactions of a type AEP intends to continue and which are regulated in certain instances by the FERC; (iii) 3% from retail sales at rates not regulated by states; and (iv) 1% attributable to power marketing transactions of a type that management has stated are transitional. This final category of transactions will be reduced consistent with AEP's decision to scale back certain trading and marketing operations as described in the preceding paragraph. AEP's public utility subsidiaries own approximately 38,000 MW of domestic generation. See Deactivation and Planned Disposition of Generating Facilities for a discussion of planned reductions in AEP's generating fleet. Other AEP subsidiaries hold interests in entities owning 1,879 MW of domestic power facilities and 5,235 MW of international power facilities. The AEP public utility subsidiaries operate their generating plants as a single interconnected and coordinated electric utility system. See Item 2 - Properties for more information regarding generation facilities. 11 AEP Power Pool and CSW Operating Agreement APCo, CSPCo, I&M, KPCo and OPCo are parties to the Interconnection Agreement, dated July 6, 1951, as amended (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." The member-load ratio is calculated monthly by dividing such company's highest monthly peak demand for the last twelve months by the aggregate of the highest monthly peak demand for the last twelve months for all east zone operating companies. As of December 31, 2002, the member-load ratios were as follows:
PEAK DEMAND MEMBER-LOAD (KW) RATIO (%) ------ ----------- APCo..................... 6,010 28.2 CSPCo.................... 4,040 19.0 I&M...................... 4,323 20.3 KPCo..................... 1,551 7.3 OPCo..................... 5,360 25.2
Although the FERC has approved the right of withdrawal of CSPCo and OPCo from the AEP Power Pool as part of its order approving the settlement agreements and AEP's FERC restructuring application, CSPCo and OPCo have remained a party to the AEP Power Pool. If CSPCo and OPCo continue to remain in the AEP Power Pool, notification to or approval by the FERC may be required. See Management's Discussion and Analysis of Results of Operations and Financial Condition, under the headings entitled Industry Restructuring and Corporate Separation for a discussion of AEP's corporate separation plan filed with the FERC and related settlement agreements with state commissions and other intervenors. The following table shows the net credits or (charges) allocated among the parties under the Interconnection Agreement and AEP System Interim Allowance Agreement during the years ended December 31, 2000, 2001 and 2002:
2000 2001 2002 --------- --------- --------- (IN THOUSANDS) APCo. ............... $(274,000) $(256,700) $(127,000) CSPCo................ (250,400) (251,200) (267,000) I&M.................. 93,900 166,200 113,600 KPCo. ............... (21,500) (27,600) (46,500) OPCo. ............... 452,000 369,300 326,900
PSO, SWEPCo, TCC and TNC, and AEPSC 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 west zone public utility subsidiaries 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 west zone 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 following table shows the net credits or (charges) allocated among the parties under the CSW Operating Agreement during the years ended December 31, 2000, 2001 and 2002:
2000 2001 2002 ------- ------- -------- (IN THOUSANDS) PSO.................. $(9,000) $(6,500) $(53,700) SWEPCo............... 55,400 62,300 67,800 TCC.................. 3,600 (13,500) 15,400 TNC.................. (50,000) (42,300) (29,500)
Power generated by or allocated or provided under the Interconnection Agreement or CSW Operating Agreement to any public utility subsidiary is often sold to customers (or in the case of the ERCOT area of Texas, REPs) by such public utility subsidiary at rates approved (other than in the ERCOT area of Texas) by the public utility commission in the jurisdiction of sale. In Ohio, Virginia and the ERCOT area of Texas, such rates are based on a statutory formula as those jurisdictions transition to the use of market rates for generation. See Energy Delivery -- Regulation -- Rates. Under the Interconnection Agreement, power allocated to a public utility subsidiary that is not required to serve its native load is sold at wholesale on behalf of such subsidiary. Under the CSW Operating Agreement, power generated that is not needed to serve the native load of any public utility subsidiary is sold at wholesale by the generating subsidiary. See Trading and Marketing of Energy Commodities for a discussion of the trading and marketing of such power. 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 distribu- 12 tion, 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 Interconnection Agreement and the CSW Operating Agreement, each of which controls the distribution of costs and benefits within each zone. Competition and Regulation Retail Sales: AEP's public utility subsidiaries have the right (which in some cases is exclusive) to sell electric power at retail within their respective service areas in the states of Arkansas, Indiana, Kentucky, Louisiana, Oklahoma, Tennessee, West Virginia and the SPP area of Texas. In Michigan, Ohio and Virginia, AEP's public utility subsidiaries continue to provide service to customers who have not been offered or have not selected alternate service from competing suppliers. In those states, service is currently being provided according to prescribed rules and rates. In the ERCOT area of Texas, TCC and TNC sell power to Centrica, which provides PTB service to certain former customers of TCC and TNC and must compete for customers. AEP's public utility subsidiaries also 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 competing generators and self-generation, the public utility subsidiaries of AEP believe that they generally maintain a favorable competitive position. 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 customers in the United States, including those served by the AEP System. Some of these industrial customers have requested price reductions from their suppliers of electric power. In addition, industrial customers that 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, providing various off-peak or interruptible supply options pursuant to tariffs filed with the various state commissions. Occasionally, these rates are first negotiated, and then filed with the state commissions. The public utility subsidiaries believe that they are unlikely to be materially adversely affected by this competition. See Energy Delivery -- Regulation -- Rates for a description of the setting of rates for power sold at bundled or unbundled state-regulated rates. Wholesale Sales: The public utility subsidiaries of AEP, like the electric industry generally, face increasing competition in the sale of available power on a wholesale basis, primarily to other public utilities and power marketers. The Energy Policy Act of 1992 was designed, among other things, to foster competition in the wholesale market by creating a generation market with fewer barriers to entry and mandating that all generators have equal access to transmission services. As a result, there are more generators able to participate in this market. The principal factors in competing for wholesale sales are price (including fuel costs), availability of capacity and power and reliability of service. The public utility subsidiaries of AEP are subject to regulation by the FERC under the Federal Power Act in respect of rates for interstate sales at wholesale. See General -- Regulation -- FERC. Seasonality Sale of electric power is generally a seasonal business. In many parts of the country, demand for power peaks during the hot summer months, with market prices also peaking at that time. In other areas, power demand peaks during the winter. The pattern of this fluctuation may change due to the nature and location of AEP's facilities and the terms of power sale contracts AEP enters into. In addition, AEP has historically sold less power, and consequently earned less income, when weather conditions are milder. Unusually mild weather in the future could diminish AEP's results of operations and may impact its financial condition. 13 Fuel Supply The following table shows the sources of power generated by the AEP System:
2000 2001 2002 ---- ---- ---- Coal........................ 78% 74% 78% Natural Gas................. 13% 12% 8% Nuclear..................... 5% 11% 11% Hydroelectric and other..... 4% 3% 3%
Variations in the generation of nuclear power are primarily related to refueling outages and, in a portion of 2000, the shutdown of the Cook Plant to respond to issues raised by the NRC. Variations in the generation of natural gas power are primarily related to the availability of cheaper alternatives to fulfill certain power requirements and to deactivate certain of its gas-fired plants. Coal and Lignite: AEP System generating companies procure coal and lignite under a combination of purchasing arrangements including long-term contracts, affiliate operations, short-term, and spot agreements with various producers and coal trading firms. AEP believes, but cannot provide assurances that, it will be able to secure coal and lignite of adequate quality and in adequate quantities to operate its coal and lignite-fired units. The following table shows the amount of coal delivered to the AEP System during the past three years and the average delivered price of spot coal purchased by System companies:
2000 2001 2002 ------- ------- ------- Total coal delivered to AEP operated plants (thousands of tons)........... 73,259 73,889 76,442 Average price per ton of spot-purchased coal............... $ 24.03 $ 27.30 $ 27.06
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, 2002, the System's coal inventory was roughly 56 days of normal usage. This estimate assumes that the total supply would be utilized through the operation of plants that use coal most efficiently. In cases of emergency or shortage, system companies have developed programs to conserve coal supplies at their plants. Such programs have been filed and reviewed with officials of federal and state agencies and, in some cases, the state regulatory agency has prescribed actions to be taken under specified circumstances by System companies, subject to the jurisdiction of such agencies. The 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 ratemaking 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. Natural Gas: AEP, through its public utility subsidiaries, consumed over 163 billion cubic feet of natural gas during 2002 for generating power. 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. A portfolio of long-term and short-term purchase and transportation agreements (that are acquired on a competitive basis and based on market prices) supplies natural gas requirements for each plant. Nuclear: I&M and STPNOC have made commitments to meet certain of the nuclear fuel requirements of the Cook Plant and STP, respectively. Steps currently are being taken, based upon the planned fuel cycles for the Cook Plant, to review and evaluate I&M's requirements for the supply of nuclear fuel. I&M has made and will make purchases of uranium in various forms in the spot, short-term, and mid-term markets until it decides that deliveries under long-term supply contracts are warranted. TCC and the other STP participants have entered into contracts with suppliers for (i) 100% of the uranium concentrate sufficient for the operation of both STP units through spring 2006 and (ii) 50% of the uranium concentrate needed for STP through spring 2007. 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 14 capability to store the spent nuclear fuel generated by the STP units over their licensed lives. Nuclear Waste and Decommissioning I&M, as the owner of the Cook Plant, and TCC, as a partial owner of STP, have a significant future financial commitment to safely dispose of SNF and decommission and decontaminate the plants. 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; and - 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 different than current projections. See Management's Discussion and Analysis of Results of Operations and Management's Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters and Note 9 to the consolidated financial statements, entitled Commitments and Contingencies, which are incorporated by reference in Items 7 and 8, respectively, for information with respect to nuclear waste and decommissioning and related litigation. Low-Level Radioactive Waste: The LLWPA mandates that the responsibility for the disposal of low-level radioactive 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. Michigan and Texas do not currently have disposal sites for such waste available. AEP cannot predict when such sites may be available, but South Carolina and Utah operate low-level radioactive waste disposal sites and accept low-level radioactive waste from Michigan and Texas. AEP's access to the South Carolina facility is currently allowed through the end of fiscal year 2008. Deactivation and Planned Disposition of Generation Facilities In September 2002, AEP indicated to ERCOT its intent to deactivate 16 gas-fired power plants (8 TCC plants and 8 TNC plants). ERCOT subsequently conducted reliability studies that determined that seven plants (4 TCC plants and 3 TNC plants) would be required to ensure reliability of the electricity grid. As a result of these studies, ERCOT and AEP agreed to enter into reliability must run agreements (which expired in December 2002, but have been renewed for all but two units of these plants) to continue operation of these plants. With ERCOT's approval, AEP proceeded with its planned deactivation of the remaining nine plants. TCC has also filed a plan of divestiture with the PUCT proposing to sell all of its power generation assets in an effort to determine its level of stranded costs in accordance with the Texas Act. The PUCT has dismissed its proceeding relating to TCC's plan of divestiture in anticipation of promulgating rules of general application regarding stranded cost determination for nuclear facilities. See Energy Delivery-Regulatory Assets and Stranded Cost Recovery and Post-Restructuring Wires Charges. The assets to be sold have a generating capacity of 4,497 MW and include eight gas-fired generating plants, one coal-fired plant, TCC's interest in another coal-fired plant, a hydroelectric facility and TCC's interest in STP. See Note 8 to the consolidated financial statements entitled Customer Choice and Industry Restructuring, incorporated by reference in Item 8, for more information on the planned disposition of TCC generation facilities. TRADING AND MARKETING OF ENERGY COMMODITIES AEP enters into transactions for the purchase and sale of 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 may require cash or cash related instruments to be deposited on these transactions as margin against open positions. AEP trades electricity and gas contracts with numerous counterparties. Since AEP's open energy trading contracts are valued based on changes in 15 market prices of the related commodities, our exposures change daily. In October 2002, AEP announced its plans to reduce its exposure to energy trading markets and to downsize the trading and wholesale marketing operations. It is expected that in the future power trading and marketing operations will be smaller in scope, will generally be limited to risk management around AEP assets and, accordingly, focused in regions in which AEP owns assets. Energy Market Investigations During 2002, several governmental entities launched investigations of participants in energy trading markets, including AEP. A number of those investigations resulted in data requests of AEP. See Management's Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters, incorporated by reference in Item 7, under the heading Energy Market Investigations. NATURAL GAS PIPELINE, STORAGE AND PROCESSING FACILITIES AEP, through certain subsidiaries, operates and owns an interest in a significant amount of gas-related assets, including: - 6,400 miles of natural gas pipelines between two systems; - 128 billion cubic feet of storage among two facilities; - Five natural gas processing plants; and - Certain gas marketing contracts. COAL MINES AND RELATED FACILITIES AEP, through certain subsidiaries, holds various properties, coal reserves, mining operations and royalty interests in Colorado, Kentucky, Louisiana, Ohio, Pennsylvania and West Virginia. BARGE, RAIL AND OTHER FUEL TRANSPORTATION RELATED ASSETS AEP, through MEMCO Barge Line Inc., is engaged in the transportation of coal and dry bulk commodities, primarily on the Ohio, Illinois, and Lower Mississippi rivers for AEP, as well as unaffiliated customers. AEP, through certain subsidiaries, owns or leases 7,000 railcars, 1,800 barges, 37 tug boats and two coal handling terminals with 20 million tons of annual capacity. STRUCTURED ARRANGEMENTS INVOLVING CAPACITY, ENERGY, AND ANCILLARY SERVICES Dow 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 November 2003. AEP is entitled to 100% of the facility's capacity and energy over The Dow Chemical Company's requirements and has contracted to sell the power from this facility to an unaffiliated party. Buckeye In January 2000, OPCo and NPC, an affiliate of Buckeye, entered into an agreement relating to the construction and operation of a 510 MW gas-fired electric generating peaking facility to be owned by NPC. From the commercial operation date (which occurred 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. CERTAIN POWER AGREEMENTS AEGCo Since its formation in 1982, AEGCo's business has consisted of the ownership and financing of its 50% interest in Unit 1 of 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 KPCo pursuant to unit power agreements. 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, when added to amounts received by AEGCo from any other sources, will be at least 16 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 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 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. The agreement will be extended until December 31, 2009 for Unit 1 and December 31, 2022 for Unit 2 if AEP's restructuring settlement agreement filed with the FERC becomes effective. 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. OVEC AEP, CSPCo and several unaffiliated utility companies jointly own OVEC. The aggregate equity participation of AEP and CSPCo in OVEC is 44.2%. Until September 1, 2001, OVEC supplied the power requirements of a uranium enrichment plant near Portsmouth, Ohio owned by the DOE. The sponsoring companies are now entitled to receive and pay for all OVEC capacity (approximately 2,200 MW) in proportion to their power participation ratios. 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. The Inter-Company Power Agreement, which defines the rights of the owners and sets the power participation ratio of each, will expire by its terms on March 12, 2006. Buckeye Contractual arrangements among OPCo, Buckeye and other investor-owned electric utility companies in Ohio provide for the transmission and delivery, over facilities of OPCo and of other investor-owned utility companies, of power generated by the two units at the Cardinal Station owned by Buckeye and back-up power to which Buckeye is entitled from OPCo under such contractual arrangements, to facilities owned by 25 of the rural electric cooperatives which operate in the State of Ohio at 342 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 1, 2002, was recorded at 1,398,559 kilowatts. ENERGY DELIVERY GENERAL AEP's public utility subsidiaries own and operate transmission and distribution lines and other facilities to deliver electric power. See Item 2--Properties for more information regarding the transmission and distribution lines. Most of the transmission and distribution services are sold, in combination with electric power, to retail customers of AEP's public utility subsidiaries in their service territories. These sales are made at rates established by the state utility commissions of the states in which they operate, and in some instances, the FERC as well. See Regulation-- Rates. The FERC regulates and approves the rates for wholesale transmission transactions. See General--Regulation-- FERC. As discussed below, some transmission services also are separately sold to non-affiliated companies. AEP's public utility subsidiaries hold franchises or other rights to provide electric service in various municipalities and regions in their service areas. In some cases, these franchises provide the utility with the exclusive right to provide electric service. These franchises have varying provisions and expiration 17 dates. In general, the operating companies consider their franchises to be adequate for the conduct of their business. For a discussion of competition in the sale of power, see Wholesale Operations-- Generation-- Competition and Regulation. REGULATION AEP is in the business of providing generation, transmission and distribution services. The transmission and distribution functions are part of AEP's energy delivery segment. The generation function is part of AEP's wholesale operations segment. This discussion covers the regulation of transmission and distribution, but also generation sold at retail (which would otherwise be included in the wholesale operations segment discussion). Rates Historically, state utility commissions have established electric service rates on a cost-of-service basis, which is designed to allow a utility an opportunity to recover its cost of providing service and to earn a reasonable return on its investment used in providing that service. A utility's cost of service is generally comprised of its operating expenses, including operation and maintenance expense, depreciation expense and taxes. State utility commissions periodically adjust rates pursuant to a review of (i) a utility's revenues and expenses during a defined test period and (ii) such utility's level of investment. Absent a legal limitation, such as a law limiting the frequency of rate changes or capping rates for a period of time as part of a transition to customer choice of generation suppliers, a state utility commission can review and change rates on its own initiative. Some states may initiate reviews at the request of a utility, customer, governmental or other representative of a group of customers. Such parties may, however, agree with one another not to request reviews of or changes to rates for a specified period of time. The rates of AEP's public utility subsidiaries are generally based on the cost of providing traditional bundled electric service (i.e., generation, transmission and distribution service). In Ohio, Virginia and the ERCOT area of Texas, rates are transitioning from bundled cost-based rates for electric service to unbundled cost-based rates for transmission and distribution service on the one hand, and market pricing for and/or customer choice of generation on the other. Historically, the state regulatory frameworks in the service area of the AEP System reflected specified fuel costs as part of bundled (or, more recently, unbundled) rates or incorporated fuel adjustment clauses in a utility's rates and tariffs. Fuel adjustment clauses permit periodic adjustments to fuel cost recovery from customers and therefore provide protection against exposure to fuel cost changes. While the historical framework remains in a portion of AEP's service territory, recovery of increased fuel costs (i) is no longer provided for in Ohio and (ii) may be limited in Indiana and Michigan, which have capped rates. Fuel recovery is also limited in the ERCOT area of Texas, but because AEP sold MECPL and MEWTU, there is little impact on AEP of fuel recovery procedures related to service in ERCOT. The following state-by-state analysis summarizes the regulatory environment of each jurisdiction in which AEP operates. Several public utility subsidiaries operate in more than one jurisdiction. Indiana: I&M provides retail electric service in Indiana at a bundled rate approved by the IURC. While rates are set on a cost-of-service basis, utilities may also generally seek to adjust fuel clause rates quarterly. I&M's base rate is capped through December 31, 2004 and its fuel recovery rate is capped through February 29, 2004. Ohio: CSPCo and OPCo operate as functionally separated utilities and provide "default" retail electric service to customers at unbundled rates established by the Ohio Act through December 31, 2005. Thereafter, CSPCo and OPCo will continue to provide distribution services to retail customers at rates approved by the PUCO. These rates will be frozen from December 31, 2005 to (i) December 31, 2008 for CSPCo and (ii) December 31, 2007 for OPCo. Transmission services will continue to be provided at rates established by the FERC. Default retail generation service rates will be based on market prices pursuant to rules currently under consideration by the PUCO. Oklahoma: PSO provides retail electric service in Oklahoma at a bundled rate approved by the OCC. PSO's rates are set on a cost-of-service basis. Fuel and purchased power costs above the amount included in base rates are recovered by applying a fuel adjustment factor to retail kilowatt-hour sales. The factor is adjusted quarterly and is based upon forecasted fuel and purchased power costs. Over or under collections of fuel costs for prior periods can be recovered when new quarterly factors are established. Texas: The Texas Act requires the legal separation of generation-related assets from transmission and 18 distribution assets. TCC and TNC currently operate on a functionally separated basis. In January 2002, TCC and TNC transferred all their retail customers in the ERCOT area of Texas to MECPL, MEWTU and AEP Commercial and Industrial REP (an AEP affiliate). TNC's retail SPP customers were ultimately transferred to Mutual Energy SWEPCo L.P. (an AEP affiliate). TCC and TNC provide retail transmission and distribution service on a cost-of-service basis at rates approved by the PUCT and wholesale transmission service under tariffs approved by the FERC consistent with PUCT rules. The implementation of the business separation plan for SWEPCo operations in the SPP area of Texas was delayed by the PUCT. As such, SWEPCo's Texas operations continue to operate and to be regulated as a traditional bundled utility with both base and fuel rates. Virginia: APCo provides unbundled retail electric service in Virginia. APCo's unbundled generation, transmission (which reflect FERC approved transmission rates) and distribution rates as well as its functional separation plan were approved by the VSCC in December 2001. The Virginia Act capped base rates at their mid-1999 levels until the end of the transition period (July 1, 2007), or sooner if the VSCC finds that a competitive market for generation exists in Virginia. The Virginia Act permits APCo to seek a one-time change to its capped non-generation rates after January 1, 2004. The Virginia Act allows adjustments to fuel rates during the transition period and continues to permit utilities to recover their actual fuel costs, the fuel component of their purchased power costs and certain capacity charges. APCo recovers its generation capacity charges through capped base rates. West Virginia: APCo and Wheeling Power Company provide retail electric service at bundled rates approved by the WVPSC. A plan to introduce customer choice was approved by the West Virginia Legislature in its 2000 legislative session. However, implementation of that plan was placed on hold pending necessary changes to the state's tax laws in a subsequent session. Those changes have not been made. While West Virginia generally allows recovery of fuel costs, the most recent proceeding resulted in the suspension of an active fuel clause for APCo and WPCo (though they continue to recover fuel costs through fixed bundled rates). APCo and Wheeling Power Company are currently unable to change the current level of fuel cost recovery, though this ability could be reinstated in a future proceeding. Other Jurisdictions: The public utility subsidiaries of AEP also provide service at regulated bundled rates in Arkansas, Kentucky, Louisiana and Tennessee and regulated unbundled rates in Michigan. 19 The table below illustrates the current rate regulation status of the states in which the public utility subsidiaries of AEP operate:
FUEL CLAUSE RATES PERCENTAGE ------------------------------------------------- OF AEP STATUS OF BASE RATES FOR SYSTEM SALES SYSTEM ----------------------------------------------- PROFITS SHARED RETAIL JURISDICTION POWER SUPPLY ENERGY DELIVERY STATUS INCLUDES W/RATEPAYERS REVENUES(1) - ------------ ---------------------- ---------------------- -------------- -------------- --------------- ----------- Ohio Frozen through 2005 Distribution frozen None Not applicable Not applicable 30% through 2007 for OPCo and 2008 for CSP; Transmission frozen through 2005 Texas (TCC, TNC) See footnote 2 Not capped or frozen Not applicable Not applicable Not applicable 17%(2) Texas (SWEPCo) Capped until 6/15/03 Active Fuel and fuel Yes, above base 3% portion of levels purchased power Indiana Capped until 1/1/05(3) Capped until Fuel and fuel No 10% 3/1/04(3) portion of purchased power Virginia Capped until as late Capped until as late Active Fuel and fuel No 9% as 7/1/07(4) as 7/1/07(4) portion of purchased power West Virginia Fixed(5) Suspended(5) Fuel and fuel Yes, but 9% portion of suspended purchased power Oklahoma Cap expired 1/1/03 Active Fuel and fuel Yes 9% portion of purchased power Louisiana Capped until 6/15/05 Active Fuel and fuel Yes, above base 5% portion of levels purchased power Kentucky Frozen until 6/15/03(6) Active Fuel and fuel Yes, above base 3% portion of levels purchased power Arkansas Capped until 6/15/03 Active Fuel and fuel Yes, above base 2% portion of levels purchased power Michigan Capped until 1/1/05(7) Capped until 1/1/05(7) Capped until Fuel and fuel Yes, in some 2% 1/1/04(8) portion of areas, but purchased suspended power Tennessee Not capped or frozen Active Fuel and fuel No 1% portion of purchased power
- --------------------------------- (1) Represents the percentage of revenues from sales to retail customers from AEP utility companies operating in each state to the total AEP System revenues from sales to retail customers for the year ended December 31, 2002. (2) Retail electric service in the ERCOT area of Texas is provided to most customers through unaffiliated REPs which must offer PTB rates until January 1, 2007. The percentage of revenues shown includes revenues from power sales contracts between MECPL and TCC and MEWTU and TNC. 20 (3) Capped base and fuel rates pursuant to a 1999 settlement with base rate freeze extended pursuant to merger stipulation. (4) Base rates are capped until the earlier of 7/1/07 or a finding by the VSCC that a competitive market for generation exists. One-time change in non-generation rates is allowed in Virginia after 1/1/04. (5) Rates fixed and expanded net energy clause suspended in West Virginia pursuant to a 1999 rate case stipulation, but subject to change in a future proceeding. (6) Utilities may request that an environmental surcharge be imposed to recover costs associated with the installation of emission control equipment. (7) Capped base and fuel rates pursuant to a 1999 settlement and base rates extended pursuant to merger stipulation. (8) Michigan fuel rates capped until 1/1/04 pursuant to a 1999 fuel settlement. AEP TRANSMISSION POOL Transmission Equalization Agreement APCo, CSPCo, I&M, KPCo and OPCo operate their transmission lines as a single interconnected and coordinated system and are parties to the Transmission Equalization Agreement, dated April 1, 1984, as amended (TEA), defining how they share the costs and benefits 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). This sharing is based upon each company's "member-load ratio." The member-load ratio is calculated monthly by dividing such company's highest monthly peak demand for the last twelve months by the aggregate of the highest monthly peak demand for the last twelve months for all east zone operating companies. As of December 31, 2002, the member-load ratios were as follows:
PEAK DEMAND MEMBER-LOAD (KW) RATIO (%) ------ ----------- APCo..................... 6,010 28.2 CSPCo.................... 4,040 19.0 I&M...................... 4,323 20.3 KPCo..................... 1,551 7.3 OPCo..................... 5,360 25.2
The following table shows the net credits or (charges) allocated among the parties to the TEA during the years ended December 31, 2000, 2001 and 2002:
2000 2001 2002 -------- -------- ------- (IN THOUSANDS) APCo................. $ 3,400 $ 3,100 $ 13,400 CSPCo................ (38,300) (40,200) (42,200) I&M.................. 43,800 41,300 36,100 KPCo................. 6,000 4,600 5,400 OPCo................. (14,900) (8,800) (12,700)
Transmission Coordination Agreement PSO, SWEPCo, TCC, TNC and AEPSC 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 public utility subsidiaries, including the performance of transmission planning studies, the interaction of such subsidiaries with independent system operators and other regional bodies interested in transmission planning and compliance with the terms of the OATT filed with the FERC and the rules of the FERC relating to such tariff. Under the TCA, the west zone public utility subsidiaries have delegated to AEPSC the responsibility of monitoring the reliability of their transmission systems and administering the AEP OATT on their behalf. The TCA also provides for the allocation among the west zone public utility subsidiaries of revenues collected for transmission and ancillary services provided under the AEP OATT. The following table shows the net credits or (charges) allocated among the parties to the TCA during the years ended December 31, 2000, 2001 and 2002:
2000 2001 2002 ------ ------ ------ (IN THOUSANDS) PSO................... $ 3,300 $ 4,000 $ 4,200 SWEPCo................ 5,900 5,400 5,000 TCC................... (3,400) (3,900) (3,600) TNC................... (5,800) (5,500) (5,600)
Transmission Services for Non-Affiliates In addition to providing transmission services in connection with their own power sales, AEP's public utility subsidiaries and other System companies also provide transmission services for non-affiliated compa- 21 nies. See Regulation--Regional Transmission Organizations. AEP's public utility subsidiaries are subject to regulation by the FERC under the FPA in respect of transmission of electric power. Coordination of East and West Zone Transmission 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 public utility subsidiaries. The System Transmission Integration Agreement functions as an umbrella agreement in addition to the TEA and the TCA. The System Transmission Integration Agreement contains two service schedules that govern: - The allocation of transmission costs and revenues and - The allocation of third-party transmission costs and revenues and System dispatch costs. The System Transmission Integration Agreement contemplates that additional service schedules may be added as circumstances warrant. COMPETITION 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. Legislation has been enacted in Michigan, Ohio, Texas and Virginia that allows for customer choice of generation supplier. Although restructuring legislation has been passed in Oklahoma and West Virginia, it has been delayed indefinitely in Oklahoma and not implemented in West Virginia. In addition, restructuring legislation in Arkansas has been repealed. See General--Electric Restructuring Legislation. Customer choice legislation generally allows competition in the generation and sale of electric power, but not in its transmission and distribution. See Management's Discussion and Analysis of Results of Operations and Management's Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters and Note 8 to the consolidated financial statements entitled Customer Choice and Industry Restructuring incorporated by reference in Items 7 and 8, respectively, for further information with respect to restructuring legislation affecting AEP subsidiaries. SEASONALITY Sale of electric power is generally a seasonal business. In many parts of the country, demand for power peaks during the hot summer months, with market prices also peaking at that time. In other areas, power demand peaks during the winter. The pattern of this fluctuation may change due to the nature and location of AEP's facilities and the terms of power sale contracts AEP enters into. In addition, AEP has historically sold less power, and consequently earned less income, when weather conditions are milder. Unusually mild weather in the future could diminish AEP's results of operations and may impact its financial condition. REGIONAL TRANSMISSION ORGANIZATIONS 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 that 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 that 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 RTOs, entities created to operate, plan and control utility transmission assets. Order 2000 also prescribes certain characteristics and functions of acceptable RTO proposals. AEP is required, as a condition of FERC's approval in 2000 of AEP's merger with CSW, to transfer functional control of its transmission facilities to one or more RTOs. In May 2002, AEP announced an agreement with PJM to pursue terms for its east zone public utility subsidiaries to participate in PJM, a 22 FERC approved RTO. In July 2002, the FERC tentatively approved AEP subsidiaries' decision to join PJM, subject to certain conditions being met. The satisfaction of these conditions is only partially within AEP's control. AEP's public utility subsidiaries have filed applications with the state utility commissions of Indiana, Kentucky, Ohio and Virginia requesting approval of the transfer of functional control of transmission assets in those states to PJM. Those applications are pending. In February 2003, the Virginia legislature enacted legislation that would prohibit the transfer of functional control of transmission assets to an RTO until at least July 2004. In July 2002, FERC conditionally accepted filings related to a proposed consolidation of MISO and the SPP. In that order the FERC required AEP's west zone subsidiaries in SPP to file reasons why those subsidiaries should not be required to join MISO. SWEPCo has filed an application with the LPSC requesting approval of the transfer of functional control of its Louisiana transmission assets to MISO and intends to make a similar filing in Arkansas with respect to its Arkansas transmission assets. AEP presently plans to transfer functional control of its transmission facilities in SPP to MISO or the merged MISO/SPP. TEXAS REGULATORY ASSETS AND STRANDED COST RECOVERY AND POST-RESTRUCTURING WIRES CHARGES Certain transmission and distribution utilities in Texas whose generation assets were unbundled pursuant to the Texas Act may recover generation-related regulatory assets and generation-related stranded costs. Regulatory assets consist of the Texas jurisdictional amount of generation-related regulatory assets and liabilities in the audited financial statements as of December 31, 1998. Stranded costs consist of the positive excess of the net regulated book value of generation assets over the market value of those assets, taking specified factors into account. The Texas Act allows alternative methods of valuation to determine the fair market value of generation assets, including outright sale, full and partial stock valuation and asset exchanges, and also, for nuclear generation assets, the ECOM model. The Texas Act further permits utilities to establish a special purpose entity to issue securitization bonds for the recovery of regulatory assets and, after the 2004 true-up proceeding, the amount of stranded costs and remaining regulatory assets not previously securitized. Securitization bonds allow for regulatory assets and stranded costs to be refinanced with recovery of the bond principal and financing costs ensured through a non-bypassable rate surcharge by the regulated transmission and distribution utility over the life of the securitization bonds. Any stranded costs not recovered through the sale of securitization bonds may be recovered through a separate non-bypassable competitive transition charge to transmission and distribution customers. Regulatory Assets In 1999, TCC filed an application with the PUCT to securitize approximately $1.27 billion of its retail generation-related regulatory assets and approximately $47 million in other qualified restructuring costs. On March 27, 2000, the PUCT issued an order authorizing issuance of up to $797 million of securitization bonds including $764 million for recovery of net generation- related regulatory assets and $33 million for other qualified refinancing costs. The securitization bonds were issued in February 2002. TCC has included a transition charge in its distribution rates to repay the bonds over a 14-year period. In addition, another $185 million of generation-related regulatory assets are being recovered through distribution rates beginning in January 2002. Remaining generation-related regulatory assets of approximately $214 million originally included by TCC in its 1999 securitization request along with certain other regulatory assets will be included in TCC's request to recover stranded costs in the 2004 true-up proceeding. Stranded Costs In a March 2000 filing with the PUCT to determine unbundled transmission and distribution charges and initial stranded cost recovery, TCC requested recovery of an additional $1.1 billion of stranded costs and regulatory assets that were not securitized. In October 2001, the PUCT issued an order in the UCOS proceeding determining an initial amount of TCC ECOM or stranded costs of approximately negative $615 million based upon the PUCT's ECOM model. The ruling indicated that TCC costs were below market after securitization of regulatory assets. TCC disagrees with the ruling and believes it has positive stranded costs in addition to the securitized regulatory assets. As a result of this stranded cost determination, the PUCT ordered TCC to refund $55 million of estimated excess earnings for the period 1999 through 2001 to customers through a credit applied to distribu- 23 tion rates over a five-year period. TCC appealed the PUCT's estimate of stranded costs and refund of excess earnings, among other issues, to the Travis County District Court. This estimate may be superseded by a final determination made as part of the 2004 true-up proceedings. The final amount of TCC's stranded costs including regulatory assets and ECOM will be established by the PUCT in the 2004 true-up proceeding. Pursuant to PUCT rules, if TCC's total stranded costs determined in the 2004 true-up proceeding are less than the amount of securitized regulatory assets, the PUCT can implement an offsetting credit to transmission and distribution rates. The Texas Third Circuit Court of Appeals ruled in February 2003 that the Texas Act does not contemplate the refunding to customers of negative stranded costs. In addition, the Court ruled that negative stranded costs cannot be offset against other true-up adjustments, including under-recovered fuel amounts. This ruling may be appealed to the Texas Supreme Court, which has discretion as to whether to accept and consider the appeal. 2004 True-Up Proceedings Beginning as early as January 2004, the PUCT will conduct true-up proceedings (with respect to the ERCOT area of Texas) for each investor-owned utility, its affiliated REP and affiliated power generation company. The purpose of the true-up proceeding is to (i) quantify and reconcile the amount of stranded costs and generation-related regulatory assets that have not yet been securitized, (ii) conduct a true-up of the PUCT ECOM model for 2002 and 2003 to reflect market prices determined in required capacity auctions, (iii) establish final fuel recovery balances and (iv) determine the price to beat clawback component. The true-up proceeding will generally result in either additional charges or credits to retail customers through transmission and distribution rates collected by their REPs and remitted to the utility. Stranded Cost and Generation-Related Regulatory Asset Determination: The Texas Act authorized the use of several valuation methodologies to quantify stranded costs and generation-related regulatory assets in the 2004 true-up proceeding, including by the sale of assets. TCC filed a plan of divestiture with the PUCT in December 2002 seeking approval to sell its generation assets to determine their market value. The PUCT has dismissed its proceeding relating to TCC's plan of divestiture in anticipation of promulgating rules of general application regarding stranded cost determination. If the PUCT determines the sale of assets methodology cannot be used to determine the market value of STP, TCC intends to pursue the use of one or more market valuation methods. Divestiture of TCC's interest in STP to a nonaffiliate will also require NRC approval. TNC does not have any recoverable stranded costs or generation-related regulatory assets that can be considered as part of the 2004 true-up. ECOM/Capacity Auction Component: The PUCT used a computer model or projection, called an ECOM model, to estimate stranded costs related to generation plant assets in the UCOS proceeding. In connection with using the ECOM model to calculate the stranded cost estimate, the PUCT estimated the market power prices that will be received in the competitive wholesale generation market. Any difference between the ECOM model market prices and actual market power prices as measured by generation capacity auctions required by the Texas Act during the period of January 1, 2002 through December 31, 2003 will be a component of the 2004 true-up proceeding, either increasing or decreasing the amount of recovery for TCC. Auctions to date have generally indicated that market prices have been lower than the PUCT's ECOM estimates. Unless this is reversed, TCC's recovery in the 2004 true-up proceeding would be increased. In the event TCC has transferred its generation assets to an affiliate, the Texas Act would require TCC to remit to its affiliate the recovery amount accruing after the transfer. See Note 8 to the consolidated financial statements, entitled Customer Choice and Industry Restructuring, incorporated by reference in Item 8, for a discussion of the current calculation of the difference between the market price and ECOM estimate. Fuel Recovery Balance Determination: The amount TCC or TNC recovers in the 2004 true-up proceeding could be increased or reduced (or the amount TCC must refund could be increased) by any under or over-recovery of fuel. The fuel component will be determined by the amount of fuel costs and expenses the PUCT approves based on a final fuel reconciliation that TCC filed on December 2, 2002 and that TNC filed on June 3, 2002. TCC's fuel reconciliation covers its fuel costs from the period beginning July 1, 1998 and ending December 31, 2001. TCC's fuel reconciliation filing seeks approval for $1.6 billion in fuel expense collected from retail customers during that period. TCC's fuel reconciliation filing reflects a fuel over-recovery balance, as of December 31, 2001, of $63.5 million, including 24 interest. A procedural schedule has been set with a hearing scheduled to begin May 7, 2003. TNC's fuel reconciliation requests approval of $292 million in fuel costs associated with serving both ERCOT and SPP retail customers from July 1, 2000 through December 31, 2001. It reflects a fuel under-recovery balance, as of December 31, 2001, of $26.9 million, including interest. The amounts in this paragraph may periodically be adjusted as filings are updated or adjusted. A final order from the PUCT is expected in the first half of 2003. Any under or over-recovery, plus interest thereon, will be recovered from or returned to customers as a component of the 2004 true-up proceeding. Price to Beat Clawback Component: The amount TCC or TNC recovers in the 2004 true-up proceeding could be reduced (or the amount TCC or TNC must refund could be increased) by the PTB clawback component. If MECPL and MEWTU (which are no longer affiliated with TCC or TNC) continue to serve 60% or more of TCC's and TNC's respective PTB load as of January 1, 2004 and the PTB (reduced by non-bypassable wires charges) exceeds the market price of electricity, any such excess must be credited to customers of TCC and TNC in the 2004 true-up proceeding, by up to $150 per customer, subject to certain adjustments. The Texas Act provides that MECPL and MEWTU effectively indemnify TCC and TNC, respectively, for any PTB clawback amounts assessed them. The MECPL and MEWTU sale agreements provide that Centrica (as purchaser of MECPL and MEWTU) and AEP Utilities (the parent of TCC and TNC, as seller of MECPL and MEWTU) will share responsibility for this indemnity. Further Securitization Bonds and Wires Charges: After final determination of its stranded costs and other true-up adjustments by the PUCT, TCC expects to issue securitization bonds in the amount of its non-securitized stranded costs and generation-related regulatory assets determined in the 2004 true-up proceeding. The bonds can have a maximum term of 15 years. If securitization bonds are not issued to finance all non-securitized stranded costs and generation-related regulatory assets, TCC will seek recovery of these amounts as well as its other true-up adjustments, through a non-bypassable competition transition charge in transmission and distribution rates. For a discussion of recovery of regulatory assets and stranded costs in Ohio and Virginia, see Note 8 to the consolidated financial statements entitled Customer Choice and Industry Restructuring, incorporated by reference in Item 8. OTHER INVESTMENTS AEP has made certain investments in telecommunications, international energy and other concerns. In 2002, AEP wrote down the value of certain of those investments. See Management's Discussion and Analysis of Results of Operations and Management's Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters and Note 13 to the consolidated financial statements entitled Asset Impairment and Investment Value Losses, incorporated by reference in Items 7 and 8, respectively. AEP also sold the following foreign investments in 2002: - SEEBOARD, an electricity supply and distribution company in the United Kingdom serving 2,000,000 customers and covering 3,000 square miles of service territory. - CitiPower, a retail electricity and gas supply and distribution subsidiary in Australia serving 240,000 customers. 25 Item 2. PROPERTIES - -------------------------------------------------------------------------------- GENERATION FACILITIES General At December 31, 2002, the AEP System owned (or leased where indicated) generating plants with net power capabilities (east zone public utility subsidiaries-winter rating; west zone public utility 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) 5,073 777 5,850 CSPCo 6(e) 2,595 2,595 I&M 10(a) 2,295 11 2,110 4,416 KPCo 1 1,060 1,060 OPCo 8(b)(f) 8,472 48 8,520 PSO 8(c) 1,043 3,169 25(g) 4,237 SWEPCo 9 1,848 1,797 842 4,487 TCC 12(c)(d)(h) 686 3,175 6 630 4,497 TNC 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) PSO, TCC and TNC jointly own the Oklaunion power station. Their respective ownership interests are reflected in this table. (d) Reflects TCC'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 TNC have 25 MW and 10 MW respectively of facilities designed primarily to burn oil. TNC has one 6 MW wind farm facility. (h) See Item 1 -- Wholesale Operations -- Power Generation -- Planned Deactivation and Planned Disposition of Generation Facilities for a discussion of TCC's planned disposition of its generation facilities. 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, 2002 is listed below.
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 - ----------------------------------------------------------------------------------------------------------
26
CAPACITY OWNERSHIP FACILITY FUEL LOCATION TOTAL MW INTEREST STATUS - ---------------------------------------------------------------------------------------------------------- Bajio Natural gas Mexico 605 50% FUCO Ferrybridge Coal United Kingdom 2,000 100% FUCO Fiddler's Ferry Coal United Kingdom 2,000 100% FUCO Nanyang Coal China 250 70% FUCO Southcoast Natural gas United Kingdom 380 50% FUCO - ---------------------------------------------------------------------------------------------------------- Total International 5,235 - ----------------------------------------------------------------------------------------------------------
See Item 1 -- Wholesale Operations for information concerning natural gas pipelines, storage and processing facilities, transportation related assets and coal operations and reserves owned or controlled by AEP subsidiaries. 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 KILOWATTS....... 1,020,000 1,090,000 1,250,600 1,250,600 NET CAPACITY FACTORS 2002............... 86.6% 80.5% 99.2% 75.0% 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 TCC 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 TCC 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 Item 1 -- Wholesale Operations -- Power Generation -- Planned Deactivation and Planned Disposition of Generation Facilities for a discussion of TCC's planned disposition of its interest in STP. 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, I&M, TCC and other AEP System companies. See Note 9 to the consolidated financial statements entitled Commitments and Contingencies, incorporated by reference in Item 8, for information with respect to nuclear incident liability insurance. 27 TRANSMISSION AND DISTRIBUTION 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 765,000-VOLT LINES ------------------ ------------------ AEP System (a)....... 226,330(b) 2,023 APCo. ............. 50,756 642 CSPCo (a).......... 12,255 -- I&M................ 25,128 615 Kingsport Power Company......... 1,335 -- KPCo. ............. 10,555 258 OPCo. ............. 35,551 509 PSO................ 21,539 -- SWEPCo............. 20,075 -- TCC................ 33,515 -- TNC................ 13,637 -- Wheeling Power Company......... 1,941 --
- ------------------------------------ (a) Includes 766 miles of 345,000-volt jointly owned lines. (b) Includes 73 miles of transmission lines not identified with an operating company. 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 exceptions, 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. 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. Proposed Transmission Facilities APCo is proceeding with its plan to build the Wyoming-Jacksons Ferry 765,000-volt transmission line. The WVPSC and the VSCC have issued certificates authorizing construction and operation of the line. On December 31, 2002, the U.S. Forest Service issued a final environmental impact statement and record of decision to allow the use of federal lands in the Jefferson National Forest for construction of a portion of the line. Additional state and federal permits are expected to be issued in the first half of 2003. Through December 31, 2002 APCo had invested approximately $51 million in this project. The line is estimated to cost $287 million with completion scheduled in 2006. 28 Construction Expenditures The following table shows construction expenditures during 2000, 2001 and 2002 and current estimates of 2003 construction expenditures, in each case including AFUDC but excluding assets acquired under leases.
2000 2001 2002 2003 ACTUAL ACTUAL ACTUAL ESTIMATE ---------- ---------- ---------- ---------- (IN THOUSANDS) AEP System (a)....... $1,773,400 $1,832,000 $1,709,800 $1,458,100 AEGCo. ............ 5,200 6,900 5,300 21,400 APCo. ............. 199,300 306,000 276,500 247,900 CSPCo. ............ 128,000 132,500 136,800 142,300 I&M................ 171,100 91,100 159,400 188,000 KPCo. ............. 36,200 37,200 178,700 72,300 OPCo. ............. 254,000 344,600 354,800 241,000 PSO................ 176,900 124,900 89,400 81,500 SWEPCo. ........... 120,200 112,100 111,800 104,900 TCC................ 199,500 194,100 151,500 126,800 TNC................ 64,500 39,800 43,600 46,500
(a) Includes expenditures of other subsidiaries not shown. See Note 9 to the consolidated 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. Item 3. LEGAL PROCEEDINGS - -------------------------------------------------------------------------------- For a discussion of material legal proceedings, see Note 9 to the consolidated financial statements, entitled Commitments and Contingencies, incorporated by reference in Item 8. 29 Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS - -------------------------------------------------------------------------------- AEP, APCO, I&M, OPCO, SWEPCO AND TCC. None. AEGCO, CSPCO, KPCO, PSO AND TNC. 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, 2003.
NAME AGE OFFICE (A) - ---- --- ---------- E. Linn Draper, Jr. ........... 61 Chairman of the Board, President and Chief Executive Officer of AEP and of the Service Corporation Thomas V. Shockley, III........ 57 Vice Chairman of AEP and Vice Chairman and Chief Operating Officer of the Service Corporation Henry W. Fayne................. 56 Vice President of AEP, Executive Vice President of the Service Corporation Thomas M. Hagan................ 58 Executive Vice President-Shared Services of the Service Corporation Holly K. Koeppel............... 44 Executive Vice President of the Service Corporation Robert P. Powers............... 49 Executive Vice President-Nuclear Generation and Technical Services of the Service Corporation Susan Tomasky.................. 49 Vice President of AEP, Executive Vice President-Policy, Finance and Strategic Planning of the Service Corporation
- --------------- (a) Dr. Draper and Mr. Fayne have been employed by the Service Corporation or System companies in various capacities (AEP, as such, has no employees) for the past five years. 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). Prior to joining the Service Corporation in June 2000 as Senior Vice President- Governmental Affairs, Mr. Hagan was Senior Vice President-External Affairs of CSW. Prior to joining the Service Corporation in July 2000 as Vice President-New Ventures, Ms. Koeppel was Regional Vice President of Asia-Pacific Operations for Consolidated Natural Gas International (1996-2000). Messrs. Hagan and Powers, Ms. Koeppel and Ms. Tomasky became executive officers of AEP effective with their promotions to Executive Vice President on September 9, 2002, October 24, 2001, November 18, 2002 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, I&M, OPCO, SWEPCO AND TCC. The names of the executive officers of APCo, I&M, OPCo, SWEPCo and TCC, the positions they hold with these companies, their ages as of March 1, 2003, and a brief account of their business experience during the past five years appear below. The directors and executive officers of APCo, I&M, OPCo, SWEPCo and TCC are elected annually to serve a one-year term. 30
NAME AGE POSITION (A)(B) PERIOD - ---- --- --------------- ------ E. Linn Draper, Jr. ........... 61 Director of SWEPCo and TCC 2000-Present Chairman of the Board and Chief Executive Officer of SWEPCo and TCC 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 Thomas V. Shockley, III........ 57 Director and Vice President of APCo, I&M, OPCo, SWEPCo and TCC 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................. 56 President of APCo, I&M, OPCo, SWEPCo and TCC 2001-Present Director of SWEPCo and TCC 2000-Present Director of APCo 1995-Present Director of OPCo 1993-Present Director of I&M 1998-Present Vice President of SWEPCo and TCC 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 Thomas M. Hagan................ 58 Director and Vice President of APCo, I&M, OPCo, SWEPCo and TCC 2002-Present Executive Vice President-Shared Services of the Service Corporation 2002-Present Senior Vice President-Governmental Affairs of the Service Corporation 2000-2002 Senior Vice President-External Affairs of CSW 1996-2000 Holly K. Koeppel............... 44 Executive Vice President of the Service Corporation 2002-Present Vice President-New Ventures 2000-2002 Regional Vice President of Asia-Pacific Operations for Consolidated Natural Gas International 1996-2000
31
NAME AGE POSITION (A)(B) PERIOD - ---- --- --------------- ------ Robert P. Powers............... 49 Director and Vice President of APCo, I&M, OPCo, SWEPCo and TCC 2001-Present Director of I&M 2001-Present Vice President of I&M 1998-Present Executive Vice President- Generation 2003-Present Executive Vice President-Nuclear Generation and Technical Services of the Service Corporation 2001-2003 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.................. 49 Director and Vice President of APCo, I&M, OPCo, SWEPCo and TCC 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
- --------------- (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, Hagan, Powers and Shockley and Ms. Tomasky are directors of AEGCo, CSPCo, KPCo, PSO and TNC. 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 2002 Annual Report. AEGCO, APCO, CSPCO, I&M, KPCO, OPCO, PSO, SWEPCO, TCC AND TNC. 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 2002 and 2001 are incorporated by reference to the material under Statement of Retained Earningsin the 2002 Annual Reports. Item 6. SELECTED FINANCIAL DATA - -------------------------------------------------------------------------------- AEGCO, CSPCO, KPCO, PSO AND TNC. Omitted pursuant to Instruction I(2)(a). AEP, APCO, I&M, OPCO, SWEPCO AND TCC. The information required by this item is incorporated herein by reference to the material under Selected Consolidated Financial Data in the 2002 Annual Reports. 32 Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION - -------------------------------------------------------------------------------- AEGCO, CSPCO, KPCO, PSO AND TNC. 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 2002 Annual Reports. AEP, APCO, I&M, OPCO, SWEPCO AND TCC. 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 2002 Annual Reports. Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK - -------------------------------------------------------------------------------- AEGCO, AEP, APCO, CSPCO, I&M, KPCO, OPCO, PSO, SWEPCO, TCC AND TNC. 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 2002 Annual Reports. Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA - -------------------------------------------------------------------------------- AEGCO, AEP, APCO, CSPCO, I&M, KPCO, OPCO, PSO, SWEPCO, TCC AND TNC. The information required by this item is incorporated herein by reference to the financial statements and financial statement schedules described under Item 15 herein. Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE - -------------------------------------------------------------------------------- AEGCO, AEP, APCO, CSPCO, I&M, KPCO, OPCO, PSO, SWEPCO, TCC AND TNC. None. PART III - -------------------------------------------------------------------------------- Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS - -------------------------------------------------------------------------------- AEGCO, CSPCO, KPCO, PSO AND TNC. 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 2003 annual meeting of shareholders, to be filed within 120 days after December 31, 2002. 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 2003 annual meeting of stockholders, to be filed within 120 days after December 31, 2002. Reference also is made to the information under the caption Executive Officers of the Registrants in Part I of this report. SWEPCO AND TCC. 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 2003 annual meeting of stockholders, to be filed within 120 days after December 31, 2002. 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 with I&M, their ages as of March 12, 2003, 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. 33
NAME AGE POSITION (A) PERIOD - ---- --- ------------ ------ K. G. Boyd..................... 51 Director 1997-Present Vice President (Appointed) -- Fort Wayne Region Distribution Operations 2000-Present Indiana Region Manager 1997-2000 John E. Ehler.................. 46 Director 2001-Present Manager of Distribution Systems-Fort Wayne District 2000-Present Region Operations Manager 1997-2000 David L. Lahrman............... 51 Director and Manager, Region Support 2001-Present Fort Wayne District Manager 1997-2001 Marc E. Lewis.................. 48 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............. 53 Director and General Manager, Community Services 2000-Present Manager, Customer Services Operations 1997-2000 John R. Sampson................ 50 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................. 59 Director 1995-Present Plant Manager, Rockport Plant 1990-Present
- --------------- (a) Positions are with I&M unless otherwise indicated. Item 11. EXECUTIVE COMPENSATION - -------------------------------------------------------------------------------- AEGCO, CSPCO, KPCO, PSO AND TNC. 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 2003 annual meeting of shareholders to be filed within 120 days after December 31, 2002. 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 2003 annual meeting of stockholders, to be filed within 120 days after December 31, 2002. I&M, SWEPCO AND TCC. The information required by this item is incorporated herein by reference to the material under Executive Compensationof the definitive information statement of APCo for the 2003 annual meeting of stockholders, to be filed within 120 days after December 31, 2002. Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS - -------------------------------------------------------------------------------- AEGCO, CSPCO, KPCO, PSO AND TNC. 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 2003 annual meeting of shareholders to be filed within 120 days after December 31, 2002. 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 state- 34 ment of each company for the 2003 annual meeting of stockholders, to be filed within 120 days after December 31, 2002. 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. SWEPCO AND TCC. 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 2003 annual meeting of stockholders, to be filed within 120 days after December 31, 2002. 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, 2003, 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 or her name. Fractions of shares and units have been rounded to the nearest whole number.
STOCK NAME SHARES (A) UNITS (B) TOTAL - ---- ---------- --------- --------- Karl G. Boyd................................................ 10,675 607 11,282 E. Linn Draper, Jr. ........................................ 472,034(c) 117,803 589,837 John E. Ehler............................................... 11 -- 11 Henry W. Fayne.............................................. 139,787(d) 12,362 152,149 Thomas M. Hagan............................................. 54,392 140 54,532 David L. Lahrman............................................ 430 -- 430 Marc E. Lewis............................................... 3,290 -- 3,290 Susanne M. Moorman.......................................... 908 -- 908 Robert P. Powers............................................ 65,862 1,293 67,155 John R. Sampson............................................. 10,643 173 10,816 Thomas V. Shockley, III..................................... 211,067(d)(e) -- 211,067 David B. Synowiec........................................... 7,645 182 7,827 Susan Tomasky............................................... 134,449(d) 6,126 140,575 All Directors and Executive Officers........................ 1,196,424(d)(f) 138,686 1,335,110
- --------------- (a) Includes share equivalents held in the AEP Retirement Savings Plan in the amounts listed below:
AEP RETIREMENT SAVINGS NAME PLAN (SHARE EQUIVALENTS) ---- ------------------------ Mr. Boyd.......................... 675 Dr. Draper........................ 4,659 Mr. Ehler......................... 11 Mr. Fayne......................... 5,804 Mr. Hagan......................... 2,515 Mr. Lahrman....................... 430 Mr. Lewis......................... 1,207
AEP RETIREMENT SAVINGS NAME PLAN (SHARE EQUIVALENTS) ---- ------------------------ Ms. Moorman....................... 908 Mr. Powers........................ 596 Mr. Sampson....................... 643 Mr. Shockley...................... 7,104 Mr. Synowiec...................... 4,312 Ms. Tomasky....................... 1,116 All Directors and Executive Officers........................ 29,980
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, 10,000; Dr. Draper, 466,666; 35 Mr. Hagan, 41,666; Mr. Lewis, 2,083; Mr. Powers, 65,266; Mr. Sampson, 10,000; Mr. Shockley, 166,666; Mr. Synowiec, 3,333; and Mr. Fayne and Ms. Tomasky, 133,333. (b) This column includes amounts deferred in stock units and held under AEP's officer benefit plans. (c) Includes 661 shares held by Dr. Draper in joint tenancy with a family member. (d) Does not include, for Messrs. Fayne, and Shockley and Ms. Tomasky, 85,231 shares in the American Electric Power System Educational Trust Fund over which Messrs. Fayne and Shockley and Ms. Tomasky 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 496 shares held by family members of Mr. Shockley over which he disclaimed beneficial ownership. (f) Represents less than 1% of the total number of shares outstanding. EQUITY COMPENSATION PLAN INFORMATION The following table summarizes the ability of AEP to issue common stock pursuant to equity compensation plans as of December 31, 2002:
NUMBER OF SECURITIES NUMBER OF REMAINING AVAILABLE SECURITIES TO BE FOR FUTURE ISSUANCE ISSUED UPON WEIGHTED AVERAGE UNDER EQUITY EXERCISE OF EXERCISE PRICE OF COMPENSATION PLANS OUTSTANDING OPTIONS OUTSTANDING (EXCLUDING SECURITIES WARRANTS AND OPTIONS, WARRANTS REFLECTED IN RIGHTS AND RIGHTS COLUMN (a)) PLAN CATEGORY (a) (b) (c) - ------------- ------------------- ------------------- --------------------- Equity compensation plans approved by security holders(1)................................... 8,779,217 $33.5767 6,901,693(2) Equity compensation plans not approved by security holders............................. 0 N/A 0 Total........................................ 8,779,217 $33.5767 6,901,693
- ------------------------------------ (1) Consists of shares to be issued upon exercise of outstanding options granted under the American Electric Power System 2000 Long-Term Incentive Plan, the CSW 1992 Long-Term Incentive Plan (CSW Plan) and the AEP Deferred Compensation and Stock Plan for Non-Employee Directors. The CSW Plan was in effect prior to the consummation of the AEP-CSW merger. All unexercised options granted under the CSW Plan were converted into 0.6 options to purchase AEP common shares, vested on the merger date and will expire ten years after their grant date. No additional options will be issued under the CSW Plan. (2) Excludes shares available for further issuance under the AEP Deferred Compensation and Stock Plan for Non-Employee Directors, which does not have a limit on the number of shares which may be issued. The amount of shares is capped, however, by the annual retainer amount paid to the Non-Employee Directors. 36 Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS - -------------------------------------------------------------------------------- AEP, AEGCO, APCO, CSPCO, I&M, KPCO, OPCO, PSO, SWEPCO, TCC AND TNC: None. PART IV - -------------------------------------------------------------------------------- Item 14. CONTROLS AND PROCEDURES - -------------------------------------------------------------------------------- AEP maintains disclosure controls and procedures designed to ensure that the information AEP must disclose in its filings with the Securities and Exchange Commission is recorded, processed, summarized and reported on a timely basis. AEP's principal executive officer and principal financial officer have reviewed and evaluated AEP's disclosure controls and procedures as defined in Rules 13a-14(c) and 15d-14(c) under the Securities Exchange Act of 1934, as amended (the Exchange Act) as of a date within 90 days prior to the filing date of this report (the Evaluation Date). Such officers have concluded that, as of the Evaluation Date, AEP's disclosure controls and procedures are effective in accumulating and communicating to management on a timely basis information required to be disclosed in AEP's periodic filings under the Exchange Act. Since the Evaluation Date, there have not been any significant changes in AEP's internal controls, or in other factors that could significantly affect these controls. Item 15. 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: Statements of Income for the years ended December 31, 2002, 2001, and 2000; Statements of Retained Earnings for the years ended December 31, 2002, 2001, and 2000; Balance Sheets as of December 31, 2002 and 2001; Statements of Cash Flows for the years ended December 31, 2002, 2001, and 2000; Statements of Capitalization as of December 31, 2002 and 2001; Combined Notes to Financial Statements; Independent Auditors' Report. AEP and Subsidiary Companies: Consolidated Statements of Operations for the years ended December 31, 2002, 2001, and 2000; Consolidated Balance Sheets as of December 31, 2002 and 2001; Consolidated Statements of Cash Flows for the years ended December 31, 2002, 2001, and 2000; Consolidated Statements of Common Shareholders' Equity and Comprehensive Income for the years ended December 31, 2002, 2001, and 2000; Schedule of Consolidated Cumulative Preferred Stocks of Subsidiaries at December 31, 2002 and 2001; Schedule of Consolidated Long-term Debt of Subsidiaries at December 31, 2002 and 2001; Combined Notes to Consolidated Financial Statements; Independent Auditors' Report. APCo, CSPCo, I&M, PSO, SWEPCo and TCC: Consolidated Statements of Income for the years ended December 31, 2002, 2001, and 2000; Consolidated Statements of Comprehensive Income for the years ended December 31, 2002, 2001, and 2000; Consolidated Statements of Retained Earnings for the years ended December 31, 2002, 2001, and 2000; Consolidated Balance Sheets as of December 31, 2002 and 2001; Consolidated Statements of Cash Flows for the years ended December 31, 2002, 2001, and 2000; Consolidated Statements of Capitalization as of December 31, 2002 and 2001; Schedule of Long-term Debt as of December 31, 2002 and 2001; Combined Notes to Consolidated Financial Statements; Independent Auditors' Report.
37 KPCo, OPCo and TNC: Statements of Income (or Statements of Operations) for the years ended December 31, 2002, 2001, and 2000; Statements of Comprehensive Income for the years ended December 31, 2002, 2001, and 2000; Statements of Retained Earnings for the years ended December 31, 2002, 2001, and 2000; Balance Sheets as of December 31, 2002 and 2001; Statements of Cash Flows for the years ended December 31, 2002, 2001, and 2000; Statements of Capitalization as of December 31, 2002 and 2001; Schedule of Long-term Debt as of December 31, 2002 and 2001; Combined Notes to Financial Statements; Independent Auditors' Report. 2. FINANCIAL STATEMENT SCHEDULES: Financial Statement Schedules are listed in the Index to S-1 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). Independent Auditors' Report 3. EXHIBITS: Exhibits for AEGCo, AEP, APCo, CSPCo, I&M, KPCo, OPCo, PSO, E-1 SWEPCo, TCC and TNC are listed in the Exhibit Index and are incorporated herein by reference (b) Reports on Forms 8-K:
COMPANY REPORTING DATE OF REPORT ITEM REPORTED - ----------------- ----------------- ---------------------------------------------- APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC.................. November 18, 2002 Item 5. Other Events I&M.................................. November 22, 2002 Item 5. Other Events Item 7. Financial Statements and Exhibits I&M.................................. November 25, 2002 Item 5. Other Events Item 7. Financial Statements and Exhibits PSO.................................. November 26, 2002 Item 5. Other Events Item 7. Financial Statements and Exhibits
Reports on Forms 8-K/A:
COMPANY REPORTING DATE OF REPORT ITEM REPORTED - ----------------- ----------------- ---------------------------------------------- PSO, SWEPCo, TCC and TNC............. November 26, 2002 Item 7. Financial Statements and Exhibits
(c) Exhibits: See Exhibit Index beginning on page E-1. 38 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 20, 2003 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, March 20, 2003 President, Chief Executive Officer And Director (II) PRINCIPAL FINANCIAL OFFICER: /s/ SUSAN TOMASKY Vice President, Secretary and March 20, 2003 - ------------------------------------------------ Chief Financial Officer (SUSAN TOMASKY) (III) PRINCIPAL ACCOUNTING OFFICER: /s/ JOSEPH M. BUONAIUTO Controller and March 20, 2003 - ------------------------------------------------ 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 *RICHARD L. SANDOR *THOMAS V. SHOCKLEY, III *DONALD G. SMITH *LINDA GILLESPIE STUNTZ *KATHRYN D. SULLIVAN March 20, 2003 *By: /s/ SUSAN TOMASKY ------------------------------------------ (SUSAN TOMASKY, ATTORNEY-IN-FACT)
39 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 AEP TEXAS CENTRAL COMPANY AEP TEXAS NORTH COMPANY APPALACHIAN POWER COMPANY COLUMBUS SOUTHERN POWER COMPANY KENTUCKY POWER COMPANY OHIO POWER COMPANY PUBLIC SERVICE COMPANY OF OKLAHOMA SOUTHWESTERN ELECTRIC POWER COMPANY By: /s/ SUSAN TOMASKY ------------------------------------- (SUSAN TOMASKY, VICE PRESIDENT) Date: March 20, 2003 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, March 20, 2003 President, Chief Executive Officer And Director (ii) PRINCIPAL FINANCIAL OFFICER: /s/ SUSAN TOMASKY Vice President, Secretary, March 20, 2003 - ------------------------------------------------ Chief Financial Officer and Director (SUSAN TOMASKY) (iii) PRINCIPAL ACCOUNTING OFFICER: /s/ JOSEPH M. BUONAIUTO Controller and March 20, 2003 - ------------------------------------------------ Chief Accounting Officer (JOSEPH M. BUONAIUTO) (iv) A MAJORITY OF THE DIRECTORS: *HENRY W. FAYNE *THOMAS M. HAGAN *A. A. PENA *ROBERT P. POWERS *THOMAS V. SHOCKLEY, III March 20, 2003 *By: /s/ SUSAN TOMASKY ------------------------------------------ (SUSAN TOMASKY, ATTORNEY-IN-FACT)
40 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 20, 2003 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, March 20, 2003 President, Chief Executive Officer and Director (ii) PRINCIPAL FINANCIAL OFFICER: /s/ SUSAN TOMASKY Vice President, Secretary, March 20, 2003 - ------------------------------------------------ Chief Financial Officer (SUSAN TOMASKY) and Director (iii) PRINCIPAL ACCOUNTING OFFICER: /s/ JOSEPH M. BUONAIUTO Controller and March 20, 2003 - ------------------------------------------------ Chief Accounting Officer (JOSEPH M. BUONAIUTO) (iv) A MAJORITY OF THE DIRECTORS: *K. G. BOYD *JOHN E. EHLER *HENRY W. FAYNE *THOMAS M. HAGAN *DAVID L. LAHRMAN *MARC E. LEWIS *SUSANNE M. MOORMAN *ROBERT P. POWERS *JOHN R. SAMPSON *THOMAS V. SHOCKLEY, III *D. B. SYNOWIEC March 20, 2003 *By: /s/ SUSAN TOMASKY ------------------------------------------ (SUSAN TOMASKY, ATTORNEY-IN-FACT)
41 CERTIFICATIONS I, E. Linn Draper, Jr., certify that: 1. I have reviewed this annual report on Form 10-K of: American Electric Power Company, Inc. AEP Generating Company AEP Texas Central Company AEP Texas North Company Appalachian Power Company Columbus Southern Power Company Indiana Michigan Power Company Kentucky Power Company Ohio Power Company Public Service Company of Oklahoma Southwestern Electric Power Company 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Dated: March 20, 2003 By: /s/ E. LINN DRAPER, JR. -------------------------------------- E. Linn Draper, Jr. Chief Executive Officer 42 I, Susan Tomasky, certify that: 1. I have reviewed this annual report on Form 10-K of: American Electric Power Company, Inc. AEP Generating Company AEP Texas Central Company AEP Texas North Company Appalachian Power Company Columbus Southern Power Company Indiana Michigan Power Company Kentucky Power Company Ohio Power Company Public Service Company of Oklahoma Southwestern Electric Power Company 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a. designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b. evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c. presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a. all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b. any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Dated: March 20, 2003 By: /s/ SUSAN TOMASKY -------------------------------------- Susan Tomasky Chief Financial Officer 43 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 AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES Schedule II -- Valuation and Qualifying Accounts and Reserves.............................................. S-3 AEP TEXAS NORTH COMPANY Schedule II -- Valuation and Qualifying Accounts and Reserves.............................................. S-3 APPALACHIAN POWER COMPANY AND SUBSIDIARIES Schedule II -- Valuation and Qualifying Accounts and Reserves.............................................. S-4 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-5 OHIO POWER COMPANY 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-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 subsidiaries and the financial statements of certain of its subsidiaries, listed in Item 15 herein, as of December 31, 2002 and 2001, and for each of the three years in the period ended December 31, 2002, and have issued our reports thereon dated February 21, 2003; such financial statements and reports are included in the 2002 Annual Reports and are incorporated herein by reference. Our audits also included the financial statement schedules of American Electric Power Company, Inc. and subsidiaries and of certain of its subsidiaries, listed in Item 15. 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 21, 2003 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(a) DEDUCTIONS(b) PERIOD - ------------------------------------------------------------------------------------------------------------------- (IN THOUSANDS) DEDUCTED FROM ASSETS: Accumulated Provision for Uncollectible Accounts: Year Ended December 31, 2002........... $69,416 $ 97,772 $11,766 $59,723 $119,231 ======= ======== ======= ======= ======== Year Ended December 31, 2001(c)........ $31,905 $109,635 $20,763 $92,887 $ 69,416 ======= ======== ======= ======= ======== Year Ended December 31, 2000(c)........ $27,091 $ 51,457 $11,729 $58,372 $ 31,905 ======= ======== ======= ======= ========
- --------------- (a) Recoveries on accounts previously written off. (b) Uncollectible accounts written off. (c) 2001 and 2000 amounts have been adjusted to reflect the treatment of SEEBOARD and CitiPower as discontinued operations in AEP's Consolidated Statements of Operations. AEP TEXAS CENTRAL 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(a) DEDUCTIONS(b) PERIOD - ------------------------------------------------------------------------------------------------------------------- (IN THOUSANDS) DEDUCTED FROM ASSETS: Accumulated Provision for Uncollectible Accounts: Year Ended December 31, 2002........... $ 186 $ 162 $ 1 $ 3 $ 346 ====== ====== ====== ====== ====== Year Ended December 31, 2001........... $1,675 $ 186 $ -- $1,675 $ 186 ====== ====== ====== ====== ====== Year Ended December 31, 2000........... $ -- $1,675 $ -- $ -- $1,675 ====== ====== ====== ====== ======
- --------------- (a) Recoveries on accounts previously written off. (b) Uncollectible accounts written off. AEP TEXAS NORTH 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(a) DEDUCTIONS(b) PERIOD - ------------------------------------------------------------------------------------------------------------------- (IN THOUSANDS) DEDUCTED FROM ASSETS: Accumulated Provision for Uncollectible Accounts: Year Ended December 31, 2002........... $ 196 $4,846 $ 17 $ 18 $5,041 ====== ====== ====== ====== ====== Year Ended December 31, 2001........... $ 288 $ 13 $ 35 $ 140 $ 196 ====== ====== ====== ====== ====== Year Ended December 31, 2000........... $ 186 $1,499 $ 46 $1,443 $ 288 ====== ====== ====== ====== ======
- --------------- (a) Recoveries on accounts previously written off. (b) Uncollectible accounts written off. S-3 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(a) DEDUCTIONS(b) PERIOD - ------------------------------------------------------------------------------------------------------------------- (IN THOUSANDS) DEDUCTED FROM ASSETS: Accumulated Provision for Uncollectible Accounts: Year Ended December 31, 2002........... $1,877 $3,937 $12,367 $4,742 $13,439 ====== ====== ======= ====== ======= Year Ended December 31, 2001........... $2,588 $2,644 $ 1,017 $4,372 $ 1,877 ====== ====== ======= ====== ======= Year Ended December 31, 2000........... $2,609 $6,592 $ 1,526 $8,139 $ 2,588 ====== ====== ======= ====== =======
- --------------- (a) Recoveries on accounts previously written off. (b) Uncollectible accounts written off. COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
- ------------------------------------------------------------------------------------------------------------------- COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E - ------------------------------------------------------------------------------------------------------------------- ADDITIONS ------------------------- BALANCE AT CHARGED TO CHARGED TO BALANCE AT BEGINNING COSTS AND OTHER END OF DESCRIPTION OF PERIOD EXPENSES ACCOUNTS(a) DEDUCTIONS(b) PERIOD - ------------------------------------------------------------------------------------------------------------------- (IN THOUSANDS) DEDUCTED FROM ASSETS: Accumulated Provision for Uncollectible Accounts: Year Ended December 31, 2002........... $ 745 $ (100) $ -- $ 11 $ 634 ====== ====== ====== ====== ====== Year Ended December 31, 2001........... $ 659 $ 331 $ -- $ 245 $ 745 ====== ====== ====== ====== ====== Year Ended December 31, 2000........... $3,045 $2,082 $1,405 $5,873 $ 659 ====== ====== ====== ====== ======
- --------------- (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(a) DEDUCTIONS(b) PERIOD - ------------------------------------------------------------------------------------------------------------------- (IN THOUSANDS) DEDUCTED FROM ASSETS: Accumulated Provision for Uncollectible Accounts: Year Ended December 31, 2002........... $ 741 $ (161) $ -- $ 2 $ 578 ====== ====== ====== ====== ====== Year Ended December 31, 2001........... $ 759 $ 65 $ 3 $ 86 $ 741 ====== ====== ====== ====== ====== Year Ended December 31, 2000........... $1,848 $ (235) $ 907 $1,761 $ 759 ====== ====== ====== ====== ======
- --------------- (a) Recoveries on accounts previously written off. (b) Uncollectible accounts written off. S-4 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(a) DEDUCTIONS(b) PERIOD - ------------------------------------------------------------------------------------------------------------------- (IN THOUSANDS) DEDUCTED FROM ASSETS: Accumulated Provision for Uncollectible Accounts: Year Ended December 31, 2002........... $ 264 $ (68) $ -- $ 4 $ 192 ====== ====== ====== ====== ====== Year Ended December 31, 2001........... $ 282 $ -- $ (24) $ (6) $ 264 ====== ====== ====== ====== ====== Year Ended December 31, 2000........... $ 637 $ 187 $ 9 $ 551 $ 282 ====== ====== ====== ====== ======
- --------------- (a) Recoveries on accounts previously written off. (b) Uncollectible accounts written off. OHIO 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(a) DEDUCTIONS(b) PERIOD - ------------------------------------------------------------------------------------------------------------------- (IN THOUSANDS) DEDUCTED FROM ASSETS: Accumulated Provision for Uncollectible Accounts: Year Ended December 31, 2002........... $1,379 $ (457) $ -- $ 13 $ 909 ====== ====== ====== ====== ====== Year Ended December 31, 2001........... $1,054 $ 554 $ -- $ 229 $1,379 ====== ====== ====== ====== ====== Year Ended December 31, 2000........... $2,223 $ 472 $ 778 $2,419 $1,054 ====== ====== ====== ====== ======
- --------------- (a) Recoveries on accounts previously written off. (b) Uncollectible accounts written off. PUBLIC SERVICE COMPANY OF OKLAHOMA 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(a) DEDUCTIONS(b) PERIOD - ------------------------------------------------------------------------------------------------------------------- (IN THOUSANDS) DEDUCTED FROM ASSETS: Accumulated Provision for Uncollectible Accounts: Year Ended December 31, 2002........... $ 44 $ 7 $ 33 $ -- $ 84 ====== ====== ====== ====== ====== Year Ended December 31, 2001........... $ 467 $ 44 $ -- $ 467 $ 44 ====== ====== ====== ====== ====== Year Ended December 31, 2000........... $ -- $ 467 $ -- $ -- $ 467 ====== ====== ====== ====== ======
- --------------- (a) Recoveries on accounts previously written off. (b) Uncollectible accounts written off. S-5 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(A) DEDUCTIONS(B) PERIOD - ------------------------------------------------------------------------------------------------------------------- (IN THOUSANDS) DEDUCTED FROM ASSETS: Accumulated Provision for Uncollectible Accounts: Year Ended December 31, 2002........... $ 89 $2,036 $ 4 $ 1 $2,128 ====== ====== ======= ====== ====== Year Ended December 31, 2001........... $ 911 $ 89 $ -- $ 911 $ 89 ====== ====== ======= ====== ====== Year Ended December 31, 2000........... $4,428 $ 911 $(4,428) $ -- $ 911 ====== ====== ======= ====== ======
- --------------- (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 KPCo [Registration Statement No. 33-32752, Exhibit 28(b)(2)]. 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 2002 Annual Report (for the fiscal year ended December 31, 2002) which are incorporated by reference in this filing. *24 -- Power of Attorney. *99(a) -- Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code. *99(b) -- Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code. 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 [Registration Statement No. 333-86050, Exhibits 4(a), 4(b) and 4(c)]. *4(b) -- Third Supplemental Indenture, dated as of June 11, 2002, between AEP and The Bank of New York, as Trustee, for 5.75% Senior Notes, Series C, due August 16, 2007.
E-1
EXHIBIT NUMBER DESCRIPTION - --------------- ----------- *4(c) -- Forward Purchase Contract Agreement, dated as of June 11, 2002, between AEP and The Bank of New York, as Forward Purchase Contract Agent. 10(a) -- Interconnection Agreement, dated July 6, 1951, among APCo, CSPCo, KPCo, 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) -- Restated and Amended Operating Agreement, dated as of January 1, 1998, among PSO, TCC, TNC, SWEPCo and AEPSC. 10(c) -- Transmission Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KPCo, 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) -- Transmission Coordination Agreement, dated October 29, 1998, among PSO, TCC, TNC, SWEPCo and AEPSC. 10(e) -- 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(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) -- Modification No. 1 to the AEP System Interim Allowance Agreement, dated July 28, 1994, among APCo, CSPCo, I&M, KPCo, 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(h)(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(h)(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(i)(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(i)(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(j) -- AEP Accident Coverage Insurance Plan for directors [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(g)]. +10(k)(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)].
E-2
EXHIBIT NUMBER DESCRIPTION - --------------- ----------- +10(k)(2) -- AEP Stock Unit Accumulation Plan for Non-Employee Directors, as amended January 1, 2002[Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2001, File No. 1-3525, Exhibit 10(i)(2)]. +10(l)(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(l)(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(l)(1)(C) -- First Amendment to AEP System Excess Benefit Plan, dated as of March 5, 2003. +10(l)(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(l)(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(m)(1) -- Employment Agreement between E. Linn Draper, Jr. and AEP and the Service Corporation [Annual Report on Form 10-K of AEGCo for the fiscal year ended December 31, 1991, File No. 0-18135, Exhibit 10(g)(3)]. +10(m)(2) -- 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(m)(3)(A) -- Letter Agreement dated June 23, 2000 between AEPSC and Holly K. Koeppel. *+10(m)(3)(B) -- Letter Agreement dated April 19, 2001 between AEPR and Holly K. Koeppel. *+10(m)(4) -- Employment Agreement dated July 29, 1998 between AEPSC and Robert P. Powers. +10(n) -- 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(o)(1) -- 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(o)(2) -- First Amendment to AEP System Survivor Benefit Plan, as amended and restated effective January 31, 2000. +10(p) -- 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(q)(1) -- AEP System Incentive Compensation Deferral Plan dated January 1, 2001. *+10(q)(2) -- First Amendment to AEP System Incentive Compensation Deferral Plan dated December 6, 2002. *+10(r) -- AEP System Nuclear Performance Long Term Incentive Compensation Plan dated August 1, 1998. *+10(s) -- Nuclear Key Contributor Retention Plan dated May 1, 2000. +10(t) -- 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(u) -- AEP System 2000 Long-Term Incentive Plan [Proxy Statement of AEP, March 10, 2000]. +10(v)(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(v)(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(v)(3) -- CSW 1992 Long-Term Incentive Plan [Proxy Statement of CSW, March 13, 1992].
E-3
EXHIBIT NUMBER DESCRIPTION - --------------- ----------- +10(v)(4) -- Central and South West Corporation Executive Deferred Savings Plan as amended and restated effective as of January 1, 1997 [Annual Report on Form 10-K of CSW for the fiscal year ended December 31, 1998, File No. 1-1443, Exhibit 24]. *12 -- Statement re: Computation of Ratios. *13 -- Copy of those portions of the AEP 2002 Annual Report (for the fiscal year ended December 31, 2002) which are incorporated by reference in this filing. *21 -- List of subsidiaries of AEP. *23 -- Consent of Deloitte & Touche LLP. *24 -- Power of Attorney. *99(a) -- Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code. *99(b) -- Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code. 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) [Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 2001, File No. 1-3457, Exhibit 3(e)]. 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)].
E-4
EXHIBIT NUMBER DESCRIPTION - --------------- ----------- 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); Registration Statement No. 333-100451, Exhibit 4(b)]. *4(c) -- Copy of Company Order and Officer's Certificate, dated November 6, 2002, establishing terms of 4.3148% Senior Notes, Series F, due 2007. 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, KPCo, 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, KPCo, 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, KPCo, 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)].
E-5
EXHIBIT NUMBER DESCRIPTION - --------------- ----------- +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)]. +10(h)(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(h)(1)(B) -- First Amendment to AEP System Excess Benefit Plan, dated as of March 5, 2003. +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)(1) -- Employment Agreement between E. Linn Draper, Jr. and AEP and the Service Corporation [Annual Report on Form 10-K of AEGCo for the fiscal year ended December 31, 1991, File No. 0-18135, Exhibit 10(g)(3)]. +10(i)(2) -- 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(i)(3) -- Employment Agreement dated July 29, 1998 between AEPSC and Robert P. Powers. +10(j)(1) -- 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(j)(2) -- First Amendment to AEP System Survivor Benefit Plan, as amended and restated effective January 31, 2000. +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)(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(n)(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(n)(3) -- CSW 1992 Long-Term Incentive Plan [Proxy Statement of CSW, March 13, 1992]. *+10(o)(1) -- AEP System Incentive Compensation Deferral Plan dated January 1, 2001. *+10(o)(2) -- First Amendment to AEP System Incentive Compensation Deferral Plan dated December 6, 2002. *+10(p) -- AEP System Nuclear Performance Long Term Incentive Compensation Plan dated August 1, 1998. *+10(q) -- Nuclear Key Contributor Retention Plan dated May 1, 2000. *12 -- Statement re: Computation of Ratios. *13 -- Copy of those portions of the APCo 2002 Annual Report (for the fiscal year ended December 31, 2002) 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, 2002, File No. 1-3525, Exhibit 21]. *23 -- Consent of Deloitte & Touche LLP
E-6
EXHIBIT NUMBER DESCRIPTION - --------------- ----------- *24 -- Power of Attorney. *99(a) -- Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code. *99(b) -- Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code. CSPCO++ 3(a) -- Copy of Amended Articles of Incorporation of CSPCo, as amended to March 6, 1992 [Registration Statement No. 33-53377, Exhibit 4(a)]. 3(b) -- Copy of Certificate of Amendment to Amended Articles of Incorporation of CSPCo, dated May 19, 1994 [Annual Report on Form 10-K of CSPCo for the fiscal year ended December 31, 1994, File No. 1-2680, Exhibit 3(b)]. 3(c) -- Composite copy of Amended Articles of Incorporation of CSPCo, as amended [Annual Report on Form 10-K of CSPCo for the fiscal year ended December 31, 1994, File No. 1-2680, Exhibit 3(c)]. 3(d) -- Copy of Code of Regulations and By-Laws of CSPCo [Annual Report on Form 10-K of CSPCo for the fiscal year ended December 31, 1987, File No. 1-2680, Exhibit 3(d)]. 4(a) -- Copy of Indenture of Mortgage and Deed of Trust, dated September 1, 1940, between CSPCo and City Bank Farmers Trust Company (now Citibank, N.A.), as trustee, as supplemented and amended [Registration Statement No. 2-59411, Exhibits 2(B) and 2(C); Registration Statement No. 2-80535, Exhibit 4(b); Registration Statement No. 2-87091, Exhibit 4(b); Registration Statement No. 2-93208, Exhibit 4(b); Registration Statement No. 2-97652, Exhibit 4(b); Registration Statement No. 33-7081, Exhibit 4(b); Registration Statement No. 33-12389, Exhibit 4(b); Registration Statement No. 33-19227, Exhibits 4(b), 4(e), 4(f), 4(g) and 4(h); Registration Statement No. 33-35651, Exhibit 4(b); Registration Statement No. 33-46859, Exhibits 4(b) and 4(c); Registration Statement No. 33-50316, Exhibits 4(b) and 4(c); Registration Statement No. 33-60336, Exhibits 4(b), 4(c) and 4(d); Registration Statement No. 33-50447, Exhibits 4(b) and 4(c); Annual Report on Form 10-K of CSPCo for the fiscal year ended December 31, 1993, File No. 1-2680, Exhibit 4(b)]. 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)].
E-7
EXHIBIT NUMBER DESCRIPTION - --------------- ----------- 10(b) -- Copy of Interconnection Agreement, dated July 6, 1951, among APCo, CSPCo, KPCo, 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, KPCo, 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, KPCo, 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 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 2002 Annual Report (for the fiscal year ended December 31, 2002) which are incorporated by reference in this filing. 21 -- List of subsidiaries of CSPCo [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2002, File No. 1-3525, Exhibit 21] *23 -- Consent of Deloitte & Touche LLP. *24 -- Power of Attorney. *99(a) -- Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code. *99(b) -- Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code. 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) [Annual Report on Form 10-K of I&M for the fiscal year ended December 31, 2001, File No. 1-3570, Exhibit 3(d)].
E-8
EXHIBIT NUMBER DESCRIPTION - --------------- ----------- 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. 333-58656, Exhibits 4(b) and 4(c); Annual Report of Form 10-K of I&M for fiscal year ended December 31, 2001, File No. 1-3570, Exhibit 4(c)]. *4(c) -- Copy of Company Order and Officer's Certificate, dated November 22, 2002 establishing certain terms of the 6% Senior Notes, Series D, due 2032. 4(d) -- Copy of Company Order and Officers' Certificate, dated December 12, 2001, establishing certain terms of the 6.125% Notes, Series C, due 2006. [Annual Report on Form 10-K of I&M for the fiscal year ended December 31, 2001, File No. 1-3570, Exhibit 4(c)]. 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(b) -- Copy of Interconnection Agreement, dated July 6, 1951, among APCo, CSPCo, KPCo, 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)].
E-9
EXHIBIT NUMBER DESCRIPTION - --------------- ----------- 10(c) -- Copy of Transmission Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KPCo, 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, KPCo, 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)]. 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 2002 Annual Report (for the fiscal year ended December 31, 2002) 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, 2002, File No. 1-3525, Exhibit 21]. *24 -- Power of Attorney. *99(a) -- Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code. *99(b) -- Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code. KPCO++ 3(a) -- Copy of Restated Articles of Incorporation of KPCo [Annual Report on Form 10-K of KPCo for the fiscal year ended December 31, 1991, File No. 1-6858, Exhibit 3(a)]. 3(b) -- Copy of By-Laws of KPCo (amended as of June 15, 2000) [Annual Report on Form 10-K of KPCo 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 KPCo and Bankers Trust Company (now Deutsche Bank Trust Company Americas, 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 KPCo and Bankers Trust Company, as Trustee [Registration Statement No. 333-75785, Exhibits 4(a), 4(b), 4(c) and 4(d); Registration Statement No. 333-87216, Exhibits 4E) and 4(f). *4(c) -- Copy of Company Order and Officer's Certificate, dated June 28, 2002 establishing certain terms of the 5.50% Senior Notes, Series A, due 2007.
E-10
EXHIBIT NUMBER DESCRIPTION - --------------- ----------- *4(d) -- Copy of Company Order and Officer's Certificate, dated November 6, 2002 establishing certain terms of the 4.3148% Senior Notes, Series B, due 2007. *4(e) -- Copy of Company Order and Officer's Certificate, dated December 12, 2002 establishing certain terms of the 4.368% Senior Notes, Series C, due 2007. 10(a) -- Copy of Interconnection Agreement, dated July 6, 1951, among APCo, CSPCo, KPCo, 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, KPCo, 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, KPCo, 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(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 KPCo dated December 15, 1999, File No. 1-6858, Exhibit 10]. *12 -- Statement re: Computation of Ratios. *13 -- Copy of those portions of the KPCo 2002 Annual Report (for the fiscal year ended December 31, 2002) which are incorporated by reference in this filing. *23 -- Consent of Deloitte & Touche LLP *24 -- Power of Attorney. *99(a) -- Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code. *99(b) -- Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code. 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) -- Copy of 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) -- Copy of Certificate of Amendment to Amended Articles of Incorporation of OPCo, dated June 3, 2002 [Quarterly Report on Form 10-Q of OPCo for the quarter ended June 30, 2002, File No. 1-6543, Exhibit 3(d)]. 3(e) -- Composite copy of the Amended Articles of Incorporation of OPCo (amended as of June 3, 2002) [[Quarterly Report on Form 10-Q of OPCo for the quarter ended June 30, 2002, File No. 1-6543, Exhibit 3(e)].
E-11
EXHIBIT NUMBER DESCRIPTION - --------------- ----------- 3(f) -- 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 (now Deutsche Bank Trust Company Americas), 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)]. 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, KPCo, 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, KPCo, 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, KPCo, 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-12
EXHIBIT NUMBER DESCRIPTION - --------------- ----------- 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]. +10(h) -- AEP System Senior Officer Annual Incentive Compensation Plan [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(i)(1)]. +10(i)(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(i)(1)(B) -- First Amendment to AEP System Excess Benefit Plan, dated as of March 5, 2003. +10(i)(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(i)(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(j)(1) -- Employment Agreement between E. Linn Draper, Jr. and AEP and the Service Corporation [Annual Report on Form 10-K of AEGCo for the fiscal year ended December 31, 1991, File No. 0-18135, Exhibit 10(g)(3)]. +10(j)(2) -- 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(j)(3) -- Employment Agreement dated July 29, 1998 between AEPSC and Robert P. Powers. +10(k)(1) -- 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)(2) -- First Amendment to AEP System Survivor Benefit Plan, as amended and restated effective January 31, 2000. +10(l) -- 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(m) -- 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(n) -- AEP System 2000 Long-Term Incentive Plan [Proxy Statement of AEP, March 10, 2000]. +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]. *+10(p)(1) -- AEP System Incentive Compensation Deferral Plan dated January 1, 2001.
E-13
EXHIBIT NUMBER DESCRIPTION - --------------- ----------- *+10(p)(2) -- First Amendment to AEP System Incentive Compensation Deferral Plan dated December 6, 2002. *+10(q) -- AEP System Nuclear Performance Long Term Incentive Compensation Plan dated August 1, 1998. *+10(r) -- Nuclear Key Contributor Retention Plan dated May 1, 2000. *12 -- Statement re: Computation of Ratios. *13 -- Copy of those portions of the OPCo 2002 Annual Report (for the fiscal year ended December 31, 2002) 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, 2002, File No. 1-3525, Exhibit 21]. *23 -- Consent of Deloitte & Touche LLP. *24 -- Power of Attorney. *99(a) -- Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code. *99(b) -- Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code. 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 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].
E-14
EXHIBIT NUMBER DESCRIPTION - --------------- ----------- (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 [Registration Statement No. 333-100623, Exhibits 4(a) and 4(b)]. *4(d) -- Second Supplemental Indenture, dated as of November 26, 2002 establishing certain terms of the 6% Senior Notes, Series B, due 2032. *10(a) -- Copy of Restated and Amended Operating Agreement, dated as of January 1, 1998, among PSO, TCC, TNC, SWEPCo and AEPSC. *10(b) -- Transmission Coordination Agreement, dated October 29, 1998, among PSO, TCC, TNC, SWEPCo and AEPSC. *12 -- Statement re: Computation of Ratios. *13 -- Copy of those portions of the PSO 2002 Annual Report (for the fiscal year ended December 31, 2002) which are incorporated by reference in this filing. 21 -- List of subsidiaries of PSO [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2002, File No. 1-3525, Exhibit 21] *23 -- Consent of Deloitte & Touche LLP. *24 -- Power of Attorney. *99(a) -- Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code. *99(b) -- Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code. 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]. 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].
E-15
EXHIBIT NUMBER DESCRIPTION - --------------- ----------- (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 [Registration Statement No. 333-87834, Exhibits 4(a) and 4(b); Form 8-K of SWEPCo filed on June 26, 2002, File No. 1-3146, Exhibit 4(b)]. *10(a) -- Copy of Restated and Amended Operating Agreement, dated as of January 1, 1998, among PSO, TCC, TNC, SWEPCo and AEPSC. *10(b) -- Transmission Coordination Agreement, dated October 29, 1998, among PSO, TCC, TNC, SWEPCo and AEPSC. *12 -- Statement re: Computation of Ratios. *13 -- Copy of those portions of the SWEPCo 2002 Annual Report (for the fiscal year ended December 31, 2002) which are incorporated by reference in this filing. 21 -- List of subsidiaries of SWEPCo [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2002, File No. 1-3525, Exhibit 21] *23 -- Consent of Deloitte & Touche LLP. *24 -- Power of Attorney. *99(a) -- Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code. *99(b) -- Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code. TCC++ 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 TCC for the quarter ended March 31, 1997, File No. 0-346, Exhibit 3.1]. *3(b) -- Articles of Amendment to Restated Articles of Incorporation of TCC dated December 18, 2002. 3(c) -- By-Laws of TCC (amended as of April 19, 2000) [Annual Report on Form 10-K of TCC for the fiscal year ended December 31, 2000, File No. 0-346, Exhibit 3(b)]. 4(a) -- Indenture of Mortgage or Deed of Trust, dated November 1, 1943, between TCC 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) -- TCC-obligated, mandatorily redeemable preferred securities of subsidiary trust holding solely Junior Subordinated Debentures of TCC: (1) Indenture, dated as of May 1, 1997, between TCC and the Bank of New York, as Trustee [Quarterly Report on Form 10-Q of TCC dated March 31, 1997, File No. 0-346, Exhibits 4.1 and 4.2].
E-16
EXHIBIT NUMBER DESCRIPTION - --------------- ----------- (2) Amended and Restated Trust Agreement of TCC Capital I, dated as of May 1, 1997, among TCC, 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 TCC dated March 31, 1997, File No. 0-346, Exhibit 4.3]. (3) Guarantee Agreement, dated as of May 1, 1997, delivered by TCC for the benefit of the holders of TCC Capital I's Preferred Securities [Quarterly Report on Form 10-Q of TCC 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 TCC and TCC Capital I [Quarterly Report on Form 10-Q of TCC 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 TCC and The Bank of New York, as Trustee, as amended and supplemented [Annual Report on Form 10-K of TCC for the fiscal year ended December 31, 2000, File No. 0-346, Exhibits 4(c), 4(d) and 4(e)]. *10(a) -- Copy of Restated and Amended Operating Agreement, dated as of January 1, 1998, among PSO, TCC, TNC, SWEPCo and AEPSC. *10(b) -- Transmission Coordination Agreement, dated October 29, 1998, among PSO, TCC, TNC, SWEPCo and AEPSC. *12 -- Statement re: Computation of Ratios. *13 -- Copy of those portions of the TCC 2002 Annual Report (for the fiscal year ended December 31, 2002) which are incorporated by reference in this filing. 21 -- List of subsidiaries of TCC [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2002, File No. 1-3525, Exhibit 21] *23 -- Consent of Deloitte & Touche LLP. *24 -- Power of Attorney. *99(a) -- Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code. *99(b) -- Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code. TNC++ 3(a) -- Restated Articles of Incorporation, as amended, and Articles of Amendment to the Articles of Incorporation [Annual Report on Form 10-K of TNC for the fiscal year ended December 31, 1996, File No. 0-340, Exhibit 3.5]. *3(b) -- Articles of Amendment to Restated Articles of Incorporation of TNC dated December 17, 2002. 3(c) -- By-Laws of TNC (amended as of May 1, 2000) [Quarterly Report on Form 10-Q of TNC for the quarter ended March 31, 2000, File No. 0-340, Exhibit 3.4]. 4(a) -- Indenture, dated August 1, 1943, between TNC 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)]. *10(a) -- Copy of Restated and Amended Operating Agreement, dated as of January 1, 1998, among PSO, TCC, TNC, SWEPCo and AEPSC. *10(b) -- Transmission Coordination Agreement, dated October 29, 1998, among PSO, TCC, TNC, SWEPCo and AEPSC. *12 -- Statement re: Computation of Ratios.
E-17
EXHIBIT NUMBER DESCRIPTION - --------------- ----------- *13 -- Copy of those portions of the TNC 2002 Annual Report (for the fiscal year ended December 31, 2002) which are incorporated by reference in this filing. *24 -- Power of Attorney. *99(a) -- Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code. *99(b) -- Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.
---------------------- ++ 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-18 (LOGO) RECYCLE LOGO PRINTED ON RECYCLED PAPER EX-10 4 x10a.txt (A) AMEND OPERATING AGREEMENT EXHIBIT 10(a) RESTATED AND AMENDED OPERATING AGREEMENT Among Central Power and Light Company Public Service Company of Oklahoma Southwestern Electric Power Company West Texas Utilities Company Central and South West Services, Inc. January 1, 1998 OPERATING AGREEMENT TABLE OF CONTENTS Page ARTICLE I TERM OF AGREEMENT........................... 2 ARTICLE II DEFINITIONS.............................. 2 2.1 Agent..................................................... 3 2.2 Agreement................................................. 3 2.3 Capacity Commitment....................................... 3 2.4 Capacity Commitment Charge................................ 3 2.5 Central Control Center.................................... 3 2.6 Chief Executive Officer (CEO)............................. 3 2.7 Company................................................... 3 2.8 Company Capability........................................ 3 2.9 Company Demand............................................ 4 2.10 Company Hourly Capability................................. 4 2.11 Company Load Responsibility............................... 4 2.12 Company Operating Capability.............................. 5 2.13 Company Operating Reserve................................. 5 2.14 Company Peak Demand....................................... 5 2.15 Day....................................................... 5 2.16 Decremental Energy Value.................................. 5 2.17 Economic Dispatch......................................... 5 2.18 Energy.................................................... 5 2.19 Generating Unit........................................... 5 2.20 Hour...................................................... 6 2.21 Incremental Energy Cost................................... 6 2.22 Internal Economy Energy................................... 6 2.23 Joint Resource Plan....................................... 6 2.24 Joint Unit................................................ 6 2.25 (a) Margin on Sales.................................. 6 2.25 (b) Margin on Purchases.............................. 6 2.25 (c) Margin on Internal Economy Energy................ 6 2.25 (d) Margin........................................... 7 2.26 Month..................................................... 7 2.27 Operating Committee....................................... 7 2.28 Own Load.................................................. 7 2.29 Parent Company............................................ 7 2.30 Planning Reserve Level.................................... 7 2.31 Pool Energy............................................... 7 2.32 Power..................................................... 8 2.33 Prorated Reserve Level.................................... 8 2.34 Reserve Capacity (Company or System)...................... 8 2.35 System.................................................... 8 2.36 System Capability......................................... 8 2.37 System Demand............................................. 8 2.38 System Load Responsibility................................ 8 2.39 System Operating Capability............................... 9 2.40 System Operating Reserve.................................. 9 2.41 System Peak Demand........................................ 9 i 2.42 Transaction Cost.......................................... 9 2.43 Variable Cost............................................. 9 2.44 Year...................................................... 9 ARTICLE III OBJECTIVES.............................. 9 3.1 Purpose................................................... 9 ARTICLE IV AGENT................................. 10 4.1 Responsibility of the Agent............................... 10 4.2 Delegation and Acceptance of Authority.................... 10 4.3 Reporting................................................. 10 ARTICLE V OPERATING COMMITTEE......................... 11 5.1 Operating Committee....................................... 11 ARTICLE VI OPERATIONS.............................. 11 6.1 Planning and Authorization of Production Facilities....... 11 6.2 Planning Reserve Levels................................... 12 6.3 Provision to Achieve Planning Reserve Levels.............. 12 6.4 Capacity Sales and Purchases and Reserve Shortfalls....... 13 6.5 Energy Exchanges Among the Companies...................... 13 6.6 Energy Exchange Pricing................................... 13 6.7 Energy Exchanges with Non-Associated Utilities............ 14 6.8 Communications and other Facilities....................... 15 ARTICLE VII CENTRAL CONTROL CENTER......................... 15 7.1 Central Control Center.................................... 15 7.2 Expenses.................................................. 15 ARTICLE VIII GENERAL................................ 16 8.1 Regulatory Authorization.................................. 16 8.2 Effect on Other Agreements................................ 16 8.3 Schedules................................................. 16 8.4 Billings.................................................. 16 8.5 Waivers................................................... 17 8.6 Successors and Assigns; No Third Party Beneficiary........ 17 8.7 Amendment................................................. 18 8.8 Independent Contractors................................... 18 8.9 Responsibility and Liability.............................. 18 ii SCHEDULES A JOINT UNIT B COMPANY UNITS THAT ARE NOT JOINT UNITS C CAPACITY COMMITMENT CHARGE D PAYMENTS AND RECEIPTS FOR POOL ENERGY EXCHANGES AMONG THE COMPANIES E PAYMENTS AND RECEIPTS FOR INTERNAL ECONOMY ENERGY EXCHANGES AMONG THE COMPANIES AND FOR OFF-SYSTEM ENERGY PURCHASES AND SALES F DISTRIBUTION OF MARGIN FOR INTERNAL ECONOMY ENERGY EXCHANGES AND FOR OFF- SYSTEM ENERGY PURCHASES AND SALES G DISTRIBUTION OF OPERATING EXPENSES OF THE CENTRAL CONTROL CENTER H CAPACITY COMMITMENT UNITS I PLANNING-RESERVE CRITERIA J STATEMENT OF PRACTICE REGARDING OFF-SYSTEM ENERGY SALES K DISTRIBUTION OF CERTAIN TRANSACTION COSTS iii RESTATED AND AMENDED OPERATING AGREEMENT Among Central Power and Light Company Public Service Company of Oklahoma Southwestern Electric Power Company West Texas Utilities Company Central and South West Services, Inc. THIS RESTATED AND AMENDED OPERATING AGREEMENT, hereinafter called Agreement, is made and entered into as of the 1st day of January, 1998 by and among Central Power and Light Company, hereinafter called CPL; Public Service Company of Oklahoma, hereinafter called PSO; Southwestern Electric Power Company, hereinafter called SWEPCO; West Texas Utilities Company, hereinafter called WTU; and Central and South West Services, Inc., hereinafter called CSWS; all of whose common stock is wholly owned by Central and South West Corporation, and supersedes the Restated and Amended Operating Agreement dated October 1, 1993. WHEREAS, CPL, PSO, SWEPCO, and WTU are the owners and operators of interconnected electric generation, transmission, and distribution facilities with which they are engaged in the business of generating, transmitting, and selling electric Power and Energy to the general public and to other electric utilities; and WHEREAS, the Companies achieve economic benefits for their customers through operation as a single interconnected system and through coordinated planning, construction, operation and maintenance of their electric supply facilities; and WHEREAS, CSWS is qualified to act as Agent for the Companies; NOW, THEREFORE, the parties hereto mutually agree as follows: ARTICLE I TERM OF AGREEMENT 1.1 This Agreement shall become effective on such date as is established by the Federal Energy Regulatory Commission. This Agreement shall continue in force and effect for a period of ten (10) Years from the effective date hereinabove described, and continue from Year to Year thereafter until terminated by one or more of the parties upon three (3) Years written notice to the other parties. 1.2 This Agreement is intended to cover only the acquisition, disposition, planning, design, construction, operation and maintenance of the Generating Units and is not to affect those matters that are the subject of orders of the United States Securities and Exchange Commission authorizing certain cost allocation methods for CSWS billings. ARTICLE II DEFINITIONS For the purposes of this Agreement and of Schedules A through K which are attached hereto and made a part hereof, the following definitions shall apply: 2.1 Agent for the Companies shall be CSWS. 2.2 Agreement shall be this Agreement including all attachments and schedules applying hereto and any amendments made hereafter. 2.3 Capacity Commitment shall be generating capacity committed by a Company to provide capability to enable another Company to attain its Planning or Prorated Reserve Level, whichever shall be lower. 2.4 Capacity Commitment Charge shall be the charge made by a Company supplying a Capacity Commitment to the Company receiving the Capacity Commitment. 2.5 Central Control Center shall be a center operated by the Agent for the optimal utilization of System resources for the supply of Power and Energy. 2.6 Chief Executive Officer (CEO) shall be the Chief Executive Officer of Central and South West Corporation or the CEO's designee. 2.7 Company shall be any one of the Central and South West Corporation operating companies and Companies shall be the Central and South West Corporation operating companies collectively. 2.8 Company Capability shall be: (a) The sum of the Company net plant capability in megawatts; plus (b) The megawatt amount of purchases and exchanges without reserves, under contract from other systems; less (c) The megawatt amount of sales and exchanges without reserves, under contract to other systems. 2.9 Company Demand shall be: (a) The clock-hour demand in megawatts of a Company's system represented by the simultaneous hourly input in megawatt-hours from all sources into the system of a Company; less (b) The sum of the simultaneous hourly output in megawatt-hours to other systems (exclusive of any wholesale requirements obligations of the Company). 2.10 Company Hourly Capability for a Company shall be: (a) The megawatt amount of dependable capability of the Company's generating units on line, including its shares of Joint Units and its shares of units owned jointly with non-associated entities, during the Hour; plus (b) The megawatt amount of capability committed to the Company by other Companies or non-associated suppliers during the Hour; less (c) The megawatt amount of capability committed by the Company to other Companies or non-associated purchasers during the Hour; less (d) Any capability required to provide operating reserves. 2.11 Company Load Responsibility shall be as follows: (a) Company Peak Demand; less (b) the difference between Company Peak Demand and Company Demand at the time of System Peak Demand; less (c) The megawatt-hour output of the Company served on an interruptible basis during the hour of Company Peak Demand; plus (d) The contractual amount of sales and exchanges with reserves during the period to other systems; less (e) The contractual amount of purchases and exchanges with reserves during the period from other systems. 2.12 Company Operating Capability shall be the dependable net capability in megawatts of Generating Units of a Company carrying load or ready to take load. 2.13 Company Operating Reserve shall be the excess of Company Operating Capability over Company Demand expressed in megawatts. 2.14 Company Peak Demand for a period shall be the highest Company Demand for any Hour during the period. 2.15 Day shall be a calendar day. 2.16 Decremental Energy Value shall be the cost that a buying Company avoids by reducing the generation of Energy from its Company Operating Capability or by reducing its purchase of Energy from others. 2.17 Economic Dispatch shall be the distribution of total generation requirements among alternative sources for System economy with due consideration of incremental generating costs, incremental transmission losses, and System security. 2.18 Energy shall be work and shall be expressed in megawatt-hours (MWH). 2.19 Generating Unit shall be an electric generator, together with its prime mover and all auxiliary and appurtenant devices and equipment designed to be operated as a unit for the production of electric Power and Energy. The above is to include equipment necessary for connection to the transmission system. 2.20 Hour shall be a clock-hour. 2.21 Incremental Energy Cost shall be the variable cost which a selling Company incurs in order to supply Energy for resale. 2.22 Internal Economy Energy shall be Energy supplied and sold by one Company to another Company, under Economic Dispatch, to meet a portion of the purchasing Company's Own Load that could otherwise be supplied internally by the purchasing Company. 2.23 Joint Resource Plan shall be the formal documented plan developed from time to time for all future Generating Units and other power supply and demand management resources. 2.24 Joint Unit shall be any Generating Unit jointly owned by two or more of the Companies. 2.25 (a) Margin on Sales shall be the difference between: (1) the revenue from off-System Energy sales made pursuant to Section 6.7 and (2) the selling Companies' Incremental Energy Cost incurred in making such sales. 2.25 (b) Margin on Purchases shall be the difference between (1) the buying Companies' Decremental Energy Value avoided as a result of off-System Energy purchases made pursuant to Section 6.7 and (2) payments for off-System Energy purchases made pursuant to Section 6.7. 2.25 (c) Margin on Internal Economy Energy shall be the difference between (1) the buying Companies' Decremental Energy Value avoided as the result of receiving Internal Economy Energy and (2) the selling Companies' Internal Economy Energy Cost incurred in supplying Internal Economy Energy. 2.25 (d) Margin for a given period shall be the sum of the amounts developed in accordance with Sections 2.25 (a), 2.25 (b) and 2.25 (c). 2.26 Month shall be a calendar Month. 2.27 Operating Committee shall be the organization established pursuant to Section 5.1 and whose duties are more fully set forth therein. 2.28 Own Load shall be Energy required to meet Company Demand plus Energy associated with sales or exchanges with reserves less Energy associated with purchases or exchanges with reserves. 2.29 Parent Company shall be Central and South West Corporation. 2.30 Planning Reserve Level shall be the megawatt amount of required Reserve Capacity for a Company, expressed as a percentage of its forecasted Company Load Responsibility. 2.31 Pool Energy shall be the Energy supplied and sold by one Company to another Company to enable the purchasing Company to meet a portion of its Own Load that such other Company cannot or does not plan to serve with its other resources. There shall be two categories of Pool Energy. Emergency Pool Energy shall be the Energy required by a Company that becomes deficient because of an unplanned occurrence (such as a generator unit trip or a missed load forecast). Planned Pool Energy shall be the Energy required by a Company to meet portions of its Own Load when it determines that (a) it will be short of capacity when planning for future operations or (b) such Energy can be taken to economic advantage. 2.32 Power shall be the rate of doing work and shall be expressed in megawatts (MW). 2.33 Prorated Reserve Level shall be a percentage reserve level for each Company that when divided by that Company's Planning Reserve Level gives the same quotient as that for all other Companies. 2.34 Reserve Capacity (Company or System) shall be that amount in megawatts by which Company or System Capability exceeds Company or System Load Responsibility. 2.35 System shall be the coordinated Generating Units of the Companies. 2.36 System Capability shall be the arithmetical sum in megawatts of the individual Company Capabilities. 2.37 System Demand shall be the arithmetical sum of the Companies' clock-hour demand in megawatts represented by: (a) The simultaneous hourly input in megawatt-hours from all sources into the System; less (b) The sum of the simultaneous hourly outputs in megawatt-hours to other systems (exclusive of any wholesale requirements obligations of the Companies). 2.38 System Load Responsibility shall be as follows: (a) System Peak Demand; less (b) The megawatt-hour output of the Companies served on an interruptible basis during the Hour of System Peak Demand; plus (c) The arithmetic sum in megawatts of all of the Companies' contractual amount of sales and exchanges with reserves during the period to other systems; less (d) The arithmetic sum in megawatts of all the Companies' contractual amount of purchases and exchanges with reserves during the period from other systems. 2.39 System Operating Capability shall be the arithmetical sum in megawatts of the individual Company Operating Capabilities. 2.40 System Operating Reserve shall be the arithmetical sum of the individual Company Operating Reserves, expressed in megawatts. 2.41 System Peak Demand for a period shall be the highest System Demand for any hour during the period. 2.42 Transaction Cost shall be the sum of the charges assessed against any one or more of the Companies for transmission services related to Internal Economy Energy exchanges and off-System Energy purchases and sales, other than such charges allocated among the Companies pursuant to the Distribution of Certain Transaction Costs procedure set forth in Schedule K. 2.43 Variable Cost shall be a Company's incremental generation cost or purchased energy cost. 2.44 Year shall be a calendar Year. ARTICLE III OBJECTIVES 3.1 Purpose The purpose of this Agreement is to provide the contractual basis for the coordinated planning, construction, operation and maintenance of the System to achieve optimal economies, consistent with reliable electric service, reasonable utilization of natural resources, and environmental requirements. ARTICLE IV AGENT 4.1 Responsibility of the Agent The Companies hereby designate CSWS as their Agent for the purpose of: (a) coordinating the acquisition, disposition, planning, design, construction, operation and maintenance of the Generating Units of the Companies, including any Joint Units; and (b) supervising the design, construction, operation and maintenance of the Central Control Center. 4.2 Delegation and Acceptance of Authority The Companies hereby delegate to the Agent and the Agent hereby accepts responsibility and authority for the duties listed in Section 4.1 and elsewhere in this Agreement. Except as herein expressly established otherwise, the Agent shall perform each of those duties in consultation with the Operating Committee. The Agent shall also perform each of those duties in accordance with the standards of conduct described in 18 C.F.R. Section 37.4. 4.3 Reporting The Agent shall provide periodic summary reports of its activities under this Agreement to the Companies and shall keep the Companies and the Operating Committee currently informed of situations or problems that may materially affect the outcome of these activities. Furthermore, the Agent agrees to report to the Companies or to the Operating Committee in such additional detail as is requested regarding specific issues or projects under its supervision as Agent. ARTICLE V OPERATING COMMITTEE 5.1 Operating Committee The Operating Committee is the organization established to ensure the coordinated operation of the System by making recommendations to the CEO regarding operations under this Agreement. The Operating Committee members will be designated by the CEO and shall include a chairperson and at least one member from the Agent and from each Company. Operating Committee decisions shall be by a majority vote of those present and shall be in the form of recommendations to the CEO. However, any member not present may vote by proxy. In any non-unanimous decision the principles of the difference shall be reported to the CEO. The chairperson shall vote only in case of a tie. ARTICLE VI OPERATIONS 6.1 Planning and Authorization of Production Facilities (a) Each Company shall forecast the amount of generating capability required to meet its Company Load Responsibility and its Planning Reserve Level in future Years. (b) A current Joint Resource Plan will be maintained that will state the current forecasted System Load Responsibility including the Planning Reserve Level and the required resources. (c) All Generating Units placed in service after the date of this Agreement shall be in accordance with the then current Joint Resource Plan. Joint Units shall be authorized by the Board of Directors of the Parent Company prior to the commencement of detailed engineering of the units. (d) For the purpose of this Agreement, the Generating Units listed in Schedule B are not Joint Units. (e) The organization designated by the CEO shall be responsible for the staffing, operation and maintenance of each Generating Unit. 6.2 Planning Reserve Levels The Operating Committee shall periodically review the Planning Reserve Level for each Company and recommend any modifications of such to the CEO. 6.3 Provision to Achieve Planning Reserve Levels (a) Each Company shall own or have available to it under contract such generating capability and other facilities as are necessary to supply its Company Load Responsibility plus its Planning Reserve Level. (b) The Joint Resource Plan shall be periodically reviewed and adjusted to provide the Companies their required Planning Reserve Levels. Any Company with Reserve Capacity in excess of its Planning Reserve Level for a future Year shall commit such excess capacity to Companies with insufficient Reserve Capacity to meet their Planning Reserve Level during that Year or any portion thereof. The deficit Companies shall make payments to the excess Companies in respect of each Month of the Year to which the commitment applies in the amount of the Capacity Commitment Charge in accordance with Schedule C. In the event that the System Capability, including outside capacity purchases, is insufficient to meet such Planning Reserve Levels, the System Capability shall be allocated to provide each Company its Prorated Reserve Level. (c) The ownership percentages in future Joint Units are established in accordance with Schedule A, but may be reallocated in the Joint Resource Plan by recommendation of the Operating Committee and authorization by the CEO. 6.4 Capacity Sales and Purchases and Reserve Shortfalls (a) The Agent shall coordinate and assist the Companies in making off-System capacity sales and purchases. (b) The System Reserve Capacity shall be at the disposal of any Company requiring such capacity. Should the System be short of capacity as a result of an emergency and be unable to purchase the deficit, each Company shall take such actions as are necessary to bring System load and generation into balance. 6.5 Energy Exchanges Among the Companies The Agent shall schedule the Energy output of System Capability to obtain the lowest cost of Energy for serving System Demand consistent with each Company's operating and security constraints, including voltage control, stability loading of facilities, operating guides as recommended by the Operating Committee and approved by the CEO, fuel commitments, environmental requirements, and continuity of service to customers. 6.6 Energy Exchange Pricing For the purpose of pricing Energy exchange among the Companies, System resources shall be utilized to serve System requirements in the following order: a) Those Generating Units which are designated not to be operated in the order of lowest to highest Variable Cost due to Company operating constraints shall be allocated to the Company requiring the Generating Unit. (b) The lowest Variable Cost generation of each Company's Hourly Capability shall first be allocated to serve its Own Load. c) The next lowest Variable Cost portion of each Company's remaining Hourly Capability shall be allocated to serve Pool Energy requirements of Companies under System Economic Dispatch. Pool Energy shall be priced in accordance with Schedule D. (d) The next lowest Variable Cost portion of each Company's remaining Hourly Capability shall be used to supply Internal Economy Energy to Companies under System Economic Dispatch. Internal Economy Energy shall be priced in accordance with Schedule E. 6.7 Energy Exchanges with Non-Associated Entities The Agent shall coordinate and direct off-System purchases of Energy necessary to meet System requirements or improve System economy, after Internal Economy Energy transactions have been effected. The Agent shall coordinate and direct off-System sales of Energy available after meeting all of the requirements of the System including the Energy associated with contractual requirements for off-System capacity sales. Such off-System Energy purchases or sales shall be implemented by decremental or incremental System Economic Dispatch as appropriate. Any Margin on off-System Energy sales or purchases made to improve System economy shall be distributed to the Companies in accordance with Schedule F. Price quotations for such Energy sales shall be determined in accordance with Schedule J. 6.8 Communications and other Facilities The Companies shall provide communications and other facilities necessary for: (a) The metering and control of the generating and transmission facilities; (b) The dispatch of electric Power and Energy; and (c) For such other purposes as may be necessary for optimum operation of the System. ARTICLE VII CENTRAL CONTROL CENTER 7.1 Central Control Center The Agent shall provide and operate a Central Control Center adequately equipped and staffed to meet the requirements of the Companies for efficient, economical and reliable operation as contemplated by this Agreement. 7.2 Expenses All expenses for operation of the Central Control Center shall be paid by the Agent and billed monthly to each Company in accordance with Schedule G. ARTICLE VIII GENERAL 8.1 Regulatory Authorization This Agreement is subject to certain regulatory approvals and each Company and the Agent shall diligently seek all necessary regulatory authorization for this Agreement. 8.2 Effect on Other Agreements This Agreement shall not modify the obligations of any Company under any agreement between that Company and others not parties to this Agreement in effect at the date of this Agreement, nor shall it modify any agreement between or among the Companies under any transmission tariff or other agreement filed with the Federal Energy Regulatory Commission. 8.3 Schedules The basis of compensation for the use of facilities and for the Power and Energy provided or supplied by a Company to another Company or Companies under this Agreement shall be in accordance with arrangements agreed upon from time to time among the Companies. Such arrangements shall be in the form of Schedules, each of which, when signed by the parties thereto and approved or accepted by appropriate regulatory authority, shall become a part of this Agreement. 8.4 Billings Bills for services rendered hereunder shall be calculated in accordance with applicable Schedules, and shall be issued on or before the tenth working Day of the Month following that in which such service was rendered and shall be payable on or before the twentieth Day of such Month. After the thirtieth Day, interest shall accrue on any balance due until paid at the latest rate approved by the United States Securities and Exchange Commission for loans among Companies in the Central and South West System. Billings in good faith disputed and paid shall be deemed to have been paid under protest. 8.5 Waivers Any waiver at any time by a Company of its rights with respect to a default by any other Company under this Agreement shall not be deemed a waiver with respect to any subsequent default of similar or different nature, nor shall it prejudice its right to deny waiver of similar default to a different Company. 8.6 Successors and Assigns; No Third Party Beneficiary This Agreement shall inure to and be binding upon the successors and assigns of the respective parties hereto, but shall not be assignable by any party without the written consent of the other parties, except upon foreclosure of a mortgage or deed of trust. Nothing expressed or mentioned or to which reference is made in this Agreement is intended or shall be construed to give any person or corporation other than the parties hereto any legal or equitable right, remedy or claim under or in respect of this Agreement or any provision herein contained, expressly or by reference, or any Schedule hereto, this Agreement, any such Schedule and any and all conditions and provisions hereof and thereof being intended to be and being for the sole and exclusive benefit of the parties hereto, and for the benefit of no other person or corporation. 8.7 Amendment It is contemplated by the parties that it may be appropriate from time to time to change, amend, modify or supplement this Agreement or the Schedules which are attached to this Agreement to reflect changes in operating practices or costs of operations or for other reasons. This Agreement may be changed, amended, modified or supplemented by an instrument in writing executed by all of the parties. 8.8 Independent Contractors It is agreed among the Companies that by entering into this Agreement the Companies shall not become partners, but as to each other and to third persons, the Companies shall remain independent contractors in all matters relating to this Agreement. 8.9 Responsibility and Liability The liability of the parties shall be several, not joint or collective. Each party shall be responsible only for its obligations, and shall be liable only for its proportionate share of the costs and expenses as provided in this Agreement, and any liability resulting herefrom. Each party hereto will defend, indemnify, and save harmless the other parties hereto from and against any and all liability, loss, costs, damages, and expenses, including reasonable attorney's fees, caused by or growing out of the gross negligence, willful misconduct, or breach of this Agreement by such indemnifying party. IN WITNESS WHEREOF, each of the Companies has caused this Agreement and the attached Schedules to be signed in its name and on its behalf by its President attested by its Secretary, both being duly authorized, and CSWS has caused this Agreement and the attached Schedules to be signed in its name and on its behalf by its Chief Executive Officer attested by its Secretary, both being duly authorized. This Agreement and attached Schedules shall become effective on such date as is established by the Federal Energy Regulatory Commission. CENTRAL POWER AND LIGHT COMPANY Attest By /s/ Secretary President PUBLIC SERVICE COMPANY OF OKLAHOMA Attest By /s/ Secretary President SOUTHWESTERN ELECTRIC POWER COMPANY Attest By /s/ Secretary President WEST TEXAS UTILITIES COMPANY Attest By /s/ Secretary President CENTRAL AND SOUTH WEST SERVICES, INC. Attest By /s/ Secretary Chief Executive Officer SCHEDULE A JOINT UNIT 9.1 Purpose The purpose of this Schedule is to provide the basis for the Companies' participation in Joint Units. 9.2 Ownership (a) Every Joint Unit shall be owned by the Companies participating in the Joint Unit as tenants in common. Ownership shares in each Joint Unit shall be allocated insofar as practical to achieve a Prorated Reserve Level for all Companies participating in the unit. The allocation shall be recommended by the Operating Committee and authorized by the CEO prior to the time the unit is authorized by the Board of Directors of the Parent Company. However, each Company shall own at least fifty (50) megawatts of each Joint Unit unless otherwise agreed to by the Operating Committee. Each Company shall be responsible for its pro rata share of the costs of construction of the unit and shall contribute such funds to the Agent as billed. (b) When a new Joint Unit is installed at a site already occupied by one or more existing Generating Units the Agent, in consultation with the Operating Committee, shall identify any existing facilities that will be common to the new Joint Unit and the portion of the common facilities to be allocated to the new Joint Unit. The owners of the new Joint Unit shall compensate the owners of the existing common facilities for the use of those common facilities. 9.3 Contracts The Companies shall execute a joint ownership agreement for each Joint Unit, such agreement to set out all of the rights and obligations of the parties relating to the specific Joint Unit, including the allocation of fuel costs, the allocation of other operation costs and the allocation of maintenance costs among the owners. SCHEDULE B COMPANY UNITS THAT ARE NOT JOINT UNITS 10.1 Purpose The purpose of this Schedule is to list the Generating Units, to be placed in service after the date of the original Operating Agreement dated September 28, 1983, which are not Joint Units. 10.2 Company Units That Are Not Joint Units The Company units that are not Joint Units are as follows: South Texas Project Unit Number 1 - CPL South Texas Project Unit Number 2 - CPL Dolet Hills Unit Number 1 - SWEPCO Pirkey Unit Number 1 - SWEPCO SCHEDULE C CAPACITY COMMITMENT CHARGE 11.1 Purpose The purpose of this Schedule is to establish the basis for Capacity Commitments between the Companies and the rates for the Capacity Commitment Charge and associated Energy. 11.2 Basis for Capacity Commitment A committing Company shall make available to a receiving Company unit capacity consisting of a portion of the output of one or more specific Generating Units. The receiving Company shall be entitled to receive Energy from the specified Generating Unit(s) up to an amount equal to an annual load factor of sixty (60) percent or such other amount as is mutually agreeable. 11.3 Provisions for Capacity Commitment Charge The monthly Capacity Commitment Charge for each specific Generating Unit(s) from which capacity is committed shall be an amount not to exceed the result of the following formula: A = (1/12) (B) (C/D) (E) Where: A = Monthly Capacity Commitment Charge for the specified unit to be due each month regardless of the availability of the specific unit. B = 0.1712 (fixed charge rate for the committing Company). C = Committing Company's total dollar investment, at original cost, in the specific Generating Unit as of December 31 of the year prior to the year of the Capacity Commitment. D = Rated net dependable capability of the specific Generating Unit in megawatts. E = Megawatts of capacity committed from the specified unit. 11.4 Provision for Energy Charge The rate for Energy received by a receiving Company from specified unit(s) shall be the Variable Cost of Energy produced from each specified unit(s) plus ten (10) percent of such costs or three (3) mills per kilowatt-hour, whichever is less. SCHEDULE D PAYMENTS AND RECEIPTS FOR POOL ENERGY EXCHANGES AMONG THE COMPANIES 12.1 Purpose The purpose of this Schedule is to provide the basis for determining payments and receipts among the Companies for Pool Energy exchanges. 12.2 Hourly Calculations The payments and receipts of Section 12.3 are calculated Hourly, but are accumulated and billed Monthly among the Companies 12.3 Receipts and Payments A selling Company shall receive from a purchasing Company one hundred and ten percent (110%) of the selling Company's Incremental Energy Cost for Pool Energy sold. A purchasing Company shall pay for Pool Energy received one hundred and ten percent (110%) of its portion of the aggregate of the selling Companies' Incremental Cost for Pool Energy. Where Pool Energy is purchased simultaneously by more than one Company, these charges shall be pro rated in proportion to the megawatt-hours of Pool Energy purchased by each buyer. SCHEDULE E PAYMENTS AND RECEIPTS FOR INTERNAL ECONOMY ENERGY EXCHANGES AMONG THE COMPANIES AND FOR OFF-SYSTEM ENERGY PURCHASES AND SALES 13.1 Purpose The purpose of this Schedule is to provide the basis for determining payments and receipts among the Companies for Internal Economy Energy exchanges and for off-System Energy purchases and sales made to improve System economy. 13.2 Hourly Calculations The payments of Section 13.3 and receipts of Section 13.4 shall be calculated Hourly, but are accumulated and billed Monthly among the Companies. 13.3 Payments A purchasing Company shall pay its Decremental Energy Value for Internal Economy Energy purchased and off-System Energy purchased to improve System economy. 13.4 Receipts A selling Company shall receive its Incremental Energy Cost for Internal Economy Energy sold and off-System Energy sold to improve System economy. SCHEDULE F DISTRIBUTION OF MARGIN FOR INTERNAL ECONOMY ENERGY EXCHANGES AND FOR OFF-SYSTEM ENERGY PURCHASES AND SALES 14.1 Purpose The purpose of this Schedule is to establish the basis for distributing among the Companies the Margin resulting from Internal Economy Energy exchanges and for off-System Energy purchases and sales made to improve System economy. 14.2 Distribution of Margin Any Margin remaining from Internal Economy Energy exchanges and off-System Energy purchases and sales made to improve System economy after deducting any Transaction Cost incurred in the period to which the Margin relates shall be distributed to the Companies in proportion to the relative magnitude of the sums for each Company of the Energy generated or not generated by such Company in order to participate in Internal Economy Energy exchanges or such off-System purchases or sales. SCHEDULE G DISTRIBUTION OF OPERATING EXPENSES OF THE CENTRAL CONTROL CENTER 15.1 Purpose The purpose of this Schedule is to provide a basis for the distribution among the Companies of the costs incurred by the Agent in operating the Central Control Center. 15.2 Costs Costs for the purpose of this Schedule shall include all costs incurred in maintaining and operating the Central Control Center including, among others, such items as salaries, wages, rentals, the cost of materials and supplies, interest, taxes, depreciation, transportation, travel expenses, consulting, and other professional services. 15.3 Distribution of Costs All costs shall be billed by Agent to the Companies in proportion to the average of the maximum Company Peak Demands experienced during the three previous calendar Years with the following exception. In the event the Central Control Center makes a study or performs a special service in which all Companies are not thus proportionately interested, any resulting cost shall be distributed to the interested parties in accordance with the standard procedures of Agent authorized by the United States Securities and Exchange Commission. SCHEDULE H CAPACITY COMMITMENT UNITS 16.1 Purpose The purpose of this Schedule is to identify the Generating Units of the Companies from which Capacity Commitments shall be made pursuant to Section 6.3 in accordance with Schedule C. 16.2 Commitment Units Listed below are the Generating Units from which each of the Companies shall commit Capacity to other Companies pursuant to Section 6.3. Capacity Commitments shall be made from the first listed unit of the committing Company unless or to the extent that such unit is not expected to be available during the commitment period. In such event, Capacity Commitments shall be made from the second listed unit of the committing Company. COMPANY UNIT NAME RATING(MW) YEAR INSTALLED CPL B. M. Davis #2 341 1976 Laredo #3 101 1975 PSO Riverside #2 465 1976 Riverside #1 457 1974 SWEPCO Knox Lee #5 344 1974 Wilkes #3 351 1971 WTU Fort Phantom #2 204 1977 Fort Phantom #1 158 1974 SCHEDULE I PLANNING-RESERVE CRITERIA 17.1 Purpose The purpose of this Schedule is to identify the criteria which shall be used by the Companies in determining their respective Planning Reserve Levels for purposes of determining their respective Capacity Commitment obligations 17.2 Planning Reserve Criteria The Planning Reserve Level for each of the Companies shall be equal to 15% of Company Load Responsibility. SCHEDULE J STATEMENT OF PRACTICE REGARDING OFF-SYSTEM ENERGY SALES 18.1 Purpose The purpose of this Schedule is to identify the basis upon which price quotations for energy sales to a non-associated entity made to improve System economy will be determined when any such non-associated entity makes a request of a Company or the Agent to purchase System Energy. The prices for sales made shall be set by negotiation or in accordance with filed rate schedules of the Companies and may include standard industry adders. 18.2 Determination of Energy Price Quotations The CSW Central Control Center will predispatch System Energy requirements based upon an estimate of on-line System generation and such System Energy requirements. Any request for the purchase of System Energy will result in a price quotation based upon the incremental running cost of the next-least-costly-to-operate System Generating Unit (that will be available to make the sale requested during the time period that is the subject of the request by the non-associated entity) after System needs have been met. In determining whether a Generating Unit will be available to make a requested sale, the matters listed in Section 6.5 and the availability of adequate transmission capacity on the System and on the systems of other utilities shall be considered. SCHEDULE K DISTRIBUTION OF CERTAIN TRANSACTION COSTS 19.1 Purpose The purpose of this Schedule is to provide a basis for the distribution among the Companies of certain charges assessed by non-associated entities against one or more of the Companies for transmission service related to transactions contemplated by the Agreement. 19.2 Fixed Transaction Costs For purposes of this Schedule, Fixed Transaction Costs shall consist of transmission service charges that are not computed based on specific schedules that vary on an hour-by-hour basis or that are not computed for specific firm transmission service reservations between Companies dependent on the level of reservation. 19.3 Distribution of Fixed Transaction Costs All Fixed Transaction Costs shall be billed to the Companies in proportion to their maximum Company Peak Demands experienced during the previous calendar Year less interruptible loads served during the peak hour. 19.4 Directly Assigned Transaction Costs For purposes of this Schedule, Directly Assigned Transaction Costs shall consist of transmission service charges due to non-associated entities that are not Fixed Transaction Costs and that are associated with the receipt by a Company of Pool Energy, Energy produced from a Joint Unit, Energy associated with a Capacity Commitment and off-System Energy purchased with reserves to meet the requirements of the receiving Company. 19.5 Distribution of Directly Assigned Transaction Costs All Directly Assigned Transaction Costs shall be billed to the Companies in accordance with the following implementation steps: 1) Directly Assigned Transaction Costs due to non-associated entities shall be paid by the Company receiving the bill. Where two or more Companies are jointly receiving such Energy for which a consolidated transmission service bill is rendered, the involved Companies will be responsible for the charges in proportion to their megawatt-hour (MWH) share of such Energy. 2) Should a non-associated entity render a bill for Directly Assigned Transaction Costs that does not separately attribute such costs to particular Pool Energy, Joint Unit, Capacity Commitment or off-System Energy purchased with reserves transactions, the terms and conditions of the contracts, tariffs or ERCOT practices on which the charges are based will be used to determine which Companies will be responsible for such Energy transaction charges. 3) When losses are required to be paid in kind, and the responsible Company provides Energy (to the scheduling Company) sufficient to cover the losses to be returned, such payments shall not be considered as Directly Assigned Transaction Costs. When the responsible Company chooses to pay the cost associated with the scheduling Company's returning the losses on behalf of the System, such Directly Assigned Transaction Costs shall be determined as the product of the losses paid back (in MWH) and the scheduling Company's average monthly fuel cost for the Month in which the losses are returned. 4) On a calendar Month basis, according to transaction date, the total Directly Assigned Transmission Costs for which each Company is responsible and the total Directly Assigned Transmission Costs paid by each Company shall be tabulated. For a given Month, an adjustment shall be made in an appropriate CSW Money Pool account for each Company by an amount equal to the difference between the total Directly Assigned Transaction Costs paid by the Company and the Directly Assigned Transaction Costs for which the Company is responsible. EX-10 5 x10b.txt (B) TRANSMISSION COOR AGREEMENT EXHIBIT 10(b) TRANSMISSION COORDINATION AGREEMENT Between Central Power and Light Company, West Texas Utilities Company, Public Service Company of Oklahoma, Southwestern Electric Power Company and Central and South West Services, Inc. Dated as of January 1, 1997 Revised as of October 29, 1999 TABLE OF CONTENTS Page ARTICLE I TERM OF AGREEMENT...................................................2 1.1 Effective Date.............................................2 -------------- 1.2 Periodic Review............................................2 --------------- ARTICLE II DEFINITIONS.........................................................3 2.1 Agreement..................................................3 --------- 2.2 Ancillary Services.........................................3 ------------------ 2.3 Company Demand.............................................3 -------------- 2.4 Company Peak Demand........................................3 ------------------- 2.5 Control Area...............................................3 ------------ 2.6 Coordinating Committee.....................................3 ---------------------- 2.7 Designated Agent...........................................4 ---------------- 2.8 Direct Assignment Facilities...............................4 ---------------------------- 2.9 Generating Unit............................................4 --------------- 2.10 Hour.......................................................4 ---- 2.11 Month......................................................4 ----- 2.12 Network Integration Transmission Service...................4 ---------------------------------------- 2.13 Open Access Transmission Tariff............................4 ------------------------------- 2.14 Point-to-Point Transmission Service........................4 ----------------------------------- 2.15 PUCT.......................................................5 ---- 2.16 Scheduling, System Control and Dispatch Service............5 ----------------------------------------------- 2.17 Transmission Customer......................................5 --------------------- 2.18 Transmission Provider......................................5 --------------------- 2.19 Transmission Service.......................................5 -------------------- 2.20 Transmission System........................................5 ------------------- 2.21 Transmission System Operator...............................5 ---------------------------- ARTICLE III OBJECTIVES..........................................................6 3.1 Purposes...................................................6 -------- ARTICLE IV COORDINATING COMMITTEE..............................................7 4.1 Coordinating Committee.....................................7 4.2 Responsibilities of the Coordinating Committee.............7 4.3 Delegation and Acceptance of Authority.....................8 4.4 Reporting..................................................8 ARTICLE V PLANNING............................................................9 5.1 Transmission Planning......................................9 --------------------- ARTICLE VI TRANSMISSION.......................................................10 6.1 Delegation to the Transmission System Operator............10 ---------------------------------------------- 6.2 Transmission Facilities...................................10 ----------------------- 6.3 Direct Assignment Facilities..............................10 ---------------------------- 6.4 Transmission Service Revenues.............................10 ----------------------------- 6.5 Payment of Costs for Network Use..........................12 -------------------------------- 6.6 Payment of Costs for Point-to-Point Transmission Service..13 -------------------------------------------------------- ARTICLE VII ANCILLARY SERVICES.................................................14 7.1 Ancillary Services........................................14 ------------------ ARTICLE VIII GENERAL............................................................15 8.1 Regulatory Authorization..................................15 ------------------------ 8.2 Effect on Other Agreements................................15 -------------------------- 8.3 Waivers...................................................15 ------- 8.4 Successors and Assigns; No Third Party Beneficiary........15 -------------------------------------------------- 8.5 Amendment.................................................16 --------- 8.6 Independent Contractors...................................16 ----------------------- 8.7 Responsibility and Liability..............................16 ---------------------------- SCHEDULE A ALLOCATION OF TRANSMISSION REVENUES................................18 SCHEDULE B ANNUAL TRANSMISSION REVENUE REQUIREMENTS RATIOS....................20 SCHEDULE C ALLOCATION OF ANCILLARY SERVICE REVENUES...........................22 TRANSMISSION COORDINATION AGREEMENT Between Central Power and Light Company, West Texas Utilities Company, Public Service Company of Oklahoma, Southwestern Electric Power Company and Central and South West Services, Inc. This TRANSMISSION COORDINATION AGREEMENT, hereinafter called "Agreement," is made and entered into as of the first day of January, 1997, by and among Central Power and Light Company (CPL), West Texas Utilities Company (WTU), Public Service Company of Oklahoma (PSO), and Southwestern Electric Power Company (SWEPCO), hereinafter separately referred to as "Company" and jointly as "Companies," and Central and South West Services, Inc. (CSWS). WHEREAS, Companies are the owners and operators of interconnected generation, transmission and distribution facilities with which they are engaged in the business of transmitting and selling electric power to the general public, to other entities and to other electric utilities; and WHEREAS, Companies achieve economic benefits for their customers through coordinated planning, operation and maintenance of their transmission facilities; NOW, THEREFORE, the Companies and CSWS mutually agree as follows: 2 ARTICLE I TERM OF AGREEMENT 1.1 Effective Date This Agreement shall become effective as of January 1, 1997, or such later date as is established by the Federal Energy Regulatory Commission. This Agreement shall continue in force and effect until December 31, 2001, and continue from year to year thereafter until terminated by written notice given by any Company to the other Companies and to CSWS. 1.2 Periodic Review This Agreement will be reviewed periodically by the Coordinating Committee, as defined herein, to determine whether revisions are necessary to meet changing conditions. In the event that revisions are made by the Companies pursuant to Section 8.5, and after requisite approval or acceptance for filing by the appropriate regulatory authorities, the Coordinating Committee may thereafter, for the purpose of ready reference to a single document, prepare for distribution to the Companies an amended document reflecting all changes in and additions to this Agreement with notations thereon of the date amended. 3 ARTICLE II DEFINITIONS For purposes of this Agreement, the following definitions shall apply: 2.1 Agreement shall mean this Transmission Coordination Agreement including all attachments and schedules applying thereto and any amendments made hereafter. 2.2 Ancillary Services shall mean those services that are necessary to support the transmission of capacity and energy from resources to loads while maintaining reliable operation of the Companies' transmission facilities in accordance with Good Utility Practice, as that term is defined in the Open Access Transmission Tariff. 2.3 Company Demand shall mean the demand in megawatts of all retail and wholesale power customers on whose behalf the Company, by statute, franchise, regulatory requirement, or contract, has undertaken an obligation to construct and operate its transmission system to meet the reliable electric needs of such customers, integrated over a period of one hour, plus the losses incidental to that service. 2.4 Company Peak Demand for a period shall be the highest Company Demand for any hour during the period. 2.5 Control Area shall mean an electric power system or combination of electric power systems to which a common automatic generation control scheme is applied for the purposes specified in the Open Access Transmission Tariff. 2.6 Coordinating Committee shall mean the organization established pursuant to Section 4.1 of this Agreement and whose duties are more fully set forth herein. 4 2.7 Designated Agent shall mean any entity that performs actions or functions on behalf of the Transmission Provider, an Eligible Customer (as that term is defined in the Open Access Transmission Tariff), or the Transmission Customer required under the Open Access Transmission Tariff. 2.8 Direct Assignment Facilities shall mean facilities or portions of facilities that are constructed by the Transmission Provider for the sole use or benefit of a particular Transmission Customer requesting service under the Open Access Transmission Tariff. 2.9 Generating Unit shall mean an electric generator, together with its prime mover and all auxiliary and appurtenant devices and equipment designed to be operated as a unit for the production of electric capacity and energy. 2.10 Hour shall mean a clock-hour. 2.11 Month shall mean a calendar month consisting of the applicable 24-Hour periods as measured by Central Standard Time. 2.12 Network Integration Transmission Service shall mean the transmission service provided under Part III of the Open Access Transmission Tariff. 2.13 Open Access Transmission Tariff shall mean the Open Access Transmission Tariff filed with the Federal Energy Regulatory Commission on behalf of the Companies as it may be amended from time to time. 2.14 Point-to-Point Transmission Service shall mean the reservation and transmission of capacity and energy on either a firm or non-firm basis from the points of receipt to the points of delivery under Part II of the Open Access Transmission Tariff. 5 2.15 PUCT shall mean the Public Utility Commission of Texas. 2.16 Scheduling, System Control and Dispatch Service shall mean the service required to schedule the movement of power through, out of, within, or into a Control Area, as specified in Schedule 1 of the Open Access Transmission Tariff. 2.17 Transmission Customer shall mean any Eligible Customer as defined in the Open Access Transmission Tariff (or its Designated Agent) that (i) executes a Service Agreement, or (ii) requests in writing that the Transmission Provider file with the Federal Energy Regulatory Commission a proposed unexecuted Service Agreement to receive service under the Open Access Transmission Tariff. This term is used in the Part I Common Service Provisions of the Open Access Transmission Tariff to include customers receiving service under Part II and Part III of the Open Access Transmission Tariff. 2.18 Transmission Provider shall mean the Transmission System Operator (or its Designated Agent). 2.19 Transmission Service shall mean Point-to-Point Transmission Service provided under Part II of the Open Access Transmission Tariff on a firm and non-firm basis. 2.20 Transmission System shall mean the facilities owned, controlled or operated by the Companies that are used to provide transmission service under Parts II and III of the Open Access Transmission Tariff. 2.21 Transmission System Operator shall mean that part of CSWS that is charged with monitoring the reliability of the Companies' Transmission System. 6 ARTICLE III OBJECTIVES 3.1 Purposes The purposes of this Agreement are (a) to provide the contractual basis for the coordinated planning and operation of the Companies' transmission facilities to achieve optimal economies, consistent with reliable electric service and regulatory and environmental requirements and (b) to provide the means by which the Companies will allocate among themselves the revenue that they receive for service provided under the Open Access Transmission Tariff. Any revenue received by a Company(ies) from the provision of service under an agreement, tariff or rate schedule other than the Open Access Transmission Tariff, including without limitation the Open Access Transmission Tariff for Service Offered by the Southwest Power Pool Transmission Providers, will be kept by the Company(ies) that is (are) the party(ies) to such agreement, tariff or rate schedule. 7 ARTICLE IV COORDINATING COMMITTEE 4.1 Coordinating Committee The Coordinating Committee is the organization established to oversee planning, construction, operation, and maintenance of the Transmission System. The Coordinating Committee members shall include at least one member representing each of the parties hereto who is not a member of the Operating Committee established under the CSW Operating Agreement. The chairperson, who shall be the appointed by the chief executive officer of the holder of the majority of the common stock of the Companies, shall appoint the member representative(s) of the Companies. Other than the chairperson, there shall be the same number of members representing each Company. The majority of the members on the Coordinating Committee shall be representatives of the Companies. Coordinating Committee decisions shall be by a majority vote of those present. However, any member not present may vote by proxy. The chairperson shall vote only in case of a tie. No merchant function employee of the Companies shall be appointed to, or serve on, the Coordinating Committee. 4.2 Responsibilities of the Coordinating Committee The Coordinating Committee shall be responsible for overseeing: (a) the Companies in the coordinated planning of their transmission facilities, including studies for transmission planning purposes and their interaction with independent system operators and other regional bodies that are interested in transmission planning; and 8 (b) compliance with the terms of the Open Access Transmission Tariff and the rules and regulations of the Federal Energy Regulatory Commission relating thereto. 4.3 Delegation and Acceptance of Authority The Companies hereby delegate to the Coordinating Committee, and the Coordinating Committee hereby accepts, responsibility and authority for the duties listed in this Article and elsewhere in this Agreement. 4.4 Reporting The Coordinating Committee shall provide periodic summary reports of its activities under this Agreement to the transmission and reliability function employees of the Companies and shall keep such employees of the Companies informed of situations or problems that may materially affect the reliability of the Transmission System. Furthermore, the Coordinating Committee agrees to report to the transmission and reliability function employees of the Companies in such additional detail as is requested regarding specific issues or projects under its oversight. 9 ARTICLE V PLANNING 5.1 Transmission Planning The Companies agree that their respective transmission facilities shall be planned and developed on the basis that their combined individual systems constitute a coordinated transmission system and that the objective of their planning shall be to maximize the economy, efficiency and reliability of the Transmission System as a whole. In this connection, the Coordinating Committee will from time to time, as it deems appropriate, direct studies for transmission planning purposes. 10 ARTICLE VI TRANSMISSION 6.1 Delegation to the Transmission System Operator The Companies shall delegate to the Transmission System Operator the responsibility and authority to act as Transmission Provider on behalf of the Companies for all of the requirements and purposes of the Open Access Transmission Tariff. 6.2 Transmission Facilities Each Company shall make its transmission facilities available to the Transmission System Operator. 6.3 Direct Assignment Facilities Each Company shall make Direct Assignment Facilities available to the Transmission System Operator as may be required to provide service to a particular Transmission Customer requesting service under the Open Access Transmission Tariff. 6.4 Transmission Service Revenues (a) The Companies shall share transmission service revenues obtained from the use of the transmission facilities that comprise the Transmission System in accordance with Schedule A to this Agreement. Transmission service revenues are those revenues received for service provided under the Open Access Transmission Tariff. The Companies' annual transmission revenue requirements are shown on Schedule B to this Agreement and shall be revised whenever there is a change to the annual transmission revenue requirements in Attachment H to the Open Access Transmission Tariff or a change to the annual transmission 11 revenue requirements underlying the rates set forth in Schedules 7 and 8 to the Open Access Transmission Tariff. Future revisions to the transmission revenue requirements ratios set forth in Schedule B will be made by the Companies' making an appropriate filing with the Commission, if required by law. Such changes shall become effective as of the date accepted or approved by the Commission, subject to refund if the Commission so orders. (b) Revenues received for ERCOT Regional Transmission Service provided under Part IV of the Open Access Transmission Tariff shall be allocated between CPL and WTU in accordance with matrices prepared by the ERCOT independent system operator (ISO). (c) Revenues received for Ancillary Services shall be allocated among the Companies in accordance with the revenue ratios set forth in Schedule C. Future revisions to the revenue ratios set forth in Schedule C will be made by the Companies' making an appropriate filing with the Commission, if required by law. Such changes shall become effective as of the date accepted or approved by the Commission, subject to refund if the Commission so orders. (d) Revenues received for third-party use of Direct Assignment Facilities shall be distributed to the Company(ies) owning such facilities. (e) The distribution to the Companies of revenues received for stranded costs received from third-party customers under the Open Access Transmission Tariff shall be determined on a case-by-case basis and shall be filed with the Commission, if required by law. (f) The distribution to the Companies of revenues received for new transmission facilities received from third-party customers under the Open Access Transmission Tariff shall be determined on a case-by-case basis and shall be filed with the Commission, if required by law. 12 (g) Revenues received for studies performed for the benefit of a Transmission Customer under Part II or Part III of the Open Access Transmission Tariff shall be allocated to each CSW Operating Company in proportion to the ratio of each CSW Operating Company's number of transmission pole miles, as such number of transmission pole miles is reported in each CSW Operating Company's Form 1 annual report, over the total number of transmission pole miles of the Transmission System. Revenues received for studies performed for the benefit of a Transmission Customer under Part IV of the Open Access Transmission Tariff shall be allocated between CPL and WTU in proportion to the ratio of each of their respective transmission pole miles, as such transmission pole miles are reported in their Form 1 annual reports, over the total number of transmission pole miles of CPL and WTU combined. 6.5 Payment of Costs for Network Use The Transmission System Operator shall bill each of the Companies for the amount due to the Transmission System Operator in each Month for their use of Network Integration Transmission Service and Ancillary Services under the Open Access Transmission Tariff on the basis set forth in the Open Access Transmission Tariff. 13 6.6 Payment of Costs for Point-to-Point Transmission Service (a) The cost of Transmission Service on the Transmission System for third-party off-system sales by a Company shall be borne by the selling Company(ies). (b) The cost of Transmission Service provided by a third-party for off-system sales by a Company shall be borne by the selling Company(ies). 14 ARTICLE VII ANCILLARY SERVICES 7.1 Ancillary Services (a) Each Company shall make available Ancillary Services as required to provide service under the Open Access Transmission Tariff. (b) Revenues received for Ancillary Services will be allocated between the Companies in accordance with Section 6.4(c) of this Agreement. 15 ARTICLE VIII GENERAL 8.1 Regulatory Authorization This Agreement is subject to certain regulatory approvals and the Companies shall diligently seek all necessary regulatory authorization for this Agreement. 8.2 Effect on Other Agreements This Agreement shall not modify the obligations of any of the Companies under any agreement between such Company and others not parties to this Agreement in effect on the effective date of this Agreement. 8.3 Waivers Any waiver at any time by a Company of its rights with respect to a default by any other Company under this Agreement shall not be deemed a waiver with respect to any subsequent default of similar or different nature. 8.4 Successors and Assigns; No Third Party Beneficiary This Agreement shall inure to and be binding upon the successors and assigns of the respective Companies, but shall not be assignable by any of the Companies without the written consent of the other Companies, except upon foreclosure of a mortgage or deed of trust. Nothing expressed or mentioned or to which reference is made in this Agreement is intended or shall be construed to give any person or corporation other than the Companies any legal or equitable right, remedy or claim under or in respect of this Agreement or any provision herein contained, expressly or by reference, or any schedule hereto, this Agreement, any such schedule 16 and any and all conditions and provisions hereof and thereof being intended to be and being for the sole exclusive benefit of the Companies, and for the benefit of no other person or corporation. 8.5 Amendment It is contemplated by the Companies that it may be appropriate from time to time to change, amend, modify or supplement this Agreement or the schedules that are attached to this Agreement, to reflect changes in operating practices or costs of operations or for other reasons. This Agreement or such schedules may be changed, amended, modified or supplemented by an instrument in writing executed by all of the Companies subject to any required approval or acceptance for filing by the appropriate regulatory authorities. 8.6 Independent Contractors By entering into this Agreement the Companies shall not become partners, and as to each other and to third persons, the Companies shall remain independent contractors in all matters relating to this Agreement. 8.7 Responsibility and Liability The liability of the Companies shall be several, not joint or collective. Each Company shall be responsible only for its obligations, and shall be liable only for its proportionate share of the costs and expenses as provided in this Agreement, and any liability resulting herefrom. Each Company will defend, indemnify, and save harmless the other Companies hereto from and against any and all liability, loss, costs, damages, and expenses, including reasonable attorney's fees, caused by or growing out of the gross negligence, willful misconduct, or breach of this Agreement by such indemnifying Company. 17 IN WITNESS WHEREOF, each Company has caused this Agreement to be executed and attested by its duly authorized officers. CENTRAL POWER AND LIGHT COMPANY Attest ________________________ By:________________________________ Secretary President WEST TEXAS UTILITIES COMPANY Attest ________________________ By:________________________________ Secretary President PUBLIC SERVICE COMPANY OF OKLAHOMA Attest ________________________ By:________________________________ Secretary President SOUTHWESTERN ELECTRIC POWER COMPANY Attest _________________________ By:________________________________ Secretary President CENTRAL AND SOUTH WEST SERVICES, INC. Attest _________________________ By:________________________________ Secretary President 18 SCHEDULE A ALLOCATION OF TRANSMISSION REVENUES 1. Allocation of Transmission Revenues The revenue the Transmission System Operator receives pursuant to Section 6.4 of the Agreement for service provided by the Companies under Parts II and III of the Open Access Transmission Tariff, other than revenues received pursuant to Sections 26 (Stranded Cost Recovery), 27 (Compensation for New Facilities and Redispatch Costs), and 34.4 (Redispatch Charge) thereof and for System and Facilities Studies made pursuant to Sections 19 (Additional Study Procedures for Firm Point-to-Point Transmission Service Requests) and 32 (Additional Study Procedures for Network Integration Transmission Service Requests), will be allocated among the Companies based on the ratios determined in accordance with Schedule B and Schedule C. Revenues related to studies performed for the benefit of Transmission Customers under Part II or Part III of the Open Access Transmission Tariff will be allocated among the four CSW Operating Companies in proportion to their respective number of transmission pole miles on the Transmission System. Revenues related to studies performed for the benefit of Transmission Customers under Part IV of the Open Access Transmission Tariff will be allocated between CPL and WTU in proportion to their respective number of transmission pole miles on the combined CPL/WTU system. Direct Assignment Facilities will be assigned to the Companies in proportion to the related costs that each of them incurred. Assignment of revenues received from a third 19 party related to stranded cost or new transmission facilities shall be determined on a case-by-case basis. 20 SCHEDULE B ANNUAL TRANSMISSION REVENUE REQUIREMENTS RATIOS From time to time the Coordinating Committee will calculate for each of the Companies its Transmission Revenue Requirements Ratios set forth below. A Company's Transmission Revenue Requirements Ratio for revenue received under Part III of the Open Access Transmission Tariff shall be a fraction, the numerator of which is the Company's transmission revenue requirement that is used to calculate the Annual Transmission Revenue Requirements amount set forth on Attachment H to the Open Access Transmission Tariff (herein called the Company Revenue Requirement) and the denominator of which is the sum of the Company Revenue Requirement for all of the Companies. A Company's Transmission Revenue Requirement Ratio for revenue received under Part II of the Open Access Transmission Tariff shall be a fraction, the numerator of which is the Company's transmission revenue requirement that is used to calculate the Annual cost of service Transmission Revenue Requirements amount underlying the rates set forth on Schedules 7 and 8 to the Open Access Transmission Tariff and the denominator of which is the sum of the Company Revenue Requirements for all of the Companies. 1. Allocation Ratio for Revenue Received Under Part III of the Open Access Transmission Tariff from a Non-ERCOT Loading Serving Entity Revenue Requirement Revenue Requirement Ratio CPL $60,092,806 33.58595% PSO $43,794,213 24.47665% SWEPCO $48,986,232 27.37848% WTU $26,049,174 14.55892% TOTAL $178,922,425 100.00000% 21 2. Allocation Ratio for Revenue Received Under Part-III of the Open Access Transmission Tariff from an ERCOT Load Serving Entity Revenue Requirement Revenue Requirement Ratio CPL $ 2,834,098 2.93693% PSO $43,794,213 45.38323% SWEPCO $48,986,232 50.76364% WTU $ 884,123 0.91620% TOTAL $96,498,666 100.00000% 3. Allocation Ratio for Revenue Received Under Part II of the Open Access Transmission Tariff Revenue Requirement Revenue Requirement Ratio CPL $60,092,806 32.83174% PSO $45,727,891 24.98347% SWEPCO $51,149,157 27.94538% WTU $26,062,756 14.23941% TOTAL $183,032,610 100.00000% 4. Allocation Ratio for Revenue Received Under Part II of the Open Access Transmission Tariff When Part II Service Is Taken In Conjunction With Part IV Service Revenue Requirement Revenue Requirement Ratio CPL $ 2,834,098 2.81695% PSO $45,727,891 45.45116% SWEPCO $51,149,157 50.83962% WTU $ 897,705 0.89227% TOTAL $100,608,851 100.00000% 22 5. Allocation Ratio for Revenue Received Under Part II the of Open Access Transmission Tariff When Part II Service Is Taken In Conjunction With the SPP Tariff Revenue Requirement Revenue Requirement Ratio CPL $60,092,806 70.01019% WTU $25,741,569 29.98981% TOTAL $85,834,375 100.00000% 23 SCHEDULE C ALLOCATION OF ANCILLARY SERVICE REVENUES The revenues the Transmission System Operator receives pursuant to Schedules 1 through 6 and Schedules 9 through 19 under the Open Access Transmission Tariff shall be allocated among the Companies as set forth below. Future revisions to the revenue ratios set forth in Schedule C will be made by the Companies' making an appropriate filing with the Commission, if required by law. Such changes shall become effective as of the date accepted or approved by the Commission, subject to refund if the Commission so orders. (a) Revenues received from System Scheduling, System Control and Dispatch Service under Schedule 1 of the Open Access Transmission Tariff will be allocated among the Companies based on the following ratio: CPL 31.25% WTU 11.78% PSO 25.48% SWEPCO 31.49% (b) Revenues received from System Reactive Supply and Voltage Control from Generation Sources Service under Schedule 2 of the Open Access Transmission Tariff will be allocated among the Companies based on the following ratio: CPL 53.59% WTU 7.23% PSO 15.60% SWEPCO 23.58% 24 (c) Revenues received from System Regulation and Frequency Response Service under Schedule 3-A and from System Load Following Service under Schedule 3-B for load served in the PSO/SWEPCO Control Area will be allocated between PSO and SWEPCO based on the following ratio: PSO 40.00% SWEPCO 60.00% Revenues received from System Regulation and Frequency Response Service under Schedule 3-A and from System Load Following Service under Schedule 3-B for load served in the CPL/WTU Control Area will be allocated between CPL and WTU based on the following ratio: CPL 70.18% WTU 29.82% (d) Revenues received for and energy exchanged as part of System Energy Imbalance Service rendered under Schedule 4 will be allocated in the same manner as margin from off- system sales and purchases as set forth in Schedule F to the CSW Operating Agreement, a copy of which is attached hereto. 25 (e) Revenues received from System Operating Reserve - Spinning Reserve Service (SPP) under Schedule 5 and from System Operating Reserve - Supplemental Reserve Service under Schedule 6 for load served in the PSO/SWEPCO Control Area will be allocated between PSO and SWEPCO based on the following ratio: PSO 35.91% SWEPCO 64.09% (f) Revenues received from System Operating Reserve - Responsive Reserve Service (ERCOT) under Schedule 5 and from System Operating Reserve - Supplemental Reserve Service under Schedule 6 for load served in the CPL/WTU Control Area will be allocated between CPL and WTU based on the following ratio: CPL 68.71% WTU 31.29% (g) Revenues received from the provision of the ERCOT Responsive Reserve Service under Schedule 9, ERCOT Spinning Reserve Service under Schedule 10, ERCOT Load Following Service under Schedule 13, ERCOT Generation - Scheduling Imbalance Service under Schedule 15, ERCOT Load - Schedule Imbalance Service under Schedule 16, ERCOT Scheduled Backup Service under Schedule 17, ERCOT Automatic Backup Service under Schedule 18, and ERCOT Emergency Energy Service under Schedule 19 for load served in the CPL/WTU Control Area will be allocated between CPL and WTU based on the following ratio: CPL 69.22% WTU 30.78% 26 (h) Revenues received from the provision of the ERCOT Static Scheduling Service under Schedule 11 and ERCOT Dynamic Scheduling Service under Schedule 12 for load served in the CPL/WTU Control Area will be allocated between CPL and WTU based on the following ratio: CPL 72.62% WTU 27.38% (i) Revenues received from the provision of the ERCOT Load Regulation Service under Schedule 14 for load served in the CPL/WTU Control Area will be allocated between CPL and WTU based on the following ratio: CPL 70.53% WTU 29.47% EX-12 6 x12swp.txt EXHIBIT 12 SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Computation of Consolidated Ratios of Earnings to Fixed Charges (in thousands except ratio data)
Year Ended December 31, 1998 1999 2000 2001 2002 Earnings: Income Before Extraordinary Item $ 97,994 $ 86,205 $ 72,672 $ 89,367 $ 82,992 Plus Federal Income Taxes 57,506 49,180 12,058 70,121 37,439 Plus State Income Taxes 5,089 6,162 2,538 8,385 5,687 Plus Provision for Deferred Income Taxes (11,909) (17,347) 14,653 (31,396) (3,134) Plus Deferred Investment Tax Credits (4,631) (4,565) (4,482) (4,453) (4,524) Plus Fixed Charges (as below) 57,084 61,177 62,851 60,503 60,529 Total Earnings $201,133 $180,812 $160,290 $192,527 $178,989 Fixed Charges: Interest on Long-term Debt $ 39,233 $ 38,380 $ 43,547 $ 41,401 $ 43,011* Interest on Short-term Debt 8,591 13,800 10,174 9,680 7,776* Distributions on Trust Preferred Securities 8,662 8,662 8,663 8,663 8,662 Interest Portion of Financing Leases 598 335 - - - Estimated Interest Element in Lease Rentals - - 467 759 1,080 Total Fixed Charges $ 57,084 $ 61,177 $ 62,851 $ 60,503 $ 60,529 Ratio of Earnings to Fixed Charges 3.52 2.95 2.55 3.18 2.95 * Certain amounts have been reclassified between interest on short-term and long-term debt compared to periods prior to January 1, 2002. This reclassification had no affect on the ratio.
EX-13 7 x13.txt 2002 ANNUAL REPORT 2002 Annual Reports American Electric Power Company, Inc. AEP Generating Company AEP Texas Central Company AEP Texas North Company Appalachian Power Company Columbus Southern Power Company Indiana Michigan Power Company Kentucky Power Company Ohio Power Company Public Service Company of Oklahoma Southwestern Electric Power Company Audited Financial Statements and Management's Discussion and Analysis
Contents Page Glossary of Terms i Forward Looking Information iv AEP Common Stock and Dividend Information v 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 Operations A-12 Consolidated Balance Sheets A-13 Consolidated Statements of Cash Flows A-15 Consolidated Statements of Common Shareholders' Equity and Comprehensive Income A-16 Schedule of Consolidated Cumulative Preferred Stocks of Subsidiaries A-17 Schedule of Consolidated Long-term Debt of Subsidiaries A-18 Index to Combined Notes to Consolidated Financial Statements A-19 Independent Auditors' Report A-20 Management's Responsibility 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 Combined Notes to Financial Statements B-8 Independent Auditors' Report B-9 AEP Texas Central 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 Comprehensive Income C-6 Consolidated Statements of Retained Earnings C-7 Consolidated Balance Sheets C-8 Consolidated Statements of Cash Flows C-10 Consolidated Statements of Capitalization C-11 Schedule of Long-term Debt C-12 Index to Combined Notes to Consolidated Financial Statements C-13 Independent Auditors' Report C-14 AEP Texas North Company Selected Financial Data D-1 Management's Narrative Analysis of Results of Operations D-2 Statements of Operations and Statements of Comprehensive Income D-6 Statements of Retained Earnings D-7 Balance Sheets D-8 Statements of Cash Flows D-10 Statements of Capitalization D-11 Schedule of Long-term Debt D-12 Index to Combined Notes to Financial Statements D-13 Independent Auditors' Report D-14 Appalachian Power Company and Subsidiaries Selected Consolidated Financial Data E-1 Management's Discussion and Analysis of Results of Operations E-2 Consolidated Statements of Income and Consolidated Statements of Comprehensive Income E-7 Consolidated Statements of Retained Earnings E-8 Consolidated Balance Sheets E-9 Consolidated Statements of Cash Flows E-11 Consolidated Statements of Capitalization E-12 Schedule of Long-term Debt E-13 Index to Combined Notes to Consolidated Financial Statements E-14 Independent Auditors' Report E-15 Columbus Southern Power Company and Subsidiaries Selected Consolidated Financial Data F-1 Management's Narrative Analysis of Results of Operations F-2 Consolidated Statements of Income and Consolidated Statements of Comprehensive Income F-6 Consolidated Statements of Retained Earnings F-7 Consolidated Balance Sheets F-8 Consolidated Statements of Cash Flows F-10 Consolidated Statements of Capitalization F-11 Schedule of Long-term Debt F-12 Index to Combined Notes to Consolidated Financial Statements F-13 Independent Auditors' Report F-14 Indiana Michigan Power Company and Subsidiaries Selected Consolidated Financial Data G-1 Management's Discussion and Analysis of Results of Operations G-2 Consolidated Statements of Income and Consolidated Statements of Comprehensive Income G-7 Consolidated Statements of Retained Earnings G-8 Consolidated Balance Sheets G-9 Consolidated Statements of Cash Flows G-11 Consolidated Statements of Capitalization G-12 Schedule of Long-term Debt G-13 Index to Combined Notes to Consolidated Financial Statements G-14 Independent Auditors' Report G-15 Kentucky Power Company Selected Financial Data H-1 Management's Narrative Analysis of Results of Operations H-2 Statements of Income, Statements of Comprehensive Income and Statements of Retained Earnings H-6 Balance Sheets H-7 Statements of Cash Flows H-9 Statements of Capitalization H-10 Schedule of Long-term Debt H-11 Index to Combined Notes to Financial Statements H-12 Independent Auditors' Report H-13 Ohio Power Company Selected Financial Data I-1 Management's Discussion and Analysis of Results of Operations I-2 Statements of Income and Statements of Comprehensive Income I-7 Statements of Retained Earnings I-8 Balance Sheets I-9 Statements of Cash Flows I-11 Statements of Capitalization I-12 Schedule of Long-term Debt I-13 Index to Combined Notes to Financial Statements I-14 Independent Auditors' Report I-15 Public Service Company of Oklahoma and Subsidiary Selected Consolidated Financial Data J-1 Management's Narrative Analysis of Results of Operations J-2 Consolidated Statements of Income and Consolidated Statements of Comprehensive Income J-5 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 Combined Notes to Consolidated Financial Statements J-12 Independent Auditors' Report J-13 Southwestern Electric Power Company and Subsidiaries Selected Consolidated Financial Data K-1 Management's Discussion and Analysis of Results of Operations K-2 Consolidated Statements of Income and Consolidated Statements of Comprehensive Income K-6 Consolidated Statements of Retained Earnings K-7 Consolidated Balance Sheets K-8 Consolidated Statements of Cash Flows K-10 Consolidated Statements of Capitalization K-11 Schedule of Long-term Debt K-12 Index to Combined Notes to Consolidated Financial Statements K-13 Independent Auditors' Report K-14 Combined Notes to Financial Statements L-1 Registrants' Combined Management's Discussion and Analysis of Financial Condition, Accounting Policies 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 consolidated subsidiaries. AEP Credit.........................AEP Credit, Inc., a subsidiary of AEP which factors accounts receivable and accrued utility revenues for affiliated and non-affiliated domestic electric utility companies. AEP East 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 companies.................PSO, SWEPCo, TCC and TNC. 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 (the FERC overturned earlier approvals of this RTO in December 2001). 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 [legal name changed to AEP Texas Central Company (TCC) effective December 2002]. See TCC. CSPCo..............................Columbus Southern Power Company, an AEP electric utility subsidiary. CSW............................... Central and South West Corporation, a subsidiary of AEP (Effective January 21, 2003, the legal name of Central and South West Corporation was changed to AEP Utilities, Inc.). 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. ICR................................Interchange Cost Reconstruction. 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. MISO...............................Midwest Independent System Operator (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. MTM................................Mark-to-Market. MTN................................Medium Term Notes. MW.................................Megawatt. MWH................................Megawatthour. NEIL...............................Nuclear Electric Insurance Limited. NOx................................Nitrogen oxide. NOx Rule...........................A final rule issued by Federal EPA which requires NOx reductions in 22 eastern states including seven of the states in which AEP companies operate. 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, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC. REP................................Retail Electric Provider. 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 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 AEP Texas Central 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 TCC. Superfund......................... The Comprehensive Environmental, Response, Compensation and Liability Act. SWEPCo.............................Southwestern Electric Power Company, an AEP electric utility subsidiary. TCC................................AEP Texas Central Company, an AEP electric utility subsidiary [formerly known as Central Power and Light Company (CPL)]. 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. TNC................................AEP Texas North Company, an AEP electric utility subsidiary [formerly known as West Texas Utilities Company (WTU)]. 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 [legal name changed to AEP Texas North Company (TNC) effective December 2002]. See TNC. 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 These reports made by AEP and its registrant subsidiaries contain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. Although AEP and its registrant subsidiaries believe that their expectations are based on reasonable assumptions, any such statements may be influenced by factors that could cause actual outcomes and results to be materially different from those projected. Among the factors that could cause actual results to differ materially from those in the forward-looking statements are: o Electric load and customer growth. o Abnormal weather conditions. o Available sources and costs of fuels. o Availability of generating capacity. o The speed and degree to which competition is introduced to our service territories. o The ability to recover stranded costs in connection with possible/proposed deregulation. o New legislation and government regulation. o Oversight and/or investigation of the energy sector or its participants. o The ability of AEP to successfully control its costs. o The success of acquiring new business ventures and disposing of existing investments that no longer match our corporate profile. o International and country-specific developments affecting AEP's foreign investments including the disposition of any current foreign investments and potential additional foreign investments. o The economic climate and growth in AEP's service territory and changes in market demand and demographic patterns. o Inflationary trends. o Electricity and gas market prices. o Interest rates. o Liquidity in the banking, capital and wholesale power markets. o Actions of rating agencies. o Changes in technology, including the increased use of distributed generation within our transmission and distribution service territory. o Other risks and unforeseen events, including wars, the effects of terrorism, embargoes and other catastrophic events.
AEP Common Stock and Dividend Information The quarterly high and low sales prices and the quarter-end closing price for AEP common stock and the cash dividends paid per share are shown in the following table: Quarter-end Quarter Ended High Low Closing Price Dividend - ------------- ------ ------- ------------- -------- March 2002 $47.08 $39.70 $46.09 $0.60 June 2002 48.80 39.00 40.02 0.60 September 2002 40.37 22.74 28.51 0.60 December 2002 30.55 15.10 27.33 0.60 March 2001 $48.10 $39.25 $47.00 $0.60 June 2001 51.20 45.10 46.17 0.60 September 2001 48.90 41.50 43.23 0.60 December 2001 46.95 39.70 43.53 0.60 AEP common stock is traded principally on the New York Stock Exchange. At December 31, 2002, AEP had approximately 144,000 shareholders of record. In 2003 management recommended that the Company reduce dividends by approximately 40% after payment of the March 2003 dividend which was approved by the Company's Board of Directors at the current level of $0.60 per share.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Selected Consolidated Financial Data Year Ended December 31, 2002 2001 2000 1999 1998 - ----------------------- ---- ---- ---- ---- ---- OPERATIONS STATEMENTS DATA (in millions): Total Revenues $14,555 $12,767 $11,113 $10,019 $14,080 Operating Income 1,263 2,182 1,774 2,061 2,046 Income Before Discontinued Operations, Extraordinary Items and Cumulative Effect 21 917 180 869 859 Discontinued Operations Income (Loss) (190) 86 122 117 116 Extraordinary Losses - (50) (35) (14) - Cumulative Effect of Accounting Change Gain (Loss) (350) 18 - - - Net Income (Loss) (519) 971 267 972 975 December 31, 2002 2001 2000 1999 1998 - ------------ ---- ---- ---- ---- ---- BALANCE SHEET DATA (in millions): Property, Plant and Equipment $37,857 $37,414 $34,895 $33,930 $32,400 Accumulated Depreciation and Amortization 16,173 15,310 14,899 14,266 13,374 ------- ------- ------- ------- ------- Net Property, Plant and Equipment $21,684 $22,104 $19,996 $19,664 $19,026 ======= ======= ======= ======= ======= Total Assets $34,741 $39,297 $46,633 $35,296 $33,418 Common Shareholders' Equity 7,064 8,229 8,054 8,673 8,452 Cumulative Preferred Stocks of Subsidiaries* 145 156 161 182 350 Trust Preferred Securities 321 321 334 335 335 Long-term Debt* 10,496 9,505 8,980 9,471 9,215 Obligations Under Capital Leases* 228 451 614 610 539 Year Ended December 31, 2002 2001 2000 1999 1998 - ----------------------- ---- ---- ---- ---- ---- COMMON STOCK DATA: Earnings per Common Share: Before Discontinued Operations, Extraordinary Items and Cumulative Effect $ 0.06 $ 2.85 $ 0.56 $ 2.71 $2.70 Discontinued Operations (0.57) 0.26 0.38 0.36 0.36 Extraordinary Losses - (0.16) (0.11) (0.04) - Cumulative Effect of Accounting Change (1.06) 0.06 - - - ------- ------ ------ ------ ----- Earnings (Loss) Per Share $ (1.57) $ 3.01 $ 0.83 $ 3.03 $3.06 ======= ====== ====== ====== ===== Average Number of Shares Outstanding (in millions) 332 322 322 321 318 Market Price Range: High $ 48.80 $51.20 $48-15/16 $48-3/16 $53-5/16 Low 15.10 39.25 25-15/16 30-9/16 42-1/16 Year-end Market Price 27.33 43.53 46-1/2 32-1/8 47-1/16 Cash Dividends on Common** $ 2.40 $2.40 $2.40 $2.40 $2.40 Dividend Payout Ratio** (152.9)% 79.7% 289.2% 79.2% 78.4% Book Value per Share $20.85 $25.54 $25.01 $26.96 $26.46 *Including portion due within one year. Long-term Debt includes Equity Unit Senior Notes. **Based on AEP historical dividend rate. See "Common Stock and Dividend Information" (on page V) regarding the potential reduction of future dividends.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Management's Discussion and Analysis of Results of Operations American Electric Power Company, Inc. (AEP or the Company) is one of the largest investor owned electric public utility holding companies in the U.S. We provide generation, transmission and distribution service to almost five 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 have a vast portfolio of assets including: o 38,000 megawatts of generating capacity, the largest complement of generation in the U.S., the majority of which has a significant cost advantage in our market areas o 4,000 megawatts of generating capacity in the U.K., a country which is currently experiencing excess generation capacity o 38,000 miles of transmission lines, the backbone of the electric interconnection grid in the Eastern U.S. o 186,000 miles of distribution lines that support delivery of electricity to our customers' premises o Substantial coal transportation assets (7,000 railcars, 1,800 barges, 37 tug boats and two coal handling terminals with 20 million tons of annual capacity) o 6,400 miles of gas pipelines in Louisiana and Texas with 128 Bcf of gas storage facilities Business Strategy We plan to focus on utility operations in the U.S. We continue to participate in wholesale electricity and natural gas markets. Weakness in these markets after the collapse of Enron and other companies caused us to re-examine and realign our strategy to direct our attention to our utility markets. We have reduced trading to focus predominantly in markets where we have assets. We plan to obtain maximum value for our assets by selling excess output and procuring economical energy using commercial expertise gained from our extensive experience in the wholesale business. Through our utility operations focus, we intend to be the energy and low cost generation provider of choice. We have ample generation to meet our customers' needs. We have a cost advantage resulting from AEP's long tradition of designing, building and operating efficient power plants and delivery networks. Our customers continue to show top quartile level of satisfaction. We provide safe and reliable sources of energy. Our business provides a vital requirement of our economy and affords an opportunity for a fair return to our shareholders. Our business provides the opportunity for a predictable stream of cash flows and earnings, allowing us to pay a competitive dividend to investors. We are addressing many challenges in our unregulated business. We have already substantially reduced our trading activities. We have written down the value of several investments to reflect deterioration in market conditions. We are evaluating our portfolio and plan to sell assets that are no longer core to our business strategy. We are also in discussion with our regulators to determine if the legal separation of certain operating company subsidiaries into regulated and unregulated segments can be avoided. We believe that the expected benefits from legal separation are no longer compelling. Transition rules for Michigan and Virginia do not require legal separation. Deregulation is no longer an expectation in the foreseeable future in the other states where we operate. Our strategy for the core business of utility operations is to: o Maintain moderate but steady earnings growth o Maximize value of transmission assets and protect our revenue stream in an RTO membership environment o Continue process improvement to maintain distribution service quality while, at the same time, further enhancing financial performance o Optimize generation assets through increased availability and sale of excess capacity o Manage the regulatory process to maximize retention of earnings improvement while providing fair and reasonable rates to our customers We remain very focused on credit quality and liquidity as discussed in greater detail later in this report. We are committed to continually evaluating 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 sustainable shareholder value. Any investment dispositions could affect future results of operations, cash flows and possibly financial condition. 2002 Overview 2002 was a year of rapid and dramatic change for the energy industry, including AEP, as the wholesale energy market quickly shrank and many of its participants exited or significantly limited future trading activity. Investors lost confidence in corporate America and the economy stalled. Investors' demand for stability, predictable cash flows, earnings, and financial strength have replaced their demand for rapid growth. Our wholesale business did not perform well. We had significant losses in options trading in the first half of the year and new investments performed well below our expectations. We focused on financial strength by: o Issuing approximately $1 billion in common stock and equity units o Retiring debt of approximately $3 billion through the sale of two f oreign retail utility companies in the U.K. (SEEBOARD) and Australia (CitiPower) o Establishing a cash liquidity reserve of $1 billion at year-end See Financing Activity in Management's Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters in section M for an overview of all changes to capital structure. We also focused on: o Implementing an enterprise-wide risk management system o Completing a cost reduction initiative which we expect to result in sustainable net annual savings of more than $200 million beginning in 2003 o Eliminating or reducing future capital requirements associated with non-core assets We have redirected our business strategy by: o Scaling back trading activities to focus principally on supporting our core assets o Selling our Texas retail business o Proposing the sale of a significant portion of the Texas unregulated generation assets Outlook for 2003 We remain focused on the fundamental earnings power of our utility operations, and we are committed to strengthening our balance sheet. Our strategy for achieving these goals is well planned: o First, we will continue to identify opportunities to reduce our operations and maintenance expense. o Second, we will find opportunities to reduce capital expenditures. o Third, management recommended a 40% reduction in the common stock dividend beginning in the second quarter to a quarterly rate of $0.35 per share. This will result in annual cash savings of approximately $340 million and should improve our retained earnings as well as create free cash flow to improve liquidity and pay-down outstanding debt. o Fourth, we plan to evaluate and, where appropriate, dispose of non-core assets. Proceeds from these sales will be used to reduce debt. o Fifth, we will continue to evaluate the potential for issuing additional equity to further strengthen our balance sheet and maintain credit quality. We remain committed to being a low cost provider of electricity, to serving our customers with excellence and to providing an attractive return to investors. We will therefore focus on producing the best possible results from our utility operations enhanced by a commercial group that ensures maximum value from our assets. Although we aim for excellent results from operations there are challenges and certain risks. We discuss these matters in detail in the Notes to Financial Statements and in Management's Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters. We will work diligently to resolve these matters by finding workable solutions that balance the interests of our customers, our employees and our investors. Results of Operations In 2002, 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, coal and other commodities o Coal mining, bulk commodity barging operations and other energy supply related businesses o Energy Delivery o Domestic electricity trans-mission o Domestic electricity distri-bution o Other Investments o Energy Services Net Income Income Before Discontinued Operations, Extraordinary Items and Cumulative Effect decreased $896 million or 98% to $21 million in 2002 from $917 million in 2001. The Company recognized impairments on under-performing assets and recorded losses in value of $854 million (net of tax) (see Note 13). The losses in the fourth quarter 2002 were generally caused by the extended decline in domestic and international wholesale energy markets and in telecommunications. In 2002, the Company's Net Loss was $519 million or a loss of $1.57 per share including the fourth quarter losses, losses on sales of SEEBOARD and CitiPower, and a loss for transitional goodwill impairment related to SEEBOARD and CitiPower that resulted from the adoption of SFAS 142 (see Note 3). Net Income increased in 2001 to $971 million or $3.01 per share from $267 million or $0.83 per share in 2000. The increase of $704 million or $2.18 per share was due to the growth of AEP's wholesale marketing business, increased revenues and the controlling of our operating and maintenance costs in the energy delivery business, and declining capital costs. 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 were all contributing factors to the increase in 2001 earnings compared to 2000. The favorable effect on comparative Net Income of these 2000 charges was offset in part in 2001 by losses from Enron's bankruptcy and extraordinary losses for the effects of deregulation and a loss on reacquired debt. Our wholesale business has been affected by a slowing economy. Wholesale energy margins and energy use by industrial customers declined in 2002 and 2001. Earnings from our wholesale business, which includes generation, increased in 2001 largely as a result of the successful return to service of the Cook Plant in June 2000 and by acquisitions of HPL and MEMCO. 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 in 2002 and 2001. Capital costs decreased due primarily to interest paid to the IRS in 2000 on a COLI deduction disallowance and continuing declines in short-term market interest rate conditions since early 2001. Volatility in energy commodities markets affects the fair values of all of our open trading and derivative contracts exposing AEP to market risk and causing our results of operations to be more volatile. See "Market Risks" section for a discussion of the policies and procedures AEP uses to manage its exposure to market and other risks from trading activities. Revenues Increase AEP's total revenues increased 14% in 2002 and 15% in 2001. The following table shows the components of revenues: For The Year Ended December 31 -------------------- 2002 2001 2000 (in millions) WHOLESALE: Residential $ 3,713 $ 3,553 $ 3,511 Commercial 2,156 2,328 2,249 Industrial 1,903 2,388 2,444 Other Retail Customers 385 419 414 Electricity Marketing (net) 2,227 802 1,073 Unrealized MTM Income-Electric 136 210 38 Other 1,397 632 837 Less: Transmission and Distribution Revenues Assigned to Energy Delivery* (3,551) (3,356) (3,174) ------ ------- ------- Wholesale Electric 8,366 6,976 7,392 ------ ------- ------- Gas Marketing (net) 3,021 2,274 310 Unrealized MTM Income (Loss)-Gas (399) 47 132 ------- ------- ------- Wholesale Gas 2,622 2,321 442 ------- ------- ------- TOTAL WHOLESALE 10,988 9,297 7,834 ------- ------- ------- DOMESTIC ELECTRICITY DELIVERY: Transmission 922 1,029 1,009 Distribution 2,629 2,327 2,165 ------- ------- ------- TOTAL DOMESTIC ELECTRICITY DELIVERY 3,551 3,356 3,174 ------- ------- ------- OTHER INVESTMENTS 16 114 105 ------- ------- ------- TOTAL REVENUES $14,555 $12,767 $11,113 ======= ======= ======= *Certain revenues in the Wholesale business include energy delivery revenues due primarily to bundled tariffs that are assignable to the Energy Delivery business. The level of electricity 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 especially in the short-term market. The increase in 2002 in wholesale revenues resulted from a 27% increase in trading volume associated with Wholesale Electricity which was offset by a continuing decrease in gross margins which began in the fourth quarter of 2001, and an increase in residential sales as a result of favorable weather conditions in the third quarter 2002. In addition Other Wholesale electric revenues increased due to the mid-year 2001 acquisition of barging and coal mining operations as well as the recognition of revenues for generation projects completed for third parties. The increase in 2002 Wholesale Gas revenues resulted from a full year of HPL operations compared to a partial year from our acquisition date in July 2001, offset by a decrease in the results from financial trading and MTM unrealized losses. Other Investments revenue decreased in 2002 due to the elimination of factoring of accounts receivable of an unaffiliated utility. Prior to the third quarter of 2002, we recorded and reported upon settlement, sales under forward trading contracts as revenues and purchases under forward trading contracts as purchased energy expenses. Effective July 1, 2002, we reclassified such forward trading revenues and purchases on a net basis, as permitted by EITF 98-10 (see Note 1). Kilowatthour sales to industrial customers decreased by 10% in 2002 and by 5% in 2001. This decrease was due to the economic slow down which began in late 2001. Sales to residential customers rose 5% due to weather related demand in 2002. The economic slow down reduced demand and wholesale prices especially in the latter part of 2001. Operating Expenses Increase Changes in the components of operating expenses were as follows: Increase (Decrease) From Previous Year 2002 2001 ---- ---- (in millions) Amount % Amount % ------ - ------ - Fuel and Purchased Energy: Electricity $ 959 43.7 $(1,275) (36.7) Gas 404 14.7 2,339 570.5 Maintenance and Other Operation 303 8.2 228 6.5 Non-recoverable Merger Costs (11) (52.4) (182) (89.7) Asset Impairments 867 N.M. - - Depreciation and Amortization 134 10.8 152 13.9 Taxes Other Than Income Taxes 51 7.6 (16) (2.3) ------ ------ Total $2,707 25.6 $1,246 13.3 ====== ====== The increase in Fuel and Purchased Energy expense was primarily attributable to an increase in power generation. Net generation increased 6% for Eastern plants due to increased demand for electricity and a reduction in planned power plant maintenance outages for various plants as compared to 2001. 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. The increase in Gas expense was primarily due to a full year of HPL operations compared to a partial year from our acquisition date in July 2001. The increase in Maintenance and Other Operation expense in 2002 is primarily due to recognizing a full year's expense for the businesses acquired during 2001 including MEMCO (a barging line), Quaker Coal, two power plants in the U.K. and HPL. In addition, increased administrative costs for the implementation of customer choice in Texas contributed to the increase. The increase was offset in part by a reduction in trading incentive compensation and the effect of planned boiler plant maintenance at various plants in 2001 and less refueling outages for STP in 2002 than 2001. 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. 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 and 2002 after the merger was consummated. In 2002 AEP recorded pre-tax impairments of assets (including Goodwill) and investments totaling $1.4 billion (consisting of approximately, $866.6 million related to asset impairments, $321.1 million related to investment value losses, and $238.7 million related to discontinued operations) that reflected downturns in energy trading markets, projected long-term decreases in electricity prices, and other factors. These impairments exclude the transitional impairment loss from adoption of SFAS142 (see Note 2). The categories of impairments included: 2002 Pre-Tax Estimated Loss (in millions) Asset Impairments Held for Sale $ 483.1 Asset Impairments Held and Used 651.4 Investment Value Losses 291.9 -------- Total $1,426.4 ======== Additional market deterioration associated with our non-core wholesale investments, including our U.K. operations, could have an adverse impact on our future results of operations and cash flows. Significant long-term changes in external market conditions could lead to additional write-offs and potential divestitures of our wholesale investments, including, but not limited to, our U.K. operations. The rise in Depreciation and Amortization expense in 2002 resulted from the amortization of Texas generation related Regulatory Assets that were securitized in early 2002, businesses acquired in 2001 and additional production plant placed into service. 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. Taxes Other Than Income Taxes increased in 2002 due to a full year of state excise taxes which replaced the state gross receipts tax in Ohio and increased local franchise taxes in Texas partly offset by the effect of Texas one-time 2001 assessments and decreased gross Texas receipts taxes due to deregulation. Interest, Preferred Stock Dividends, Minority Interest The decrease in Interest in 2002 was primarily due to a reduction in short-term interest rates and lower outstanding balances of short-term debt and the refinancing of long-term debt at favorable interest rates offset in part by an increased amount of long-term debt outstanding. Interest expense decreased 15% in 2001 due to the effect of interest paid to 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. Minority Interest in Finance Subsidiary increased substantially in 2002 because the distributions to minority interest were in effect for the entire year. 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. The minority interest was only in effect during the last four months of 2001. Other Income/Other Expenses Other Income increased by $110 million or 33% in 2002 due to the sale of AEP'S retail electric providers in Texas and due to non-operational revenue (see Note 1). Other Expenses increased $134 million or 72% in 2002 due to non-operational expenses (see Note 1). Other Income increased $240 million in 2001. This increase was primarily caused by an increase in equity earnings due to acquisitions of $63 million and a $73 million gain from the sale of a generating plant (see Note 1). Other Expenses increased by $110 million or 143% in 2001 due to costs to exit air transportation, fiber optic and Datapult businesses (see Note 1). Income Taxes The decrease in total Income Taxes in 2002 was due to a decrease in pre-tax book income offset by the tax effects of the sale of foreign operations. Although pre-tax book income increased considerably in 2001, 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. Extraordinary Losses and Cumulative Effect The loss for transitional goodwill impairment related to SEEBOARD and CitiPower resulted from the adoption of SFAS 142 (see Notes 2 and 3) and has been reported as a Cumulative Effect of Accounting Change on January 1, 2002. 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. Discontinued Operations The operations shown below were discontinued or held for sale in 2002 (See Note 12). Results of operations including impairment losses, net of tax, of these businesses have been reclassified: Company 2002 2001 2000 - ------- ---- ---- ---- (in millions) SEEBOARD $ 96 $ 88 $ 99 CitiPower (123) (6) 17 Pushan (7) 4 7 Eastex (156) - (1) ----- ---- ---- $(190) $ 86 $122 ===== ==== ==== Reclassification Balance sheet amounts have been restated to reflect our change in accounting policy regarding certain assets and liabilities related to forward physical and financial transactions (see "Reclassification" discussion Note 1.) Based upon AEP's legal rights of offset, physical and financial contracts were netted in 2002 and 2001 amounts and financial contracts were netted in 2000 and 1999 amounts. Related assets and liabilities were not netted in 1998 amounts as the impact is not material.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Consolidated Statements of Operations - ------------------------------------- (in millions - except per share amounts) Year Ended December 31, -------------------------- 2002 2001 2000 ---- ---- ---- REVENUES: Wholesale Electricity $ 8,366 $ 6,976 $ 7,392 Wholesale Gas 2,622 2,321 442 Domestic Electricity Delivery 3,551 3,356 3,174 Other Investment 16 114 105 ------- ------- ------- TOTAL REVENUES 14,555 12,767 11,113 ------- ------- ------- EXPENSES: Fuel and Purchased Energy: Electricity 3,154 2,195 3,470 Gas 3,153 2,749 410 ------- ------- ------- TOTAL FUEL AND PURCHASED ENERGY 6,307 4,944 3,880 Maintenance and Other Operation 4,013 3,710 3,482 Non-recoverable Merger Costs 10 21 203 Asset Impairments 867 - - Depreciation and Amortization 1,377 1,243 1,091 Taxes Other Than Income Taxes 718 667 683 ------- ------- ------- TOTAL EXPENSES 13,292 10,585 9,339 ------- ------- ------- OPERATING INCOME 1,263 2,182 1,774 OTHER INCOME 445 335 95 LESS: INVESTMENT VALUE AND OTHER IMPAIRMENT LOSSES 321 - - LESS: OTHER EXPENSES 321 187 77 LESS: INTEREST 785 844 999 PREFERRED STOCK DIVIDEND REQUIREMENTS OF SUBSIDIARIES 11 10 11 MINORITY INTEREST IN FINANCE SUBSIDIARY 35 13 - ------- ------- ------- INCOME BEFORE INCOME TAXES 235 1,463 782 INCOME TAXES 214 546 602 ------- ------- ------- INCOME BEFORE DISCONTINUED OPERATIONS, EXTRAORDINARY ITEMS AND CUMULATIVE EFFECT 21 917 180 DISCONTINUED OPERATIONS (LOSS) INCOME (NET OF TAX) (190) 86 122 EXTRAORDINARY LOSSES (NET OF TAX): DISCONTINUANCE OF REGULATORY ACCOUNTING FOR GENERATION - (48) (35) LOSS ON REACQUIRED DEBT - (2) - CUMULATIVE EFFECT OF ACCOUNTING CHANGE (NET OF TAX) (350) 18 - ------- ------- ------- NET INCOME (LOSS) $ (519) $ 971 $ 267 ======= ======= ======= AVERAGE NUMBER OF SHARES OUTSTANDING 332 322 322 === === === EARNINGS (LOSS) PER SHARE: Income Before Discontinued Operations, Extraordinary Items and Cumulative Effect of Accounting Change $ 0.06 $ 2.85 $ 0.56 Discontinued Operations (0.57) 0.26 0.38 Extraordinary Losses - (0.16) (0.11) Cumulative Effect of Accounting Change (1.06) 0.06 - ------ ------ ------ Earnings (Loss) Per Share (Basic and Diluted) $(1.57) $ 3.01 $ 0.83 ====== ====== ====== 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, ----------- 2002 2001 ---- ---- ASSETS CURRENT ASSETS: Cash and Cash Equivalents $ 1,213 $ 224 Accounts Receivable: Customers 466 343 Miscellaneous 1,394 1,365 Allowance for Uncollectible Accounts (119) (69) Fuel, Materials and Supplies 1,166 1,037 Energy Trading and Derivative Contracts 1,046 2,125 Other 935 639 ------- ------- TOTAL CURRENT ASSETS 6,101 5,664 ------- ------- PROPERTY, PLANT AND EQUIPMENT: Electric: Production 17,031 17,054 Transmission 5,882 5,764 Distribution 9,573 9,309 Other (including gas and coal mining assets and nuclear fuel) 3,965 4,272 Construction Work in Progress 1,406 1,015 ------- ------- Total Property, Plant and Equipment 37,857 37,414 Accumulated Depreciation and Amortization 16,173 15,310 ------- ------- NET PROPERTY, PLANT AND EQUIPMENT 21,684 22,104 ------- ------- REGULATORY ASSETS 2,688 3,162 ------- ------- SECURITIZED TRANSITION ASSETS 735 - ------- ------- INVESTMENTS IN POWER AND DISTRIBUTION PROJECTS 283 633 ------- ------- ASSETS HELD FOR SALE 247 721 ------- ------- ASSETS OF DISCONTINUED OPERATIONS - 3,954 ------- ------- GOODWILL 396 392 ------- ------- LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 824 795 ------- ------- OTHER ASSETS 1,783 1,872 ------- ------- TOTAL ASSETS $34,741 $39,297 ======= ======= See Notes to Consolidated Financial Statements beginning on page L-1.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Consolidated Balance Sheets December 31, ----------- 2002 2001 ---- ---- LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES: Accounts Payable $ 2,042 $ 1,914 Short-term Debt 3,164 4,011 Long-term Debt Due Within One Year* 1,633 1,095 Energy Trading and Derivative Contracts 1,147 1,877 Other 1,804 1,924 ------- ------- TOTAL CURRENT LIABILITIES 9,790 10,821 ------- ------- LONG-TERM DEBT* 8,487 8,410 ------- ------- EQUITY UNIT SENIOR NOTES 376 - ------- ------- LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 484 603 ------- ------- DEFERRED INCOME TAXES 3,916 4,500 ------- ------- DEFERRED INVESTMENT TAX CREDITS 455 491 ------- ------- DEFERRED CREDITS AND REGULATORY LIABILITIES 765 819 ------- ------- DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2 185 194 ------- ------- OTHER NONCURRENT LIABILITIES 1,903 1,334 ------- ------- LIABILITIES HELD FOR SALE 91 87 ------- ------- LIABILITIES OF DISCONTINUED OPERATIONS - 2,582 ------- ------- COMMITMENTS AND CONTINGENCIES (Note 9) CERTAIN SUBSIDIARY OBLIGATED, MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY TRUSTS HOLDING SOLELY JUNIOR SUBORDINATED DEBENTURES OF SUCH SUBSIDIARIES 321 321 ------- ------- MINORITY INTEREST IN FINANCE SUBSIDIARY 759 750 ------- ------- CUMULATIVE PREFERRED STOCK OF SUBSIDIARIES* 145 156 ------- ------- COMMON SHAREHOLDERS' EQUITY: Common Stock-Par Value $6.50: 2002 2001 ---- ---- Shares Authorized. . . . .600,000,000 600,000,000 Shares Issued. . . . . . .347,835,212 331,234,997 (8,999,992 shares were held in treasury at December 31, 2002 and 2001) 2,261 2,153 Paid-in Capital 3,413 2,906 Accumulated Other Comprehensive Income (Loss) (609) (126) Retained Earnings 1,999 3,296 ------- ------- TOTAL COMMON SHAREHOLDERS' EQUITY 7,064 8,229 ------- ------- TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $34,741 $39,297 ======= ======= *See Accompanying Schedules. See Notes to Consolidated Financial Statements beginning on page L-1.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Consolidated Statements of Cash Flows (in millions) Year Ended December 31, --------------------------- 2002 2001 2000 ---- ---- ---- OPERATING ACTIVITIES: Net Income (Loss) $ (519) $ 971 $ 267 Plus: Discontinued Operations 540 (86) (122) ------ ------- ------ Net Income from Continuing Operations 21 885 145 Adjustments for Noncash Items: Asset Impairments, Investment Value and Other Impairments 1,188 - - Depreciation and Amortization 1,403 1,277 1,152 Deferred Investment Tax Credits (31) (29) (36) Deferred Income Taxes (66) 157 (190) Amortization of Operating Expenses and Carrying Charges 40 40 48 Cumulative Effect of Accounting Change - (18) - Equity Earnings of Yorkshire Electricity Group plc - - (44) Extraordinary Loss - 50 35 Deferred Costs Under Fuel Clause Mechanisms (31) 340 (449) Mark-to-Market of Energy Trading Contracts 263 (257) (170) Miscellaneous Accrued Expenses 30 (384) 217 Changes in Certain Current Assets and Liabilities: Accounts Receivable (net) (152) 1,766 (1,530) Fuel, Materials and Supplies (127) (78) 149 Accrued Revenues (283) 35 (71) Accounts Payable 52 (478) 1,292 Taxes Accrued (216) (147) 171 Payment of Disputed Tax and Interest Related to COLI - - 319 Change in Other Assets (177) (239) (283) Change in Other Liabilities (237) (161) 386 ------ ------- ------- Net Cash Flows From Operating Activities 1,677 2,759 1,141 ------ ------- ------- INVESTING ACTIVITIES: Construction Expenditures (1,722) (1,654) (1,468) Purchase of Gas Pipe Line - (727) - Purchase of U.K. Generation - (943) - Purchase of Coal Company - (101) - Purchase of Barging Operations - (266) - Purchase of Wind Generation - (175) - Proceeds from Sale of Retail Electric Providers 146 - - Proceeds from Sale of Foreign Investments 1,117 383 - Proceeds from Sale of U.S. Generation - 265 - Other 37 (42) (18) ------ ------- ------- Net Cash Flows Used For Investing Activities (422) (3,260) (1,486) ------ ------- ------- FINANCING ACTIVITIES: Issuance of Common Stock 656 11 14 Issuance of Minority Interest - 744 - Issuance of Long-term Debt 2,893 2,863 878 Issuance of Equity Unit Senior Notes 334 - - Retirement of Cumulative Preferred Stock (10) (5) (21) Retirement of Long-term Debt (2,514) (1,570) (1,303) Change in Short-term Debt (net) (829) (790) 1,328 Dividends Paid on Common Stock (793) (773) (805) Dividends on Minority Interest in Subsidiary - (5) - ------ ------- ------- Net Cash Flows From (Used for) Financing Activities (263) 475 91 ------ ------- ------- Effect of Exchange Rate Changes on Cash (3) (1) 30 ------ ------- ------- Net Increase (Decrease) in Cash and Cash Equivalents 989 (27) (224) Cash and Cash Equivalents from Continuing Operations - Beginning of Period 224 251 475 ------ ------- ------- Cash and Cash Equivalents from Continuing Operations - End of Period $1,213 $ 224 $ 251 ====== ======= ======= Net Increase (Decrease) in Cash and Cash Equivalents from Discontinued Operations $ (100) $ 17 $ (17) Cash and Cash Equivalents from Discontinued Operations - Beginning of Period 108 91 108 ------ ------- ------- Cash and Cash Equivalents from Discontinued Operations - End of Period $ 8 $ 108 $ 91 ====== ======= ======= 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 ------ ------ ------- -------- ------------- ----- 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 Issuances 17 108 568 - - 676 Cash Dividends Declared - - - (793) - (793) Other - - (61) 15 - (46) ------ (163) Comprehensive Income: Other Comprehensive Income, Net of Taxes Foreign Currency Translation Adjustment - - - - 117 117 Unrealized Gain (Loss) on Hedged Derivatives (13) (13) Minimum Pension Liability - - - - (585) (585) Unrealized Loss on Securities Available For Sale (2) (2) Net Income (Loss) - - - (519) (519) ------ Total Comprehensive Income (1,002) --- ------ ------ ------ ----- ------ DECEMBER 31, 2002 348 $2,261 $3,413 $1,999 $(609) $7,064 === ====== ====== ====== ===== ====== See Notes to Consolidated Financial Statements beginning on page L-1.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Schedule of Consolidated Cumulative Preferred Stocks of Subsidiaries December 31, 2002 ----------------- 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 1,525,903 608,150 $ 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 51 ---- Total Subject to Mandatory Redemptio(C)(c) 84 Total Preferred Stock $145 ====
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 ---- Total Preferred Stock $156 ====
NOTES TO SCHEDULE OF CONSOLIDATED 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, 2002 the subsidiaries had 13,749,202, 22,200,000 and 7,713,501 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. (d) Not callable prior to 2003, after that the call price is $100 per share plus accrued dividends. (e) With sinking fund. (f) The number of shares of preferred stock redeemed is 106,458 shares in 2002, 50,000 shares in 2001 and 209,563 shares in 2000.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Schedule of Consolidated Long-term Debt of Subsidiaries Weighted Average Maturity Interest Rate Interest Rates at December 31, December 31, - -------- ----------------- ----------------------------- ----------- December 31, 2002 2002 2001 2002 2001 ----------------- ---- ---- ---- ---- (in millions) ------------- FIRST MORTGAGE BONDS (a) 2002-2004 6.87% 6.00%-7.85% 6.00%-7.85% $ 648 $ 1,246 2005-2008 6.90% 6.20%-8% 6.20%-8% 463 699 2022-2025 7.66% 6.875%-8.7% 6-7/8%-8.80% 773 850 INSTALLMENT PURCHASE CONTRACTS (b) 2002-2009 4.62% 3.75%-7.70% 1.80%-7.70% 396 446 2011-2030 5.83% 1.35%-8.20% 1.55%-8.20% 1,284 1,234 NOTES PAYABLE (c) 2002-2021 5.54% 3.732%-9.60% 4.048%-9.60% 520 217 SENIOR UNSECURED NOTES 2002-2005 5.53% 2.12%-7.45% 2.31%-7.45% 1,834 1,910 2006-2012 5.91% 4.31%-6.91% 6.125%-6.91% 2,295 1,727 2032-2038 6.64% 6.00%-7-3/8% 7.20%-7-3/8% 690 340 JUNIOR DEBENTURES 2025-2038 7.90% 7.60%-8.72% 7.60%-8.72% 205 618 SECURITIZATION BONDS 2003-2016 5.40% 3.54%-6.25% - 797 - OTHER LONG-TERM DEBT (d) 247 258 Unamortized Discount (net) (32) (40) ------- ------- Total Long-term Debt Outstanding 10,120 9,505 Less Portion Due Within One Year 1,633 1,095 ------- ------- Long-term Portion $ 8,487 $ 8,410 ======= ======= EQUITY UNIT SENIOR NOTES 2007 5.75% 5.75% - $ 376 $ - ======= =======
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 9 of the Notes to Consolidated Financial Statements) and financing obligation under sale lease back agreements. Long-term debt outstanding at December 31, 2002 (includes Equity Unit Senior Notes) is payable as follows: (in millions) 2003 $ 1,633 2004 824 2005 993 2006 1,611 2007 1,081 Later Years 4,386 ------- 10,528 Unamortized Discount 32 ------- Total $10,496 AMERICAN ELECTRIC POWER COMPANY INC. AND SUBSIDIARY COMPANIES Index to Combined 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 Goodwill and Other Intangible Assets Note 3 Merger Note 4 Nuclear Plant Restart Note 5 Rate Matters Note 6 Effects of Regulation Note 7 Customer Choice and Industry Restructuring Note 8 Commitments and Contingencies Note 9 Guarantees Note 10 Sustained Earnings Improvement Initiative Note 11 Acquisitions, Dispositions and Discontinued Operations Note 12 Asset Impairments and Investment Value Losses Note 13 Benefit Plans Note 14 Stock-Based Compensation Note 15 Business Segments Note 16 Risk Management, Financial Instruments And Derivatives Note 17 Income Taxes Note 18 Basic and Diluted Earnings Per Share Note 19 Supplementary Information Note 20 Power and Distribution Projects Note 21 Leases Note 22 Lines of Credit and Sale of Receivables Note 23 Unaudited Quarterly Financial Information Note 24 Trust Preferred Securities Note 25 Minority Interest in Finance Subsidiary Note 26 Equity Units Note 27 Subsequent Events (Unaudited) Note 30 INDEPENDENT AUDITORS' REPORT To the Shareholders and Board of Directors of American Electric Power Company, Inc.: We have audited the accompanying consolidated balance sheets of American Electric Power Company, Inc. and subsidiaries as of December 31, 2002 and 2001, and the related consolidated statements of operations, cash flows and common shareholders' equity and comprehensive income, for each of the three years in the period ended December 31, 2002. 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, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of American Electric Power Company, Inc. and subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. As discussed in Note 3 to the consolidated financial statements, the Company adopted SFAS 142, "Goodwill and Other Intangible Assets," effective January 1, 2002. As discussed in Note 13 to the consolidated financial statements, the Company recorded certain impairments of goodwill, long-lived assets and other investments in the fourth quarter of 2002. /s/ Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 MANAGEMENT'S RESPONSIBILITY The management of American Electric Power Company, Inc. has prepared the financial statements and schedules herein and 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 accounting principles generally accepted in the United States of America, 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 previous 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. AEP GENERATING COMPANY
AEP GENERATING COMPANY Selected Financial Data - ----------------------- Year Ended December 31, ---------------------- 2002 2001 2000 1999 1998 ---- ---- ---- ---- ---- (in thousands) INCOME STATEMENTS DATA: Operating Revenues $213,281 $227,548 $228,516 $217,189 $224,146 Operating Expenses 207,152 220,571 220,092 211,849 215,415 -------- -------- -------- -------- -------- Operating Income 6,129 6,977 8,424 5,340 8,731 Nonoperating Items, Net 3,681 3,484 3,429 3,659 3,364 Interest Charges 2,258 2,586 3,869 2,804 3,149 -------- -------- -------- -------- -------- Net Income $ 7,552 $ 7,875 $ 7,984 $ 6,195 $ 8,946 ======== ======== ======== ======== ======== December 31, ----------- 2002 2001 2000 1999 1998 ---- ---- ---- ---- ---- (in thousands) BALANCE SHEETS DATA: Electric Utility Plant $652,213 $648,254 $642,302 $640,093 $636,460 Accumulated Depreciation 358,174 337,151 315,566 295,065 277,855 -------- -------- -------- -------- -------- Net Electric Utility Plant $294,039 $311,103 $326,736 $345,028 $358,605 ======== ======== ======== ======== ======== Total Assets $349,729 $361,341 $374,602 $398,640 $403,892 ======== ======== ======== ======== ======== Common Stock and Paid-in Capital $ 24,434 $ 24,434 $ 24,434 $ 30,235 $ 36,235 Retained Earnings 18,163 13,761 9,722 3,673 2,770 -------- -------- -------- -------- -------- Total Common Shareholder's Equity $ 42,597 $ 38,195 $ 34,156 $ 33,908 $ 39,005 ======== ======== ======== ======== ======== Long-term Debt (a) $ 44,802 $ 44,793 $ 44,808 $ 44,800 $ 44,792 ======== ======== ======== ======== ======== Total Capitalization And Liabilities $349,729 $361,341 $374,602 $398,640 $403,892 ======== ======== ======== ======== ======== (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 will purchase all of AEGCo's Rockport capacity unless it is sold to other utilities. A unit power agreement between AEGCo and KPCo expires in 2004. The KPCo unit power agreement extends until December 31, 2009 for Rockport Plant Unit 1 and until December 7, 2022 for Rockport Plant Unit 2 if AEP's restructuring settlement agreement filed with the FERC becomes operative. 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. Results of Operations Net Income decreased $323,000 or 4% as a result of limits on recovery of return on capital related to operating and in-service ratios of the Rockport Plant. Operating Revenues Decrease - --------------------------- The decrease in Operating Revenues of $14,267,000 or 6% reflects a decrease in recoverable expenses, primarily fuel. Operating Expenses Decrease - --------------------------- Operating Expenses decreased 6% as follows: Increase (Decrease) (dollars in thousands) From Previous Year - --------------------- ------------------ Amount % ------ - Fuel $(13,723) (13) Other Operation 1,899 17 Maintenance 565 6 Depreciation 137 1 Taxes Other Than Income Taxes (976) (23) Income Taxes (1,321) (46) -------- Total $(13,419) (6) ======== The decrease in Fuel expense reflects a decrease in generation and lower average fuel costs. Other Operation expense increased due to increased costs for employee benefits and property insurance. The increase in Maintenance expense can be attributed to shorter duration of maintenance outages for boiler inspection and repair in 2001. Taxes Other Than Income Taxes decreased due to a decrease in Indiana real and personal property taxes reflecting a favorable change in the law which lowered the tax for Rockport Plant. The decrease in Income Taxes attributable to operations is primarily due to a decrease in pre-tax operating income and a change in estimate for state income tax accruals.
AEP GENERATING COMPANY Statements of Income - -------------------- Year Ended December 31, ----------------------------------------- 2002 2001 2000 ---- ---- ---- (in thousands) OPERATING REVENUES $213,281 $227,548 $228,516 -------- -------- -------- OPERATING EXPENSES: Fuel 89,105 102,828 102,978 Rent - Rockport Plant Unit 2 68,283 68,283 68,283 Other Operation 12,924 11,025 10,295 Maintenance 9,418 8,853 9,616 Depreciation 22,560 22,423 22,162 Taxes Other Than Income Taxes 3,281 4,257 3,854 Income Taxes 1,581 2,902 2,904 -------- -------- -------- TOTAL OPERATING EXPENSES 207,152 220,571 220,092 -------- -------- -------- OPERATING INCOME 6,129 6,977 8,424 NONOPERATING INCOME 343 30 6 NONOPERATING EXPENSES 198 16 17 NONOPERATING INCOME TAX CREDITS 3,536 3,470 3,440 INTEREST CHARGES 2,258 2,586 3,869 -------- -------- -------- NET INCOME $ 7,552 $ 7,875 $ 7,984 ======== ======== ======== Statements of Retained Earnings Year Ended December 31, ---------------------------------------- 2002 2001 2000 ---- ---- ---- (in thousands) RETAINED EARNINGS JANUARY 1 $13,761 $ 9,722 $3,673 NET INCOME 7,552 7,875 7,984 CASH DIVIDENDS DECLARED 3,150 3,836 1,935 ------- ------- ------ RETAINED EARNINGS DECEMBER 31 $18,163 $13,761 $9,722 ======= ======= ====== See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY Balance Sheets - -------------- December 31, ----------------------------- 2002 2001 ---- ---- (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production $637,095 $638,297 General 4,728 3,012 Construction Work in Progress 10,390 6,945 -------- -------- Total Electric Utility Plant 652,213 648,254 Accumulated Depreciation 358,174 337,151 -------- ------- NET ELECTRIC UTILITY PLANT 294,039 311,103 -------- ------- OTHER PROPERTY AND INVESTMENTS 119 119 -------- -------- CURRENT ASSETS: Cash and Cash Equivalents - 983 Accounts Receivable: Affiliated Companies 18,454 22,344 Miscellaneous - 147 Fuel 20,260 15,243 Materials and Supplies 4,913 4,480 Prepayments - 244 -------- -------- TOTAL CURRENT ASSETS 43,627 43,441 -------- -------- REGULATORY ASSETS 4,970 5,207 -------- -------- DEFERRED CHARGES 6,974 1,471 -------- -------- TOTAL ASSETS $349,729 $361,341 ======== ======== See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY December 31, ----------- 2002 2001 ---- ---- (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 18,163 13,761 -------- -------- Total Common Shareholder's Equity 42,597 38,195 Long-term Debt 44,802 44,793 -------- -------- TOTAL CAPITALIZATION 87,399 82,988 -------- -------- OTHER NONCURRENT LIABILITIES 301 76 -------- -------- CURRENT LIABILITIES: Advances from Affiliates 28,034 32,049 Accounts Payable: General 26 7,582 Affiliated Companies 15,907 1,654 Taxes Accrued 2,327 4,777 Rent Accrued - Rockport Plant Unit 2 4,963 4,963 Other 1,111 3,481 -------- -------- TOTAL CURRENT LIABILITIES 52,368 54,506 -------- -------- DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2 111,046 116,617 -------- -------- REGULATORY LIABILITIES: Deferred Investment Tax Credits 52,943 56,304 Amounts Due to Customers for Income Taxes 16,670 22,725 -------- -------- TOTAL REGULATORY LIABILITIES 69,613 79,029 -------- -------- DEFERRED INCOME TAXES 29,002 27,975 -------- -------- DEFERRED CREDITS - 150 -------- -------- COMMITMENTS AND CONTINGENCIES (Note 9) TOTAL CAPITALIZATION AND LIABILITIES $349,729 $361,341 ======== ======== See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY Statements of Cash Flows - ------------------------ Year Ended December 31, ------------------------------------------- 2002 2001 2000 ---- ---- ---- (in thousands) OPERATING ACTIVITIES: Net Income $ 7,552 $ 7,875 $ 7,984 Adjustments for Noncash Items: Depreciation 22,560 22,423 22,162 Deferred Income Taxes (5,028) (6,224) (5,842) Deferred Investment Tax Credits (3,361) (3,414) (3,396) 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 4,037 1,224 1,392 Fuel, Materials and Supplies (5,450) (4,738) 6,486 Accounts Payable 6,697 (4,597) (13,157) Taxes Accrued (2,450) (216) 708 Other Assets (5,211) (569) 1,636 Other Liabilities (2,295) (1,244) (404) -------- -------- -------- Net Cash Flows From Operating Activities 11,480 4,949 11,998 -------- -------- -------- INVESTING ACTIVITIES - Construction Expenditures (5,298) (6,868) (5,190) -------- -------- -------- FINANCING ACTIVITIES: Return of Capital to Parent Company - - (5,801) Change in Short-term Debt (net) - - (24,700) Change in Advances From Affiliates (net) (4,015) 3,981 28,068 Dividends Paid (3,150) (3,836) (1,935) -------- -------- -------- Net Cash Flows From (Used For) Financing Activities (7,165) 145 (4,368) -------- -------- -------- Net Increase (Decrease) in Cash and Cash Equivalents (983) (1,774) 2,440 Cash and Cash Equivalents January 1 983 2,757 317 -------- -------- -------- Cash and Cash Equivalents December 31 $ - $ 983 $ 2,757 ======== ======== ======== Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $2,019,000, $1,509,000 and $3,531,000 and for income taxes was $7,884,000, $8,597,000 and $6,820,000 in 2002, 2001 and 2000, respectively. See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY Statements of Capitalization - ---------------------------- December 31, ----------- 2002 2001 ---- ---- (in thousands) COMMON STOCK EQUITY (a) $42,597 $38,195 ------- ------- 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 (198) (207) ------- ------- TOTAL LONG-TERM DEBT 44,802 44,793 ------- ------- TOTAL CAPITALIZATION $87,399 $82,988 ======= ======= (a) In 2000, AEGCo returned capital to AEP in the amounts of $5.8 million. There were no other material transactions affecting Common Stock and Paid-in Capital in 2002, 2001 and 2000. (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 had selected a daily rate which ranged from 0.9% to 5.6% during 2001 and averaged 2.8% in 2001. Effective July 13, 2001, AEGCo selected a term rate of 4.05% for five years ending July 12, 2006. See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY Index to Combined Notes to Financial Statements - ----------------------------------------------- The notes to AEGCo'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 AEGCo. The combined footnotes begin on page L-1. Combined Footnote Reference --------- Significant Accounting Policies Note 1 Effects of Regulation Note 7 Commitments and Contingencies Note 9 Guarantees Note 10 Sustained Earnings Improvement Initiative Note 11 Business Segments Note 16 Risk Management, Financial Instruments and Derivatives Note 17 Income Taxes Note 18 Leases Note 22 Lines of Credit and Sale of Receivables Note 23 Unaudited Quarterly Financial Information Note 24 Related Party Transactions Note 29 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, 2002 and 2001, and the related statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2002. 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, 2002 and 2001, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. /s/ Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES Selected Consolidated Financial Data - ------------------------------------ Year Ended December 31, ---------------------- 2002 2001 2000 1999 1998 ---- ---- ---- ---- ---- (in thousands) INCOME STATEMENTS DATA: Operating Revenues $1,690,493 $1,738,837 $1,770,402 $1,482,475 $1,406,117 Operating Expenses 1,296,760 1,443,106 1,463,304 1,188,490 1,123,330 --------- --------- --------- --------- --------- Operating Income 393,733 295,731 307,098 293,985 282,787 Nonoperating Items, Net 8,079 5,324 7,235 8,113 760 Interest Charges 125,871 116,268 124,766 114,380 122,036 ------- --------- ------- ------- --------- Income Before Extraordinary Item 275,941 184,787 189,567 187,718 161,511 Extraordinary Loss - (2,509) - (5,517) - --------- --------- --------- -------- --------- Net Income 275,941 182,278 189,567 182,201 161,511 Preferred Stock Dividend Requirements 241 242 241 6,931 6,901 Gain (Loss) on Reacquired Preferred Stock 4 - - (2,763) - --------- --------- --------- -------- -------- Earnings Applicable To Common Stock $275,704 $182,036 $189,326 $172,507 $154,610 ======== ======== ======== ======== ======== Year Ended December 31, ---------------------- 2002 2001 2000 1999 1998 ---- ---- ---- ---- ---- (in thousands) BALANCE SHEETS DATA: Electric Utility Plant $5,625,736 $5,769,707 $5,592,444 $5,511,894 $5,336,191 Accumulated Depreciation And Amortization 2,405,492 2,446,027 2,297,189 2,247,225 2,072,686 --------- ---------- --------- --------- --------- Net Electric Utility Plant $3,220,244 $3,323,68 $3,295,255 $3,264,669 $3,263,505 ========== ========== ========== ========== ========== Total Assets $5,356,438 $4,893,030 $5,467,701 $4,847,857 $4,735,656 ========== ========== ========== ========== ========== Common Stock and Paid-in Capital $187,898 $ 573,903 $573,904 $573,904 $573,904 Accumulated Other Comprehensive Income (Loss) (73,160) - - - - Retained Earnings 986,396 826,197 792,219 758,894 734,387 ------- ---------- ------- ------- ------- Total Common Shareholder's Equity $1,101,134 $1,400,100 $1,366,123 $1,332,798 $1,308,291 ========== ========== ========== ========== ========== Preferred Stock $ 5,942 $ 5,952 $ 5,951 $ 5,951 $163,188 ======= ========== ======= ======= ======== CPL - Obligated, Mandatorily Redeemable Preferred Securities of Subsidiary Trust Holding Solely Junior Subordinated Debentures of CPL $136,250 $ 136,250 $148,500 $150,000 $150,000 ======== ========= ======== ======== ======== Long-term Debt (a) $1,438,565 $1,253,768 $1,454,559 $1,454,541 $1,350,706 ========== ========== ========== ========== ========== Total Capitalization And Liabilities $5,356,438 $4,893,030 $5,467,701 $4,847,857 $4,735,656 ========== ========== ========== ========== ========== (a) Including portion due within one year.
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES Management's Discussion and Analysis of Results of Operations - ------------------------------------------------------------- AEP Texas Central Company (TCC), formerly known as Central Power and Light Company (CPL), is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power in southern Texas. TCC also sells electric power at wholesale to other utilities, municipalities, rural electric cooperatives and beginning in 2002 to its affiliated retail electric provider (REP) in Texas. Wholesale power marketing activities are conducted on TCC's behalf by AEPSC. TCC, along with the other AEP electric operating subsidiaries, shares in AEP's electric power transactions with other utility systems and power marketers. On January 1, 2002, customer choice of electricity supplier began in the Electric Reliability Council of Texas (ERCOT) area of Texas where TCC operates. Under the Texas Restructuring Legislation, each electric utility was required to submit a plan to structurally unbundle its business into an affiliated REP, a power generator, and a transmission and distribution utility. During the year 2000, TCC submitted a plan for separation that was subsequently approved by the PUCT. TCC has functionally separated its generation from its transmission and distribution operations and AEP formed a separate affiliated REP. Pending regulatory approval, TCC anticipates legally separating its generation from its transmission and distribution operations (see Note 8). The affiliated REP, a separate legal entity that was an AEP subsidiary (not owned by or consolidated with TCC) was sold in December 2002 (see Note 12). Since the affiliated REP is the electricity supplier to retail customers in the ERCOT area, TCC sells its generation to the affiliated REP and other market participants and provides transmission and distribution services to retail customers of the REPs in the TCC service territory. As a result of the formation of the affiliated REP, effective January 1, 2002, TCC no longer supplies electricity directly to retail customers. The implementation of REPs as suppliers to retail customers has caused a significant shift in TCC's sales as described below under "Results of Operations." In December 2002, AEP sold the affiliated REP to an unrelated third party who assumed the obligations of the affiliated REP under the Texas Restructuring Legislation (see Note 12). Prior to the sale during 2002 sales to the affiliated REP were classified as Sales to AEP Affiliates. Subsequent to the sale, transactions with the REP were classified as Wholesale Electricity or Energy Delivery. Results of Operations - --------------------- In 2002, Net Income increased $94 million or 51% primarily due to $262 million of revenues associated with recognition of stranded costs in Texas offset in part by losses associated with the commencement of customer choice in Texas which resulted in the loss of customers and reduced prices (see Note 8). In 2001, Income Before Extraordinary Item decreased $5 million or 3%, primarily resulting from a settlement of Texas municipal franchise fees and increased Maintenance expenses. Changes in Operating Revenues - ----------------------------- Increase (Decrease) From Previous Year (dollars in millions) --------------------- 2002 2001 Amount % Amount % ------ - ------ - Wholesale Electricity* $(1,096.4) (90) $(29.9) (2) Energy Delivery* 81.4 17 (5.6) (1) Sales to AEP Affiliates 966.7 N.M. 4.0 11 -------- ------ Total $ (48.3) (3) $(31.5) (2) ======= ====== *Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery. N.M. = Not Meaningful In 2002, Wholesale Electricity revenues decreased as a result of the elimination of TCC's retail electricity sales in the ERCOT region as of January 1, 2002 and a decrease in wholesale power marketing margins offset in part by the interchange cost reconstruction (ICR) adjustments (see Note 6). In 2001, the decrease in Wholesale Electricity revenues was primarily attributable to unfavorable wholesale power marketing and trading conditions. In 2002, Sales to AEP Affiliates revenue increased primarily due to increased revenues from the newly created affiliated REP. Although TCC sold electricity to the affiliated REP instead of directly to retail customers, total revenues decreased due to lower prices for power sold to the affiliated REP. Additionally, delivery charges provided to the affiliated REP in 2002 are classified as Sales to AEP Affiliates in 2002, whereas in 2001 they were classified as Energy Delivery revenue. Revenues for 2002 included $262 million of revenues, associated with recognition of stranded costs in Texas (see Note 8). Energy Delivery revenue also included revenues received for securitized assets beginning in 2002 (see Note 8). Changes in Operating Expenses - ----------------------------- Increase (Decrease) From Previous Year (dollars in millions) --------------------- 2002 2001 Amount % Amount % ------ - ------ - Fuel $(246.2) (50) $(58.8) (11) Purchased Power: Wholesale Electricity 83.5 65 (16.2) (11) AEP Affiliates (35.3) (60) 26.0 80 Other Operation (17.1) (5) 1.7 1 Maintenance (7.8) (11) 10.7 18 Depreciation And Amortization 45.8 27 (10.4) (6) Taxes Other Than Income Taxes 4.6 5 14.4 19 Income Taxes 26.1 23 12.4 12 ------- ------ Total $(146.4) (10) $(20.2) (1) ======= ====== In 2002, the decrease in Fuel expense was due to a decrease in the average unit cost of fuel and decreased generation. 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. TCC used natural gas as fuel for 32% of its generation in 2002. 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 TCC's fuel expense; however, they generally did not impact results of operations in 2001 and 2000 due to fuel recovery mechanisms, which are no longer in place beginning with deregulation in 2002. In 2002, the increase in Wholesale Electricity Purchased Power expense is due to higher MWH purchases from the market where we could purchase power at prices lower than our cost to produce. ICR adjustments also had the effect of increasing Wholesale Electricity Purchased Power expense and decreasing AEP Affiliates Purchased Power expense in 2002 (see Note 6). In 2001, Purchased Power increased overall largely due to higher natural gas prices. Although gas prices declined in 2001, they were higher during the first half of 2001 when TCC was making most of its purchases. In 2002, Other Operation expense decreased due primarily to the elimination of factoring of accounts receivable and lower ERCOT transmission related expenses. In 2002, Maintenance expense decreased due to two scheduled "18 month interval" refueling outages for STP during 2001 that increased Maintenance expense above the 2002 and 2000 levels. Also contributing to the decrease in 2002, and the increase in 2001, was an increase in Maintenance expense for scheduled major overhauls of four power plants in 2001. In 2002, the increase in Depreciation and Amortization is attributable to the amortization of regulatory assets that were securitized in the first quarter of 2002, offset by the elimination of excess earnings expense in 2002 under Texas Restructuring Legislation (see Note 8). In 2002, the increase in Taxes Other Than Income Taxes resulted primarily from higher local franchise taxes, offset by one-time 2001 assessments and decreased gross receipts tax, due to deregulation. In 2001, Taxes Other Than Income Taxes increased due primarily to an increase in franchise related taxes, including a settlement of disputed franchise fees, and a new tax levied by the PUCT, the Texas System Benefit Fund Assessment. In 2002, the increase in Income Taxes is due to an increase in pre-tax income offset by changes in timing between book/tax accounting differences in state income taxes. In 2001 the increase in Income Tax expense is primarily due to adjustments associated with prior year tax returns and an increase in pre-tax book income. Other Changes - ------------- In 2002, Nonoperating Income and Nonoperating Expenses increased significantly as a result of increased non-utility revenue and expenses associated with energy related construction projects for third parties, offset in part by decreased interest income. The revenues associated with the energy related construction projects included in Nonoperating Income increased $34 million and $15 million in 2002 and 2001. The expenses associated with these projects included in Nonoperating Expenses increased $32 million and $14 million in 2002 and 2001. In 2002, Nonoperating Income Tax Expense increased due to increases in pre-tax non-operating income. In 2002, Interest Charges increased primarily due to higher levels of outstanding debt (see TCC's schedule of Long-term Debt and Consolidated Statements of Capitalization for further information). In 2001, the decrease in interest charges was attributable to lower average interest rates associated with short-term and long-term 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. Impairment - ---------- As a result of TCC's recent ability to purchase electricity at a significantly lower price than its current cost to generate electricity, TCC proposed in September 2002 to "inactivate" various, high-cost gas fired generating facilities. In the third quarter 2002, TCC recorded an impairment charge of approximately $95.6 million (pre-tax) related to these plants and recorded approximately $4.0 million (pre-tax) for severance charges. Both of these charges were deferred and recorded in Regulatory Assets Designated for or Subject to Securitization, to be included as a stranded cost in the Texas 2004 true-up proceeding (see Note 8). In the fourth quarter 2002 an additional pre-tax charge of $21.6 million was recorded related to additional plant impairments, fuel inventory and materials and supplies, and an additional $1.5 million pre-tax charge was recorded related to severance charges (see Note 13) related to the "inactivated" plants. The entire $23.1 million was also deferred and recorded in Regulatory Assets Designated for or Subject to Securitization.
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES Consolidated Statements of Income - --------------------------------- Year Ended December 31, ------------------------------------------------- 2002 2001 2000 ---- ---- ---- (in thousands) OPERATING REVENUES: Wholesale Electricity $ 127,502 $1,223,893 $1,253,836 Energy Delivery 554,547 473,182 478,814 Sales to AEP Affiliates 1,008,444 41,762 37,752 ---------- ---------- ---------- TOTAL OPERATING REVENUES 1,690,493 1,738,837 1,770,402 ---------- ---------- ---------- OPERATING EXPENSES: Fuel 245,834 492,057 550,903 Purchased Power: Wholesale Electricity 211,358 127,816 144,021 AEP Affiliates 23,406 58,641 32,591 Other Operation 304,094 321,227 319,539 Maintenance 63,392 71,212 60,528 Depreciation and Amortization 214,162 168,341 178,786 Taxes Other Than Income Taxes 95,500 90,916 76,477 Income Taxes 139,014 112,896 100,459 ---------- ---------- ---------- TOTAL OPERATING EXPENSES 1,296,760 1,443,106 1,463,304 ---------- ---------- ---------- OPERATING INCOME 393,733 295,731 307,098 NONOPERATING INCOME 53,141 22,552 5,830 NONOPERATING EXPENSES 41,910 17,626 3,668 NONOPERATING INCOME TAX EXPENSE (CREDIT) 3,152 (398) (5,073) INTEREST CHARGES 125,871 116,268 124,766 ---------- ---------- ---------- INCOME BEFORE EXTRAORDINARY ITEM 275,941 184,787 189,567 EXTRAORDINARY LOSS ON REACQUIRED DEBT (Net of Tax of $1,351,000 for 2001) - (2,509) - ---------- ---------- ---------- NET INCOME 275,941 182,278 189,567 PREFERRED STOCK DIVIDEND REQUIREMENTS 241 242 241 GAIN ON REACQUIRED PREFERRED STOCK 4 - - ---------- ---------- ---------- EARNINGS APPLICABLE TO COMMON STOCK $ 275,704 $ 182,036 $ 189,326 ========== ========== ========== Consolidated Statements of Comprehensive Income - ----------------------------------------------- Year Ended December 31, ------------------------------------------------ 2002 2001 2000 ---- ---- ---- (in thousands) NET INCOME $275,941 $182,278 $189,567 OTHER COMPREHENSIVE INCOME (LOSS): Cash Flow Power Hedges (36) - - Minimum Pension Liability (73,124) - - -------- -------- -------- COMPREHENSIVE INCOME $202,781 $182,278 $189,567 ======== ======== ======== The common stock of TCC is owned by a wholly owned subsidiary of AEP. See Notes to Financial Statements beginning on page L-1.
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES Consolidated Statements of Retained Earnings - -------------------------------------------- Year Ended December 31, --------------------------------------------- 2002 2001 2000 ---- ---- ---- (in thousands) BEGINNING OF PERIOD $826,197 $792,219 $758,894 NET INCOME 275,941 182,278 189,567 DEDUCTIONS (ADDITIONS): Capital Stock Gains (4) - - Cash Dividends Declared: Common Stock 115,505 148,057 156,000 Preferred Stock 241 242 241 Other - 1 1 -------- -------- -------- BALANCE AT END OF PERIOD $986,396 $826,197 $792,219 ======== ======== ======== The common stock of TCC is owned by a wholly owned subsidiary of AEP. See Notes to Financial Statements beginning on page L-1.
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES Consolidated Balance Sheets - --------------------------- December 31, ----------- 2002 2001 ---- ---- (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production $2,903,942 $3,169,421 Transmission 698,964 663,655 Distribution 1,296,731 1,279,037 General 258,386 241,137 Construction Work in Progress 200,947 169,075 Nuclear Fuel 266,766 247,382 ------- ------- Total Electric Utility Plant 5,625,736 5,769,707 Accumulated Depreciation and Amortization 2,405,492 2,446,027 --------- --------- NET ELECTRIC UTILITY PLANT 3,220,244 3,323,680 --------- --------- OTHER PROPERTY AND INVESTMENTS 3,977 47,950 ----- ------ SECURITIZED TRANSITION ASSETS 734,591 - ------- ---------- LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 4,392 28,039 ----- ------ CURRENT ASSETS: Cash and Cash Equivalents 85,420 10,909 Accounts Receivable: General 113,543 38,459 Affiliated Companies 121,324 6,249 Allowance for Uncollectible Accounts (346) (186) Fuel Inventory 32,563 38,690 Materials and Supplies 51,593 55,475 Accrued Utility Revenues 27,150 - Energy Trading and Derivative Contracts 22,493 34,480 Prepayments and Other Current Assets 2,133 2,742 ----- ----- TOTAL CURRENT ASSETS 455,873 186,818 ------- ------- REGULATORY ASSETS 458,552 226,812 ------- ------- REGULATORY ASSETS DESIGNATED FOR OR SUBJECT TO SECURITIZATION 336,444 959,294 ------- ------- NUCLEAR DECOMMISSIONING TRUST FUND 98,474 98,600 ------ ------ DEFERRED CHARGES 43,891 21,837 ------ ------ TOTAL ASSETS $5,356,438 $4,893,030 ========== ========== See Notes to Financial Statements beginning on page L-1.
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES December 31, ----------- 2002 2001 ---- ---- (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock - $25 Par Value: Authorized - 12,000,000 Shares Outstanding - 2,211,678 Shares at December 31, 2002 6,755,535 Shares at December 31, 2001 $ 55,292 $ 168,888 Paid-in Capital 132,606 405,015 Accumulated Other Comprehensive Income (Loss) (73,160) - Retained Earnings 986,396 826,197 --------- --------- Total Common Shareholder's Equity 1,101,134 1,400,100 Preferred Stock 5,942 5,952 CPL - Obligated, Mandatorily Redeemable Preferred Securities of Subsidiary Trust Holding Solely Junior Subordinated Debentures of CPL 136,250 136,250 Long-term Debt 1,209,434 988,768 --------- ------- TOTAL CAPITALIZATION 2,452,760 2,531,070 --------- --------- OTHER NONCURRENT LIABILITIES 74,572 10,905 --------- --------- CURRENT LIABILITIES: Short-term Debt - Affiliates 650,000 - Long-term Debt Due Within One Year 229,131 265,000 Advances from Affiliates (net) 126,711 354,277 Accounts Payable - General 72,199 65,307 Accounts Payable - Affiliated Companies 36,242 49,301 Customer Deposits 666 26,744 Taxes Accrued 24,791 83,512 Interest Accrued 51,205 23,715 Energy Trading and Derivative Contracts 19,811 40,987 Other 36,698 18,076 ------ ------ TOTAL CURRENT LIABILITIES 1,247,454 926,919 --------- ------- DEFERRED INCOME TAXES 1,261,252 1,163,795 --------- --------- DEFERRED INVESTMENT TAX CREDITS 117,686 122,892 ------- ------- LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 1,713 17,675 ----- ------ REGULATORY LIABILITIES AND DEFERRED CREDITS 201,001 119,774 ------- ------- COMMITMENTS AND CONTINGENCIES (Note 9) TOTAL CAPITALIZATION AND LIABILITIES $5,356,438 $4,893,030 ========== ========== See Notes to Financial Statements beginning on page L-1.
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES Consolidated Statements of Cash Flows - ------------------------------------- Year Ended December 31, ------------------------------------------- 2002 2001 2000 ---- ---- ---- (in thousands) OPERATING ACTIVITIES: Net Income $275,941 $182,278 $189,567 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: Depreciation and Amortization 214,162 168,341 178,786 Extraordinary Loss on Reacquired Debt - 2,509 - Deferred Income Taxes 113,655 (72,568) 16,263 Deferred Investment Tax Credits (5,206) (5,208) (5,207) Mark-toMarket Energy Trading and Derivative Contracts (1,558) (12,048) 8,191 Change in Certain Current Assets and Liabilities: Accounts Receivable (net) (189,999) 52,862 (32,902) Fuel, Materials and Supplies (4,899) (18,215) 8,680 Interest Accrued 27,490 (2,502) 11,494 Accrued Utility Revenues (27,150) - - Accounts Payable (6,167) (55,311) 45,873 Taxes Accrued (58,721) 27,986 14,405 Fuel Recovery 16,455 179,866 (96,872) Transmission Coordination Agreement Settlement - - 15,519 Texas Wholesale Clawback (see Note 7) (262,000) - - Change in Other Assets (534) 10,767 589 Change in Other Liabilities 56,024 11,163 12,243 -------- -------- -------- Net Cash Flows From Operating Activities 147,493 469,920 366,629 -------- -------- -------- INVESTING ACTIVITIES: Construction Expenditures (151,645) (193,732) (199,484) Proceeds From Sales of Property and Other 143 (354) - -------- -------- -------- Net Cash Flows Used For Investing Activities (151,502) (194,086) (199,484) -------- -------- -------- FINANCING ACTIVITIES: Issuance of Long-term Debt 797,335 260,162 149,248 Change in Short-term Debt Affiliate (Net) 650,000 - - Retirement of Common Stock (386,005) - - Retirement of Preferred Stock (6) - - Retirement of Long-term Debt (639,492) (475,606) (151,440) Change in Advances from Affiliates (net) (227,566) 84,565 (52,446) Special Deposit for Reacquisition of Long-term Debt - - 50,000 Dividends Paid on Common Stock (115,505) (148,057) (156,000) Dividends Paid on Cumulative Preferred Stock (241) (242) (249) -------- -------- -------- Net Cash Flows From (Used For) Financing Activities 78,520 (279,178) (160,887) -------- -------- -------- Net Increase (Decrease) in Cash and Cash Equivalents 74,511 (3,344) 6,258 Cash and Cash Equivalents January 1 10,909 14,253 7,995 -------- -------- -------- Cash and Cash Equivalents December 31 $ 85,420 $ 10,909 $ 14,253 ======== ======== ======== Supplemental Disclosure: Cash paid for interest net of capitalized amounts (including distributions on Trust Preferred Securities) was $93,120,000, $109,835,000 and $110,010,000 and for income taxes was $95,600,000, $161,529,000 and $48,141,000 in 2002, 2001 and 2000,respectively. See Notes to Financial Statements beginning on page L-1.
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES Consolidated Statements of Capitalization - ----------------------------------------- December 31, ----------- 2002 2001 ---- ---- (in thousands) COMMON SHAREHOLDER'S EQUITY (a) $1,101,134 $1,400,100 ---------- ---------- PREFERRED STOCK - 3,035,000 authorized shares, $100 par value Not Subject to Mandatory Redemption: Call Price Shares December 31, Number of Shares Redeemed Outstanding Series 2002 Year Ended December 31, December 31, 2002 - ------ ------------ ---------------------------- ----------------- 2002 2001 2000 ---- ---- ---- 4.00% $105.75 100 - - 41,938 4,194 4,204 4.20% 103.75 - - - 17,476 1,748 1,748 ---------- ---------- Total Preferred Stock 5,942 5,952 ---------- ---------- TRUST PREFERRED SECURITIES: TCC-obligated, mandatorily redeemable preferred securities of subsidiary trust holding solely Junior Subordinated Debentures of TCC, 8.00%, due April 30, 2037 136,250 136,250 ---------- ---------- LONG-TERM (See Schedule of Long-term Debt): First Mortgage Bonds 152,353 614,200 Securitization Bonds (a) 796,635 - Installment Purchase Contracts 489,577 489,568 Senior Unsecured Notes - 150,000 Less Portion Due Within One year (229,131) (265,000) ---------- ---------- Long-term Debt Excluding Portion Due Within One Year 1,209,434 988,768 ---------- ---------- TOTAL CAPITALIZATION $2,452,760 $2,531,070 ========== ========== (a) In February 2002, TCC issued securitization bonds. $386 million of the proceeds was used to retire 4,543,857 shares of common stock. See Notes to Financial Statements beginning on page L-1.
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES Schedule of Long-term Debt - -------------------------- First mortgage bonds outstanding were as follows: December 31, 2002 2001 ---- ---- (in thousands) % Rate Due 7.25 2004 - October 1 $ 27,400 $100,000 7.50 2002 - December 1 - 115,000 6-7/8 2003 - February 1 16,418 49,200 7-1/8 2008 - February 1 18,581 75,000 7.50 2023 - April 1 17,996 75,000 6-5/8 2005 - July 1 71,958 200,000 -------- -------- Total $152,353 $614,200 ======== ======== First mortgage bonds are secured by a first mortgage lien on electric utility plant. The indenture, as supplemented, relating to the first mortgage bonds contains maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. Securitization Bonds outstanding were as follows: December 31, ------------------ Final 2002 2001 ---- ---- Payment Maturity (in thousands) Rate Date Date - ---- --------- ------------ 3.54 1/15/2005 1/15/2007 $128,950 $ - 5.01 1/15/2008 1/15/2010 154,507 - 5.56 1/15/2010 1/15/2012 107,094 - 5.96 7/15/2013 7/15/2015 214,927 - 6.25 1/15/2016 1/15/2017 191,857 - Unamortized Discount (700) - -------- ----- Total $796,635 $ - ======== ===== In February 2002, CPL Transition Funding LLC, a special purpose subsidiary of TCC, issued $797 million of Securitization Bonds, Series 2002-1. The Securitization Bonds mature at different times through 2017 and have a weighted average interest rate of 5.4 percent. Installment purchase contracts have been entered into in connection with the issuance of pollution control revenue bonds by governmental authorities as follows: December 31, 2002 2001 ---- ---- (in thousands) % Rate Due Matagorda County Navigation District, Texas: 6.00 2028 - July 1 $120,265 $120,265 6-1/8 2030 - May 1 60,000 60,000 3.75 2030(a) - May 1 111,700 111,700 4.00 2030(a) - May 1 50,000 50,000 4.55 2029(a) - Nov 1 100,635 100,635 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 (243) (252) -------- -------- Total $489,577 $489,568 ======== ======== (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, 2002 was 1.7%. Under the terms of the installment purchase contracts, TCC 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, 2002 2001 ---- ---- (in thousands) % Rate Due 2002 - February 22 (c) $ - $150,000 ------ -------- Total $ - $150,000 ====== ======== (c) A floating interest rate is determined monthly. The rate on December 31, 2001 was 2.56%. At December 31, 2002, future annual long-term debt payments are as follows: Amount ------ (in thousands) 2003 $229,131 2004 75,951 2005 121,937 2006 152,900 2007 52,729 Later Years 806,860 ---------- Total Principal Amount 1,439,508 Unamortized Discount (943) ---------- Total $1,438,565 See Note 25 for discussion of the Trust Preferred Securities issued by a wholly owned statutory business trust of TCC. AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES Index to Combined Notes to Consolidated Financial Statements - ------------------------------------------------------------ The notes to TCC's consolidated 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 TCC. 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 4 Rate Matters Note 6 Effects of Regulation Note 7 Customer Choice and Industry Restructuring Note 8 Commitments and Contingencies Note 9 Guarantees Note 10 Sustained Earnings Improvement Initiative Note 11 Acquisitions, Dispositions and Discontinued Operations Note 12 Asset Impairment and Investment Value Losses Note 13 Benefit Plans Note 14 Business Segments Note 16 Risk Management, Financial Instruments and Derivatives Note 17 Income Taxes Note 18 Leases Note 22 Lines of Credit and Sale of Receivables Note 23 Unaudited Quarterly Financial Information Note 24 Trust Preferred Securities Note 25 Jointly Owned Electric Utility Plant Note 28 Related Party Transactions Note 29 INDEPENDENT AUDITORS' REPORT To the Shareholders and Board of Directors of AEP Texas Central Company: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of AEP Texas Central Company and subsidiaries as of December 31, 2002 and 2001, 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, 2002. 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 AEP Texas Central Company and subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. /s/ Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 AEP TEXAS NORTH COMPANY
AEP TEXAS NORTH COMPANY Selected Financial Data - ----------------------- Year Ended December 31, ------------------------ 2002 2001 2000 1999 1998 ---- ---- ---- ---- ---- (in thousands) INCOME STATEMENTS DATA: Operating Revenues $ 450,740 $556,458 $571,064 $445,709 $424,953 Operating Expenses 442,869 523,068 518,723 391,910 365,677 ---------- -------- -------- -------- -------- Operating Income 7,871 33,390 52,341 53,799 59,276 Nonoperating Items, Net (703) 2,195 (1,675) 2,488 2,712 Interest Charges 20,845 23,275 23,216 24,420 24,263 ---------- -------- -------- -------- -------- Income (Loss) Before Extraordinary Item (13,677) 12,310 27,450 31,867 37,725 Extraordinary Loss - - - (5,461) - ---------- -------- -------- -------- -------- Net Income (Loss) (13,677) 12,310 27,450 26,406 37,725 Preferred Stock Dividend Requirements 104 104 104 104 104 ---------- -------- -------- -------- -------- Earnings (Loss) Applicable to Common Stock $ (13,781) $ 12,206 $ 27,346 $ 26,302 $ 37,621 ========== ======== ======== ======== ======== December 31, ----------- 2002 2001 2000 1999 1998 ---- ---- ---- ---- ---- (in thousands) BALANCE SHEETS DATA: Electric Utility Plant $1,201,747 $1,260,872 $1,229,339 $1,182,544 $1,146,582 Accumulated Depreciation and Amortization 521,792 546,162 515,041 495,847 473,503 ---------- ---------- ---------- ---------- ---------- Net Electric Utility Plant $679,955 $714,710 $714,298 $686,697 $673,079 ======== ======== ======== ======== ======== Total Assets $877,175 $ 864,875 $1,087,504 $861,205 $819,446 ======== ========== ========== ======== ======== Common Stock and Paid-in Capital $139,565 $139,565 $139,565 $139,565 $139,565 Accumulated Other Comprehensive Income (Loss) (30,763) - - - - Retained Earnings 71,942 105,970 122,588 113,242 114,940 --------- ---------- ---------- ---------- ---------- Total Common Shareholder's Equity $180,744 $245,535 $262,153 $252,807 $254,505 ======== ======== ======== ======== ======== Cumulative Preferred Stock: Not Subject to Mandatory Redemption $2,367 $ 2,367 $ 2,367 $ 2,367 $ 2,368 ====== ======= ======= ======= ======= Long-term Debt (a) $132,500 $255,967 $255,843 $303,686 $303,518 ======== ======== ======== ======== ======== Total Capitalization And Liabilities $877,175 $ 864,875 $1,087,504 $861,205 $819,446 ======== ========== ========== ======== ======== (a) Including portion due within one year.
AEP TEXAS NORTH COMPANY Management's Narrative Analysis of Results of Operations - -------------------------------------------------------- AEP Texas North Company (TNC), formerly known as West Texas Utilities Company (WTU), is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power in west and central Texas. TNC also sells electric power at wholesale to other utilities, municipalities, rural electric cooperatives and beginning in 2002 to its affiliated retail electric provider (REP) in Texas. Wholesale power marketing activities are conducted on TNC's behalf by AEPSC. TNC, along with the other AEP electric operating subsidiaries, shares in AEP's electric power transactions with other utility systems and power marketers. On January 1, 2002, customer choice of electricity supplier began in the Electric Reliability Council of Texas (ERCOT) area of Texas. TNC operates in both the ERCOT and Southwest Power Pool (SPP) regions of Texas, with the majority of its operations being in the ERCOT territory. Under the Texas Restructuring Legislation, each electric utility was required to submit a plan to structurally unbundle its business into an affiliated REP, a power generator, and a transmission and distribution utility. During the year 2000, TNC submitted a plan for separation that was subsequently approved by the PUCT. TNC has functionally separated its generation from its transmission and distribution operations and AEP formed a separate affiliated REP. Pending regulatory approval, TNC anticipates legally separating its generation from its transmission and distribution operations (see Note 8). The affiliated REP, a separate legal entity that was an AEP subsidiary (not owned by or consolidated with TNC) was sold in December 2002 (see Note 12). Since the affiliated REP is the electricity supplier to retail customers in the ERCOT area, TNC sells its generation to the affiliated REP and other market participants and provides transmission and distribution services to retail customers of the REPs in the TNC service territory. As a result of the formation of the affiliated REP, effective January 1, 2002, TNC no longer supplies electricity directly to retail customers. The implementation of REPs as suppliers to retail customers has caused a significant shift in TNC's sales as described below under "Results of Operations." In December 2002, AEP sold the affiliated REP to an unrelated third party, who assumed the obligations of the affiliated REP under the Texas Restructuring Legislation (see Note 12). Prior to the sale, during 2002, sales to the affiliated REP were classified as Sales to AEP Affiliates. Subsequent to the sale, transactions with the REP will be classified as Wholesale Electricity or Energy Delivery. Results of Operations - --------------------- In 2002, Net Income decreased $26.0 million or 211% primarily due to a $38.1 million long-lived asset impairment charge ($24.8 million net of tax) related to the inactivation of inefficient gas fired plants (see Note 13) and a $4.7 million impairment charge ($3.1 million net of tax) related to the abandonment of a wind-powered generation facility (see Note 13). Changes in Operating Revenues - ----------------------------- Increase (Decrease) From Previous Year -------------------------------------- (in millions) % Wholesale Electricity* $(231.7) (63) Energy Delivery* (95.7) (57) Sales to AEP Affiliates 221.7 N.M. ------- Total $(105.7) (19) ======= *Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery. N.M. = Not Meaningful Wholesale Electricity revenues decreased as a result of the elimination of TNC's retail electricity sales in the ERCOT region as of January 1, 2002 and a decrease in wholesale power marketing margins, partially offset by the ICR adjustments (see Note 6). Sales to AEP Affiliates increased primarily due to increased revenues from the newly created affiliated REP. Although TNC sold electricity to the affiliated REP instead of directly to retail customers in the ERCOT region, total revenues decreased due to lower prices for power sold to the affiliated REP. Additionally, delivery charges provided to the affiliated REP in 2002 are classified as Sales to AEP Affiliates in 2002, whereas in 2001 they were classified as Energy Delivery revenue. Changes in Operating Expenses - ----------------------------- Increase (Decrease) From Previous Year -------------------------------------- (in millions) % Fuel $(76.7) (43) Purchased Power: Wholesale Electricity 10.0 14 AEP Affiliates (19.1) (34) Other Operation (6.3) (6) Asset Impairments 42.9 N.M. Maintenance - - Depreciation and Amortization (7.1) (14) Taxes Other Than Income Taxes (5.8) (21) Income Taxes (18.1) N.M. ----- Total $(80.2) (15) ====== N.M. = Not Meaningful Fuel expense decreased due to a decrease in the average unit cost of fuel and decreased generation required due to decreased energy sales. TNC used natural gas as fuel for 42% of its generation in 2002. 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 TNC's fuel expense; however, they generally did not impact results of operations in 2001 due to fuel recovery mechanisms, which are no longer in place beginning with deregulation in 2002. The net decline in total Purchased Power expense in 2002 was mainly due to both reduced MWHs purchased and reduced prices, partially offset by ICR adjustments (see Note 6). Other Operation expense decreased slightly in 2002 due to lower factoring and transmission expenses, offset in part by a $1.4 million write-down of material and supply inventory associated with the impaired plants. As a result of TNC's recent ability to purchase electricity at a significantly lower price than its current cost to generate electricity, TNC proposed in September 2002 to "inactivate" various, high-cost gas fired generating facilities. TNC recorded an impairment charge in the third quarter 2002 of approximately $34.2 million related to these plants, which was recorded in Asset Impairments expense. In the fourth quarter 2002, an additional asset impairments charge of $3.9 million was also recorded in connection with these plants, along with a $4.7 million charge for a wind-powered generation facility (see Note 13). Additionally, a $1.2 million charge associated with fuel inventory (recorded in Fuel) and a $1.4 million charge associated with materials and supplies (recorded in Other Operations) was recorded in the fourth quarter of 2002 related to the "inactivated" plants. Depreciation and Amortization expense decreased due to the elimination in 2002 of excess earnings expense under Texas Restructuring Legislation and the elimination of regulatory asset amortization that ended in 2001. The decrease in Taxes Other Than Income Taxes is primarily a result of one time 2001 assessments and a decrease in the gross receipts tax due to deregulation. The decrease in Income Taxes is primarily a result of a decrease in pre-tax income resulting from the impairment of various generating facilities. Other Changes Nonoperating Income and Nonoperating Expenses increased significantly as a result of increased non-utility revenue and expenses associated with energy related construction projects for third parties, offset in part by decreased interest income. The revenues associated with the aforementioned energy related construction projects included in Nonoperating Income increased $45.5 million in 2002. The expenses associated with these projects included in Nonoperating Expenses increased $43.0 million in 2002. Interest Charges declined primarily due to lower interest rates.
AEP TEXAS NORTH COMPANY Statements of Operations - ------------------------ Year Ended December 31, ------------------------------------------------------- 2002 2001 2000 ---- ---- ---- (in thousands) OPERATING REVENUES: Wholesale Electricity $136,962 $368,741 $376,206 Energy Delivery 73,353 169,036 176,204 Sales to AEP Affiliates 240,425 18,681 18,654 -------- -------- -------- TOTAL OPERATING REVENUES 450,740 556,458 571,064 -------- -------- -------- OPERATING EXPENSES: Fuel 100,466 177,140 183,154 Purchased Power: Wholesale Electricity 80,391 70,395 68,080 AEP Affiliates 37,582 56,656 57,773 Other Operation 104,960 111,248 93,078 Asset Impairments 42,898 - - Maintenance 22,295 22,343 21,241 Depreciation and Amortization 43,620 50,705 55,172 Taxes Other Than Income Taxes 22,471 28,319 25,321 Income Tax Expense (Credit) (11,814) 6,262 14,904 -------- -------- -------- TOTAL OPERATING EXPENSES 442,869 523,068 518,723 -------- -------- -------- OPERATING INCOME 7,871 33,390 52,341 NONOPERATING INCOME 53,763 12,199 9,530 NONOPERATING EXPENSES 54,755 10,695 12,664 NONOPERATING INCOME TAX CREDIT (289) (691) (1,459) INTEREST CHARGES 20,845 23,275 23,216 -------- -------- -------- NET INCOME (LOSS) (13,677) 12,310 27,450 PREFERRED STOCK DIVIDEND REQUIREMENTS 104 104 104 -------- -------- -------- EARNINGS (LOSS) APPLICABLE TO COMMON STOCK $(13,781) $ 12,206 $ 27,346 ======== ======== ======== Statements of Comprehensive Income Year Ended December 31, ---------------------------------------------- 2002 2001 2000 ---- ---- ---- NET INCOME (LOSS) $(13,677) $12,310 $27,450 OTHER COMPREHENSIVE INCOME (LOSS): Cash Flow Power Hedges (15) - - Minimum Pension Liability (30,748) - - -------- ------- ------- COMPREHENSIVE INCOME (LOSS) $(44,440) $12,310 $27,450 ======== ======= ======= The common stock of TNC is owned by a wholly owned subsidiary of AEP. See notes to Financial Statements beginning on page L-1.
AEP TEXAS NORTH COMPANY Statements of Retained Earnings - ------------------------------- Year Ended December 31, ---------------------------------------------- 2002 2001 2000 ---- ---- ---- (in thousands) BEGINNING OF PERIOD $105,970 $122,588 $113,242 NET INCOME (LOSS) (13,677) 12,310 27,450 DEDUCTIONS: Cash Dividends Declared: Common Stock 20,247 28,824 18,000 Preferred Stock 104 104 104 -------- -------- -------- BALANCE AT END OF PERIOD $ 71,942 $105,970 $122,588 ======== ======== ======== The common stock of TNC is owned by a wholly owned subsidiary of AEP. See notes to Financial Statements beginning on page L-1.
AEP TEXAS NORTH COMPANY Balance Sheets - -------------- December 31, 2002 2001 ---- ---- (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production $ 353,087 $ 443,508 Transmission 254,483 250,023 Distribution 445,486 431,969 General 111,679 112,797 Construction Work in Progress 37,012 22,575 ---------- ---------- Total Electric Utility Plant 1,201,747 1,260,872 Accumulated Depreciation and Amortization 521,792 546,162 ---------- ---------- NET ELECTRIC UTILITY PLANT 679,955 714,710 ---------- ---------- OTHER PROPERTY AND INVESTMENTS 1,213 24,933 ---------- ---------- LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 2,248 8,327 ---------- ---------- CURRENT ASSETS: Cash and Cash Equivalents 1,219 2,454 Accounts Receivable: Customers 62,660 18,720 Affiliated Companies 43,632 8,656 Allowance for Uncollectible Accounts (5,041) (196) Fuel Inventory 12,677 8,307 Materials and Supplies 9,574 11,190 Accrued Utility Revenues 6,829 - Energy Trading and Derivative Contracts 4,130 10,240 Prepayments and Other 1,070 966 ---------- ---------- TOTAL CURRENT ASSETS 136,750 60,337 ---------- ---------- REGULATORY ASSETS 45,097 54,122 ---------- ---------- DEFERRED CHARGES 11,912 2,446 ---------- ---------- TOTAL ASSETS $ 877,175 $ 864,875 ========== ========== See Notes to Financial Statements beginning on page L-1.
AEP TEXAS NORTH COMPANY December 31, 2002 2001 ---- ---- (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 2,351 2,351 Accumulated Other Comprehensive Income (Loss) (30,763) - Retained Earnings 71,942 105,970 -------- -------- Total Common Shareholder's Equity 180,744 245,535 Cumulative Preferred Stock Not Subject to Mandatory Redemption 2,367 2,367 Long-term Debt 132,500 220,967 -------- -------- TOTAL CAPITALIZATION 315,611 468,869 -------- -------- OTHER NONCURRENT LIABILITIES 28,861 6,296 -------- -------- CURRENT LIABILITIES: Short-term Debt - Affiliates 125,000 - Long-term Debt Due Within One Year - 35,000 Advances from Affiliates 80,407 50,448 Accounts Payable - General 32,714 33,782 Accounts Payable - Affiliated Companies 76,217 11,388 Customer Deposits 117 4,191 Taxes Accrued 3,697 17,358 Interest Accrued 2,776 4,762 Energy Trading and Derivative Contracts 3,801 12,402 Other 17,414 9,824 -------- -------- TOTAL CURRENT LIABILITIES 342,143 179,155 -------- -------- DEFERRED INCOME TAXES 117,521 145,049 -------- -------- DEFERRED INVESTMENT TAX CREDITS 21,510 22,781 -------- -------- LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 557 5,250 -------- -------- REGULATORY LIABILITIES AND DEFERRED CREDITS 50,972 37,475 -------- -------- COMMITMENTS AND CONTINGENCIES (Note 9) TOTAL CAPITALIZATION AND LIABILITIES $877,175 $864,875 ======== ======== See Notes to Financial Statements beginning on page L-1.
AEP TEXAS NORTH COMPANY Statements of Cash Flows ------------------------ Year Ended December 31, ---------------------------------------------- 2002 2001 2000 ---- ---- ---- (in thousands) OPERATING ACTIVITIES: Net Income (Loss) $(13,677) $ 12,310 $ 27,450 Adjustments to Reconcile Net Income to Net Cash Flows From Operating Activities: Depreciation and Amortization 43,620 50,705 55,172 Writedown of Utility Assets 38,154 - Writedown of Wind Farm Assets 4,744 - - Deferred Income Taxes (12,275) (11,891) 8,164 Deferred Investment Tax Credits (1,271) (1,271) (1,271) Mark-to-Market Energy Trading and Derivative Contracts (1,127) (3,506) 2,590 CHANGES IN CERTAIN CURRENT ASSETS AND LIABILITIES: Accounts Receivable (net) (74,071) 24,844 (1,445) Fuel, Materials and Supplies (2,754) 3,187 8,478 Accrued Utility Revenues (6,829) - - Accounts Payable 63,761 (42,604) 28,393 Taxes Accrued (13,661) (1,543) 6,443 Fuel Recovery 14,169 32,505 (53,841) Transmission Coordination Agreement Settlement - - 15,465 Change in Other Assets (16,928) (1,432) 2,549 Change in Other Liabilities 16,514 11,056 (3,869) -------- -------- -------- Net Cash Flows From Operating Activities 38,369 72,360 94,278 -------- -------- -------- INVESTING ACTIVITIES: Construction Expenditures (43,563) (39,662) (64,477) Sales Proceeds and Other 150 (127) - -------- -------- -------- Net Cash Used For Investing Activities (43,413) (39,789) (64,477) -------- -------- -------- FINANCING ACTIVITIES: Retirement of Long-term Debt (130,799) - (48,000) Change in Short-term Debt Affiliated (net) 125,000 - - Change in Advances from Affiliates (net) 29,959 (8,130) 37,170 Dividends Paid on Common Stock (20,247) (28,824) (18,000) Dividends Paid on Cumulative Preferred Stock (104) (104) (104) -------- -------- -------- Net Cash Flows From (Used For) Financing Activities 3,809 (37,058) (28,934) -------- -------- -------- Net Increase (Decrease) in Cash and Cash Equivalents (1,235) (4,487) 867 Cash and Cash Equivalents at Beginning of Period 2,454 6,941 6,074 -------- -------- -------- Cash and Cash Equivalents at End of Period $ 1,219 $2,454 $6,941 ======== ====== ====== Supplemental Disclosure: Cash paid (received) for interest net of capitalized amounts was $19,934,000 $19,279,000 and $19,088,000 and for income taxes was $15,544,000, $21,997,000 and ($906,000) in 2002, 2001 and 2000 respectively. See Notes to Financial Statements beginning on page L-1.
AEP TEXAS NORTH COMPANY Statements of Capitalization - ---------------------------- December 31, 2002 2001 ---- ---- (in thousands) COMMON SHAREHOLDER'S EQUITY $180,744 $245,535 -------- -------- PREFERRED STOCK: $100 par value - authorized shares 810,000 Call Price Shares December 31, Number of Shares Redeemed Outstanding Series 2002 Year Ended December 31, December 31, 2002 - ------ ------------ ---------------------------- ----------------- 2002 2001 2000 ---- ---- ---- Not Subject to Mandatory Redemption: 4.40% $107 - - 1 23,672 2,367 2,367 LONG-TERM DEBT (See Schedule of Long-term Debt): First Mortgage Bonds 88,190 211,657 Installment Purchase Contracts 44,310 44,310 Less Portion Due Within One Year - (35,000) -------- -------- Long-term Debt Excluding Portion Due Within One Year 132,500 220,967 -------- -------- TOTAL CAPITALIZATION $315,611 $468,869 ======== ======== See Notes to Financial Statements beginning on page L-1.
AEP TEXAS NORTH COMPANY Schedule of Long-term Debt - -------------------------- First mortgage bonds outstanding were as follows: December 31, ----------- 2002 2001 ---- ---- (in thousands) % Rate Due 6-7/8 2002 - October 1 $ - $ 35,000 7 2004 - October 1 18,469 40,000 6-1/8 2004 - February 1 24,036 40,000 6-3/8 2005 - October 1 37,609 72,000 7-3/4 2007 - June 1 8,151 25,000 Unamortized Discount (75) (343) ------- -------- $88,190 $211,657 First mortgage bonds are secured by a first mortgage lien on electric utility plant. The indenture, as supplemented, relating to the first mortgage bonds contains 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, ----------- 2002 2001 ---- ---- (in thousands) % Rate Due Red River Authority of Texas: 6.00 2020 - June 1 $44,310 $44,310 ======= ======= Under the terms of the installment purchase contracts, TNC is required to pay amounts sufficient to enable the payment of interest on and the principal of (at stated maturities and upon mandatory redemptions) related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants. At December 31, 2002, future annual long-term debt payments are as follows: Amount ------ (in thousands) 2003 $ - 2004 42,505 2005 37,609 2006 - 2007 8,151 Later Years 44,310 -------- Principal Amount 132,575 Less: Unamortized Discount (75) -------- Total $132,500 AEP TEXAS NORTH COMPANY Index to Combined Notes to Financial Statements - ----------------------------------------------- The notes to TNC'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 TNC. 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 4 Rate Matters Note 6 Effects of Regulation Note 7 Customer Choice and Industry Restructuring Note 8 Commitments and Contingencies Note 9 Guarantees Note 10 Sustained Earnings Improvement Initiative Note 11 Acquisitions, Dispositions and Discontinued Operations Note 12 Asset Imapairments and Investment Value Losses Note 13 Benefit Plans Note 14 Business Segments Note 16 Risk Management, Financial Instruments and Derivatives Note 17 Income Taxes Note 18 Leases Note 22 Lines of Credit and Sale of Receivables Note 23 Unaudited Quarterly Financial Information Note 24 Jointly Owned Electric Utility Plant Note 28 Related Party Transactions Note 29 INDEPENDENT AUDITORS' REPORT To the Shareholders and Board of Directors of AEP Texas North Company: We have audited the accompanying balance sheets and statements of capitalization of AEP Texas North Company as of December 31, 2002 and 2001, and the related statements of operations, retained earnings, comprehensive income, and cash flows for each of the three years in the period ended December 31, 2002. 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 Texas North Company as of December 31, 2002 and 2001, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. /s/ Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 APPALACHIAN POWER COMPANY AND SUBSIDIARIES
APPALACHIAN POWER COMPANY AND SUBSIDIARIES Selected Consolidated Financial Data - ------------------------------------ Year Ended December 31, ----------------------------------------------------------------------------------------- 2002 2001 2000 1999 1998 ---- ---- ---- ---- ---- (in thousands) INCOME STATEMENTS DATA: Operating Revenues $1,814,470 $1,784,259 $1,759,253 $1,586,050 $1,672,244 Operating Expenses 1,512,407 1,509,273 1,558,099 1,344,814 1,443,701 ---------- ---------- ---------- ---------- ---------- Operating Income 302,063 274,986 201,154 241,236 228,543 Nonoperating Items, Net 20,106 6,868 11,752 8,096 (8,301) Interest Charges 116,677 120,036 148,000 128,840 126,912 ---------- ---------- ---------- ---------- ----------- Income Before Extraordinary Item 205,492 161,818 64,906 120,492 93,330 Extraordinary Gain - - 8,938 - - ---------- ---------- ---------- ---------- ---------- Net Income 205,492 161,818 73,844 120,492 93,330 Preferred Stock Dividend Requirements 2,897 2,011 2,504 2,706 2,497 ---------- ---------- ---------- ---------- ---------- Earnings Applicable to Common Stock $ 202,595 $ 159,807 $ 71,340 $ 117,786 $ 90,833 =========== ========== ========== ========== ========== December 31, ------------------------------------------------------------------------------------------ 2002 2001 2000 1999 1998 ---- ---- ---- ---- ---- (in thousands) BALANCE SHEETS DATA: Electric Utility Plant $5,895,303 $5,664,657 $5,418,278 $5,262,951 $5,087,359 Accumulated Depreciation and Amortization 2,424,607 2,296,481 2,188,796 2,079,490 1,984,856 ---------- ---------- ---------- ---------- ---------- Net Electric Utility Plant $3,470,696 $3,368,176 $3,229,482 $3,183,461 $3,102,503 ========== ========== ========== ========== ========== Total Assets $4,627,847 $4,482,785 $6,572,595 $4,352,219 $4,047,038 ========== ========== ========== ========== ========== Common Stock and Paid-in Capital $977,700 $976,244 $975,676 $974,717 $924,091 Accumulated Other Comprehensive Income (Loss) (72,082) (340) - - - Retained Earnings 260,439 150,797 120,584 175,854 179,461 ---------- ---------- ---------- ---------- ---------- Total Common Shareholder's Equity $1,166,057 $1,126,701 $1,096,260 $1,150,571 $1,103,552 ========== ========== ========== ========== ========== Cumulative Preferred Stock: Not Subject to Mandatory Redemption $ 17,790 $ 17,790 $ 17,790 $ 18,491 $ 19,359 Subject to Mandatory Redemption 10,860 10,860 10,860 20,310 22,310 ---------- ---------- ---------- ---------- ----------- Total Cumulative Preferred Stock $ 28,650 $ 28,650 $ 28,650 $ 38,801 $ 41,669 ======== ========== ========== ========== ========== Long-term Debt (a) $1,893,861 $1,556,559 $1,605,818 $1,665,307 $1,552,455 ========== ========== ========== ========== ========== Obligations Under Capital Leases (a) $ 33,589 $ 46,285 $ 63,160 $ 64,645 $ 65,175 ========== ========== ======== ========== ========== Total Capitalization And Liabilities $4,627,847 $4,482,785 $6,572,595 $4,352,219 $4,047,038 ========== ========== ========== ========== ========== (a) Including portion due within one year.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES Management's Discussion and Analysis of Results of Operation ------------------------------------------------------------ APCo is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to 925,000 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. Results of Operations - --------------------- Net Income increased $44 million or 27% in 2002 due to higher retail sales resulting from increased generation, weather related electricity demands and reductions in Maintenance expense. Most significantly, the Mountainer, Amos and Glen Lyn plants, down for boiler maintenance in 2001, were back online in 2002 resulting in increased availability of generation and decreased maintenance expense. In addition, Nonoperating Income less Nonoperating Expenses increased $10 million as a result of a reduction in trading incentive compensation recorded in Nonoperating Expenses offset in part by decreased power trading gains recorded in Nonoperating 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. Also contributing to the increase in net income was growth in and strong performance by the wholesale electricity 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 - ------------------ Operating Revenues increased $30 million or 2% in 2002 as a result of weather related demand and increased generation resulting from availablility of plants previously down for maintenance coming back online. An increase of $25 million, or 1%, in 2001 Operating Revenues was attributable to an increase in AEP Power Pool transactions. Changes in components of revenues were as follows: Increase (Decrease) From Previous Year (dollars in millions) 2002 2001 --------------------------- Amount % Amount % ------ - ------ - Wholesale Electricity* $16.0 2 $(11.7) (1) Energy Delivery* (1.0) - 20.1 3 Sales to AEP Affiliates 15.2 9 16.6 11 ----- ------ Total Revenues $30.2 2 $ 25.0 1 ===== ====== *Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery. Operating Revenues for 2002 increased as a result of an increase in generation and availability at the Mountaineer, Amos and Glen Lyn plants; and increases in residential and commercial sales due to warmer weather during July and September. Sales to AEP affiliates increased for the year due to an increase in generation capacity and power available to be delivered to AEP Power Pool. These increases were partially offset by flat industrial sales as recessionary conditions continued into 2002. The year 2001 saw a decrease in kilowatt hour sales to industrial customers. This decrease was due to the economic recession. In the fourth quarter, sales to residential and commercial customers declined, reflecting recession-related reductions in demand. The increase in Sales to AEP Affiliates in 2001 is due to an 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. Operating Expenses - ------------------ Operating Expenses for 2002 were comparable to those of 2001. Increases in Fuel and Wholesale Electricity Purchased Power expenses were offset by decreases in power purchases from AEP Affiliates due to increases in APCo generation and availability as plants previously down for maintenance resumed operations. The decrease in operating expenses in 2001 of 3% is due to decreases in income taxes, other operation expense, fuel expense and taxes other than income taxes partially offset by increases in electricity purchased power expense and depreciation and amortization expenses. Changes in the components of Operating Expenses are as follows: Increase (Decrease) From Previous Year (dollars in millions) 2002 2001 ----------------------------- Amount % Amount % ------ - ------ - Fuel $ 79.4 23 $ (17.6) (5) Wholesale Electricity Purchases 15.0 36 17.4 70 AEP Affiliate Purchases (112.3) (32) (8.9) (3) Other Operation 8.9 3 (18.6) (7) Maintenance (10.2) (8) 7.9 6 Depreciation and Amortization 8.9 5 17.3 11 Taxes Other Than Income Taxes (4.6) (5) (11.8) (11) Income Taxes 18.0 19 (34.5) (27) ------- -------- Total $ 3.1 - $ (48.8) (3) ======= ======== Fuel expense increased for 2002 as a result of an increase in APCo generation. Mountaineer, Amos, and Glen Lyn plants had undergone boiler plant maintenance in 2001 which resulted in increased availability in 2002. The decrease in Fuel expense in 2001 is due to a decline in generation as a result of scheduled plant maintenance. Wholesale Electricity Purchases increased for 2002 as a result of increased purchases from third parties for resale to wholesale customers and to meet internal demand. Electricity purchased power expense increased in 2001 due to increases in wholesale electricity prices and as a result of the previously mentioned plant outages. The decrease for 2002 in Purchases from AEP Affiliates is a result of increased internal generation due to plant availability. 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. Other Operation expense increased in 2002 mainly due to severance expenses related to the sustained earnings initiative plan, a reduction in the gains recorded on the dispositions of SO2 emission allowances, and increased insurance premiums and other employee benefit costs. These increases were offset by reduced trading overhead expenses as a result of reduced staffing and weaker market conditions; a decrease in transmission equalization charges caused by a reduction in APCo's MLR ratio; and energy delivery severance accruals recorded in 2001 for which there was no comparable activity in 2002. 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 decrease in Maintenance expense in 2002 is primarily due to previously discussed boiler plant maintenance at Amos, Mountaineer and Glen Lyn plants in the year 2001. Depreciation and Amortization expense increased during 2002 due to increased amortization for the net generation-related regulatory assets related to the Company's West Virginia jurisdiction which were assigned to the distribution portion of the Company's business and are being recovered through regulated rates. Investment in production plant in service, primarily equipment related to emission control, contributed to the increase in depreciation and amortization expense. Depreciation and Amortization expense increased in 2001 due to accelerated amortization, beginning in July 2000, of the transition regulatory assets in the Virginia and West Virginia jurisdictions. Additional investments in distribution and transmission plant also contributed to the increases in depreciation and amortization expense in 2001. During June 2000 we discontinued the application of SFAS 71 in the Virginia and West Virginia jurisdictions. Consequently net generation-related regulatory assets were assigned to the energy delivery business's regulated distribution business where the Virginia and West Virginia jurisdictions authorized the recovery of these transition regulatory assets through regulated rates. The decrease in Taxes Other Than Income Taxes for the year 2002 is due primarily to a decrease in municipal license tax. The municipal license tax was replaced by the Virginia consumption tax. The municipal license tax was imposed on APCo and the Virginia consumption tax is imposed on the customer with APCo acting as collector agent. 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. The increase in Income Taxes for 2002 was due to an increase in pre-tax income. 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. Nonoperating Income and Nonoperating Expenses - --------------------------------------------- The Nonoperating Income decrease for 2002 was due primarily to a decrease in net power trading gains driven by a decline in market prices. Nonoperating Expenses decreased as a result of decreased trading incentives. The increase in Nonoperating Income and Nonoperating Expenses for 2001 is due to considerable increases in the level of activity in the wholesale business's trading transactions outside of the AEP System's traditional marketing area. Interest Charges - ---------------- Interest Charges for 2002 decreased primarily as a result of lower AEP money pool balances and interest rates and the retirement of first mortgage bonds in 2001. 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.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Income - --------------------------------- Year Ended December 31, --------------------------------------------------- 2002 2001 2000 ---- ---- ---- (in thousands) OPERATING REVENUES: Wholesale Electricity $1,033,904 $1,017,938 $1,029,657 Energy Delivery 594,089 595,036 574,918 Sales to AEP Affiliates 186,477 171,285 154,678 ---------- ---------- ---------- Total Operating Revenues 1,814,470 1,784,259 1,759,253 ---------- ---------- ---------- OPERATING EXPENSES: Fuel 430,963 351,557 369,161 Purchased Power: Wholesale Electricity 57,091 42,092 24,720 AEP Affiliates 234,597 346,878 355,774 Other Operation 269,426 260,518 279,114 Maintenance 122,209 132,373 124,493 Depreciation and Amortization 189,335 180,393 163,089 Taxes Other Than Income Taxes 95,249 99,878 111,692 Income Taxes 113,537 95,584 130,056 ---------- ---------- ---------- Total Operating Expenses 1,512,407 1,509,273 1,558,099 ---------- ---------- ---------- OPERATING INCOME 302,063 274,986 201,154 NONOPERATING INCOME 29,278 49,507 31,204 NONOPERATING EXPENSES 11,783 41,500 16,329 NONOPERATING INCOME TAX EXPENSE (BENEFIT) (2,611) 1,139 3,123 INTEREST CHARGES 116,677 120,036 148,000 ---------- ---------- ---------- INCOME BEFORE EXTRAORDINARY ITEM 205,492 161,818 64,906 EXTRAORDINARY GAIN - DISCONTINUANCE OF REGULATORY ACCOUNTING FOR GENERATION (Inclusive of Tax Benefit of $7,872,000) - - 8,938 ---------- ---------- ---------- NET INCOME 205,492 161,818 73,844 PREFERRED STOCK DIVIDEND REQUIREMENTS 2,897 2,011 2,504 ---------- ---------- ---------- EARNINGS APPLICABLE TO COMMON STOCK $202,595 $159,807 $ 71,340 ======== ======== ======== Consolidated Statements of Comprehensive Income Year Ended December 31, ------------------------------------------------ 2002 2001 2000 ---- ---- ---- (in thousands) NET INCOME $205,492 $161,818 $73,844 OTHER COMPREHENSIVE INCOME (LOSS) Foreign Currency Exchange Rate Hedge (1,580) (340) - Minimum Pension Liability (70,162) - - -------- -------- ------- COMPREHENSIVE INCOME $133,750 $161,478 $73,844 ======== ======== ======= See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Retained Earnings - -------------------------------------------- Year Ended December 31, --------------------------------------------------- 2002 2001 2000 ---- ---- ---- (in thousands) Retained Earnings January 1 $150,797 $120,584 $175,854 Net Income 205,492 161,818 73,844 -------- -------- -------- 356,289 282,402 249,698 -------- -------- -------- Deductions: Cash Dividends Declared: Common Stock 92,952 129,594 126,612 Cumulative Preferred Stock: 4-1/2% Series 801 801 811 5.90% Series 278 278 307 5.92% Series 364 364 364 6.85% Series - - 289 -------- -------- -------- Total Cash Dividends Declared 94,395 131,037 128,383 Capital Stock Expense 1,455 568 731 -------- -------- -------- Total Deductions 95,850 131,605 129,114 -------- -------- -------- Retained Earnings December 31 $260,439 $150,797 $120,584 ======== ======== ======== See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES Consolidated Balance Sheets - --------------------------- December 31, ------------------------------ 2002 2001 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production $2,245,945 $2,093,532 Transmission 1,218,108 1,222,226 Distribution 1,951,804 1,887,020 General 272,901 257,957 Construction Work in Progress 206,545 203,922 ---------- ---------- Total Electric Utility Plant 5,895,303 5,664,657 Accumulated Depreciation and Amortization 2,424,607 2,296,481 ---------- ---------- NET ELECTRIC UTILITY PLANT 3,470,696 3,368,176 ---------- ---------- OTHER PROPERTY AND INVESTMENTS 54,653 53,736 ---------- ---------- LONG-TERM ENERGY TRADING CONTRACTS 115,748 119,638 ---------- ---------- CURRENT ASSETS: Cash and Cash Equivalents 4,285 13,663 Accounts Receivable: Customers 132,266 113,371 Affiliated Companies 122,665 63,368 Miscellaneous 28,629 11,847 Allowance for Uncollectible Accounts (13,439) (1,877) Fuel Inventory 53,646 56,699 Materials and Supplies 59,886 59,849 Accrued Utility Revenues 30,948 30,907 Energy Trading and Derivative Contracts 94,238 137,742 Prepayments and Other 13,396 16,018 ---------- ---------- TOTAL CURRENT ASSETS 526,520 501,587 ---------- ---------- REGULATORY ASSETS 395,553 397,383 ---------- ---------- DEFERRED CHARGES 64,677 42,265 ---------- ---------- TOTAL ASSETS $4,627,847 $4,482,785 ========== ========== See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES December 31, ------------------------------- 2002 2001 ---- ---- (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 717,242 715,786 Accumulated Other Comprehensive Income (Loss) (72,082) (340) Retained Earnings 260,439 150,797 ---------- ---------- Total Common Shareowner's Equity 1,166,057 1,126,701 Cumulative Preferred Stock: Not Subject to Mandatory Redemption 17,790 17,790 Subject to Mandatory Redemption 10,860 10,860 Long-term Debt 1,738,854 1,476,552 ---------- ---------- TOTAL CAPITALIZATION 2,933,561 2,631,903 ---------- ---------- OTHER NONCURRENT LIABILITIES 173,438 84,104 ---------- ---------- CURRENT LIABILITIES: Long-term Debt Due Within One Year 155,007 80,007 Advances From Affiliates 39,205 291,817 Accounts Payable - General 141,546 127,597 Accounts Payable - Affiliated Companies 98,374 84,518 Taxes Accrued 29,181 55,583 Customer Deposits 26,186 13,177 Interest Accrued 22,437 21,770 Energy Trading and Derivative Contracts 69,001 121,161 Other 79,832 79,089 ---------- ---------- Total CURRENT LIABILITIES 660,769 874,719 ---------- ---------- DEFERRED INCOME TAXES 701,801 703,575 ---------- ---------- DEFERRED INVESTMENT TAX CREDITS 33,691 38,328 ---------- ---------- LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 44,517 60,518 ---------- ---------- REGULATORY LIABILITIES AND DEFERRED CREDITS 80,070 89,638 ---------- ---------- COMMITMENTS AND CONTINGENCIES (Note 9) TOTAL CAPITALIZATION AND LIABILITIES $4,627,847 $4,482,785 ========== ========== See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Cash Flows - ------------------------------------- Year Ended December 31, ----------------------------------------------- 2002 2001 2000 ---- ---- ---- (in thousands) OPERATING ACTIVITIES: Net Income $ 205,492 $ 161,818 $73,844 Adjustments for Noncash Items: Depreciation and Amortization 189,335 180,505 163,202 Deferred Income Taxes 16,777 42,498 8,602 Deferred Investment Tax Credits (4,637) (4,765) (4,915) Deferred Power Supply Costs (net) 6,365 1,411 (84,408) Mark-to-Market of Energy Trading Contracts (21,151) (68,254) (1,843) Provision for Rate Refunds - - (4,818) Extraordinary Gain - - (8,938) Change in Certain Current Assets and Liabilities: Accounts Receivable (net) (83,412) 134,099 (166,911) Fuel, Materials and Supplies 3,016 (19,957) 18,487 Accrued Utility Revenues (41) 35,592 (13,081) Accounts Payable 27,805 (45,073) 159,369 Taxes Accrued (26,402) (7,675) 14,220 Revenue Refunds Accrued - - 181 Incentive Plan Accrued (858) (2,451) 10,662 Disputed Tax and Interest Related to COLI - - 72,440 Change in Operating Reserves (3,190) (5,358) (19,770) Rate Stabilization Deferral - - 75,601 Change in Other Assets (43,337) 19,418 (13,021) Change in Other Liabilities 14,948 (27,954) 9,817 --------- --------- --------- Net Cash Flows From Operating Activities 280,710 393,854 288,720 --------- --------- --------- INVESTING ACTIVITIES: Construction Expenditures (276,549) (306,046) (199,285) Proceeds From Sales of Property and Other 1,074 1,182 159 Net Cost of Removal and Other - (8,434) (7,500) --------- --------- --------- Net Cash Flows Used For Investing Activities (275,475) (313,298) (206,626) --------- --------- --------- FINANCING ACTIVITIES: Issuance of Long-term Debt 647,401 124,588 74,788 Retirement of Cumulative Preferred Stock - - (9,924) Retirement of Long-term Debt (315,007) (175,000) (136,166) Change in Short-term Debt (net) - (191,495) 68,015 Change in Advances From Affiliates (252,612) 300,204 (8,387) Dividends Paid on Common Stock (92,952) (129,594) (126,612) Dividends Paid on Cumulative Preferred Stock (1,443) (1,443) (1,938) --------- --------- --------- Net Cash Flows Used For Financing Activities (14,613) (72,740) (140,224) --------- --------- --------- Net Increase (Decrease) in Cash and Cash Equivalents (9,378) 7,816 (58,130) Cash and Cash Equivalents January 1 13,663 5,847 63,977 --------- --------- --------- Cash and Cash Equivalents December 31 $ 4,285 $13,663 $ 5,847 ========= ======= ======= Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $111,528,000, $117,283,000 and $124,579,000 and for income taxes was $125,120,000, $56,981,000 and $63,682,000 in 2002, 2001 and 2000, respectively. There were no noncash acquisitions under capital leases in 2002. In 2001 and 2000, non cash acquisitions under capital leases were $2,510,000 and $14,116,000, respectively. See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Capitalization - ----------------------------------------- December 31, ----------- 2002 2001 ---- ---- (in thousands) COMMON SHAREHOLDER'S EQUITY $1,166,057 $1,126,701 ---------- ---------- PREFERRED STOCK: No par value - authorized shares 8,000,000 Call Price Shares December 31, Number of Shares Redeemed Outstanding Series 2002 (a) Year Ended December 31, December 31, 2002 - ------ ------------ ---------------------------- ----------------- 2002 2001 2000 ---- ---- ---- Not Subject to Mandatory Redemption (b): 4-1/2% $110 6 - 7,011 177,899 17,790 17,790 ---------- ---------- Subject to Mandatory Redemption (b): 5.90% (c) - - 10,000 47,100 4,710 4,710 5.92% (c) - - - 61,500 6,150 6,150 ---------- ---------- 10,860 10,860 ---------- ---------- LONG-TERM DEBT (See Schedule of Long-term Debt): First Mortgage Bonds 489,697 639,365 Installment Purchase Contracts 235,027 234,904 Senior Unsecured Notes 1,166,609 518,247 Junior Debentures - 161,507 Other Long-term Debt 2,528 2,536 Less Portion Due Within One Year (155,007) (80,007) ---------- ---------- Long-term Debt Excluding Portion Due Within One Year 1,738,854 1,476,552 ---------- ---------- TOTAL CAPITALIZATION $2,933,561 $2,631,903 ========== ========== (a) 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. (b) The sinking fund provisions of each series subject to mandatory redemption have been met by shares purchased in advance of the due date. (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 redeemed in 2008. Shares previously redeemed may be applied to meet the sinking fund requirement. 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, ----------- 2002 2001 ---- ---- (in thousands) % Rate Due 7.38 2002 - August 15 $ - $ 50,000 7.40 2002 - December 1 - 30,000 6.65 2003 - May 1 - 40,000 6.85 2003 - June 1 - 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 (1,540) (1,872) -------- -------- Total $489,697 $639,365 ======== ======== First mortgage bonds are secured by a first mortgage lien on electric utility plant. Certain supplemental indentures to the first mortgage lien contain 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, ----------- 2002 2001 ---- ---- (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 (1,973) (2,096) -------- -------- Total $235,027 $234,904 ======== ======== 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 of (at stated maturities and upon mandatory redemptions) 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, ----------- 2002 2001 ---- ---- (in thousands) % Rate Due (a) 2003 - August 20 $ 125,000 $125,000 7.45 2004 - November 1 50,000 50,000 4.80 2005 - June 15 450,000 - 4.32 2007 - November 12 200,000 - 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 (8,391) (6,753) Total $1,166,609 $518,247 ========== ======== (a) A floating interest rate is determined monthly. The rate on December 31, 2002 and 2001 was 2.167% and 2.839%, respectively. Junior debentures outstanding were as follows: December 31, ----------- 2002 2001 ---- ---- (in thousands) 8-1/4% Series A due 2026 - September 30 $ - $ 75,000 8% Series B due 2027 - March 31 - 90,000 Unamortized Discount - (3,493) -------- -------- Total $ - $161,507 ======== ======== At December 31, 2002, future annual long-term debt payments are as follows: Amount ------ (in thousands) 2003 $ 155,007 2004 121,008 2005 530,010 2006 100,011 2007 217,513 Later Years 782,216 ---------- Total Principal Amount 1,905,765 Unamortized Discount (11,904) ---------- Total $1,893,861 ========== APPALACHIAN POWER COMPANY AND SUBSIDIARIES Index to Combined Notes to Consolidated Financial Statements - ------------------------------------------------------------ The notes to APCo's consolidated 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 Effects of Regulation Note 7 Customer Choice and Industry Restructuring Note 8 Commitments and Contingencies Note 9 Guarantees Note 10 Sustained Earnings Improvement Initiative Note 11 Asset Impairments and Investments Value Losses Note 13 Benefit Plans Note 14 Business Segments Note 16 Risk Management, Financial Instruments and Derivatives Note 17 Income Taxes Note 18 Supplementary Information Note 20 Leases Note 22 Lines of Credit and Sale of Receivables Note 23 Unaudited Quarterly Financial Information Note 24 Related Party Transactions Note 29 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 subsidiaries as of December 31, 2002 and 2001, 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, 2002. 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 subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. /s/ Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Selected Consolidated Financial Data - ------------------------------------ Year Ended December 31, -------------------------------------------------------------------------------------- 2002 2001 2000 1999 1998 ---- ---- ---- ---- ---- (in thousands) INCOME STATEMENTS DATA: Operating Revenues $1,400,160 $1,350,319 $1,304,409 $1,190,997 $1,187,745 Operating Expenses 1,180,381 1,098,142 1,108,532 968,207 975,534 ---------- ---------- ---------- ---------- ---------- Operating Income 219,779 252,177 195,877 222,790 212,211 Nonoperating Items, Net 15,263 7,738 5,153 2,709 (1,343) Interest Charges 53,869 68,015 80,828 75,229 77,824 ---------- ---------- --------- ---------- ---------- Income Before Extraordinary Item 181,173 191,900 120,202 150,270 133,044 Extraordinary Loss - (30,024) (25,236) - - ---------- ---------- --------- ---------- ---------- Net Income 181,173 161,876 94,966 150,270 133,044 Preferred Stock Dividend Requirements 1,332 1,095 1,783 2,131 2,131 ---------- ---------- --------- ---------- ---------- Earnings Applicable to Common Stock $179,841 $160,781 $93,183 $148,139 $130,913 ======== ======== ======= ======== ======== Year Ended December 31, -------------------------------------------------------------------------------------- 2002 2001 2000 1999 1998 ---- ---- ---- ---- ---- (in thousands) BALANCE SHEETS DATA: Electric Utility Plant $3,467,626 $3,354,320 $3,266,794 $3,151,619 $3,053,565 Accumulated Depreciation 1,465,174 1,377,032 1,299,697 1,210,994 1,134,348 ---------- ---------- ---------- ---------- ---------- Net Electric Utility Plant $2,002,452 $1,977,288 $1,967,097 $1,940,625 $1,919,217 ========== ========== ========== ========== ========== Total Assets $2,753,240 $2,722,388 $3,877,491 $2,808,623 $2,681,690 ========== ========== ========== ========== ========== Common Stock and Paid-in Capital $616,410 $615,395 $614,380 $613,899 $613,518 Accumulated Other Comprehensive Income (Loss) (59,357) - - - - Retained Earnings 290,611 176,103 99,069 246,584 186,441 ---------- ---------- ---------- ---------- ---------- Total Common Shareholder's Equity $847,664 $791,498 $713,449 $860,483 $799,959 ======== ======== ======== ======== ======== Cumulative Preferred Stock - Subject to Mandatory Redemption (a) $ - $ 10,000 $ 15,000 $ 25,000 $ 25,000 ======== ======== ======== ======== ======== Long-term Debt (a) $621,626 $791,848 $899,615 $924,545 $959,786 ======== ======== ======== ======== ======== Obligations Under Capital Leases (a) $ 27,610 $ 34,887 $ 42,932 $ 40,270 $ 42,362 ======== ======== ======== ======== ======== Total Capitalization and Liabilities $2,753,240 $2,722,388 $3,877,491 $2,808,623 $2,681,690 ========== ========== ========== ========== ========== (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 689,000 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 companies percentage share of AEP Power Pool revenues and costs. Results of Operations - --------------------- Net Income increased $19 million or 12% in 2002 due to reduced interest charges and a $30 million extraordinary loss recorded in 2001 to recognize prepaid Ohio excise taxes stranded by Ohio deregulation offset by higher operating expenses. Operating Revenues - ------------------ Operating Revenues increased in 2002 mainly as a result of increased residential and commercial sales due to demand caused by weather conditions. Changes in the components of Operating Revenues were: Increase (Decrease) From Previous Year ------------------ (dollars in millions) Amount % ------ - Retail* $51 8 Wholesale Marketing 3 2 Unrealized MTM (4) (22) Other 1 3 --- Wholesale Electricity* 51 6 Energy Delivery* 9 2 Sales to AEP Affiliates (10) (15) ---- Total Revenues $50 4 === * Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery. During the summer months, cooling degree days increased 35%. For the fall season, heating degree days increased 34%. This reflects a return to more normal weather conditions since the weather experienced in 2001 was abnormally mild. Operating Expenses - ------------------ Operating Expenses increased in 2002 mainly as a result of purchased power, operating expenses and state taxes. Changes in the components of Operating Expenses were: Increase (Decrease) From Previous Year ------------------ (dollars in millions) Amount % ------ - Fuel $10 6 Wholesale Purchased Power 4 37 AEP Affiliates Purchased Power 18 6 Other Operation Expenses 18 8 Maintenance Expense (2) (4) Depreciation and Amortization 4 3 Taxes Other Than Income Taxes 25 22 Income Taxes 5 5 --- Total $82 7 === Fuel cost increased as a result of a 10% increase in generation partially offset by a slight cost decrease per ton of coal consumed. Wholesale Purchased Power increased in 2002 due to increased purchases from third parties for resale to wholesale customers and to meet internal demand. Expenses related to AEP Affiliates Purchased Power increased due to greater system pool capacity charges. The increase in Other Operation expenses was attributable to a number of factors: higher OPEB post retirement costs as a result of higher medical cost and lower investment performance, 2002 Sustained Earnings Initiative Expenses, and the 2001 reversal of a quality of service liability accrual. The increase was partially offset by a reduction in energy trading overheads reflecting reduced marketing activity. The increase in Taxes Other Than Income Taxes in 2002 is due to an increase in property taxes and a full year of the state excise tax which replaced the state gross receipts tax during 2001. The increase in Income Taxes is predominately due to an increase in state taxes as a result of the State of Ohio's tax legislation resulting from utility deregulation. This increase was offset in part by a decrease in federal taxes due to a decrease in pre-tax operating income. Nonoperating Income and Nonoperating Expense - -------------------------------------------- The decrease in Nonoperating Income in 2002 is due to a reduction in net gains from AEP Power Pool trading transactions outside of the AEP System's traditional marketing area. The AEP Power Pool enters into power trading transactions for the purchase and sale of electricity and for options, futures and swaps. CSPCo's share of the AEP Power Pool's gains and losses from forward electricity trading transactions outside of the AEP System traditional marketing area and for speculative financial transactions (options, futures, swaps) is included in Nonoperating Income. The decrease reflects a reduction in electricity prices and margins due to a decrease in demand. The decrease in Nonoperating Expenses in 2002 was due to a decrease in energy trading incentive compensation. Nonoperating Income Tax Expense increased in 2002 due to increase in pre-tax nonoperating income. Interest Charges - ---------------- Interest Charges decreased in 2002 primarily due to a decrease in the outstanding balance of long-term debt since the first quarter of 2001, the refinancing of debt at favorable interest rates and a reduction in short-term interest rates.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Income - --------------------------------- Year Ended December 31, --------------------------------------------------- 2002 2001 2000 ---- ---- ---- OPERATING REVENUES: Wholesale Electricity $ 850,680 $ 799,589 $ 856,998 Energy Delivery 492,278 483,219 398,046 Sales to AEP Affiliates 57,202 67,511 49,365 ---------- ---------- ---------- Total Operating Revenues 1,400,160 1,350,319 1,304,409 ---------- ---------- ---------- OPERATING EXPENSES: Fuel 185,086 175,153 189,155 Purchased Power: Wholesale Electricity 15,023 10,957 9,879 AEP Affiliates 310,605 292,199 287,750 Other Operation 237,802 219,497 219,840 Maintenance 60,003 62,454 69,676 Depreciation and Amortization 131,624 127,364 99,640 Taxes Other Than Income Taxes 136,024 111,481 123,223 Income Taxes 104,214 99,037 109,369 ---------- ---------- ---------- TOTAL OPERATING EXPENSES 1,180,381 1,098,142 1,108,532 ---------- ---------- ---------- OPERATING INCOME 219,779 252,177 195,877 NONOPERATING INCOME 26,360 32,756 20,580 NONOPERATING EXPENSES 4,308 21,095 8,070 NONOPERATING INCOME TAX EXPENSE 6,789 3,923 7,357 INTEREST CHARGES 53,869 68,015 80,828 ---------- ---------- ---------- INCOME BEFORE EXTRAORDINARY ITEM 181,173 191,900 120,202 EXTRAORDINARY LOSS - DISCONTINUANCE OF REGULATORY ACCOUNTING FOR GENERATION - Net of tax (Note 2) - (30,024) (25,236) ---------- ---------- ---------- NET INCOME 181,173 161,876 94,966 PREFERRED STOCK DIVIDEND REQUIREMENTS 1,332 1,095 1,783 ---------- ---------- ---------- EARNINGS APPLICABLE TO COMMON STOCK $179,841 $160,781 $ 93,183 ======== ======== ======== Consolidated Statements of Comprehensive Income - ----------------------------------------------- Year Ended December 31, ------------------------------------------------- 2002 2001 2000 ---- ---- ---- NET INCOME $181,173 $161,876 $94,966 OTHER COMPREHENSIVE INCOME (LOSS) Foreign Currency Exchange Rate Hedge (267) - - Minimum Pension Liability (59,090) - - -------- -------- ------- COMPREHENSIVE INCOME $121,816 $161,876 $94,966 ======== ======== ======= The common stock of the CSPCo is wholly owned by AEP. See Notes to Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Retained Earnings - -------------------------------------------- Year Ended December 31, -------------------------------------------------- 2002 2001 2000 ---- ---- ---- (in thousands) Retained Earnings January 1 $176,103 $ 99,069 $246,584 Net Income 181,173 161,876 94,966 -------- -------- -------- 357,276 260,945 341,550 -------- -------- -------- Deductions: Cash Dividends Declared: Common Stock 65,300 82,952 240,600 Cumulative Preferred Stock - 7% Series 350 875 1,400 -------- -------- -------- Total Cash Dividends Declared 65,650 83,827 242,000 Capital Stock Expense 1,015 1,015 481 -------- -------- -------- Total Deductions 66,665 84,842 242,481 -------- -------- -------- Retained Earnings December 31 $290,611 $176,103 $ 99,069 ======== ======== ======== See Notes to Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Consolidated Balance Sheets - --------------------------- December 31, ----------- 2002 2001 ---- ---- (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production $1,582,627 $1,574,506 Transmission 413,286 401,405 Distribution 1,208,255 1,159,105 General 165,025 146,732 Construction Work in Progress 98,433 72,572 ---------- ---------- Total Electric Utility Plant 3,467,626 3,354,320 Accumulated Depreciation 1,465,174 1,377,032 ---------- ---------- NET ELECTRIC UTILITY PLANT 2,002,452 1,977,288 ---------- ---------- OTHER PROPERTY AND INVESTMENTS 35,759 40,369 ---------- ---------- LONG-TERM ENERGY TRADING CONTRACTS 77,810 73,310 ---------- ---------- CURRENT ASSETS: Cash and Cash Equivalents 1,479 12,358 Advances to Affiliates 31,257 - Accounts Receivable: Customers 49,566 41,770 Affiliated Companies 54,518 63,470 Miscellaneous 22,005 16,968 Allowance for Uncollectible Accounts (634) (745) Fuel 24,844 20,019 Materials and Supplies 40,339 38,984 Accrued Utility Revenues 12,671 7,087 Energy Trading Contracts 63,348 84,323 Prepayments and Other Current Assets 7,308 28,733 ---------- ---------- TOTAL CURRENT ASSETS 306,701 312,967 ---------- ---------- REGULATORY ASSETS 257,682 262,267 ---------- ---------- DEFERRED CHARGES 72,836 56,187 ---------- ---------- TOTAL ASSETS $2,753,240 $2,722,388 ========== ========== See Notes to Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES December 31, ----------- 2002 2001 ---- ---- (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 575,384 574,369 Accumulated Other Comprehensive Income (Loss) (59,357) - Retained Earnings 290,611 176,103 ---------- ---------- Total Common Shareholder's Equity 847,664 791,498 Cumulative Preferred Stock - Subject to Mandatory Redemption - 10,000 Long-term Debt - General 418,626 571,348 Long term Debt - Affiliated Companies 160,000 - ---------- ---------- TOTAL CAPITALIZATION 1,426,290 1,372,846 ---------- ---------- OTHER NONCURRENT LIABILITIES 95,460 36,715 ---------- ---------- CURRENT LIABILITIES: Long-term Debt Due Within One Year - General 43,000 20,500 Long-term Debt Due Within One Year - Affiliated Companies - 200,000 Short-term Debt - Affiliated Companies 290,000 - Advances from Affiliates - 181,384 Accounts Payable - General 89,736 60,689 Accounts Payable - Affiliated Companies 81,599 83,697 Taxes Accrued 112,172 116,364 Interest Accrued 9,798 10,907 Energy Trading Contracts 46,375 72,082 Other 36,790 36,305 ---------- ---------- TOTAL CURRENT LIABILITIES 709,470 781,928 ---------- ---------- DEFERRED INCOME TAXES 437,771 443,722 ---------- ---------- DEFERRED INVESTMENT TAX CREDITS 33,907 37,176 ---------- ---------- LONG-TERM ENERGY TRADING CONTRACTS 29,926 37,101 ---------- ---------- DEFERRED CREDITS 20,416 12,900 ---------- ---------- COMMITMENTS AND CONTINGENCIES (Note 9) TOTAL CAPITALIZATION AND LIABILITIES $2,753,240 $2,722,388 ========== ========== See Notes to Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Cash Flows - ------------------------------------- Year Ended December 31, ----------------------------------------------- 2002 2001 2000 ---- ---- ---- (in thousands) OPERATING ACTIVITIES: Net Income $ 181,173 $ 161,876 $ 94,966 Adjustments for Noncash Items: Depreciation and Amortization 131,753 128,500 100,182 Deferred Income Taxes 23,292 24,108 (4,063) Deferred Investment Tax Credits (3,269) (4,058) (3,482) Deferred Fuel Costs (net) - - 5,352 Mark to Market of Energy Trading Contracts (16,667) (44,680) (3,393) Extraordinary Loss - 30,024 25,236 Change in Certain Current Assets and Liabilities: Accounts Receivable (net) (3,992) 19,987 (29,737) Fuel, Materials and Supplies (6,180) (7,780) 11,957 Accrued Utility Revenues (5,584) 2,551 38,479 Accounts Payable 26,949 (16,249) 81,284 Disputed Tax and Interest Related to COLI - - 39,483 Change in Other Assets (8,027) (42,066) (121,115) Change in Other Liabilities (22,448) (18,769) 132,441 --------- --------- --------- Net Cash Flows From Operating Activities 297,000 233,444 367,590 --------- --------- --------- INVESTING ACTIVITIES: Construction Expenditures (136,800) (132,532) (127,987) Proceeds From Sales and Leaseback Transactions and Other 730 10,841 1,560 --------- --------- --------- Net Cash Flows Used For Investing Activities (136,070) (121,691) (126,427) --------- --------- --------- FINANCING ACTIVITIES: Change in Advances from Affiliates (net) (212,641) 92,652 88,732 Issuance of Affiliated Long-term Debt 160,000 200,000 - Retirement of Preferred Stock (10,000) (5,000) (10,000) Retirement of General Long-term Debt (133,343) (314,733) (25,274) Retirement of Affiliated Long-term Debt (200,000) - - Change in Short-term Debt (net) 290,000 - (45,500) Dividends Paid on Common Stock (65,300) (82,952) (240,600) Dividends Paid on Cumulative Preferred Stock (525) (962) (1,575) --------- --------- --------- Net Cash Flows Used For Financing Activities (171,809) (110,995) (234,217) --------- --------- --------- Net Increase (Decrease) in Cash and Cash Equivalents (10,879) 758 6,946 Cash and Cash Equivalents January 1 12,358 11,600 4,654 --------- --------- --------- Cash and Cash Equivalents December 31 $ 1,479 $ 12,358 $ 11,600 ========= ========= ========= Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $53,514,000, $68,596,000 and $68,506,000 and for income taxes was $117,591,000, 80,485,000 and $81,109,000 in 2002, 2001 and 2000, respectively. Noncash acquisitions under capital leases were $1,019,000 and $10,777,000 in 2001 and 2000, respectively. See Notes to Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Capitalization - ----------------------------------------- December 31, ----------- 2002 2001 (in thousands) COMMON SHAREHOLDER'S EQUITY $ 847,664 $ 791,498 ---------- ---------- PREFERRED STOCK: $100 par value - authorized shares 2,500,000 $25 par value - authorized shares 7,000,000 Shares Number of Shares Redeemed Outstanding Series Year Ended December 31, December 31, 2002 - ------ ---------------------------- ----------------- 2002 2001 2000 ---- ---- ---- Subject to Mandatory Redemption: 7.00% 100,000 50,000 100,000 - - 10,000 ---------- ---------- LONG-TERM DEBT (See Schedule of Long-term Debt): First Mortgage Bonds 222,797 243,197 Installment Purchase Contracts 91,275 91,220 Senior Unsecured Notes 147,554 147,458 Notes - Affiliated 160,000 200,000 Junior Debentures - 109,973 Less Portion Due Within One Year ( 43,000) (220,500) ---------- ---------- Total Long-term Debt Excluding Portion Due Within One Year 578,626 571,348 ---------- ---------- TOTAL CAPITALIZATION $1,426,290 $1,372,846 ========== ========== 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, ----------- 2002 2001 ---- ---- (in thousands) % Rate Due 7.25 2002 - October 1 $ - $ 14,000 7.15 2002 - November 1 - 6,500 6.80 2003 - May 1 13,000 13,000 6.60 2003 - August 1 25,000 25,000 6.10 2003 - November 1 5,000 5,000 6.55 2004 - March 1 26,500 26,500 6.75 2004 - May 1 26,000 26,000 8.70 2022 - July 1 2,000 2,000 8.55 2022 - August 1 15,000 15,000 8.40 2022 - August 15 14,000 14,000 8.40 2022 - October 15 13,000 13,000 7.90 2023 - May 1 40,000 40,000 7.75 2023 - August 1 33,000 33,000 7.60 2024 - May 1 11,000 11,000 Unamortized Discount (703) (803) -------- -------- Total $222,797 $243,197 ======== ======== First mortgage bonds are secured by a first mortgage lien on electric utility plant. Certain supplemental indentures to the first mortgage lien contain 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, ----------- 2002 2001 ---- ---- (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 (970) (1,025) ------- ------- Total $91,275 $91,220 ======= ======= 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 of (at stated maturities and upon mandatory redemptions) 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, ----------- 2002 2001 ---- ---- (in thousands) % Rate Due - ------ ------------------ 6.85 2005 - October 3 $ 36,000 $ 36,000 6.51 2008 - February 1 52,000 52,000 6.55 2008 - June 26 60,000 60,000 Unamortized Discount (446) (542) -------- -------- Total $147,554 $147,458 ======== ======== Notes payable to parent company were as follows: December 31, ----------- 2002 2001 ---- ---- (in thousands) % Rate Due (a) 2002 - Sept 25 $ - $200,000 6.501% 2006 - May 15 160,000 - -------- -------- Total $160,000 $200,000 ======== ======== (a) Redemed 9/25/02 Junior debentures outstanding were as follows: December 31, ----------- 2002 2001 ---- ---- (in thousands) % Rate Due - ------ ------------------ 8-3/8 2025 - Sept 30 $ - $ 72,843 7.92 2027 - March 31 - 40,000 Unamortized Discount - (2,870) -------- -------- Total $ - $109,973 ======== ======== At December 31, 2002, future annual long-term debt payments are as follows: Amount ------ (in thousands) 2003 $ 43,000 2004 52,500 2005 36,000 2006 160,000 2007 - Later Years 332,245 -------- Total Principal Amount 623,745 Unamortized Discount (2,119) -------- Total $621,626 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Index to Combined Notes to Consolidated Financial Statements - ------------------------------------------------------------ The notes to CSPCo's consolidated 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 7 Customer Choice and Industry Restructuring Note 8 Commitments and Contingencies Note 9 Guarantees Note 10 Sustained Earnings Improvement Initiative Note 11 Asset Impairments and Investment Value Losses Note 13 Benefit Plans Note 14 Business Segments Note 16 Risk Management, Financial Instruments and Derivatives Note 17 Income Taxes Note 18 Supplementary Information Note 20 Leases Note 22 Lines of Credit and Sale of Receivables Note 23 Unaudited Quarterly Financial Information Note 24 Jointly Owned Electric Utility Plant Note 28 Related Party Transactions Note 29 INDEPENDENT AUDITORS' REPORT To the Shareholder 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 subsidiaries as of December 31, 2002 and 2001, 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, 2002. 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 subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. /s/ Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Selected Consolidated Financial Data - ------------------------------------ Year Ended December 31, ----------------------------------------------------------------------------------------- 2002 2001 2000 1999 1998 ---- ---- ---- ---- ---- (in thousands) INCOME STATEMENTS DATA: Operating Revenues $1,526,764 $1,526,997 $1,488,209 $1,351,666 $1,405,794 Operating Expenses 1,375,575 1,367,292 1,522,911 1,243,014 1,239,787 ---------- ---------- ---------- ---------- ---------- Operating Income (Loss) 151,189 159,705 (34,702) 108,652 166,007 Nonoperating Items, Net 16,726 9,730 9,933 4,530 (839) Interest Charges 93,923 93,647 107,263 80,406 68,540 ---------- ---------- ---------- ---------- ---------- Net Income (Loss) 73,992 75,788 (132,032) 32,776 96,628 Preferred Stock Dividend Requirements 4,601 4,621 4,624 4,885 4,824 ---------- ---------- --------- ---------- ---------- Earnings (Loss) Applicable to Common Stock $ 69,391 $ 71,167 $(136,656) $ 27,891 $ 91,804 ========== ========== ========= ========== ========== December 31, ----------------------------------------------------------------------------------------- 2002 2001 2000 1999 1998 ---- ---- ---- ---- ---- (in thousands) BALANCE SHEETS DATA: Electric Utility Plant $5,029,958 $4,923,721 $4,871,473 $4,770,027 $4,631,848 Accumulated Depreciation and Amortization 2,568,604 2,436,972 2,280,521 2,194,397 2,081,355 ---------- ---------- ---------- ---------- ---------- Net Electric Utility Plant $2,461,354 $2,486,749 $2,590,952 $2,575,630 $2,550,493 ========== ========== ========== ========== ========== Total Assets $4,587,191 $4,394,062 $5,774,108 $4,575,210 $4,148,523 ========== ========== ========== ========== ========== Common Stock and Paid-in Capital $ 915,144 $ 789,800 $ 789,656 $ 789,323 $ 789,189 Accumulated Other Comprehensive Income (Loss) (40,487) (3,835) - - - Retained Earnings 143,996 74,605 3,443 166,389 253,154 ---------- ---------- ---------- ---------- ---------- Total Common Shareholder's Equity $1,018,653 $ 860,570 $ 793,099 $ 955,712 $1,042,343 ========== ========== ========== ========== ========== Cumulative Preferred Stock: Not Subject to Mandatory Redemption $ 8,101 $ 8,736 $ 8,736 $ 9,248 $ 9,273 Subject to Mandatory Redemption (a) 64,945 64,945 64,945 64,945 68,445 ---------- ---------- ---------- ---------- ---------- Total Cumulative Preferred Stock $ 73,046 $ 73,681 $ 73,681 $ 74,193 $ 77,718 ========== ========== ========== ========== ========== Long-term Debt (a) $1,617,062 $1,652,082 $1,388,939 $1,324,326 $1,175,789 ========== ========== ========== ========== ========== Obligations Under Capital Leases (a) $ 50,848 $ 61,933 $ 163,173 $ 187,965 $ 186,427 ========== ========== ========== ========== ========== Total Capitalization And Liabilities $4,587,191 $4,394,062 $5,774,108 $4,575,210 $4,148,523 ========== ========== ========== ========== ========== (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 571,000 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. I&M also sells wholesale power to municipalities and electric cooperatives. The cost of the AEP Power Pool's generating capacity is allocated among its 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. Under unit power agreements, I&M purchases 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. An agreement between AEGCo and KPCo provides for the sale of 390 MW of AEGCo's Rockport Plant capacity to KPCo through 2004. The KPCo agreement extends until December 31, 2009 for Rockport Unit 1 and until December 7, 2022 for Rockport Plant Unit 2 if AEP's restructuring settlement agreement filed with the FERC becomes operative. Therefore, I&M purchases 910 MW of AEGCo's 50% share of Rockport Plant capacity. Results of Operations - --------------------- During 2002 Net Income decreased by $2 million due to increased operations and maintenance costs incurred as part of planned and unplanned outages at Cook Plant and Rockport Plant. 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 Note 5). As a result of costs incurred in 2000 to restart the Cook Plant and a disallowance of interest deductions for a corporate owned life insurance (COLI) program, Net Income increased in 2001 by $208 million. 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. The deferrals were expensed and impacted Net Income in 2000. Operating Revenues Increase - --------------------------- Operating Revenues were flat in 2002 and increased 3% in 2001. The 2001 increase reflects increased sales to AEP affiliates through the AEP Power Pool. The following analyzes the changes in Operating Revenues: Increase (Decrease) From Previous Year ------------------ (dollars in millions) 2002 2001 ------------------------------ Amount % Amount % ------ - ------ - Retail* $ 28.2 4 $ (2.3) N.M Marketing 2.6 1 (12.0) (4) Other 2.6 6 5.0 13 ------ ------ Total Wholesale Electricity 33.4 3 (9.3) (1) Energy Delivery* 7.3 2 3.4 1 Sales to AEP Affiliates (40.9) (16) 44.7 21 ------ ------ Total $ (0.2) N.M. $ 38.8 3 ====== ====== 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 is primarily due to increased sales to AEP affiliates reflecting increased availablility of the Cook Plant. The return to service of the Cook Plant units increased the amount of power I&M could sell to its affiliates in the AEP Power Pool. Operating Expenses - ------------------ Total Operating Expenses increased 1% in 2002 and decreased 10% in 2001. The 2001 decrease was primarily due to the unfavorable COLI tax ruling and costs related to the extended Cook Plant outage and restart efforts in 2000. The changes in the components of Operating Expenses were: Increase (Decrease) From Previous Year ------------------- (dollars in millions) 2002 2001 ----------------------------- Amount % Amount % ------ - ------ - Fuel $(10.6) (4) $ 39.2 19 Wholesale Electricity Purchases 4.7 25 4.9 36 AEP Affiliate Purchases (4.5) (2) (27.2) (10) Other Operation 13.6 3 (147.7) (25) Maintenance 24.3 19 (92.6) (42) Depreciation and Amortization 3.8 2 9.3 6 Taxes Other Than Income Taxes (7.8) (12) 4.9 8 Income Taxes (15.2) (28) 53.6 N.M. ------ ------- Total $ 8.3 1 $(155.6) (10) ====== ======= N.M. = Not Meaningful Fuel expense decreased in 2002 due to lower average costs of fuel and a decline in nuclear generation. The increase in Fuel expense in 2001 reflects an increase in nuclear generation as the Cook Plant units returned to service following the extended outage. Wholesale Electricity purchases increased in 2002 and 2001 due to increased purchases from third parties for sales for resale. AEP Affiliates purchases declined in 2002 due to lower purchases from AEGCo at lower costs. The decline in purchased power from AEP affiliates in 2001 reflects generation from the Cook Plant replacing purchases from the AEP Power Pool which declined 21%. Other Operation expense increased in 2002 primarily due to higher costs for pensions, other benefits and insurance. 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. Maintenance expense increased for nuclear maintenance costs incurred during refueling outages in 2002. 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. Due to a change in the Indiana property tax law which lowered the floor percentage for calculating tax liability, Taxes Other Than Income Taxes declined in 2002. 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 of amounts recorded in December 2000 to actual expenses. Income Taxes attributable to operations decreased in 2002 due to a decrease in pre-tax operating income. The significant increase in Income Taxes attributable to operations in 2001 is due to an increase in pre-tax operating income. Nonoperating Income, Nonoperating Expenses and Income Taxes - ----------------------------------------------------------- The decrease in Nonoperating Income in 2002 is primarily due to decreased net gains on forward electricity trading transactions outside AEP's traditional marketing area. The increase in Nonoperating Income in 2001 is primarily due to increased net gains on forward electricity trading transactions outside AEP's traditional marketing area. Nonoperating Expenses decreased in 2002 due to decreased trading overheads and traders' incentive compensation. Nonoperating Expenses increased in 2001 due to increased trading overheads and traders' incentive compensation. The increase in Nonoperating Income Taxes in 2001 reflects the increase in nonoperating pre-tax income. 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.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Income - --------------------------------- Year Ended December 31, ------------------------------------------------- 2002 2001 2000 ---- ---- ---- (in thousands) OPERATING REVENUES: Wholesale Electricity $ 990,905 $ 957,548 $ 966,882 Energy Delivery 321,721 314,410 311,019 Sales to AEP Affiliates 214,138 255,039 210,308 ---------- ---------- ---------- TOTAL OPERATING REVENUES 1,526,764 1,526,997 1,488,209 ---------- ---------- ---------- OPERATING EXPENSES: Fuel 239,455 250,098 210,870 Purchased Power: Wholesale Electricity 23,443 18,707 13,785 AEP Affiliates 233,724 238,237 265,475 Other Operation 462,707 449,115 596,861 Maintenance 151,602 127,263 219,854 Depreciation and Amortization 168,070 164,230 154,920 Taxes other Than Income Taxes 57,721 65,518 60,622 Income Taxes 38,853 54,124 524 ---------- ---------- ---------- TOTAL OPERATING EXPENSES 1,375,575 1,367,292 1,522,911 ---------- ---------- ---------- OPERATING INCOME (LOSS) 151,189 159,705 (34,702) NONOPERATING INCOME 93,739 97,810 76,499 NONOPERATING EXPENSES 71,029 83,037 62,377 NONOPERATING INCOME TAXES 5,984 5,043 4,189 INTEREST CHARGES 93,923 93,647 107,263 ---------- ---------- ---------- NET INCOME (LOSS) 73,992 75,788 (132,032) PREFERRED STOCK DIVIDEND REQUIREMENTS 4,601 4,621 4,624 ---------- ---------- --------- EARNINGS (LOSS) APPLICABLE TO COMMON STOCK $ 69,391 $ 71,167 $(136,656) ========== ========== ========= Consolidated Statements of Comprehensive Income - ----------------------------------------------- Year Ended December 31, -------------------------------------------------- 2002 2001 2000 ---- ---- ---- (in thousands) NET INCOME (LOSS) $ 73,992 $75,788 $(132,032) OTHER COMPREHENSIVE INCOME (LOSS) Cash Flow Interest Rate Hedge 3,835 (3,835) - Cash Flow Power Hedge (286) - - Minimum Pension Liability (40,201) - - -------- ------- --------- COMPREHENSIVE INCOME (LOSS) $ 37,340 $71,953 $(132,032) ======== ======= ========= 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, -------------------------------------------------- 2002 2001 2000 ---- ---- ---- (in thousands) Retained Earnings January 1 $ 74,605 $ 3,443 $ 166,389 Net Income (Loss) 73,992 75,788 (132,032) -------- -------- --------- 148,597 79,231 34,357 -------- -------- --------- Deductions: Cash Dividends Declared: Common Stock - - 26,290 Cumulative Preferred Stock: 4-1/8% Series 229 229 230 4.56% Series 66 66 66 4.12% Series 52 72 74 5.90% Series 897 897 897 6-1/4% Series 1,203 1,203 1,203 6.30% Series 834 834 834 6-7/8% Series 1,186 1,186 1,186 -------- -------- --------- Total Cash Dividends Declared 4,467 4,487 30,780 Capital Stock Expense 134 139 134 -------- -------- --------- Total Deductions 4,601 4,626 30,914 -------- -------- --------- Retained Earnings December 31 $143,996 $ 74,605 $ 3,443 ======== ======== ======= See Notes to Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Consolidated Balance Sheets - --------------------------- December 31, ----------- 2002 2001 ---- ---- (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production $2,768,463 $2,758,160 Transmission 971,599 957,336 Distribution 921,835 900,921 General (including nuclear fuel) 220,137 233,005 Construction Work in Progress 147,924 74,299 ---------- ---------- Total Electric Utility Plant 5,029,958 4,923,721 Accumulated Depreciation and Amortization 2,568,604 2,436,972 ---------- ---------- NET ELECTRIC UTILITY PLANT 2,461,354 2,486,749 ---------- ---------- NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR FUEL DISPOSAL TRUST FUNDS 870,754 834,109 ---------- ---------- LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 83,265 82,898 ---------- ---------- OTHER PROPERTY AND INVESTMENTS 120,941 127,977 ---------- ---------- CURRENT ASSETS: Cash and Cash Equivalents 3,237 16,804 Advances to Affiliates 191,226 46,309 Accounts Receivable: Customers 67,333 60,864 Affiliated Companies 122,489 31,908 Miscellaneous 30,468 25,398 Allowance for Uncollectible Accounts (578) (741) Fuel 32,731 28,989 Materials and Supplies 95,552 91,440 Energy Trading and Derivative Contracts 68,148 108,895 Accrued Utility Revenues 6,511 2,072 Prepayments and Other 11,899 6,497 ---------- ---------- TOTAL CURRENT ASSETS 629,016 418,435 ---------- ---------- REGULATORY ASSETS 348,212 408,927 ---------- ---------- DEFERRED CHARGES 73,649 34,967 ---------- ---------- TOTAL ASSETS $4,587,191 $4,394,062 ========== ========== See Notes to Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES December 31, ----------- 2002 2001 ---- ---- (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 858,560 733,216 Accumulated Other Comprehensive Income (Loss) (40,487) (3,835) Retained Earnings 143,996 74,605 ---------- ---------- Total Common Shareholder's Equity 1,018,653 860,570 Cumulative Preferred Stock: Not Subject to Mandatory Redemption 8,101 8,736 Subject to Mandatory Redemption 64,945 64,945 Long-term Debt 1,587,062 1,312,082 ---------- ---------- TOTAL CAPITALIZATION 2,678,761 2,246,333 ---------- ---------- OTHER NONCURRENT LIABILITIES: Nuclear Decommissioning 620,672 600,244 Other 138,965 87,025 ---------- ---------- TOTAL OTHER NONCURRENT LIABILITIES 759,637 687,269 ---------- ---------- CURRENT LIABILITIES: Long-term Debt Due Within One Year 30,000 340,000 Accounts Payable - General 125,048 86,766 Accounts Payable - Affiliated Companies 93,608 43,956 Taxes Accrued 71,559 69,761 Interest Accrued 21,481 20,691 Obligations Under Capital Leases 8,229 10,840 Energy Trading and Derivative Contracts 48,568 93,413 Other 92,822 76,486 ---------- ---------- TOTAL CURRENT LIABILITIES 491,315 741,913 ---------- ---------- DEFERRED INCOME TAXES 356,197 400,531 ---------- ---------- DEFERRED INVESTMENT TAX CREDITS 97,709 105,449 ---------- ---------- DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2 73,885 77,592 ---------- ---------- LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 32,261 42,936 ---------- ---------- REGULATORY LIABILITIES AND DEFERRED CREDITS 97,426 92,039 ---------- ---------- COMMITMENTS AND CONTINGENCIES (Note 9) TOTAL CAPITALIZATION AND LIABILITIES $4,587,191 $4,394,062 ========== ========== 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, ---------------------- 2002 2001 2000 ---- ---- ---- (in thousands) OPERATING ACTIVITIES: Net Income (Loss) $ 73,992 $ 75,788 $(132,032) Adjustments for Noncash Items: Depreciation and Amortization 168,070 166,360 163,391 Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses (net) (26,577) 418 5,737 Amortization of Nuclear Outage Costs 40,000 40,000 40,000 Deferred Income Taxes (16,921) (29,205) (125,179) Deferred Investment Tax Credits (7,740) (8,324) (7,854) Unrecovered Fuel and Purchased Power Costs 37,501 37,501 37,501 Changes in Certain Current Assets And Liabilities: Accounts Receivable (net) (102,283) 64,841 (25,305) Fuel, Materials and Supplies (7,854) (19,426) 10,743 Accrued Utility Revenues (4,439) (2,072) 44,428 Accounts Payable 87,934 (60,185) 85,056 Taxes Accrued 1,798 1,345 19,446 Mark-to-Market of Energy Trading and Derivatives Contracts (9,517) (62,647) 14,830 Disputed Tax and Interest Related to COLI - - 56,856 Regulatory Asset - Trading Losses (992) 8,493 (17,914) Regulatory Liability - Trading Gains 2,494 34,293 (7,416) Change in Other Assets (28,233) (5,871) (68,160) Change in Other Liabilities 21,001 (5,102) 37,309 --------- --------- --------- Net Cash Flows From Operating Activities 228,234 236,207 131,437 --------- --------- --------- INVESTING ACTIVITIES: Construction Expenditures (167,484) (91,052) (171,071) Buyout of Nuclear Fuel Leases - (92,616) - Other 1,759 1,074 587 --------- --------- --------- Net Cash Flows Used For Investing Activities (165,725) (182,594) (170,484) --------- --------- --------- FINANCING ACTIVITIES: Capital Contributions from Parent Company 125,000 - - Issuance of Long-term Debt 288,732 297,656 199,220 Retirement of Cumulative Preferred Stock (424) - (314) Retirement of Long-term Debt (340,000) (44,922) (148,000) Change in Advances from Affiliates (net) (144,917) (299,891) 253,582 Change in Short-term Debt (net) - - (224,262) Dividends Paid on Common Stock - - (26,290) Dividends Paid on Cumulative Preferred Stock (4,467) (4,487) (3,368) --------- --------- --------- Net Cash Flows From (Used For) Financing Activities (76,076) (51,644) 50,568 --------- --------- --------- Net Increase (Decrease) in Cash and Cash Equivalents (13,567) 1,969 11,521 Cash and Cash Equivalents January 1 16,804 14,835 3,314 --------- --------- --------- Cash and Cash Equivalents December 31 $ 3,237 $16,804 $14,835 ======= ======= ======= Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $89,984,000, $92,140,000 and $82,511,000 and for income taxes was $60,523,000, $100,470,000 and $73,254,000 in 2002, 2001 and 2000, respectively. Noncash acquisitions under capital leases were $1,023,000 and $22,218,000 in 2001 and 2000, respectively. See Notes to Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Capitalization - ----------------------------------------- December 31, ----------- 2002 2001 ---- ---- (in thousands) COMMON SHAREHOLDER'S EQUITY $1,018,653 $ 860,570 ---------- ---------- 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 2002 (a) Year Ended December 31, December 31, 2002 - ------ ------------ ------------------------ ----------------- 2002 2001 2000 ---- ---- ---- Not Subject to Mandatory Redemption-$100 Par: 4-1/8% 106.125 20 - 3,750 55,369 5,537 5,539 4.56% 102 - - - 14,412 1,441 1,441 4.12% 102.728 6,326 - 1,375 11,230 1,123 1,756 ---------- ---------- 8,101 8,736 ---------- ---------- Subject to Mandatory Redemption-$100 Par(b): 5.90% (c) - - - 152,000 15,200 15,200 6-1/4% (c) - - - 192,500 19,250 19,250 6.30% (c) - - - 132,450 13,245 13,245 6-7/8% (d) - - - 172,500 17,250 17,250 ---------- ---------- 64,945 64,945 ---------- ---------- LONG-TERM DEBT (See Schedule of Long-term Debt): First Mortgage Bonds 174,245 264,141 Installment Purchase Contracts 310,336 310,239 Senior Unsecured Notes 747,027 696,144 Other Long-term Debt (e) 223,736 219,947 Junior Debentures 161,718 161,611 Less Portion Due Within One Year (30,000) (340,000) ---------- ---------- Long-term Debt Excluding Portion Due Within One Year 1,587,062 1,312,082 ---------- ---------- TOTAL CAPITALIZATION $2,678,761 $2,246,333 ========== ========== (a) The cumulative preferred stock is callable at the price indicated plus accrued dividends (b) Sinking fund provisions require the redemption of 15,000 shares in 2003 and 67,500 shares in each of 2004, 2005, 2006 and 2007. The sinking fund provisions of each series subject to mandatory redemption have been met by purchase of shares in advance of these due dates. Shares previously purchased may be applied to meet the sinking fund requirement. (c) Commencing in 2004 and continuing through 2008 I&M 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. The series are callable beginning November 1, 2003 for the 5.90% series, December 1, 2003 for the 6-1/4% series and March 1, 2004 for the 6.30% series at $100 plus accrued dividends. (d) 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. Callable at $100 per share plus accrued dividends beginning February 1, 2003. (e) Represents a liability for SNF disposal including interest payable to the DOE. See Note 9. 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, ----------- 2002 2001 ---- ---- (in thousands) % Rate Due 7.60 2002 - November 1 $ - $ 50,000 7.70 2002 - December 15 - 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 15,000 7.20 2024 - February 1 30,000 30,000 7.50 2024 - March 1 25,000 25,000 Unamortized Discount (755) (859) -------- -------- $174,245 $264,141 First mortgage bonds are secured by a first mortgage lien on electric utility plant. Certain supplemental indentures to the first mortgage lien contain 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 in connection with the issuance of pollution control revenue bonds by governmental authorities as follows: December 31, ----------- 2002 2001 ---- ---- (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 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 4.90(c) 2025 - June 1 50,000 - City of Sullivan, Indiana: 5.95 2009 - May 1 45,000 45,000 Unamortized Discount (1,664) (1,761) -------- -------- $310,336 $310,239 ======== ======== (a) A variable interest rate was determined weekly. The average weighted interest rates were 1.5% in 2002 and 2.4% for 2001. (b) In June 2001 an auction rate was established. Auction rates are determined by standard procedures every 35 days. The auction rate for 2002 ranged from 1.3% to 1.7% and averaged 1.5%. 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 averaged 3.3% during 2001. (c) Rate is fixed until June 1, 2007 (term rate bonds). The terms of the installment purchase contracts require I&M to pay amounts sufficient for the cities to pay interest on and the principal of (at stated maturities and upon mandatory redemptions) related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain generating plants. The term rate bonds due 2025 are subject to mandatory tender for purchase on the term maturity date (June 1, 2007). Accordingly, the term rate bonds have been classified for repayment purposes in 2007 (the term end date). Senior unsecured notes outstanding were as follows: December 31, ----------- 2002 2001 ---- ---- (in thousands) % Rate Due - ------ ------------------ (a) 2002 - September 3 $ - $200,000 6-7/8 2004 - July 1 150,000 150,000 6.125 2006 - December 15 300,000 300,000 6.45 2008 - November 10 50,000 50,000 6.375 2012 - November 1 100,000 - 6 2032 - December 31 150,000 - Unamortized Discount (2,973) (3,856) -------- -------- $747,027 $696,144 ======== ======== (a) A floating interest rate was determined quarterly. The rate on December 31, 2001 was 2.71%. The average interest rates were 2.6% in 2002 and 5.1% in 2001. Junior debentures outstanding were as follows: December 31, ----------- 2002 2001 ---- ---- (in thousands) % Rate Due - ------ ----------------- 8.00 2026 - March 31 $ 40,000 $ 40,000 7.60 2038 - June 30 125,000 125,000 Unamortized Discount (3,282) (3,389) -------- -------- Total $161,718 $161,611 ======== ======== 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, 2002, future annual long-term debt payments are as follows: Amount ------ (in thousands) 2003 $ 30,000 2004 150,000 2005 - 2006 300,000 2007 50,000 Later Years 1,095,736 ---------- Total Principal Amount 1,625,736 Unamortized Discount (8,674) ---------- Total $1,617,062 ========== INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Index to Combined Notes to Consolidated Financial Statements The notes to I&M's consolidated 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 I&M. The combined footnotes begin on page L-1. Combined Footnote Reference --------- Significant Accounting Policies Note 1 Merger Note 4 Nuclear Plant Restart Note 5 Effects of Regulation Note 7 Customer Choice and Industry Restructuring Note 8 Commitments and Contingencies Note 9 Guarantees Note 10 Sustained Earnings Improvement Initiative Note 11 Asset Impairments and Investment Value Losses Note 13 Benefit Plans Note 14 Business Segments Note 16 Risk Management, Financial Instruments and Derivatives Note 17 Income Taxes Note 18 Supplementary Information Note 20 Leases Note 22 Lines of Credit and Sale of Receivables Note 23 Unaudited Quarterly Financial Information Note 24 Related Party Transactions Note 29 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 subsidiaries as of December 31, 2002 and 2001, 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, 2002. 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 subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. /s/ Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 KENTUCKY POWER COMPANY
KENTUCKY POWER COMPANY Selected Financial Data - ----------------------- Year Ended December 31, -------------------------------------------------------------------------------------- 2002 2001 2000 1999 1998 ---- ---- ---- ---- ---- (in thousands) INCOME STATEMENTS DATA: Operating Revenues $ 378,683 $ 379,025 $ 389,875 $ 358,757 $ 362,999 Operating Expenses 336,486 331,347 340,137 304,082 311,106 ---------- ----------- ---------- ---------- ---------- Operating Income 42,197 47,678 49,738 54,675 51,893 Nonoperating Items, Net 5,206 1,248 2,070 (327) (1,726) Interest Charges 26,836 27,361 31,045 28,918 28,491 ---------- ----------- ---------- ---------- ---------- Net Income $ 20,567 $ 21,565 $ 20,763 $ 25,430 $ 21,676 ========== =========== ========== ========== ========== Year Ended December 31, -------------------------------------------------------------------------------------- 2002 2001 2000 1999 1998 ---- ---- ---- ---- ---- (in thousands) BALANCE SHEETS DATA: Electric Utility Plant $1,295,619 $1,128,415 $1,103,064 $1,079,048 $1,043,711 Accumulated Depreciation and Amortization 397,304 384,104 360,648 340,008 315,546 ---------- ---------- ---------- ---------- ---------- Net Electric Utility Plant $ 898,315 $744,311 $742,416 $739,040 $728,165 ========== ======== ======== ======== ======== Total Assets $1,164,676 $ 999,048 $1,494,543 $ 986,123 $ 921,847 ========== ========== ========== ========== ========== Common Stock and Paid-in Capital $ 259,200 $ 209,200 $209,200 $209,200 $199,200 Accumulated Other Comprehensive Income (Loss) (9,451) (1,903) - - - Retained Earnings 48,269 48,833 57,513 67,110 71,452 ---------- ---------- ---------- ---------- ---------- Total Common Shareholder's Equity $ 298,018 $ 256,130 $266,713 $276,310 $270,652 ========== ========== ======== ======== ======== Long-term Debt (a) $ 466,632 $ 346,093 $330,880 $365,782 $368,838 ========== ========== ======== ======== ======== Obligations Under Capital Leases(a) $ 7,248 $ 9,583 $ 14,184 $ 15,141 $ 18,977 ========== ========== ======== ======== ======== Total Capitalization and Liabilities $1,164,676 $ 999,048 $1,494,543 $ 986,123 $ 921,847 ========== ========== ========== ========== ========== (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 174,000 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. KPCo has a unit power agreement with AEGCo, an affiliated company, which expires in 2004. The unit power agreement extends until December 31, 2009 for Rockport Plant Unit 1 and until December 7, 2002 for Rockport Plant Unit 2 if AEP's settlement restructuring agreement filed with the FERC becomes operative. The agreement provides for KPCo to purchase 15% of the total output of the two unit 2,600-mw capacity Rockport Plant. Under the unit power agreement, there is a demand charge for the right to receive the power, which is payable even it the power is not taken. The amount of the demand charge is such that when added to other amounts received by AEGCo, it will enable AEGCo to recover all its fixed expenses including a FERC-approved rate of return on common equity. Results of Operations - --------------------- Net Income for 2002 decreased $1 million or 5%. Total Revenues were flat while increases in Operating Expenses, driven by expenses related to planned outages at the Big Sandy plant, were offset by comparable gains in net nonoperating income which benefited from decreases in trading incentive compensation. Changes in Revenues - ------------------- Increase (Decrease) Year-to-Date ------------------- (dollars in millions) Amount % ------ - Wholesale Electricity* $13 6 Energy Delivery* 1 1 Sales to AEP Affiliates (14) (34) --- Total $ - - === *Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery. Revenues in 2002 were comparable to those of last year. Increased sales to retail electricity customers reflecting warmer summer weather, colder days in late 2002, and increased fuel recovery revenues were offset by lower Sales to AEP Affiliates resulting from planned outages in 2002. KPCo's decreased generation was due to scheduled maintenance resulting in lower availability in the fourth quarter. Changes in Operating Expenses - ----------------------------- Increase (Decrease) Year-to-Date ------------------- (dollars in millions) Amount % ------ - Fuel $(5.6) (8) Wholesale Electricity - N.M. Purchases from AEP Affiliates 2.8 2 Other Operation (5.4) (9) Maintenance 12.6 56 Depreciation .7 2 Taxes Other Than Income Taxes .4 5 Income Taxes (.4) (4) ----- Total Operating Expenses $ 5.1 2 ===== N.M. = Not Meaningful Fuel expense decreased in 2002 as a result of planned fourth quarter outages at the Big Sandy plant for scheduled boiler maintenance. The 800 megawatt Unit 2, representing approximately 75% of the plant's generation capacity, was off-line from mid-September through the end of the year, thereby reducing the demand for fuel in the fourth quarter. Purchases from AEP Affiliates for 2002 increased to meet demand during the planned outages at the Big Sandy plant. Other Operation expense decreased in 2002 due to reduced consumption of emission allowances due to the planned outage; reduced accruals for trading incentive compensation due to reduced trading activity; and improvements in transmission expense resulting from less wholesale activity and related transmission, and an increase in AEP transmission equalization credits. Under the AEP Transmission Equalization Agreement, KPCo and certain eastern region affiliates share the costs associated with the ownership of their transmission system based upon each company's peak demand and investment. A decrease in KPCo's peak demand relative to its affiliates' peak demand was the main reason for the increase in transmission equalization credits. These developments were offset in part by severance expenses related to a sustained earnings initiative (see Note 11). Maintenance expense increased in 2002 primarily as a result of planned power plant outages. Big Sandy plant Unit 2 was down for the fourth quarter for planned boiler overhaul and electric plant maintenance. The Company experienced marginal increases in overhead line maintenance expense. Nonoperating Income Taxes for 2002 have increased as a result of increases in pre-tax income for the year offset in part by prior-year tax return adjustments. Other Changes - ------------- Nonoperating Income for 2002 decreased as a result of AEP's previously announced plan to reduce trading activity, and decreased margins on power trading activity outside of the AEP System's traditional marketing area resulting from soft market demand. Nonoperating Expenses decreased in 2002 as a result of decreases in trading incentive compensation.
KENTUCKY POWER COMPANY Statements of Income - -------------------- Year Ended December 31, ------------------------------------------------- 2002 2001 2000 ---- ---- ---- (in thousands) OPERATING REVENUES: Wholesale Electricity $218,665 $205,476 $226,708 Energy Delivery 132,054 131,183 121,346 Sales to AEP Affiliates 27,964 42,366 41,821 -------- -------- -------- TOTAL OPERATING REVENUES 378,683 379,025 389,875 -------- -------- -------- OPERATING EXPENSES: Fuel 65,043 70,635 74,638 Purchased Power: Wholesale Electricity 29 86 1,940 AEP Affiliates 133,002 130,204 127,707 Other Operation 52,892 58,275 52,495 Maintenance 35,089 22,444 25,866 Depreciation and Amortization 33,233 32,491 31,028 Taxes Other Than Income Taxes 8,240 7,854 7,251 Income Taxes 8,958 9,358 19,212 -------- -------- -------- TOTAL OPERATING EXPENSES 336,486 331,347 340,137 -------- -------- -------- OPERATING INCOME 42,197 47,678 49,738 NONOPERATING INCOME 7,863 10,881 6,139 NONOPERATING EXPENSES 753 8,949 2,940 NONOPERATING INCOME TAXES 1,904 684 1,129 INTEREST CHARGES 26,836 27,361 31,045 -------- -------- -------- NET INCOME $ 20,567 $ 21,565 $ 20,763 ======== ======== ======== Statements of Comprehensive Income - ---------------------------------- Year Ended December 31, ------------------------------------------------- 2002 2001 2000 ---- ---- ---- (in thousands) NET INCOME $ 20,567 $21,565 $20,763 OTHER COMPREHENSIVE INCOME (LOSS) Cash Flow Interest Rate Hedge 2,225 (1,903) - Minimum Pension Liability (9,773) - - -------- ------- ------- COMPREHENSIVE INCOME $ 13,019 $19,662 $20,763 ======== ======= ======= Statements of Retained Earnings - ------------------------------- Year Ended December 31, ------------------------------------------------- 2002 2001 2000 ---- ---- ---- (in thousands) RETAINED EARNINGS JANUARY 1 $48,833 $57,513 $67,110 NET INCOME 20,567 21,565 20,763 CASH DIVIDENDS DECLARED 21,131 30,245 30,360 ------- ------- ------- RETAINED EARNINGS DECEMBER 31 $48,269 $48,833 $57,513 ======= ======= ======= See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY Balance Sheets - -------------- December 31, ----------- 2002 2001 ---- ---- (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production $ 275,121 $ 271,070 Transmission 373,639 374,116 Distribution 425,817 402,537 General 55,913 65,059 Construction Work in Progress 165,129 15,633 ---------- ---------- Total Electric Utility Plant 1,295,619 1,128,415 Accumulated Depreciation and Amortization 397,304 384,104 ---------- ---------- NET ELECTRIC UTILITY PLANT 898,315 744,311 ---------- ---------- OTHER PROPERTY AND INVESTMENTS 6,904 6,492 ---------- ---------- LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 29,871 29,477 ---------- ---------- CURRENT ASSETS: Cash and Cash Equivalents 2,304 1,947 Accounts Receivable: Customers 22,044 20,036 Affiliated Companies 23,802 16,012 Miscellaneous 2,889 3,333 Allowance for Uncollectible Accounts (192) (264) Fuel 10,817 12,060 Materials and Supplies 16,127 15,766 Accrued Utility Revenues 5,301 5,395 Accrued Tax Benefit 1,253 - Energy Trading Contracts 24,320 33,905 Prepayments and other 2,127 1,314 ---------- ---------- TOTAL CURRENT ASSETS 110,792 109,504 ---------- ---------- REGULATORY ASSETS 101,976 97,692 ---------- ---------- DEFERRED CHARGES 16,818 11,572 ---------- ---------- TOTAL ASSETS $1,164,676 $ 999,048 ========== ========== See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY December 31, ----------- 2002 2001 ---- ---- (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock - $50 Par Value: Authorized - 2,000,000 Shares Outstanding - 1,009,000 Shares $ 50,450 $ 50,450 Paid-in Capital 208,750 158,750 Accumulated Other Comprehensive Income (Loss) (9,451) (1,903) Retained Earnings 48,269 48,833 ---------- -------- Total Common Shareowner's Equity 298,018 256,130 Long-term Debt 391,632 176,093 Long-term Debt - Affiliated Companies 60,000 75,000 ---------- -------- TOTAL CAPITALIZATION 749,650 507,223 ---------- -------- OTHER NONCURRENT LIABILITIES 27,319 11,929 ---------- -------- CURRENT LIABILITIES: Long-term Debt Due Within One Year - General - 95,000 Long-term Debt Due within One Year - Affiliated Companies 15,000 - Advances from Affiliates 23,386 66,200 Accounts Payable: General 46,515 23,464 Affiliated Companies 44,035 22,557 Customer Deposits 8,048 4,461 Taxes Accrued - 10,305 Interest Accrued 6,471 5,269 Energy Trading and Derivative Contracts 17,803 38,664 Other 14,322 12,882 ---------- -------- TOTAL CURRENT LIABILITIES 175,580 278,802 ---------- -------- DEFERRED INCOME TAXES 178,313 168,304 ---------- -------- DEFERRED INVESTMENT TAX CREDITS 9,165 10,405 ---------- -------- LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 11,488 14,917 ---------- -------- REGULATORY LIABILITIES AND DEFERRED CREDITS 13,161 7,468 ---------- -------- COMMITMENTS AND CONTINGENCIES (Note 9) TOTAL CAPITALIZATION AND LIABILITIES $1,164,676 $999,048 ========== ======== See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY Statements of Cash Flows - ------------------------ Year Ended December 31, ---------------------------------------------- 2002 2001 2000 ---- ---- ---- (in thousands) OPERATING ACTIVITIES: Net Income $ 20,567 $ 21,565 $ 20,763 Adjustments for Noncash Items: Depreciation and Amortization 33,233 32,491 31,034 Deferred Income Taxes 9,839 6,293 3,765 Deferred Investment Tax Credits (1,240) (1,251) (1,252) Deferred Fuel Costs (net) 2,998 (4,707) 2,948 Mark-to-Market of Energy Trading Contracts (12,267) (1,454) (4,376) Change in Certain Current Assets and Liabilities: Accounts Receivable (net) (9,426) 23,694 (20,930) Fuel, Materials and Supplies 882 (7,658) 8,386 Accrued Utility Revenues 94 1,105 7,237 Accounts Payable 44,529 (22,942) 39,883 Taxes Accrued (11,558) (1,580) 2,025 Disputed Tax and Interest Related to COLI - - 5,943 Change in Other Assets (21,491) (2,762) 62,653 Change in Other Liabilities 16,161 (9,446) (62,702) --------- -------- --------- Net Cash Flows From Operating Activities 72,321 33,348 95,377 --------- -------- --------- INVESTING ACTIVITIES: Construction Expenditures (178,700) (37,206) (36,209) Proceeds From Sales of Property 217 216 266 --------- -------- --------- Net Cash Flows Used For Investing Activities (178,483) (36,990) (35,943) --------- -------- --------- FINANCING ACTIVITIES: Capital Contributions from Parent Company 50,000 - - Issuance of Long-term Debt 274,964 75,000 69,685 Retirement of Long-term Debt (154,500) (60,000) (105,000) Change in Short-term Debt (net) - - (39,665) Change in Advances From Affiliates (net) (42,814) 18,564 47,636 Dividends Paid (21,131) (30,245) (30,360) --------- -------- --------- Net Cash Flows From (Used For) Financing Activities 106,519 3,319 (57,704) --------- -------- --------- Net Increase (Decrease) in Cash and Cash Equivalents 357 (323) 1,730 Cash and Cash Equivalents January 1 1,947 2,270 540 --------- -------- --------- Cash and Cash Equivalents December 31 $ 2,304 $ 1,947 $ 2,270 ========= ======== ========= Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $25,176,000, $27,090,000 and $28,619,000 and for income taxes was $13,040,500, $7,549,000 and $7,923,000 in 2002, 2001 and 2000, respectively. Noncash acquisitions under capital leases were $22,021, $817,000 and $2,817,000 and in 2002, 2001 and 2000, respectively. See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY Statements of Capitalization - ---------------------------- December 31, ----------- 2002 2001 ---- ---- (in thousands) COMMON SHAREHOLDER'S EQUITY $298,018 $256,130 -------- -------- LONG-TERM DEBT (See Schedule of Long-term Debt): First Mortgage Bonds - 59,383 Senior Unsecured Notes 352,508 147,625 Notes Payable 75,000 100,000 Junior Debentures 39,124 39,085 Less Portion Due Within One Year (15,000) (95,000) -------- - ------- Long-term Debt Excluding Portion Due Within One Year 451,632 251,093 -------- - ------- TOTAL CAPITALIZATION $749,650 $507,223 ======== ======== 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, ----------- 2002 2001 ---- ---- (in thousands) % Rate Due 6.65 2003 - May 1 $ - $ 15,000 6.70 2003 - June 1 - 15,000 6.70 2003 - July 1 - 15,000 7.90 2023 - June 1 - 14,500 Unamortized Discount - (117) -------- -------- $ - $ 59,383 ======== ======== First mortgage bonds were secured by a first mortgage lien on electric utility plant. Senior unsecured notes outstanding were as follows: December 31, ----------- 2002 2001 ---- ---- (in thousands) % Rate Due - ------ ------------------ (a) 2002 - November 19 $ - $ 70,000 6.91 2007 - October 1 48,000 48,000 6.45 2008 - November 10 30,000 30,000 5.50 2007 - July 125,000 - 4.31 2007 - November 12 80,400 - 4.37 2007 - December 12 69,564 - Unamortized Discount (456) (375) -------- -------- $352,508 $147,625 (a) A floating interest rate is determined monthly. The rate December 31, 2001 was 4.3%. Notes payable to parent company were as follows: December 31, ----------- 2002 2001 ---- ---- (in thousands) % Rate Due 4.336 2003 - May 15 $15,000 $15,000 6.501 2006 - May 15 60,000 60,000 ------- ------- $75,000 $75,000 Notes payable to banks outstanding were as follows: December 31, ----------- 2002 2001 ---- ---- (in thousands) % Rate Due 7.45 2002 - September 20 $ - $25,000 ======= ======= Junior debentures outstanding were as follows: December 31, ----------- 2002 2001 ---- ---- (in thousands) % Rate Due 8.72 2025 - June 30 $40,000 $40,000 Unamortized Discount (876) (915) ------- ------- Total $39,124 $39,085 ======= ======= 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, 2002, future annual long-term debt payments are as follows: Amount ------ (in thousands) 2003 $ 15,000 2004 - 2005 - 2006 60,000 2007 322,964 Later Years 70,000 -------- Total Principal Amount 467,964 Unamortized Discount (1,332) -------- Total $466,632 ======== KENTUCKY POWER COMPANY Index to Combined Notes to Financial Statements - ----------------------------------------------- The notes to KPCo'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 KPCo. The combined footnotes begin on page L-1. Combined Footnote Reference --------- Significant Accounting Policies Note 1 Merger Note 4 Rate Matters Note 6 Effects of Regulation Note 7 Commitments and Contingencies Note 9 Guarantees Note 10 Sustained Earnings Improvement Initiative Note 11 Asset Impairments and Investment Value Losses Note 13 Benefit Plans Note 14 Business Segments Note 16 Risk Management, Financial Instruments and Derivatives Note 17 Income Taxes Note 18 Leases Note 22 Lines of Credit and Sale of Receivables Note 23 Unaudited Quarterly Financial Information Note 24 Related Party Transactions Note 29 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, 2002 and 2001, 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, 2002. 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, 2002 and 2001, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. /s/ Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 OHIO POWER COMPANY
OHIO POWER COMPANY Selected Financial Data - ----------------------- Year Ended December 31, --------------------------------------------------------------------------------------- 2002 2001 2000 1999 1998 ---- ---- ---- ---- ---- (in thousands) INCOME STATEMENTS DATA: Operating Revenues $2,113,125 $2,098,105 $2,140,331 $1,978,826 $2,105,547 Operating Expenses 1,814,796 1,857,395 1,913,504 1,689,997 1,816,175 ---------- ---------- ---------- ---------- ---------- Operating Income 298,329 240,710 226,827 288,829 289,372 Nonoperating Items, Net 5,376 18,686 (5,004) 7,000 588 Interest Charges 83,682 93,603 119,210 83,672 80,035 ---------- ---------- ---------- ---------- ---------- Income Before Extraordinary Item 220,023 165,793 102,613 212,157 209,925 Extraordinary Loss - (18,348) (18,876) - - ---------- ---------- --------- ---------- ---------- Net Income 220,023 147,445 83,737 212,157 209,925 Preferred Stock Dividend Requirements 1,258 1,258 1,266 1,417 1,474 ---------- ---------- ---------- ---------- ---------- Earnings Applicable To Common Stock $ 218,765 $ 146,187 $ 82,471 $ 210,740 $ 208,451 ========== ========== ========== ========== ========== Year Ended December 31, --------------------------------------------------------------------------------------- 2002 2001 2000 1999 1998 ---- ---- ---- ---- ---- (in thousands) BALANCE SHEETS DATA: Electric Utility Plant $5,685,826 $5,390,576 $5,577,631 $5,400,917 $5,257,841 Accumulated Depreciation 2,566,828 2,452,571 2,764,130 2,621,711 2,461,376 ---------- ---------- ---------- ---------- ---------- Net Electric Utility Plant $3,118,998 $2,938,005 $2,813,501 $2,779,206 $2,796,465 ========== ========== ========== ========== ========== Total Assets $4,457,032 $4,394,073 $6,193,975 $4,675,159 $4,344,680 ========== ========== ========== ========== ========== Common Stock and Paid-in Capital $783,684 $783,684 $783,684 $783,577 $783,536 Accumulated Other Comprehensive Income (Loss) (72,886) (196) - - - Retained Earnings 522,316 401,297 398,086 587,424 587,500 ---------- ---------- ---------- ---------- ---------- Total Common Shareholder's Equity $1,233,114 $1,184,785 $1,181,770 $1,371,001 $1,371,036 ========== ========== ========== ========== ========== Cumulative Preferred Stock: Not Subject to Mandatory Redemption $ 16,648 $ 16,648 $ 16,648 $ 16,937 $ 17,370 Subject to Mandatory Redemption (a) 8,850 8,850 8,850 8,850 11,850 ---------- ---------- ---------- ---------- ---------- Total Cumulative Preferred Stock $ 25,498 $ 25,498 $ 25,498 $ 25,787 $ 29,220 ========== ========== ========== ========== ========== Long-term Debt (a) $1,067,314 $1,203,841 $1,195,493 $1,151,511 $1,084,928 ========== ========== ========== ========== ========== Obligations Under Capital Leases (a) $ 65,626 $ 80,666 $ 116,581 $ 136,543 $ 142,635 ========== ========== ========== ========== ========== Total Capitalization and Liabilities $4,457,032 $4,394,073 $6,193,975 $4,675,159 $4,344,680 ========== ========== ========== ========== ========== (a) Including portion due within one year.
OHIO POWER COMPANY Management's Discussion and Analysis of Results of Operations - ------------------------------------------------------------- Ohio Power Company (OPCo) is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to 702,000 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. Results of Operations - --------------------- Income Before Extraordinary Item increased $54 million or 33% in 2002 mainly due to reductions in operating expenses, predominantly fuel, and interest charges. 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 effects of the COLI decision in 2000 and favorable wholesale business in 2001 were offset in part by the commencement of the amortization of transition regulatory assets in 2001, the effect of mild winter weather and the economic downturn. Operating Revenues - ------------------ Operating Revenues increased 1% in 2002 mainly as a result of increased residential and commercial sales due to demand caused by weather conditions. Changes in the components of Operating Revenues were: Increase (Decrease) From Previous Year ------------------ (Dollars in Millions) 2002 2001 ----------------------------- Amount % Amount % ------ - ------ - Retail* $ 11 2 $(66) (8) Wholesale Marketing 10 5 (19) (8) Unrealized MTM 2 8 33 N.M. Other 1 1 (4) (5) ---- ---- Total Wholesale Electricity* 24 2 (56) (5) Energy Delivery* 37 7 85 18 Sales to AEP Affiliates (46) (9) (71)(12) ---- ---- Total $ 15 1 $(42) (2) ==== ==== * Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery. During the summer months, cooling degree days increased 39%. For the fall season, heating degree days increased 32%. This reflects a return to more normal weather conditions since 2001 weather was abnormally mild. Sales to AEP Affiliates decreased due to a 15% decrease in price, reflective of lower average fuel cost, while MWH sales rose slightly. Operating Revenues decreased 2% in 2001 due to decreased sales to the AEP Power Pool. This was the result of an affiliate being able to supply more power to the Power Pool from two nuclear units that returned to service in June and December 2000. Operating Expenses - ------------------ Operating Expenses decreased 2% in 2002 mostly due to reductions in Fuel. Operating Expenses in 2001 also decreased 3%. This reduction was the result of lower Fuel and Income Taxes partially offset by amortization of transition regulatory assets. Changes in the components of Operating Expenses were: Increase (Decrease) From Previous Year ------------------ (dollars in millions) 2002 2001 ---- ---- Amount % Amount % ------ - ------ - Fuel $(102) (15) $(85) (11) Wholesale Electricity Purchased Power 4 6 15 30 AEP Affiliates Purchased Power 8 14 12 23 Other Operation 16 4 (4) (1) Maintenance (6) (4) 18 15 Depreciation and Amortization 9 4 84 54 Taxes Other Than Income Taxes 16 10 (10) (6) Income Taxes 12 12 (86) (46) ----- ---- Total Operating Expenses $ (43) (2) $(56) (3) ===== ==== The Fuel expense decrease for 2002 reflects a reduction of 19% in average cost of fuel for generation, offset in part by a slight increase in MWH generated. The decrease in fuel costs are the result of purchasing coal at lower prices on the open market in 2002 instead of affiliated company coal. 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. Wholesale Electricity Purchased Power expense increased in 2002. This was the result of a 11% increase of MWH sales, partially offset by a decrease in price. In 2001 the increase was due to increases in MWH purchases from third parties because of the non-availability of associated nuclear power for resale to wholesale customers and to meet internal demand. AEP Affiliates Purchased Power expense increased in 2002 as a result of an 18% increase of MWH purchased from affiliates with a slight decrease in the average price. The increase for 2001 was also a result of increased purchases through the AEP Power Pool. 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. In 2001, 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. The 2002 increase in Taxes Other Than Income Taxes is the result of increases in state excise tax created from a change in the base tax calculation. The decrease 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 increased in 2002 due to an increase in both federal and state tax expenses. Federal taxes increased due to higher pre-tax operating income offset in part by changes in certain book/tax timing differences accounted for on a flow-thru basis. State taxes increased predominately as a result of the State of Ohio's tax legislation revision involving utility deregulation. 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. Nonoperating Income and Nonoperating Expense - -------------------------------------------- Nonoperating Expenses decreased during 2002 due to reductions in variable incentive compensation expenses associated with wholesale trading. Nonoperating Income and Nonoperating Expenses increased in 2001 as a result of an increase in the level of trading activity outside of the AEP System's traditional marketing area. The 2002 increase in Nonoperating Income Tax Expense is a result of the favorable tax benefit from the sale of the Ohio Coal companies in 2001. This event also caused the decrease for 2001. Interest Charges - ---------------- The 2002 decrease in Interest Charges was primarily due to a decrease in the outstanding balances of long-term debt, the refinancing of debt at favorable interest rates and a reduction in short-term interest rates. The major reason for the decrease in Interest Charges in 2001 was the recognition in 2000 of deferred interest payments to the IRS related to COLI disallowances. 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 Statements of Income - -------------------- Year Ended December 31, ------------------------------------------------- 2002 2001 2000 ---- ---- ---- (in thousands) OPERATING REVENUES: Wholesale Electricity $1,058,250 $1,034,026 $1,090,297 Energy Delivery 589,673 552,713 467,587 Sales to AEP Affiliates 465,202 511,366 582,447 ---------- ---------- ---------- TOTAL OPERATING REVENUES 2,113,125 2,098,105 2,140,331 ---------- ---------- ---------- OPERATING EXPENSES: Fuel 584,730 686,568 771,969 Purchased Power: Wholesale Electricity 67,385 63,441 48,657 AEP Affiliates 71,154 62,585 50,741 Other Operation 416,533 400,790 404,410 Maintenance 136,609 142,878 124,735 Depreciation and Amortization 248,557 239,982 155,944 Taxes Other Than Income Taxes 176,247 159,778 169,527 Income Taxes 113,581 101,373 187,521 ---------- ---------- ---------- TOTAL OPERATING EXPENSES 1,814,796 1,857,395 1,913,504 ---------- ---------- ---------- OPERATING INCOME 298,329 240,710 226,827 NONOPERATING INCOME 51,953 70,108 57,163 NONOPERATING EXPENSES 28,567 53,802 44,009 NONOPERATING INCOME TAX EXPENSE (CREDIT) 18,010 (2,380) 18,158 INTEREST CHARGES 83,682 93,603 119,210 ---------- ---------- ---------- INCOME BEFORE EXTRAORDINARY ITEM 220,023 165,793 102,613 EXTRAORDINARY LOSS - DISCONTINUANCE OF REGULATORY ACCOUNTING FOR GENERATION - Net of tax (See Note 2) - (18,348) (18,876) ---------- ---------- ---------- NET INCOME 220,023 147,445 83,737 PREFERRED STOCK DIVIDEND REQUIREMENTS 1,258 1,258 1,266 ---------- ---------- ---------- EARNINGS APPLICABLE TO COMMON STOCK $ 218,765 $ 146,187 $ 82,471 ========== ========== ========== Statements of Comprehensive Income - ---------------------------------- Year Ended December 31, ----------------------------------------------- (in thousands) 2002 2001 2000 ---- ---- ---- NET INCOME $220,023 $147,445 $83,737 OTHER COMPREHENSIVE INCOME (LOSS) Foreign Currency Exchange Rate Hedge (542) (196) - Minimum Pension Liability (72,148) - - -------- -------- ------- COMPREHENSIVE INCOME $147,333 $147,249 $83,737 ======== ======== ======= The common stock of OPCo is wholly owned by AEP. See Notes to Financial Statements beginning on page L-1. OHIO POWER COMPANY Statement of Retained Earnings - ------------------------------ Year Ended December 31, ----------------------------------------------- 2002 2001 2000 ---- ---- ---- (in thousands) Retained Earnings January 1 $401,297 $398,086 $587,424 Net Income 220,023 147,445 83,737 -------- -------- -------- 621,320 545,531 671,161 -------- -------- -------- Deductions: Cash Dividends Declared: Common Stock 97,746 142,976 271,813 Cumulative Preferred Stock: 4.08% Series 58 58 59 4.20% Series 96 96 96 4.40% Series 139 139 139 4-1/2% Series 439 439 442 5.90% Series 428 428 428 6.02% Series 66 66 66 6.35% Series 32 32 32 -------- -------- -------- Total Dividends 99,004 144,234 273,075 -------- -------- -------- Retained Earnings December 31 $522,316 $401,297 $398,086 ======== ======== ======== See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY Balance Sheets - -------------- December 31, ----------- 2002 2001 ---- ---- (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production $3,116,825 $3,007,866 Transmission 905,829 891,283 Distribution 1,114,600 1,081,122 General 260,153 245,232 Construction Work in Progress 288,419 165,073 ---------- ---------- Total Electric Utility Plant 5,685,826 5,390,576 Accumulated Depreciation and Amortization 2,566,828 2,452,571 ---------- ---------- NET ELECTRIC UTILITY PLANT 3,118,998 2,938,005 ---------- ---------- OTHER PROPERTY AND INVESTMENTS 61,686 62,303 ---------- ---------- LONG-TERM ENERGY TRADING CONTRACTS 103,230 99,706 ---------- ---------- CURRENT ASSETS: Cash and Cash Equivalents 5,285 8,848 Accounts Receivable: Customers 95,100 84,694 Affiliated Companies 124,244 148,563 Miscellaneous 19,281 20,409 Allowance for Uncollectible Accounts (909) (1,379) Fuel 87,409 84,724 Materials and Supplies 85,379 88,768 Energy Trading Contracts 92,108 114,280 Prepayments and Other 12,083 20,865 ---------- ---------- TOTAL CURRENT ASSETS 519,980 569,772 ---------- ---------- REGULATORY ASSETS 568,641 644,625 ---------- ---------- DEFERRED CHARGES 84,497 79,662 ---------- ---------- TOTAL ASSETS $4,457,032 $4,394,073 ========== ========== See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY December 31, ----------- 2002 2001 ---- ---- (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) (72,886) (196) Retained Earnings 522,316 401,297 ---------- ---------- Total Common Shareholder's Equity 1,233,114 1,184,785 Cumulative Preferred Stock: Not Subject to Mandatory Redemption 16,648 16,648 Subject to Mandatory Redemption 8,850 8,850 Long-term Debt 917,649 1,203,841 ---------- ---------- TOTAL CAPITALIZATION 2,176,261 2,414,124 ---------- ---------- OTHER NONCURRENT LIABILITIES 227,689 130,386 ---------- ---------- CURRENT LIABILITIES: Long-term Debt Due Within One Year - General 89,665 - Long-term Debt Due Within One Year - Affiliated Companies 60,000 - Short-term Debt - Affiliated Companies 275,000 - Advances From Affiliates 129,979 300,213 Accounts Payable - General 170,563 131,057 Accounts Payable - Affiliated Companies 145,718 176,520 Customer Deposits 12,969 5,452 Taxes Accrued 111,778 126,770 Interest Accrued 18,809 17,679 Obligations Under Capital Leases 14,360 16,405 Energy Trading Contracts 61,839 98,081 Other 80,608 90,431 ---------- ---------- Total CURRENT LIABILITIES 1,171,288 962,608 ---------- ---------- DEFERRED INCOME TAXES 794,387 797,889 ---------- ---------- DEFERRED INVESTMENT TAX CREDITS 18,748 21,925 ---------- ---------- LONG-TERM ENERGY TRADING CONTRACTS 39,702 50,459 ---------- ---------- REGULATORY LIABILITIES AND DEFERRED CREDITS 28,957 16,682 ---------- ---------- COMMITMENTS AND CONTINGENCIES (Note 9) TOTAL CAPITALIZATION AND LIABILITIES $4,457,032 $4,394,073 ========== ========== See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY Statements of Cash Flows - ------------------------ Year Ended December 31, ---------------------------------------------- 2002 2001 2000 ---- ---- ---- (in thousands) OPERATING ACTIVITIES: Net Income $ 220,023 $ 147,445 $ 83,737 Adjustments for Noncash Items: Depreciation, Depletion and Amortization 248,557 252,123 200,350 Deferred Income Taxes 46,010 215,833 (65,956) Deferred Investment Tax Credits (3,177) (3,289) (3,399) Deferred Fuel Costs (net) - - (56,869) Extraordinary Loss 18,348 18,876 Mark to Market of Energy Trading Contracts (28,693) (59,833) (5,614) Change in Certain Current Assets and Liabilities: Accounts Receivable (net) 14,571 51,640 51,430 Fuel, Materials and Supplies 704 4,852 46,645 Accrued Utility Revenues 3,081 264 45,311 Accounts Payable 8,704 9,887 56,069 Customer Deposits 7,517 (34,284) 31,540 Taxes Accrued (14,992) (96,331) 60,919 Disputed Tax and Interest Related to COLI - - 110,494 Employee Benefit and Other Noncurrent Liabilities 110,298 (392,026) 145,573 Impairment Loss 1,757 - - Change in Other Assets (2,233) 79,831 (439,448) Change in Other Liabilities (133,154) (107,704) 359,640 --------- --------- --------- Net Cash Flows From Operating Activities 478,973 86,756 639,298 --------- --------- --------- INVESTING ACTIVITIES: Construction Expenditures (354,797) (344,571) (254,016) Proceeds From Sales of Property and Other 6,499 16,778 6,354 Investment in Coal Companies - (32,115) - --------- --------- --------- Net Cash Flows Used For Investing Activities (348,298) (359,908) (247,662) --------- --------- --------- FINANCING ACTIVITIES: Issuance of Long-term Debt - 300,000 74,748 Change in Advances From Affiliates (net) (170,234) 392,699 (92,486) Retirement of Cumulative Preferred Stock - - (182) Retirement of Long-term Debt (140,000) (297,858) (30,663) Change in Short-term Debt (net) 275,000 - (194,918) Dividends Paid on Common Stock (97,746) (142,976) (271,813) Dividends Paid on Cumulative Preferred Stock (1,258) (1,258) (1,262) --------- --------- --------- Net Cash Flows From (Used For) Financing Activities (134,238) 250,607 (516,576) --------- --------- --------- Net Decrease in Cash and Cash Equivalents (3,563) (22,545) (124,940) Cash and Cash Equivalents January 1 8,848 31,393 156,333 --------- --------- --------- Cash and Cash Equivalents December 31 $ 5,285 $ 8,848 $31,393 ======= ======= ======= Supplemental Disclosure: Cash paid (received) for interest net of capitalized amounts was $81,041,000, $94,747,000 and $87,120,000 and for income taxes was $105,058,000, $(22,417,000) and $142,710,000 in 2002, 2001 and 2000, respectively. Noncash acquisitions under capital leases were $106,000, $2,380,000 and $17,005,000 in 2002, 2001 and 2000, respectively. See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY Statements of Capitalization - ---------------------------- December 31, ----------- 2002 2001 ---- ---- (in thousands) COMMON SHAREHOLDER'S EQUITY $1,233,114 $1,184,785 ---------- ---------- PREFERRED STOCK: $100 par value - authorized shares 3,762,403 $25 par value - authorized shares 4,000,000 Call Price Shares December 31, Number of Shares Redeemed Outstanding Series 2002 (a) Year Ended December 31, December 31, 2002 - ------ ------------- --------------------------- ----------------- 2002 2001 2000 ---- ---- ---- Not Subject to Mandatory Redemption-$100 Par: 4.08% $103 - - - 14,595 1,460 1,460 4.20% 103.20 - - 276 22,824 2,282 2,282 4.40% 104 - - 432 31,512 3,151 3,151 4-1/2% 110 - - 2,181 97,546 9,755 9,755 ---------- ---------- 16,648 16,648 ---------- ---------- Subject to Mandatory Redemption-$100 Par (b): 5.90% (c) $ - - - - 72,500 7,250 7,250 6.02% (d) - - - - 11,000 1,100 1,100 6.35% (d) - - - - 5,000 500 500 ---------- ---------- 8,850 8,850 ---------- ---------- LONG-TERM DEBT (See Schedule of Long-term Debt): First Mortgage Bonds 136,633 141,544 Installment Purchase Contracts 233,340 233,235 Senior Unsecured Notes 397,341 396,962 Notes Payable to Affiliated Company 300,000 300,000 Junior Debentures - 132,100 Less Portion Due Within One Year (149,665) - ---------- ---------- Long-term Debt Excluding Portion Due Within One Year 917,649 1,203,841 ---------- ---------- TOTAL CAPITALIZATION $2,176,261 $2,414,124 ========== ========== (a) The cumulative preferred stock is callable at the price indicated plus accrued dividends. (b) Sinking fund provisions require the redemption of 35,000 shares in 2003 and 57,500 shares in each of 2004, 2005, 2006 and 2007. The sinking fund provisions of each series subject to mandatory redemption have been met by purchase of shares in advance of the due dates. Shares previously purchased may be applied to the sinking fund requirement. At the company's option, all shares are redeemable at $100 per share plus accrued and unpaid dividends with at least 30 days notice beginning on or after November 1, 2003 for the 5.09% series, October 1, 2003 for the 6.02% series, and April 1, 2003 for the 6.35% series. (c) 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. (d) Commencing in 2003 and continuing through 2007 sinking fund provisions 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 Schedule of Long-term Debt - -------------------------- First mortgage bonds outstanding were as follows: December 31, ----------- 2002 2001 ---- ---- (in thousands) % Rate Due 6.75 2003 - April 1 $ 29,850 $ 29,850 6.55 2003 - October 1 27,315 27,315 6.00 2003 - November 1 12,500 12,500 6.15 2003 - December 1 20,000 20,000 (a) 2022 - February 10 - 5,000 7.75 2023 - April 1 5,000 5,000 7.375 2023 - October 1 20,250 20,250 7.10 2023 - November 1 12,000 12,000 7.30 2024 - April 1 10,000 10,000 Unamortized Discount (282) (371) -------- -------- Total $136,633 $141,544 ======== ======== (a) Redeemed on May 10, 2002. First mortgage bonds are secured by a first mortgage lien on electric utility plant. Certain supplemental indentures to the first mortgage lien contain 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, ----------- 2002 2001 ---- ---- (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 (1,660) (1,765) Total $233,340 $233,235 ======== ======== 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 of (at stated maturities and upon mandatory redemptions) 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, ----------- 2002 2001 ---- ---- (in thousands) % Rate Due - ------ ------------------ 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 (2,884) (3,263) -------- -------- Total $397,341 $396,962 ======== ======== Notes payable to parent company were as follows: December 31, ----------- 2002 2001 ---- ---- (in thousands) % Rate Due 4.336% 2003 - May 15 $ 60,000 $ 60,000 6.501% 2006 - May 15 240,000 240,000 -------- -------- Total $300,000 $300,000 ======== ======== Junior debentures outstanding were as follows: December 31, ----------- 2002 2001 ---- ---- (in thousands) % Rate Due - ------ ----------------- (a) 2025 - September 30 $ - $ 85,000 (a) 2027 - March 31 - 50,000 Unamortized Discount - (2,900) -------- -------- Total $ - $132,100 ======== ======== (a) Redeemed on July 24, 2002 At December 31, 2002 future annual long-term debt payments are as follows: Amount ------ (in thousands) 2003 $ 149,665 2004 223,000 2005 - 2006 240,000 2007 - Later Years 459,475 ---------- Total Principal Amount 1,072,140 Unamortized Discount 4,826 ---------- Total $1,067,314 ========== OHIO POWER COMPANY Index to Combined Notes to Financial Statements - ----------------------------------------------- The notes to OPCo'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 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 7 Customer Choice and Industry Restructuring Note 8 Commitments and Contingencies Note 9 Guarantees Note 10 Sustained Earnings Improvement Initiative Note 11 Acquisitions, Dispositions and Discontinued Operations Note 12 Asset Impairments and Investment Value Losses Note 13 Benefit Plans Note 14 Business Segments Note 16 Risk Management, Financial Instruments and Derivatives Note 17 Income Taxes Note 18 Supplementary Information Note 20 Leases Note 22 Lines of Credit and Sale of Receivables Note 23 Unaudited Quarterly Financial Information Note 24 Related Party Transactions Note 29 INDEPENDENT AUDITORS' REPORT To the Shareholders and Board of Directors of Ohio Power Company: We have audited the accompanying balance sheets and statements of capitalization of Ohio Power Company as of December 31, 2002 and 2001, 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, 2002. 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 Ohio Power Company as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. /s/ Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY Selected Consolidated Financial Data - ------------------------------------ Year Ended December 31, --------------------------------------------------------------------------------- 2002 2001 2000 1999 1998 ---- ---- ---- ---- ---- (in thousands) INCOME STATEMENTS DATA: Operating Revenues $ 793,647 $957,000 $956,398 $749,390 $780,159 Operating Expenses 708,926 860,012 859,729 650,677 665,085 ---------- -------- -------- -------- -------- Operating Income 84,721 96,988 96,669 98,713 115,074 Nonoperating Items, Net (3,239) 20 8,974 946 (91) Interest Charges 40,422 39,249 38,980 38,151 38,074 ---------- -------- -------- -------- -------- Net Income 41,060 57,759 66,663 61,508 76,909 Preferred Stock Dividend Requirements 213 213 212 212 213 Gain On Reacquired Preferred Stock 1 - - - - ---------- -------- -------- -------- -------- Earnings Applicable to Common Stock $ 40,848 $ 57,546 $ 66,451 $ 61,296 $ 76,696 ========== ======== ======== ======== ======== December 31, --------------------------------------------------------------------------------- 2002 2001 2000 1999 1998 ---- ---- ---- ---- ---- (in thousands) BALANCE SHEETS DATA: Electric Utility Plant $2,759,504 $2,695,099 $2,604,670 $2,459,705 $2,391,722 Accumulated Depreciation and Amortization 1,239,855 1,184,443 1,150,253 1,114,255 1,082,081 ---------- ---------- ---------- ---------- ---------- Net Electric Utility Plant $1,519,649 $1,510,656 $1,454,417 $1,345,450 $1,309,641 ========== ========== ========== ========== ========== Total Assets $1,776,690 $1,748,911 $2,138,423 $1,524,846 $1,471,089 ========== ========== ========== ========== ========== Common Stock and Paid-in Capital $ 337,246 $ 337,246 $ 337,246 $ 337,246 $ 337,246 Accumulated Other Comprehensive Income (Loss) (54,473) - - - - Retained Earnings 116,474 142,994 137,688 139,237 142,941 ---------- ---------- ---------- ---------- ---------- Total Common Shareholder's Equity $ 399,247 $ 480,240 $ 474,934 $ 476,483 $ 480,187 ========== ========== ========== ========== ========== Cumulative Preferred Stock: Not Subject to Mandatory Redemption $ 5,267 $ 5,267 $ 5,267 $ 5,270 $ 5,271 ========== ========== ========== ========== ========== Preferred Securities of Subsidiary Trust $ 75,000 $ 75,000 $ 75,000 $ 75,000 $ 75,000 ========== ========== ========== ========== ========== Long-term Debt (a) $ 545,437 $ 451,129 $ 470,822 $ 384,516 $ 384,064 ========== ========== ========== ========== ========== Total Capitalization and Liabilities $1,776,690 $1,748,911 $2,138,423 $1,524,846 $1,471,089 ========== ========== ========== ========== ========== (a) Including portion due within one year.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY Management's Narrative Analysis of Results of Operations - -------------------------------------------------------- Public Service Company of Oklahoma (PSO) is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to approximately 505,000 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 activities are conducted on PSO's behalf by AEPSC. PSO, along with the other AEP electric operating subsidiaries, shares in AEP's electric power transactions with other utility systems and power marketers. Results of Operations - --------------------- In 2002, Net Income decreased by $17 million or 29% primarily resulting from reduced wholesale margins and increased depreciation expense. Changes in Operating Revenues - ----------------------------- Operating revenues decreased in 2002 as a result of reduced wholesale margins, a decline in fuel recovery revenue and decreases due to the interchange cost reconstruction (ICR) adjustments (see Note 6). Increase (Decrease) From Previous Year ------------------ (dollars in millions) Amount % ------ - Wholesale Electricity* $(149.7) (23) Energy Delivery* 13.6 5 Sales to AEP Affiliates (27.3) (74) ------- Total Operating Revenues $(163.4) (17) ======= *Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery. Changes in Operating Expenses - ----------------------------- Increase (Decrease) From Previous Year ------------------ (dollars in millions) Amount % ------ - Fuel $(215.3) (47) Purchased Power: Wholesale Electricity 23.3 96 AEP Affiliates 45.7 104 Other Operation (4.1) (3) Maintenance 1.9 4 Depreciation and Amortization 5.6 7 Taxes Other Than Income Taxes 2.1 7 Income Taxes (10.3) (30) -------- --- Total $(151.1) (18) ======= === N.M. = Not Meaningful The decrease in Fuel expense in 2002 was primarily due to lower market prices for natural gas and fuel oil, and deferral of underrecovered fuel costs due to the ICR adjustments through the fuel clause recovery mechanism (see Note 6) and to the amortization of previously overrecovered fuel costs. The increase in Electricity Marketing Purchased Power expense in 2002 resulted mainly from ICR adjustments (see Note 6), partially offset by a decrease in energy prices. The increase in the AEP Affiliates Purchased Power expense in 2002 resulted mainly from the ICR adjustments (see Note 6). Other Operation expense decreased in 2002 primarily due to lower transmission expenses and decreased factoring expenses due to reduced revenues. Maintenance expense increased, in 2002 largely as a result of increased expenses to repair damage to overhead lines caused by a winter storm in 2002. Depreciation and Amortization expense increased in 2002 primarily due to the additional depreciable capitalized costs involved in repowering Northeast Station Units 1 & 2 completed in 2001. Taxes Other Than Income Taxes increased in 2002 primarily due to the increase in ad valorem taxes. Income Taxes decreased in 2002 primarily due to a decrease in pre-tax income. Other Changes - ------------- Nonoperating Expenses increased primarily due to the write-down of certain non-utility investments in 2002.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY Consolidated Statements of Income - --------------------------------- Year Ended December 31, ----------------------------------------------- 2002 2001 2000 ---- ---- ---- (in thousands) OPERATING REVENUES: Wholesale Electricity $508,661 $658,352 $696,626 Energy Delivery 275,547 261,877 245,124 Sales to AEP Affiliates 9,439 36,771 14,648 -------- -------- -------- TOTAL OPERATING REVENUES 793,647 957,000 956,398 -------- -------- -------- OPERATING EXPENSES: Fuel 246,199 461,470 402,933 Purchased Power: Wholesale Electricity 47,507 24,187 88,088 AEP Affiliates 89,454 43,758 60,788 Other Operation 133,538 137,678 121,697 Maintenance 48,060 46,188 45,858 Depreciation and Amortization 85,896 80,245 76,418 Taxes Other Than Income Taxes 34,077 31,973 28,688 Income Taxes 24,195 34,513 35,259 -------- -------- -------- TOTAL OPERATING EXPENSES 708,926 860,012 859,729 -------- -------- -------- OPERATING INCOME 84,721 96,988 96,669 NONOPERATING INCOME 1,920 2,112 8,807 NONOPERATING EXPENSES 6,971 1,740 1,139 NONOPERATING INCOME TAX EXPENSE (CREDIT) (1,812) 352 (1,306) INTEREST CHARGES 40,422 39,249 38,980 -------- -------- -------- NET INCOME 41,060 57,759 66,663 GAIN ON REACQUIRED PREFERRED STOCK 1 - - LESS: PREFERRED STOCK DIVIDEND REQUIREMENTS 213 213 212 -------- -------- -------- EARNINGS APPLICABLE TO COMMON STOCK $ 40,848 $ 57,546 $ 66,451 ======== ======== ======== Consolidated Statements of Comprehensive Income - ----------------------------------------------- Year Ended December 31, ----------------------------------------------- 2002 2001 2000 ---- ---- ---- (in thousands) NET INCOME $ 41,060 $57,759 $66,663 OTHER COMPREHENSIVE INCOME (LOSS): Cash Flow Power Hedges (42) - - Minimum Pension Liability (54,431) - - -------- ------- ------- COMPREHENSIVE INCOME (LOSS) $(13,413) $57,759 $66,663 ======== ======= ======= The common stock of PSO is owned by a wholly owned subsidiary of AEP. See Notes to Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY Consolidated Statements of Retained Earnings - -------------------------------------------- Year Ended December 31, --------------------------------------------- 2002 2001 2000 ---- ---- ---- (in thousands) BEGINNING OF PERIOD $142,994 $137,688 $139,237 NET INCOME 41,060 57,759 66,663 DEDUCTIONS Capital Stock Gains (1) - - Cash Dividends Declared: Common Stock 67,368 52,240 68,000 Preferred Stock 213 213 212 -------- -------- -------- BALANCE AT END OF PERIOD $116,474 $142,994 $137,688 ======== ======== ======== The common stock of PSO is owned by a wholly owned subsidiary of AEP. See Notes to Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY Consolidated Balance Sheets - --------------------------- December 31, ----------- 2002 2001 ---- ---- (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production $1,040,520 $1,034,711 Transmission 432,846 427,110 Distribution 990,947 972,806 General 206,747 203,572 Construction Work in Progress 88,444 56,900 ---------- ---------- Total Electric Utility Plant 2,759,504 2,695,099 Accumulated Depreciation and Amortization 1,239,855 1,184,443 ---------- ---------- NET ELECTRIC UTILITY PLANT 1,519,649 1,510,656 ---------- ---------- OTHER PROPERTY AND INVESTMENTS 5,383 41,020 ---------- ---------- LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 4,481 21,354 ---------- ---------- CURRENT ASSETS: Cash and Cash Equivalents 16,774 5,795 Accounts Receivable: Customers 31,687 31,144 Affiliated Companies 14,139 10,905 Allowance for Uncollectible Accounts (84) (44) Fuel Inventory 19,973 21,559 Materials and Supplies 37,375 36,785 Under-recovered Fuel Costs 76,470 756 Energy Trading and Derivative Contracts 3,841 26,259 Prepayments and Other 2,735 2,368 ---------- ---------- TOTAL CURRENT ASSETS 202,910 135,527 ---------- ---------- REGULATORY ASSETS 26,150 35,064 ---------- ---------- DEFERRED CHARGES 18,117 5,290 ---------- ---------- TOTAL ASSETS $1,776,690 $1,748,911 ========== ========== See Notes to Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY December 31, ----------- 2002 2001 ---- ---- (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 180,016 180,016 Accumulated Other Comprehensive Income (Loss) (54,473) - Retained Earnings 116,474 142,994 ---------- ---------- Total Common Shareholder's Equity 399,247 480,240 ---------- ---------- Cumulative Preferred Stock Not Subject to Mandatory Redemption 5,267 5,267 PSO-Obligated, Mandatorily Redeemable Preferred Securities of Subsidiary Trust Holding Solely Junior Subordinated Debentures of PSO 75,000 75,000 Long-term Debt 445,437 345,129 ---------- ---------- TOTAL CAPITALIZATION 924,951 905,636 ---------- ---------- OTHER NONCURRENT LIABILITIES 54,761 7,263 ---------- ---------- CURRENT LIABILITIES: Long-term Debt Due Within One Year 100,000 106,000 Advances from Affiliates 86,105 123,087 Accounts Payable - General 61,169 72,759 Accounts Payable - Affiliated Companies 78,076 40,857 Customer Deposits 21,789 21,041 Over-Recovered Fuel Costs - 9,476 Taxes Accrued 6,854 18,150 Interest Accrued 6,979 7,298 Energy Trading and Derivative Contracts 3,260 31,718 Other 24,957 12,216 ---------- ---------- TOTAL CURRENT LIABILITIES 389,189 442,602 ---------- ---------- DEFERRED INCOME TAXES 341,396 296,877 ---------- ---------- DEFERRED INVESTMENT TAX CREDITS 32,201 33,992 ---------- ---------- REGULATORY LIABILITIES AND DEFERRED CREDITS 32,611 49,080 ---------- ---------- LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 1,581 13,461 ---------- ---------- COMMITMENTS AND CONTINGENCIES (Note 9) TOTAL CAPITALIZATION AND LIABILITIES $1,776,690 $1,748,911 ========== ========== See Notes to Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY Consolidated Statements of Cash Flows - ------------------------------------- Year Ended December 31, --------------------------- 2002 2001 2000 ---- ---- ---- (in thousands) OPERATING ACTIVITIES: Net Income $ 41,060 $ 57,759 $ 66,663 Adjustments to Reconcile Net Income to Net Cash from Operating Activities: Depreciation and Amortization 85,896 80,245 76,418 Deferred Income Taxes 75,659 (17,751) 25,453 Deferred Investment Tax Credits (1,791) (1,791) (1,791) Changes in Certain Assets and Liabilities: Accounts Receivable (net) (3,737) 21,405 (28,826) Fuel, Materials and Supplies 996 (589) 677 Other Property and Investments (419) (2,809) 7,994 Accounts Payable 25,629 (55,319) 89,330 Taxes Accrued (11,296) 16,491 (16,821) Fuel Recovery (85,190) 51,987 (36,798) Transmission Coordination Agreement Settlement - - (15,063) Changes in Other Assets 2,215 (9,120) 4,482 Changes in Other Liabilities (6,928) 9,351 (6,103) --------- --------- --------- Net Cash From Operating Activities 122,094 149,859 165,615 --------- --------- --------- INVESTING ACTIVITIES: Construction Expenditures (89,365) (124,520) (176,851) Proceeds from Sale of Property 963 - - Other Items - (359) - --------- --------- --------- Net Cash Used For Investing Activities (88,402) (124,879) (176,851) --------- --------- --------- FINANCING ACTIVITIES: Issuance of Long-term Debt 187,850 - 105,625 Retirement of Long-term Debt (106,000) (20,000) (20,000) Change in Advances From Affiliates (net) (36,982) 41,967 1,951 Dividends Paid on Common Stock (67,368) (52,240) (68,000) Dividends Paid on Cumulative Preferred Stock (213) (213) (212) --------- --------- --------- Net Cash From (used For) Financing Activities (22,713) (30,486) 19,364 --------- --------- --------- Net Increase (Decrease) in Cash and Cash Equivalents 10,979 (5,506) 8,128 Cash and Cash Equivalents January 1 5,795 11,301 3,173 --------- --------- --------- Cash and Cash Equivalents December 31 $ 16,774 $ 5,795 $ 11,301 ========= ========= ========= Supplemental Disclosure: Cash paid (received) for interest net of capitalized amounts was $38,620,000, $38,250,000 and $33,732,000 and for income taxes was ($38,943,000), $38,653,000 and $25,786,000 in 2002, 2001 and 2000, respectively. See Notes to Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY Consolidated Statements of Capitalization - ----------------------------------------- December 31, ------------ 2002 2001 ---- ---- (in thousands) COMMON SHAREHOLDER'S EQUITY $ 399,247 $480,240 --------- -------- 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 2002 Year Ended December 31, December 31, 2002 - ------ ------------ ---------------------------- ----------------- 2002 2001 2000 ---- ---- ---- Not Subject to Mandatory Redemption: 4.00% $105.75 6 - 25 44,600 4,460 4,460 4.24% 103.19 - - - 8,069 807 807 --------- --------- 5,267 5,267 --------- --------- 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 298,079 297,772 Installment Purchase Contracts 47,358 47,357 Senior Unsecured Notes 200,000 106,000 Less Portion Due Within One Year (100,000) (106,000) --------- -------- Long-term Debt Excluding Portion Due Within One Year 445,437 345,129 --------- -------- TOTAL CAPITALIZATION $ 924,951 $905,636 ========= ======== See Notes to Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY Schedule of Long-term Debt - -------------------------- First mortgage bonds outstanding were as follows: December 31, ----------- 2002 2001 ---- ---- (in thousands) % Rate Due 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 (1,921) (2,228) -------- -------- $298,079 $297,772 First mortgage bonds are secured by a first mortgage lien on electric utility plant. The indenture, as supplemented, relating to the first mortgage bonds contains 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, ----------- 2002 2001 ---- ---- (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 (2) (3) ------- ------- Total $47,358 $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 of (at stated maturities and upon mandatory redemptions) 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, ----------- 2002 2001 ---- ---- (in thousands) % Rate Due (a) 2002 - November 21 $ - $106,000 (b) 2032 - December 31 200,000 - -------- -------- TOTAL $200,000 $106,000 ======== ======== (a) A floating interest rate is determined monthly. The rate on December 31, 2001 was $2.775%. (b) A fixed interest rate of 6.00% was the rate on December 31, 2002. At December 31, 2002, future annual long-term debt payments are as follows: Amount ------ (in thousands) 2003 $100,000 2004 50,000 2005 50,000 2006 - 2007 1,000 Later Years 346,360 -------- Total Principal Amount 547,360 Unamortized Discount (1,923) -------- Total $545,437 ======== See Note 25 for discussion of the Trust Preferred Securities issued by a wholly owned statutory business trust of PSO (see Note 25). PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY Index to Combined Notes to Consolidated Financial Statements - ------------------------------------------------------------ The notes to PSO's consolidated 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 PSO. The combined footnotes begin on page L-1. Combined Footnote Reference --------- Significant Accounting Policies Note 1 Merger Note 4 Rate Matters Note 6 Effects of Regulation Note 7 Customer Choice and Industry Restructuring Note 8 Commitments and Contingencies Note 9 Guarantees Note 10 Sustained Earnings Improvement Initiative Note 11 Benefit Plans Note 14 Business Segments Note 16 Risk Management, Financial Instruments and Derivatives Note 17 Income Taxes Note 18 Leases Note 22 Lines of Credit and Sale of Receivables Note 23 Unaudited Quarterly Financial Information Note 24 Trust Preferred Securities Note 25 Jointly Owned Electric Utility Plant Note 28 Related Party Transactions Note 29 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 subsidiary as of December 31, 2002 and 2001, 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, 2002. 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 Public Service Company of Oklahoma and subsidiary as of December 31, 2002 and 2001, and the results of their operations and their cash flows each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. /s/ Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Selected Consolidated Financial Data - ------------------------------------ Year Ended December 31, ------------------------------------------------------------------------------------ 2002 2001 2000 1999 1998 ---- ---- ---- ---- ---- (in thousands) INCOME STATEMENTS DATA: Operating Revenues $1,084,720 $1,101,326 $1,118,274 $ 971,527 $ 952,952 Operating Expenses 942,251 955,119 989,996 824,465 802,274 ---------- ---------- ---------- ---------- ---------- Operating Income 142,469 146,207 128,278 147,062 150,678 Nonoperating Items, Net (309) 741 3,851 (1,965) 2,451 Interest Charges 59,168 57,581 59,457 58,892 55,135 ---------- ---------- ---------- ---------- ---------- Income Before Extraordinary Item 82,992 89,367 72,672 86,205 97,994 Extraordinary Loss - - - (3,011) - ---------- ---------- ---------- ---------- ---------- Net Income 82,992 89,367 72,672 83,194 97,994 Preferred Stock Dividend Requirements 229 229 229 229 705 Loss on Reacquired Preferred Stock - - - - (856) ---------- ---------- ---------- ---------- ---------- Earnings Applicable to Common Stock $ 82,763 $ 89,138 $ 72,443 $ 82,965 $ 96,433 ========== ======== ======== ========== ========== December 31, ------------------------------------------------------------------------------------ 2002 2001 2000 1999 1998 ---- ---- ---- ---- ---- (in thousands) BALANCE SHEETS DATA: Electric Utility Plant $3,596,174 $3,460,764 $3,319,024 $3,231,431 $3,157,911 Accumulated Depreciation and Amortization 1,697,338 1,550,618 1,457,005 1,384,242 1,317,057 ---------- ---------- ---------- ---------- ---------- Net Electric Utility Plant $1,898,836 $1,910,146 $1,862,019 $1,847,189 $1,840,854 ========== ========== ========== ========== ========== Total Assets $2,208,675 $2,300,676 $2,658,389 $2,106,762 $2,082,258 ========== ========== ========== ========== ========== Common Stock and Paid-in Capital $ 380,663 $ 380,663 $ 380,663 $ 380,663 $ 380,663 Accumulated Other Comprehensive Income (Loss) (53,683) - - - - Retained Earnings 334,789 308,915 293,989 283,546 296,581 ---------- ---------- ---------- ---------- ---------- Total Common Shareholder's Equity $ 661,769 $ 689,578 $ 674,652 $ 664,209 $ 677,244 ========== ========== ========== ========== ========== Preferred Stock $ 4,701 $ 4,701 $ 4,701 $ 4,703 $ 4,704 ========== ========== ========= ========== ========== Trust Preferred Securities $ 110,000 $ 110,000 $ 110,000 $ 110,000 $ 110,000 ========== ========== ========== ========== ========== Long-term Debt (a) $ 693,448 $ 645,283 $ 645,963 $ 541,568 $ 587,673 ========== ========== ========== ========== ========== Total Capitalization and Liabilities $2,208,675 $2,300,676 $2,658,389 $2,106,762 $2,082,258 ========== ========== ========== ========== ========== (a) Including portion due within one year.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Management's Discussion and Analysis of Results of Operations - ------------------------------------------------------------- Southwestern Electric Power Company (SWEPCo) is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to approximately 437,000 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 activities are conducted on SWEPCo's behalf by AEPSC. SWEPCo, along with the other AEP electric operating subsidiaries, shares in AEP's electric power transactions with other utility systems and power marketers. Results of Operations - --------------------- In 2002, Net Income decreased $6.4 million or 7% primarily resulting from reduced margins. In 2001, Net Income increased $16.7 million or 23% resulting primarily from the favorable impact of our sharing in AEP's power marketing activities for a full year. Changes in Operating Revenues - ----------------------------- Increase (Decrease) From Previous Year ------------------ (dollars in millions) 2002 2001 ---- ---- Amount % Amount % ------ - ------ - Wholesale Electricity* $(25) (4) $(21) (3) Energy Delivery* 15 5 (12) (3) Sales to AEP Affiliates (7) (9) 16 26 ---- ---- Total Operating Revenues $(17) (2) $(17) (2) ==== ==== *Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery. Operating Revenues decreased 2% for 2002 primarily due to decreased fuel revenues offset in part by the addition of the Dolet Hills mining operation ($12.6 million) and the positive impact of the interchange cost reconstruction (ICR) adjustments (see Note 6). In 2001, Operating Revenues decreased $17 million or 2% resulting from unfavorable wholesale marketing and trading conditions. Changes in Operating Expenses - ----------------------------- Increase (Decrease) From Previous Year ------------------ (dollars in millions) 2002 2001 ---- ---- Amount % Amount % ------ - ------ - Fuel $(69) (15) $(41) (8) Purchased Power: Wholesale Electricity 26 143 (40) (69) AEP Affiliates 26 165 2 19 Other Operation 18 10 12 7 Maintenance (8) (10) - (1) Depreciation and Amortization 3 3 15 14 Taxes Other Than Income Taxes (1) (1) 2 4 Income Taxes (8) (20) 16 60 ---- ---- Total $(13) (1) $(34) (4) ==== ==== Fuel expense decreased in 2002 due to a reduction in MWH generated and a decrease in the cost of fuel, primarily natural gas. Fuel expense decreased in 2001 from lower natural gas prices and a mild summer resulting in a reduction in generation. In 2002, Purchased Power increased primarily due to the impact of ICR adjustments (see Note 6). In 2001, the decrease in Purchased Power expense was mainly due to reduced prices caused by decreased electricity demand. The acquisition of Dolet Hills Lignite Company (Dolet Hills) in June 2001 caused Other Operation expense to increase in 2002 by $4.3 million. Other Operation expense was also impacted by the ICR adjustments (see Note 6). In 2001, Other Operation expense increased also as a result of the Dolet Hills mining operation in June 2001. The 10% decrease in Maintenance expense in 2002 is primarily a result of higher storm and tree trimming related expenses in 2001. The increase in Depreciation and Amortization expense in 2002 is primarily due to the addition of Dolet Hills in June 2001, which added $3.0 million of additional expense in 2002. 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. In 2002, the decrease in Income Taxes was due to a decrease in pre-tax income. In 2001, the increase in income tax expense was primarily due to an increase in pre-tax income.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Income - --------------------------------- Year Ended December 31, ------------------------------------------------ 2002 2001 2000 ---- ---- ---- (in thousands) OPERATING REVENUES: Wholesale Electricity $ 664,185 $ 689,085 $ 710,200 Energy Delivery 348,236 333,004 344,950 Sales to AEP Affiliates 72,299 79,237 63,124 ---------- ---------- ---------- TOTAL OPERATING REVENUES 1,084,720 1,101,326 1,118,274 ---------- ---------- ---------- OPERATING EXPENSES: Fuel 388,334 457,613 498,805 Purchased Power: Wholesale Electricity 44,119 18,164 58,518 AEP Affiliates 42,022 15,858 13,338 Other Operation 189,024 171,314 159,459 Maintenance 66,855 74,677 75,123 Depreciation and Amortization 122,969 119,543 104,679 Taxes Other Than Income Taxes 55,232 55,834 53,830 Income Taxes 33,696 42,116 26,244 ---------- ---------- ---------- TOTAL OPERATING EXPENSES 942,251 955,119 989,996 ---------- ---------- ---------- OPERATING INCOME 142,469 146,207 128,278 NONOPERATING INCOME 3,260 4,512 5,487 NONOPERATING EXPENSES 1,797 3,229 3,112 NONOPERATING INCOME TAX EXPENSE (CREDIT) 1,772 542 (1,476) INTEREST CHARGES 59,168 57,581 59,457 ---------- ---------- ---------- NET INCOME 82,992 89,367 72,672 PREFERRED STOCK DIVIDEND REQUIREMENTS 229 229 229 ---------- ---------- ---------- EARNINGS APPLICABLE TO COMMON STOCK $ 82,763 $ 89,138 $ 72,443 ========== ========== ========== Consolidated Statements of Comprehensive Income - ----------------------------------------------- Year Ended December 31, ----------------------------------------------- 2002 2001 2000 ---- ---- ---- (in thousands) NET INCOME $82,992 $89,367 $72,672 OTHER COMPREHENSIVE INCOME (LOSS): Cash Flow Power Hedges (48) - - Minimum Pension Liability (53,635) - - ------- ------- ------- COMPREHENSIVE INCOME $29,309 $89,367 $72,672 ======= ======= ======= The common stock of SWEPCo is owned by a wholly owned subsidiary of AEP. See Notes to Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Retained Earnings - -------------------------------------------- Year Ended December 31, ---------------------------------------------- 2002 2001 2000 ---- ---- ---- (in thousands) BALANCE AT BEGINNING OF PERIOD $308,915 $293,989 $283,546 NET INCOME 82,992 89,367 72,672 DEDUCTIONS: Cash Dividends Declared: Common Stock 56,889 74,212 62,000 Preferred Stock 229 229 229 -------- -------- -------- BALANCE AT END OF PERIOD $334,789 $308,915 $293,989 ======== ======== ======== The common stock of SWEPCo is owned by a wholly owned subsidiary of AEP. See Notes to Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Consolidated Balance Sheets - --------------------------- December 31, ----------- 2002 2001 ---- ---- (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production $1,503,722 $1,429,356 Transmission 575,003 538,749 Distribution 1,063,564 1,042,523 General 378,130 376,016 Construction Work in Progress 75,755 74,120 ---------- ---------- Total Electric Utility Plant 3,596,174 3,460,764 Accumulated Depreciation and Amortization 1,697,338 1,550,618 ---------- ---------- NET ELECTRIC UTILITY PLANT 1,898,836 1,910,146 ---------- ---------- OTHER PROPERTY AND INVESTMENTS 5,978 43,000 ---------- ---------- LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 5,119 24,508 ---------- ---------- CURRENT ASSETS: Cash and Cash Equivalents 2,069 5,415 Accounts Receivable: Customers 62,359 43,133 Affiliated Companies 19,253 12,069 Allowance for Uncollectible Accounts (2,128) (89) Fuel Inventory 61,741 52,212 Materials and Supplies 33,539 32,527 Under-recovered Fuel Costs 2,865 8,839 Energy Trading and Derivative Contracts 4,388 30,139 Prepayments and Other 17,851 18,716 ---------- ---------- TOTAL CURRENT ASSETS 201,937 202,961 ---------- ---------- REGULATORY ASSETS 49,233 52,308 ---------- ---------- DEFERRED CHARGES 47,572 67,753 ---------- ---------- TOTAL ASSETS $2,208,675 $2,300,676 ========== ========== See Notes to Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES December 31, ----------- 2002 2001 ---- ---- (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 245,003 245,003 Accumulated Other Comprehensive Income (Loss) (53,683) - Retained Earnings 334,789 308,915 ---------- ---------- Total Common Shareholder's Equity 661,769 689,578 Preferred Stock 4,701 4,701 SWEPCo-Obligated, Mandatorily Redeemable Preferred Securities of Subsidiary Trust Holding Solely Junior Subordinated Debentures of SWEPCo 110,000 110,000 Long-term Debt 637,853 494,688 ---------- ---------- TOTAL CAPITALIZATION 1,414,323 1,298,967 ---------- ---------- OTHER NONCURRENT LIABILITIES 78,494 40,109 ---------- ---------- CURRENT LIABILITIES: Long-term Debt Due Within One Year 55,595 150,595 Advances from Affiliates, net 23,239 117,367 Accounts Payable - General 62,139 71,810 Accounts Payable - Affiliated Companies 58,773 37,469 Customer Deposits 20,110 19,880 Taxes Accrued 19,081 36,522 Interest Accrued 17,051 13,027 Energy Trading and Derivative Contracts 3,724 36,297 Over-recovered Fuel 17,226 5,487 Other 34,565 26,074 ---------- ---------- TOTAL CURRENT LIABILITIES 311,503 514,528 ---------- ---------- DEFERRED INCOME TAXES 341,064 369,781 ---------- ---------- DEFERRED INVESTMENT TAX CREDITS 44,190 48,714 ---------- ---------- REGULATORY LIABILITIES AND DEFERRED CREDITS 17,295 13,127 ---------- ---------- LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 1,806 15,450 ---------- ---------- COMMITMENTS AND CONTINGENCIES (Note 9) TOTAL CAPITALIZATION AND LIABILITIES $2,208,675 $2,300,676 ========== ========== 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, -------------------------------------------- 2002 2001 2000 ---- ---- ---- (in thousands) OPERATING ACTIVITIES: Net Income $ 82,992 $ 89,367 $ 72,672 Adjustments to Reconcile Net Income to Net Cash Flows From Operating Activities: Depreciation and Amortization 122,969 119,543 104,679 Deferred Income Taxes (3,134) (31,396) 14,653 Deferred Investment Tax Credits (4,524) (4,453) (4,482) Mark-to-Market Energy Trading and Derivative Contracts (1,151) (10,695) 7,795 Changes in Certain Current Assets and Liabilities: Accounts Receivable (net) (24,371) (11,447) (1,254) Fuel, Materials and Supplies (10,541) (19,578) 22,103 Accounts Payable 11,633 (34,489) 43,962 Taxes Accrued (17,441) 25,298 (13,150) Transmission Coordination Agreement Settlement - - (24,406) Fuel Recovery 17,713 34,423 (38,357) Change in Other Assets 24,257 1,323 54,414 Change in Other Liabilities 12,161 11,714 (37,001) --------- --------- --------- Net Cash Flows From Operating Activities 210,563 169,610 201,628 --------- --------- --------- INVESTING ACTIVITIES: Construction Expenditures (111,775) (111,725) (120,671) Purchase of Dolet Hills Mining Operations - (85,716) - Other 1,134 (411) 446 --------- --------- --------- Net Cash Flows Used For Investing Activities (110,641) (197,852) (120,225) --------- --------- --------- FINANCING ACTIVITIES: Issuance of Long-term Debt 198,573 - 149,360 Redemption of Preferred Stock - - (1) Retirement of Long-term Debt (150,595) (595) (45,595) Change in Advances From Affiliates (net) (94,128) 106,786 (124,074) Dividends Paid on Common Stock (56,889) (74,212) (62,000) Dividends Paid on Cumulative Preferred Stock (229) (229) (229) --------- --------- --------- Net Cash Flows From (Used For) Financing Activities (103,268) 31,750 (82,539) --------- --------- --------- Net Increase (Decrease) in Cash and Cash Equivalents (3,346) 3,508 (1,136) Cash and Cash Equivalents January 1 5,415 1,907 3,043 --------- --------- --------- Cash and Cash Equivalents December 31 $ 2,069 $ 5,415 $ 1,907 ========= ========= ========= Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $49,008,000, $51,126,000 and $51,111,000 and for income taxes was $60,451,000, $49,901,000 and $27,994,000 in 2002, 2001, and 2000, respectively. See Notes to Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Capitalization - ----------------------------------------- December 31, ----------- 2002 2001 ---- ---- (in thousands) COMMON SHAREHOLDER'S EQUITY $ 661,769 $ 689,578 ---------- ---------- PREFERRED STOCK: $100 par value - authorized shares 1,860,000 Call Price Shares December 31, Number of Shares Redeemed Outstanding Series 2002 Year Ended December 31, December 31, 2002 - ------ ------------ ---------------------------- ----------------- 2002 2001 2000 ---- ---- ---- Not Subject to Mandatory Redemption: 4.28% $103.90 - - - 7,386 740 740 4.65% $102.75 - - - 1,907 190 190 5.00% $109.00 - - 12 37,715 3,771 3,771 ---------- ---------- 4,701 4,701 ---------- ---------- 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 315,420 315,449 Installment Purchase Contracts 179,183 179,834 Senior Unsecured Notes 198,845 150,000 Less Portion Due Within One Year (55,595) (150,595) ---------- ---------- Long-term Debt Excluding Portion Due Within One Year 637,853 494,688 ---------- ---------- TOTAL CAPITALIZATION $1,414,323 $1,298,967 ========== ========== 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, ----------- 2002 2001 ---- ---- (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 5,505 5,650 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 (1,085) (1,201) -------- -------- $315,420 $315,449 ======== ======== First mortgage bonds are secured by a first mortgage lien on electric utility plant. The indenture, as supplemented, relating to the first mortgage bonds contains 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, ----------- 2002 2001 ---- ---- (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 12,620 13,070 8.20 2011 - August 1 17,125 17,125 Unamortized Premium 1,948 2,149 -------- -------- $179,183 $179,834 ======== ======== 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 of (at stated maturities and upon mandatory redemptions) 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, ----------- 2002 2001 ---- ---- (in thousands) % Rate Due - ------ ------------------ 4.50 2005 - July 1 $200,000 $ - (a) 2002 - March 1 - 150,000 Unamortized Discount (1,155) - -------- -------- $198,845 $150,000 ======== ======== (a)A floating interest rate is determined monthly. The rate on December 31, 2001 was 2.311%. At December 31, 2002 future annual long-term debt payments are as follows: Amount ------ (in thousands) 2003 $ 55,595 2004 52,885 2005 200,595 2006 6,520 2007 90,450 Later Years 287,695 -------- Total Principal Amount 693,740 Unamortized Discount (292) -------- Total $693,448 ======== See Note 25 for discussion of Trust Preferred Securities issued by a wholly-owned statutory business trust of SWEPCo. SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Index to Combined Notes to Consolidated Financial Statements - ------------------------------------------------------------ The notes to SWEPCo's consolidated 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 SWEPCo. The combined footnotes begin on page L-1. Combined Footnote Reference --------- Significant Accounting Policies Note 1 Extraordinary Items and Cumulative Effect Note 2 Goodwill and Other Intangible Assets Note 3 Merger Note 4 Rate Matters Note 6 Effects of Regulation Note 7 Customer Choice and Industry Restructuring Note 8 Commitments and Contingencies Note 9 Guarantees Note 10 Sustained Earnings Improvement Initiative Note 11 Acquisitions, Dispositions and Discontinued Operations Note 12 Benefit Plans Note 14 Business Segments Note 16 Risk Management, Financial Instruments and Derivatives Note 17 Income Taxes Note 18 Leases Note 22 Lines of Credit and Sale of Receivables Note 23 Unaudited Quarterly Financial Information Note 24 Trust Preferred Securities Note 25 Jointly Owned Electric Utility Plant Note 28 Related Party Transactions Note 29 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, 2002 and 2001, 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, 2002. 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 Southwestern Electric Power Company and subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. /s/ Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio February 21, 2003 COMBINED NOTES TO FINANCIAL STATEMENTS Index to Combined 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, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC 2. Extraordinary Items and AEP, APCo, CSPCo, OPCo, SWEPCo, Cumulative Effect TCC, TNC 3. Goodwill and Other Intangible Assets AEP, SWEPCo 4. Merger AEP, I&M, KPCo, PSO, SWEPCo, TCC, TNC 5. Nuclear Plant Restart AEP, I&M 6. Rate Matters AEP, KPCo, PSO, SWEPCo, TCC, TNC 7. Effects of Regulation AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC 8. Customer Choice and Industry AEP, APCo, CSPCo, I&M, OPCo, PSO, Restructuring SWEPCo, TCC, TNC 9. Commitments and Contingencies AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC 10. Guarantees AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC 11. Sustained Earnings Improvement AEP, AEGCo, APCo, CSPCo, I&M, KPCo, Initiative OPCo, PSO, SWEPCo, TCC, TNC 12. Acquisitions, Dispositions and AEP, OPCo, SWEPCo, TCC, TNC Discontinued Operations 13. Asset Impairments and Investment AEP, APCo, CSPCo, I&M, KPCo, OPCo, Value Losses TCC, TNC 14. Benefit Plans AEP, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC 15. Stock-Based Compensation AEP 16. Business Segments AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC 17. Risk Management, Financial AEP, AEGCo, APCo, CSPCo, I&M, KPCo, Instruments and Derivatives OPCo, PSO, SWEPCo, TCC, TNC 18. Income Taxes AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC 19. Basic and Diluted Earnings Per Share AEP 20. Supplementary Information AEP, APCo, CSPCo, I&M, OPCo 21. Power and Distribution Projects AEP 22. Leases AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC 23. Lines of Credit and Sale AEP, AEGCo, APCo, CSPCo, I&M, KPCo, of Receivables OPCo, PSO, SWEPCo, TCC, TNC 24. Unaudited Quarterly Financial AEP, AEGCo, APCo, CSPCo, I&M, KPCo, Information OPCo, PSO, SWEPCo, TCC, TNC 25. Trust Preferred Securities AEP, PSO, SWEPCo, TCC 26. Minority Interest in Finance AEP Subsidiary 27. Equity Units AEP 28. Jointly Owned Electric Utility Plant CSPCo, PSO, SWEPCo, TCC, TNC 29. Related Party Transactions AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC 30. Subsequent Events (Unaudited) AEP 1. Significant Accounting Policies: Business Operations - AEP's (the Company'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, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC, 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, other commodities in the United States and Europe. In addition, the Company's domestic operations include non-regulated independent power and cogeneration facilities, coal mining and intra-state midstream natural gas operations in Louisiana and Texas. International operations include supply of electricity and other non-regulated power generation projects in the United Kingdom, and to a lesser extent in Mexico, Australia, China and the Pacific Rim region. These operations are either wholly-owned or partially-owned by various AEP subsidiaries. We also maintained operations in Brazil through the fourth quarter of 2002. See Note 13 for discussion of impaired investments and assets held for sale. The Company also operates domestic barging operations, provides various energy related services and furnishes communications related services domestically. See Note 13 for further discussion of changes in our communications related business and other business operations announced in 2002. 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 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, CSPCo, I&M, PSO, SWEPCo and TCC 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 TCC, TNC, and SWEPCo in September 1999 and in Arkansas by SWEPCo in September 1999. See Note 8, "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 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 overhead incurred to operate and maintain plant are included in operating expenses. Plants are tested for impairment as required under SFAS 144. See Note 13. 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 2002, 2001 and 2000 were not significant. Effective with the discontinuance of SFAS 71 regulatory accounting for domestic generating assets in Arkansas, Ohio, Texas, Virginia, West Virginia and 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 2002, 2001, and 2000. 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 - ---------------- ------------------ 2002 ---- Production: Steam-Nuclear 2.5% to 3.4% Steam-Fossil-Fired 2.6% to 4.5% Hydroelectric- Conventional and Pumped Storage 1.9% to 3.4% Transmission 1.7% to 3.0% Distribution 3.3% to 4.2% Other 1.8% to 9.9% 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% The following table provides the annual composite depreciation rates generally used by the AEP registrant subsidiaries for the years 2002, 2001 and 2000 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 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 6.3 SWEPCo - 3.4 - 2.7 3.6 4.7 TCC 2.5 2.6 1.9 2.3 3.5 4.0 TNC - 2.8 - 3.1 3.3 6.8
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. These costs are included in the cost of coal charged to fuel expense for coal used by utility operations. Current average amortization rates are $0.32 per ton in 2002, $3.46 per ton in 2001 and $5.07 per ton in 2000. In 2001, an AEP subsidiary sold coal mines in Ohio and West Virginia. See Note 12, Acquisitions, Dispositions and Discontinued Operations for further discussion of the changes in our coal investments leading to the decline in amortization rates in 2002. Cash and Cash Equivalents - Cash and cash equivalents include temporary cash investments with original maturities of three months or less. Inventory - Except for PSO, TCC and TNC, the regulated domestic utility companies value fossil fuel inventories using a weighted average cost method. PSO, TCC and TNC, 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. Materials and supplies inventories are carried at average cost. Non-trading gas inventory is carried at the lower of cost or market. In compliance with EITF 02-03 as described in the New Accounting Pronouncements section of Note 1, natural gas inventories held in connection with trading operations at October 25, 2002 continued to be carried at fair value until December 31, 2002, and inventory purchased from October 26 through December 31, 2002 was carried at the lower of cost or market. Effective January 1, 2003, all natural gas inventories held in connection with trading operations will be adjusted to the historical cost basis and carried at the lower of cost or market. We estimate the adjustment in January 2003 will decrease the value of natural gas inventories held in connection with trading operations by approximately $39 million. This change will be accounted for as a cumulative effect of a change in accounting principle. Accounts Receivable - AEP Credit, Inc. factors accounts receivable for certain of the domestic utility subsidiaries and, until the first quarter of 2002, factored accounts receivable for 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 company's balance sheet. See Note 23 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 Statements of Cash Flows in Effect of Exchange Rate Changes 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 $143 million at December 31, 2002 and $139 million at December 31, 2001. See Note 7 "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. 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 6, "Rate Matters" and Note 8, "Customer Choice and Industry Restructuring" for further information about fuel recovery. Revenue Recognition - Regulatory Accounting - The consolidated financial statements of AEP and the financial statements of electric operating subsidiary companies with cost-based rate-regulated operations (I&M, KPCo, PSO, and a portion of APCo, OPCo, CSPCo, TCC, TNC and SWEPCo), 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 to be recovered in the future) and regulatory liabilities (deferred 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 and by matching income with its passage to customers through regulated revenues in the same accounting period. Regulatory liabilities are also recorded to provide currently for refunds to customers that have not yet been made. 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 - Revenues are recognized on the accrual or settlement basis for normal retail and wholesale 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 purchased electricity is received and when expenses are incurred. Domestic Gas Pipeline and Storage Activities - Revenues are recognized from domestic gas pipeline and storage services when gas is delivered to contractual meter points or when services are provided. Transportation and storage revenues also include the accrual of earned, but unbilled and/or not yet metered gas. Substantially all of the forward gas purchase and sale contracts, excluding wellhead purchases of natural gas, swaps and options for the domestic pipeline operations, qualify as derivative financial instruments as defined by SFAS 133. Accordingly, net gains and losses resulting from revaluation of these contacts to fair value during the period are recognized currently in the results of operations, appropriately discounted and net of applicable credit and liquidity reserves. Energy Marketing and Trading Transactions - In 2000, 2001 and throughout the majority of 2002, AEP engaged in wholesale electricity, natural gas and other commodity marketing and trading transactions (trading activities). Trading activities involve 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. We use the mark-to-market method of accounting for trading activities as required by EITF Issue No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" (EITF 98-10). Under the mark-to-market method of accounting, gains and losses from settlements of forward trading contracts are recorded net in revenues. For energy contracts not yet settled, whether physical or financial, changes in fair value are recorded net in revenues as unrealized gains and losses from mark-to-market valuations. When positions are settled and gains and losses are realized, the previously recorded unrealized gains and losses from mark-to-market valuations are reversed. In October 2002, management announced plans to focus on wholesale markets around owned assets. All of the registrant subsidiaries except AEGCo participate in AEP's wholesale marketing and trading of electricity. For I&M, KPCo, PSO and a portion of TNC and SWEPCo, when the contract settles the total gain or loss is realized in cash. Where this amount is recorded 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 for sales and the cost of purchased energy are included in revenues on a net basis. 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 contracts with delivery points outside of AEP's traditional marketing area only the difference between the accumulated unrealized net gains or losses recorded in prior periods and the cash proceeds is recognized in the income statement as nonoperating income. 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. For APCo, CSPCo and OPCo, depending on whether the delivery point for the electricity is in AEP's traditional marketing area or not determines where the contract is reported in the income statement. Physical forward trading sale and purchase contracts with delivery points in AEP's traditional marketing area are included in revenues on a net basis. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts in AEP's traditional marketing area are also included in revenues on a net basis. Physical forward sale and purchase contracts for delivery outside of AEP's traditional marketing area are included in nonoperating income 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. The trading of energy options, futures and swaps, represents financial transactions with unrealized gains and losses from changes in fair values reported net in AEP's revenues until the contracts settle. When these contracts settle, the net proceeds are recorded in revenues and reverse the prior cumulative unrealized net gain or loss. APCo, CSPCo, OPCo, I&M and KPCo also have financial transactions, but record the unrealized gains and losses, as well as the net proceeds upon settlement, in nonoperating income. 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 models are derived from internally assessed market prices with the exception of the NYMEX gas curve, where we use daily settled prices. All fair value amounts are net of appropriate valuation adjustments for items such as discounting, liquidity and credit quality. Such valuation adjustments provide for a better approximation of fair value. 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 prices, at the time of settlement, do not correlate with AEP-developed price models. As explained above, the effect on AEP's Consolidated Statements of Operations of marking to market open electricity trading contracts in AEP's regulated jurisdictions is deferred as regulatory assets (losses) or liabilities (gains) 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. Construction Projects for Outside Parties - Certain AEP entities engage in construction projects for outside parties that are accounted for on the percentage-of-completion method of revenue recognition. This method recognizes revenue in proportion to costs incurred compared to total estimated costs. Debt Instrument Hedging and Related Activities - In order to mitigate the risks of market price and interest rate fluctuations, AEP, APCo, CSPCo, I&M, KPCo 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, 2002 or 2001. See Note 17 - - "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 each year 1999 through 2002 leaving $40 million as an SFAS 71 regulatory asset at December 31, 2002 on the Consolidated Balance Sheets of AEP and I&M. Other Income and Other Expenses - Other Income includes non-operational revenue including area business development and river transportation, 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 miscellaneous income. Other Expenses includes non-operational expense including area business development and river transportation, losses on dispositions of property, miscellaneous amortization, donations and various other non-operating and miscellaneous expenses. AEP Consolidated Other Income and Deductions December 31, 2002 2001 2000 ---- ---- ---- (in millions) OTHER INCOME: Equity Earnings $ 104 $ 123 $ 22 Non-operational Revenue 187 123 71 Interest and Miscellaneous Income 25 16 2 Gain on Sale of Frontera - 73 - Gain on Sale of Retail Electric Provider 129 - - ----- ----- ---- Total Other Income $ 445 $ 335 $ 95 ===== ===== ==== OTHER EXPENSES: Property Taxes and Miscellaneous Expenses $ 142 $ 68 $ 28 Non-operational Expenses 179 56 49 Fiber Optic and Datapult Exit Costs - 49 - Provision for Loss - Airplane - 14 - ----- ----- ---- Total Other Expenses $ 321 $ 187 $ 77 ===== ===== ==== 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 Loss on Reacquired Debt, an extraordinary item on the Consolidated Statements of Operations of AEP and TCC. See discussion of SFAS 145 in New Accounting Pronouncements section of this note for new treatment effective in 2003. Debt discount or premium and debt issuance expenses are deferred and amortized utilizing the effective interest rate method over the term of the related debt. The amortization expense is 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 - In June 2001, the FASB issued SFAS 141, Business Combinations, and SFAS 142, Goodwill and Other Intangible Assets, affecting AEP and SWEPCo. SFAS 141 requires that the purchase method of accounting be used for all business combinations initiated after June 30, 2001 and established new standards for the recognition of certain identifiable intangible assets, separate from goodwill. We adopted the provisions of SFAS 141 effective July 1, 2001. See Note 12 for further discussion of acquisitions initiated after June 30, 2001 and Note 3 for further discussion of our components of goodwill and intangible assets. SFAS 142 requires that goodwill and intangible assets with finite useful lives no longer be amortized, but instead tested for impairment at least annually. SFAS 142 also requires that intangible assets with finite useful lives be amortized over their respective estimated lives to the estimated residual values. In accordance with SFAS 142, for all business combinations with an acquisition date before July 1, 2001, we amortized goodwill and intangible assets with indefinite lives through December 2001, and then ceased amortization. The goodwill associated with those business combinations with an acquisition date before July 1, 2001 was amortized on a straight-line basis generally over 40 years except for the portion of goodwill associated with gas trading and marketing activities which was amortized on a straight-line basis over 10 years. In accordance with SFAS 142, for all business combinations with an acquisition date after June 30, 2001, we have not amortized goodwill and intangible assets with indefinite lives. Intangible assets with finite lives continue to be amortized over their respective estimated lives ranging from 5 to 10 years. See Note 3 for total goodwill, accumulated amortization and the impact on operations of the adoption of SFAS 142. In early 2002, we began testing our goodwill and intangible assets with indefinite useful lives for impairment, in accordance with SFAS 142. See Note 3 for the results of our testing and the corresponding net transitional impairment loss recorded as a Cumulative Effect of Accounting Change during 2002. 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 (Loss) - Comprehensive income (loss) 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 (loss) has two components: net income (loss) and other comprehensive income (loss). There were no material differences between net income and comprehensive income for AEGCo. Components of Other Comprehensive Income (Loss) - Other comprehensive income (loss) 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 (Loss) for AEP. December 31, Components 2002 2001 2000 - ------------------------------------------------------------ (in millions) Foreign Currency Adjustments $ 4 $(113) $ (99) Unrealized Losses On Securities (2) - - Unrealized Gain on Hedged Derivatives (16) (3) - Minimum Pension Liability (595) (10) (4) ----- ----- ----- $(609) $(126) $(103) ===== ===== ===== Accumulated Other Comprehensive Income (Loss) for AEP registrant subsidiaries as of December 31, 2002 and 2001 is shown in the following table. Registrant subsidiary balances for Accumulated Other Comprehensive Income (Loss) for the year ended December 31, 2000 was zero. December 31, Components 2002 2001 - ------------------------------------------------------ (in thousands) Cash Flow Hedges: APCo $(1,920) $ (340) CSPCo (267) - I&M (286) (3,835) KPCo 322 (1,903) OPCo (738) (196) PSO (42) - SWEPCo (48) - TCC (36) - TNC (15) - Minimum Pension Liability: APCo $(70,162) $ - CSPCo (59,090) - I&M (40,201) - KPCo (9,773) - OPCo (72,148) - PSO (54,431) - SWEPCo (53,635) - TCC (73,124) - TNC (30,748) - 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 16, "Business Segments" for further discussion and details regarding segments. Common Stock Options - At December 31, 2002, AEP has two stock-based employee compensation plans with outstanding stock options, which are described more fully in Note 15. AEP accounts for these plans under the recognition and measurement principles of APB Opinion No. 25, Accounting for Stock Issued to Employees and related Interpretations. No stock-based employee compensation expense is reflected in AEP's earnings, as all options granted under these plans had exercise prices equal to or above the market value of the underlying common stock on the date of grant. The following table illustrates the effect on AEP's net income (loss) and earnings (loss) per share as if AEP had applied the fair value recognition provisions of FASB Statement No. 123, "Accounting for Stock-Based Compensation", to stock-based employee compensation. Year Ended December 31, 2002 2001 2000 ---- ---- ---- (in millions except per share data) Net Income(Loss), as reported $ (519) $ 971 $ 267 Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects (9) (12) (3) ------ ----- ----- Pro forma net income (loss) $ (528) $ 959 $ 264 ====== ===== ===== Earnings (Loss) per share: Basic - as reported $(1.57) $3.01 $0.83 ====== ===== ===== Basic - pro forma $(1.59) $2.98 $0.82 ====== ===== ===== Diluted - as reported $(1.57) $3.01 $0.83 ====== ===== ===== Diluted - pro forma $(1.59) $2.97 $0.82 ====== ===== ===== Earnings Per Share (EPS) - AEP calculates earnings (loss) per share in accordance with SFAS No. 128, "Earnings Per Share" (see Note 19). Basic earnings (loss) per common share is calculated by dividing net earnings (loss) available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted earnings (loss) per common share is calculated by adjusting the weighted average outstanding common shares, assuming conversion of all potentially dilutive stock options and awards. The effects of stock options have not been included in the fiscal 2002 diluted loss per common share calculation as their effect would have been anti-dilutive. Basic and diluted EPS are the same in 2002, 2001 and 2000. AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC are wholly-owned subsidiaries of AEP and are not required to report EPS. Reclassification - Beginning in the fourth quarter of 2002, AEP and its registrant subsidiaries elected to begin netting certain assets and liabilities related to forward physical and financial transactions. This is done in accordance with FASB Interpretation No. 39, "Offsetting of Amounts Related to Certain Contracts" and Emerging Issues Task Force Topic D-43, "Assurance That a Right of Setoff is Enforceable in a Bankruptcy under FASB Interpretation No. 39". Transactions with common counterparties have been netted at the applicable entity level, by commodity and type (physical or financial) where the legal right of offset exists. For comparability purposes, prior periods presented in this report have been netted in accordance with this policy. Certain additional prior year financial statement items have been reclassified to conform to current year presentation. Such reclassifications had no impact on previously reported net income. New Accounting Pronouncements SFAS 142, "Goodwill and Other Intangible Assets", was effective for AEP on January 1, 2002. The adoption of SFAS 142 required the transition testing for impairment of all indefinite lived intangibles by the end of the first quarter 2002 and initial testing of goodwill by the end of the second quarter 2002. In the first quarter 2002, AEP completed testing the goodwill of its domestic operations and its indefinite lived intangible assets and there was no impairment. In the second quarter 2002, AEP completed initial testing for goodwill impairment of the U.K. and Australian retail electricity and supply operations. The fair values of the U.K. and Australia retail electricity and supply operations were estimated using a combination of market values based on recent market transactions and cash flow projections. As a result of that testing, AEP determined that there was a net transitional impairment loss, which is reported as a cumulative effect of a change in accounting principle. See Notes 2, 3, 12 and 13 for further discussion of the actual impairment charges and sales of impaired assets. SFAS 142 also changed the accounting and reporting for goodwill and other intangible assets. In accordance with SFAS 142 goodwill and indefinite lived intangible assets acquired through acquisition after June 30, 2001 were not amortized. Effective January 1, 2002, amortization related to goodwill and indefinite lived intangible assets acquired before July 1, 2001 ceased. SFAS 142 requires that other intangible assets be separately identified and if they have finite lives, they must be amortized over that life. See Note 3 for amortization lives of AEP's and SWEPCo's intangible assets. SFAS 143, "Accounting for Asset Retirement Obligations", is effective for AEP on January 1, 2003. SFAS 143 generally applies to legal obligations associated with the retirement of long-lived assets. A company is required to recognize an estimated liability for any legal obligations associated with the future retirement of its long-lived assets. The liability is measured at fair value and is capitalized as part of the related asset's capitalized cost. The increase in the capitalized cost is included in determining depreciation expense over the expected useful life of the asset. The catch-up effect of adopting SFAS 143 will be recorded as a cumulative effect of an accounting change. Additionally, because the asset retirement obligation is recorded initially at fair value, accretion expense (similar to interest) will be recognized each period as an operating expense in the statement of operations. The regulated entities have an asset retirement obligation associated with nuclear decommissioning costs for the Cook and STP Nuclear Plants (affects I&M and TCC) and possibly other obligations. AEP expects to establish regulatory assets and liabilities that will result in no cumulative effect adjustment of adopting SFAS 143 for the regulated entities. In addition, the regulated transmission and distribution entities have asset retirement obligations related to the final retirement of certain transmission and distribution lines. There are also underground storage tanks located at various sites throughout the AEP System and PCB's are contained in certain transformer rectifier sets at power plants. The amounts relating to these obligations cannot be determined because the entities are not able to estimate the final retirement dates for these facilities. In January 2003, the SEC Staff concluded that SFAS 143 also precludes an entity from recording an expense for estimated costs associated with the removal or retirement of assets that result from other than legal obligations. The SEC Staff concluded that amounts that are included in accumulated depreciation related to estimated removal costs arising from other than legal obligations should be written off as part of the cumulative effect of adopting SFAS 143 unless the company is regulated under SFAS 71. Companies regulated under SFAS 71 may continue to include removal costs in depreciation rates but must quantify the removal costs included in accumulated depreciation as regulatory liabilities in footnote disclosure. The AEP registrant subsidiaries that are regulated entities have included estimated removal costs for non-legal retirement obligations in book depreciation rates. For non-regulated entities, including certain formerly regulated generation facilities, asset retirement obligations associated with wind farms, closure costs associated with power plants in the U.K. and possibly other items will be incurred. Also the amount of removal costs embedded in accumulated depreciation is expected to result in a favorable cumulative effect adjustment to net income. However, AEP and its registrant subsidiaries have not completed their determination of the net effect of these items on first quarter 2003 results of operations upon the adoption of the provisions of this standard. 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 replaced, SFAS 121, "Accounting for Long-lived Assets and for Long-lived Assets to be Disposed Of." AEP adopted SFAS 144 effective January 1, 2002. The adoption of SFAS 144 did not materially affect AEP's results of operations or financial conditions. See Notes 3 and 13 for discussion of impairments recognized in 2002 by AEP and its registrant subsidiaries, affected by SFAS 144. In April 2002, the FASB issued SFAS 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections". SFAS 145 rescinds SFAS 4, "Reporting Gains and Losses from Extinguishment of Debt", effective for fiscal years beginning after May 15, 2002. SFAS 4 required gains and losses from extinguishment of debt to be aggregated and classified as an extraordinary item if material. In 2003, for financial reporting purposes AEP and TCC will reclassify extraordinary losses net of tax on TCC's reacquired debt of $2 million for 2001. In October 2002, the Emerging Issues Task Force of the FASB reached a final consensus on Issue No. 02-3, "Recognition and Reporting of Gains and Losses on Energy Contracts under Issues No. 98-10 and 00-17" (EITF 02-3). EITF 02-3 rescinds EITF 98-10 and related interpretive guidance. Under EITF 02-3, mark-to-market accounting is precluded for energy trading contracts that are not derivatives pursuant to SFAS 133. The consensus to rescind EITF 98-10 will also eliminate any basis for recognizing physical inventories at fair value other than as provided by generally accepted accounting principles. The consensus is effective for fiscal periods beginning after December 15, 2002, and applies to all energy trading contracts entered into and inventory purchased through October 25, 2002. Effective January 1, 2003, nonderivative energy contracts are required to be accounted for on a settlement basis and inventory is required to be presented at the lower of cost or market. The effect of implementing this consensus will be reported as a cumulative effect of an accounting change. Such contracts and inventory will continue to be accounted for at fair value through December 31, 2002. Energy contracts that qualify as derivatives will continue to be accounted for at fair value under SFAS 133. Effective January 1, 2003, EITF 02-3 requires that gains and losses on all derivatives, whether settled financially or physically, be reported in the income statement on a net basis if the derivatives are held for trading purposes. Previous guidance in EITF 98-10 permitted non-financial settled energy trading contracts to be reported either gross or net in the income statement. Prior to the third quarter of 2002, AEP and its registrant subsidiaries recorded and reported upon settlement, sales under forward trading contracts as revenues and purchases under forward trading contracts as purchased energy expenses. Effective July 1, 2002, AEP and its registrant subsidiaries reclassified such forward trading revenues and purchases on a net basis, as permitted by EITF 98-10. The reclassification of such trading activity to a net basis of reporting resulted in a substantial reduction in both revenues and purchased energy expense, but did not have any impact on financial condition, results of operations or cash flows. Effective July 1, 2002, AEP and its registrant subsidiaries modified their valuation procedures for estimating the fair value of energy trading contracts at inception. Unrealized gain or loss at inception is recognized only when the fair value of a contract is obtained from a quoted market price in an active market or is otherwise evidenced by comparison to other observable market data. Any fair value changes subsequent to the inception of a contract, however, are recognized immediately based on the best market data available. AEP and its registrant subsidiaries now also use such procedures for determining unrealized gain or loss at inception for all derivative contracts. In June 2002, FASB issued SFAS 146 which addresses accounting for costs associated with exit or disposal activities. This statement supersedes previous accounting guidance, principally EITF No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)." Under EITF No. 94-3, a liability for an exit cost was recognized at the date of an entity's commitment to an exit plan. SFAS 146 requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred. SFAS 146 also establishes that the liability should initially be measured and recorded at fair value. The timing of recognizing future costs related to exit or disposal activities, including restructuring, as well as the amounts recognized may be affected by SFAS 146. AEP will adopt the provisions of SFAS 146 for exit or disposal activities initiated after December 31, 2002. In November 2002, the FASB issued Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" (FIN 45) which requires that a liability related to issuing a guarantee be recognized, as well as additional disclosures of guarantees. This new guidance is an interpretation of SFAS Nos. 5, 57 and 107 and a rescission of FIN No. 34. The initial recognition and initial measurement provisions of FIN 45 are effective on a prospective basis to guarantees issued or modified after December 31, 2002. The disclosure requirements of FIN 45 are effective for financial statements of interim and annual periods ending after December 15, 2002. We do not expect that the implementation of FIN 45 will materially affect results of operations, cash flows or financial condition. See guarantee details discussed in Note 10. In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based Compensation-Transition and Disclosure", which amends SFAS No. 123, "Accounting for Stock-Based Compensation". SFAS 148 provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. Under the fair value based method, compensation cost for stock options is measured when options are issued. In addition, SFAS 148 amends the disclosure requirements of SFAS 123 to require more prominent and more frequent (quarterly) disclosures in financial statements of the effects of stock-based compensation. SFAS 148 is effective for fiscal years ending after December 15, 2002. AEP does not currently intend to adopt the fair value based method of accounting for stock options. In November 2002, the FASB issued an Invitation to Comment, "Accounting for Stock-Based Compensation: A Comparison of FASB Statement No. 123, Accounting for Stock-Based Compensation, and Its Related Interpretations, and IASB Proposed IFRS, Share-Based Payment." The FASB plans to make a decision in the first quarter of 2003 whether it will begin a more comprehensive reconsideration of the accounting for stock options. This may include revisiting the decision in SFAS 123 allowing companies to disclose the pro forma effects of the fair value based method rather than requiring recognition of the fair value of employee stock options as an expense. In January 2003, the FASB issued FASB Interpretation No. 46, "Consolidation of Variable Interest Entities" (FIN 46) which changes the requirements for consolidation of certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. This new guidance is an interpretation of Accounting Research Bulletin (ARB) No. 51, "Consolidated Financial Statements". The initial recognition and initial measurement provisions of FIN 46 for all enterprises with variable interests in variable interest entities created after January 31, 2003, shall apply the provisions of this Interpretation to those entities immediately. A public entity with variable interests in variable interest entities created before February 1, 2003 shall apply the provisions of this Interpretation no later than the beginning of the first interim or annual reporting period beginning after June 15, 2003. If it is reasonably possible that an enterprise will consolidate or disclose information about a variable interest entity when this Interpretation becomes effective, the enterprise shall disclose the following information in all financial statements initially issued after January 31, 2003, regardless of the date on which the variable interest entity was created: a. The nature, purpose, size, and activities of the variable interest entity b. The enterprise's maximum exposure to loss as a result of its involvement with the variable interest entity AEP and its subsidiaries believe it is reasonably possible that they will be required to consolidate identified variable interest entities as a result of this new guidance. See Notes 9, 22, 23 and 26 for additional disclosures relating to the variable interest entities. 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 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. In April 2002, the Ohio Supreme Court denied recovery of the final year of the GRT. In October 2001, TCC reacquired $101 million of pollution control bonds in advance of their maturity. Since these pollution control bonds were used to finance unregulated generation assets, a loss of $2 million after-tax was recorded. AEP and its registrant subsidiaries had no extraordinary items in 2002. The following table shows the components of the extraordinary items reported on AEP's Consolidated Statements of Operations: Year Ended December 31, ----------- 2002 2001 2000 ---- ---- ---- (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)(a) $ - $(48) $(44) Virginia and West Virginia Jurisdictions (Inclusive of Tax Benefit of $8 Million)(b) - - 9 Loss on Reacquired Debt (Net of Tax of $1 Million in 2001)(c) - (2) - ---- ---- ---- Extraordinary Items $ - $(50) $(35) ==== ==== ==== (a) Relates to AEP, OPCo and CSPCo. (b) Relates to AEP and APCo. (c) Relates to AEP and TCC. Cumulative Effect of Accounting Change - SFAS 142 requires that goodwill and intangible assets with indefinite useful lives no longer be amortized and be tested annually for impairment. The implementation of SFAS 142 resulted in a $350 million net transitional loss for our U.K. and Australian operations and is reported in AEP's Consolidated Statements of Operations as a cumulative effect of accounting change (see Note 3 for further details). 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 certain option-type contracts and forward contracts in electricity can qualify for the normal purchase or sale exclusion. For AEP, the effect of initially adopting the DIG guidance at July 1, 2001 was a favorable earnings mark-to-market effect of $18 million, net of tax of $2 million. It was reported as a cumulative effect of an accounting change on AEP's Consolidated Statements of Operations. 3. Goodwill and Other Intangible Assets: As described in the Significant Accounting Policies footnote, AEP adopted the provisions of SFAS 141 effective July 1, 2001. SFAS 141 requires that the purchase method of accounting be used for all business combinations initiated after June 30, 2001 and established new standards for the recognition of certain identifiable intangible assets, separate from goodwill. Business combinations initiated after June 30, 2001 (see Note 12 for details) are accounted for utilizing SFAS 141. SFAS 142 requires that goodwill and intangible assets with indefinite useful lives no longer be amortized, but instead tested for impairment at least annually. SFAS 142 required a two-step impairment test for goodwill. The first step was to compare the carrying amount of the reporting unit's assets to the fair value of the reporting unit. If the carrying amount exceeded the fair value then the second step was required to be completed, which involves allocating the fair value of the reporting unit to each asset and liability, with the excess being implied goodwill. The impairment loss is the amount by which the recorded goodwill exceeds the implied goodwill. AEP was required to complete a "transitional" impairment test for goodwill as of the beginning of the fiscal year in which the statement was adopted. This transitional impairment test required that AEP complete step one of the goodwill impairment test within six months from the date of initial adoption, or June 30, 2002. In the first quarter 2002, AEP completed the transitional impairment test of goodwill related to domestic operations and indefinite lived intangible assets and concluded that those assets were not impaired. In the second quarter 2002, AEP completed testing for goodwill impairment on AEP's U.K. and Australian retail electricity and supply operations. The fair values of the U.K. and Australian retail electricity and supply operations were estimated using a combination of market values based on recent market transactions and cash flow projections. As a result of this testing, AEP determined that there was a net transitional impairment loss of $350 million, which was reported in AEP's Consolidated Statements of Operations as a Cumulative Effect of Accounting Change. SFAS 142 also requires that intangible assets with finite useful lives be amortized over their respective estimated lives to the estimated residual values. In accordance with SFAS 142, for all business combinations initiated before July 1, 2001, AEP amortized goodwill and intangible assets with indefinite lives through December 2001, and then ceased amortization. The goodwill associated with those business combinations with acquisition dates before July 1, 2001 was amortized on a straight-line basis generally over 40 years except for the portion of goodwill associated with gas trading and marketing activities, which was amortized on a straight-line basis over 10 years. Also, in accordance with SFAS 142, for all business combinations with acquisition dates after June 30, 2001, AEP has not amortized goodwill and intangible assets with indefinite lives. Intangible assets with finite lives continue to be amortized over their respective estimated lives ranging from 5 to 10 years. New reporting requirements imposed by SFAS 142 include the disclosures shown below. Goodwill The changes in AEP's the carrying amount of goodwill for the twelve months ended December 31, 2002 by operating segment are:
Energy AEP Wholesale Delivery Other Consolidated --------- -------- ----- ------------ (in millions) Balance January 1, 2002 $340 $37 $15 $392 Goodwill acquired 2 - - 2 Changes to Goodwill due to purchase price adjustments 181 - - 181 Non-transitional impairment losses (173) - (12) (185) Foreign currency exchange rate changes 6 - - 6 ---- --- --- ---- Balance December 31, 2002 $356 $37 $ 3 $396 ==== === === ====
Accumulated amortization of goodwill was approximately $22 million and $25 million at December 31, 2002 and 2001, respectively. A decrease of $3 million related principally to the non-transitional impairment of goodwill on Gas Power Systems (see Note 13a). The transitional impairment loss related to SEEBOARD and CitiPower goodwill, which is reported as a cumulative effect of an accounting change, is excluded from the above schedule. Under SFAS 144, the assets of SEEBOARD and CitiPower, including goodwill and acquired intangible assets no longer subject to amortization, are reported as Assets of Discontinued Operations in AEP's Consolidated Balance Sheets. See Note 12 related to the sale of SEEBOARD and CitiPower. Changes to goodwill due to purchase price adjustments of $181 million was primarily due to purchase price adjustments related to AEP's acquisition of U.K. Generation. The purchase price adjustments also include adjustments related to the acquisition of Houston Pipe Line Company, MEMCO, Nordic Trading and AEP Coal (see Note 12). In the first quarter of 2002, AEP recognized a goodwill impairment loss of $12 million for all goodwill related to the acquisition of Gas Power Systems (see Note 13a). In the fourth quarter of 2002, AEP prepared its annual goodwill impairment tests. The fair values of the operations were estimated using cash flow projections. There were no goodwill impairments as a result of the annual goodwill impairment tests. However, in the fourth quarter, AEP recognized goodwill impairment losses totaling $173 million related to impairment studies performed on the U.K. Generation assets ($166 million), AEP Coal ($3 million), and Nordic Trading ($4 million). These goodwill impairment studies were triggered by the SFAS 144 asset impairment losses recognized on these operations in the fourth quarter (refer to Note 13). The fair values of these operations were estimated using cash flow projections. The following tables show the transitional disclosures to adjust AEP's reported net income (loss) and earnings (loss) per share to exclude amortization expense recognized in prior periods related to goodwill and intangible assets that are no longer being amortized.
Net Income (Loss) Year Ended December 31, ----------------------- 2002 2001 2000 ---- ---- ---- (in millions) Reported Net Income (Loss) $(519) $ 971 $267 Add back: Goodwill amortization (a) - 39 39 Add back: Amortization for intangibles with indefinite lives under SFAS 142 (b) - 8 9 ----- ------ ---- Adjusted Net Income (Loss) $(519) $1,018 $315 ===== ====== ====
Twelve Months Ended Earnings (Loss) Per Share (Basic and Dilutive) December 31, ------------------- 2002 2001 2000 ---- ---- ---- Reported Earnings (Loss) per Share $(1.57) $3.01 $0.83 Add back: Goodwill amortization (c) - 0.12 0.12 Add back: Amortization for intangibles with indefinite lives under SFAS 142 (d) - 0.02 0.03 ------ ----- ----- Adjusted Earnings (Loss) per Share $(1.57) $3.15 $0.98 ====== ===== =====
(a) This amount includes $34 million and $37 million in 2001 and 2000 related to Seeboard and CitiPower amortization expense included in Discontinued Operations on AEP's Consolidated Statements of Operations. (b) The amounts shown for 2001 and 2000 relate to CitiPower amortization expense included in Discontinued Operations on AEP's Consolidated Statements of Operations. (c) This amount includes $0.10 and $0.11 in 2001 and 2000 related to Seeboard and CitiPower amortization expense included in Discontinued Operations on AEP's Consolidated Statements of Operations. (d) The amounts shown for 2001 and 2000 relate to CitiPower amortization expense included in Discontinued Operations on AEP's Consolidated Statements of Operations. Acquired Intangible Assets Acquired intangible assets subject to amortization are $37 million at December 31, 2002 and $33 million at December 31, 2001, net of accumulated amortization. Of those amounts, $25 million and $33 million at December 31, 2002 and 2001, relate to SWEPCo. The gross carrying amount, accumulated amortization and amortization life by major asset class are:
December 31, 2002 December 31, 2001 Gross Gross Amortization Carrying Accumulated Carrying Accumulated Life Amount Amortization Amount Amortization ------------ -------- ------------ ------- ------------ (in years) (in millions) (in millions) Dolet Hills Advanced Royalties (SWEPCo) 10 $35 $5 $35 $2 Less: Adjustment Due to Purchase Price Reallocation (SWEPCo) 6 1 - - Trade name and Administration of Contracts 7 2 - - - Unpatented Technology 10 10 - - - --- -- --- -- Totals $41 $4 $35 $2 === == === ==
Amortization of intangible assets (primarily SWEPCo) was $2 million for the twelve months ended December 31, 2002. AEP's estimated aggregate amortization expense is $4 million for each year 2003 through 2008. SWEPCo's estimated aggregate amortization expense (included in AEP's estimated amount) is $3 million for each year 2003 through 2008. AEP's acquired intangible assets no longer subject to amortization were comprised of retail and wholesale distribution licenses for CitiPower operating franchises. The licenses were being amortized on a straight-line basis over 20 and 40 years for the retail and wholesale licenses, respectively. In accordance with SFAS 144, the assets of CitiPower, including acquired intangible assets no longer subject to amortization, are reported as Assets of Discontinued Operations on one line in AEP's Consolidated Balance Sheets. See Note 12 related to the sale of CitiPower. 4. 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. 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. Effective January 2003, the legal name of CSW was changed to AEP Utilities, Inc. In connection with the merger, $10 million ($7 million after tax), $21 million ($14 million after tax) and $203 million ($180 million after tax) of non-recoverable merger costs were expensed in 2002, 2001 and 2000. Such costs included transaction and transition costs not recoverable from ratepayers. Also included in the merger costs were non-recoverable changes in control payments. Merger transaction and transition costs of $52 million recoverable from ratepayers were deferred pursuant to state regulator approved settlement agreements through December 31, 2002. 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, $8 million and $4 million for the years 2002, 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, 2002 December 31, 2002 ----------------- ----------------- (in millions) I&M $8.2 $1.7 KPCo 2.9 0.6 PSO 5.0 1.6 SWEPCo 3.9 1.1 TCC 9.1 2.6 TNC 2.7 0.8 Amortization Merger Cost Expense for the Deferral at Year Ended December 31, 2001 December 31, 2001 ----------------- ----------------- (in millions) I&M $ 9.1 $1.7 KPCo 3.2 0.6 PSO 6.6 1.2 SWEPCo 5.0 1.1 TCC 11.8 2.6 TNC 3.5 0.8 Amortization Merger Cost Expense for the Deferral at Year Ended December 31, 2000 December 31, 2000 ----------------- ----------------- (in millions) I&M $ 6.9 $0.7 KPCo 2.5 0.3 PSO 7.9 0.5 SWEPCo 6.1 0.5 TCC 14.4 1.3 TNC 4.2 0.4 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 - SWEPCo, TCC, TNC $221 million rate reduction 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 to share merger savings estimated to be $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. See Note 9, "Commitments and Contingencies" for information on a court decision concerning the merger. 5. 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 nuclear operation and maintenance (O&M) costs 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, o A freeze in base rates and fixed power supply costs recovery factors until January 1, 2004 for the Michigan jurisdiction. The amount of costs and deferrals charged to other operation and maintenance expenses were as follows: Year Ended December 31, 2002 2001 2000 ---- ---- ---- Costs Incurred $- $ 1 $297 Amortization of Deferrals 40 40 40 - -- - -- -- -- Charged to O&M Expense $40 $41 $337 === === ==== At December 31, 2002 and 2001, deferred O&M costs of $40 million and $80 million, respectively, remained in Regulatory Assets to be amortized through 2003. Also pursuant to the settlement agreements, accrued fuel-related revenues of $38 million were amortized as a reduction of revenues in each of 2002, 2001 and 2000. At December 31, 2002 and 2001, fuel-related revenues of $37 million and $75 million, respectively, were included in Regulatory Assets and will be amortized through December 31, 2003 for both jurisdictions. The amortization of O&M 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 O&M costs and fuel-related revenue deferrals is approximately $78 million. 6. Rate Matters: Texas Fuel - Affecting AEP, SWEPCo, TCC and TNC Prior to the start of retail competition in ERCOT on January 1, 2002, fuel recovery for Texas utilities was a multi-step procedure. When fuel costs changed, utilities filed with the PUCT for authority to adjust fuel factors. If a utility's prior fuel factors resulted in material over-recovery or under-recovery of fuel costs, the utility would also request a refund or surcharge factor to refund or collect those amounts. While fuel factors were intended to recover fuel costs, final settlement of these amounts was subject to reconciliation and approval by the PUCT. Fuel reconciliation proceedings determine whether fuel costs incurred 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 is no longer subject to PUCT review and reconciliation. During 2002, TCC and TNC filed 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. See discussion of TCC and TNC fuel reconciliations below. 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 TNC's service territory are in SPP. SWEPCo's existing Texas 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 TNC fuel factors in the SPP area will be based upon the price-to-beat fuel factors offered by the retail electric provider in the ERCOT portion of TNC's service territory. TNC transferred its SPP customers to Mutual Energy SWEPCo effective December 1, 2002. TNC filed in 2002 with the PUCT to determine the most appropriate method to reconcile fuel costs in TNC's SPP area and a decision is expected by mid 2003. Under Texas restructuring, customer choice to select a retail electric provider began January 1, 2002. Sales to customers using 1 MW or less will be at fixed base rates during a transition period from 2002 through 2006. As discussed in Note 12 "Acquisitions, Dispositions and Discontinued Operations", AEP sold its Texas retail electric providers (REP) and their retail customers in December 2002. The former AEP subsidiaries serving as REPs for the ERCOT area filed with the PUCT in May 2002 to increase the fuel portion of their price-to-beat rate in compliance with the Texas Restructuring Legislation and the PUCT's rules. The Texas legislation provides for the adjustment of the fuel portion of the rate up to twice annually to reflect significant changes in the market price of natural gas and purchased energy used to serve retail customers using NYMEX natural gas prices. On July 15, 2002, the PUCT required further hearings to reconsider the validity of their existing rules for fuel factor adjustments. On July 24, 2002, the Texas REPs filed a petition with the District Court seeking an injunction commanding the PUCT to proceed to a final order based on the existing rules and prohibiting the PUCT from conducting a remand proceeding. The District Court issued an order on August 9, 2002 requiring the PUCT to comply with the existing rules. On August 26, 2002, the PUCT issued an order approving a 22% increase to the fuel portion of the price-to-beat rates effective immediately for both REPs. The PUCT order approving the 22% increase has been appealed by parties opposing the price-to-beat adjustment. With the sale of the REPs to Centrica in December 2002, Centrica is responsible for these appeals. Any adverse ruling from the appeal could impact TCC and TNC by requiring refunds for the time period AEP served the retail customers prior to the sale to Centrica (January 2002 to December 2002). TCC Fuel Reconciliation - Affecting AEP and TCC In December 2002, TCC filed with the PUCT to reconcile fuel costs and to defer its over-recovery of fuel for inclusion in the 2004 true-up proceeding. This reconciliation for the period of July 1998 through December 2001 will be the final fuel reconciliation. At December 31, 2001, the over-recovery balance for TCC was $63.5 million including interest. During the reconciliation period, TCC incurred $1.6 billion of eligible fuel and fuel-related expenses. Recommendations from intervening parties are expected in April 2003 with hearings scheduled in May 2003. A final order is expected in late 2003. An adverse ruling from the PUCT could have a material impact on future results of operations, cash flows and financial condition. Additional information regarding the 2004 true-up proceeding for TCC can be found in Note 8 "Customer Choice and Industry Restructuring". TNC Fuel Reconciliation - Affecting AEP and TNC In June 2002, TNC filed with the PUCT to reconcile fuel costs and to defer any unrecovered portion applicable to retail sales within its ERCOT service area for inclusion in the 2004 true-up proceeding. This reconciliation for the period of July 2000 through December 2001 will be the final fuel reconciliation for TNC's ERCOT service territory. At December 31, 2001, the under-recovery balance associated with TNC's ERCOT service area was $27.5 million including interest. During the reconciliation period, TNC incurred $293.7 million of eligible fuel costs serving both ERCOT and SPP retail customers. TNC also requested authority to surcharge its SPP customers. TNC's SPP customers will continue to be subject to fuel reconciliations until competition begins in SPP. The under-recovery balance at December 31, 2001 for TNC's service within SPP was $0.7 million including interest. In October 2002, the filing was split into two phases for hearing purposes. The first phase examined all components of the filing except for AEP trading activities and the associated margins that flow back to customers as an offset to fuel costs consistent with the PUCT - approved Texas merger settlement. Intervenors filed testimony in the first phase recommending that up to $25 million of TNC's requested retail eligible fuel recovery be disallowed and hearings were held on October 23, 2002. TNC disputed the recommendations. On October 21, 2002, the PUCT Staff and Office of Public Utility Counsel (OPC) filed a joint Motion for Summary Decision related to the second phase issue and requested that approximately $18.5 million of TNC's retail eligible fuel recovery be disallowed without a hearing. On November 8, 2002, the administrative law judges (ALJs) in the case denied the motion. The intervenors filed testimony on October 29, 2002 in the second phase recommending that up to $34 million of TNC's requested retail eligible fuel recovery be disallowed. The intervenors recommended disallowance includes the amount sought in the October 21 Motion for Summary Decision. The total intervenor recommended retail disallowance is approximately $59 million. Hearings for the second phase were held on November 13-14, 2002. On February 3, 2003, TNC filed a motion to reopen the evidentiary record and include a decrease to retail eligible fuel costs of $1.3 million, including interest, to reflect final resettlement revenues and expenses from ERCOT for the period August through December 2001 (see discussion in Fuel and Purchased Power below). The PUCT is expected to issue a final order in this case by mid 2003. An adverse ruling from the PUCT could have a material impact on future results of operations, cash flows and financial condition. ERCOT Over-scheduling - Affecting AEP, TCC and TNC ERCOT began serving as a central control center for all of ERCOT at the end of July 2001 when ERCOT became a single control area. Qualified scheduling entities (QSE) schedule loads and resources for ERCOT market participants including power generation companies and retail electric providers. In August 2001, ERCOT incurred substantial costs for managing transmission in its north zone. The costs incurred by ERCOT to manage congestion are shared by all ERCOT QSEs. In late 2001, the PUCT initiated an investigation of the impact of scheduling of electric loads and resources by QSEs during August 2001. The PUCT's investigation determined that a substantial amount of the congestion charges were the result of QSEs, including AEP's QSE, scheduling more resources than required to meet their actual load requirements in the ERCOT north zone. AEP's QSE over-scheduled resources due to an error in the allocation of estimated load requirements between ERCOT congestion zones. Pursuant to the PUCT's investigation, QSEs, including AEP's QSE, agreed to a settlement that provides for the refund of payments received for adjusting resource schedules for congestion. The settlement was approved by the PUCT in November 2002. The settlement recognizes that the scheduling errors were associated with the start up of the ERCOT competitive market. AEP's QSE paid $3.2 million to ERCOT and received $1.7 million from ERCOT in congestion refunds for a net payment of $1.5 million. Payments were assigned to TNC and the refunds were allocated to TCC and TNC. TNC incurred a net cost of $2.8 million and TCC received a refund of $1.3 million. The TNC payment and TCC refund have been reflected in the final fuel reconciliation filings for each company. However, intervening parties have objected to the inclusion of the TNC payment in its final fuel reconciliation. Recommendations from intervening parties in the TCC proceeding are not expected until April 2003. An adverse ruling from the PUCT would impact future results of operations, cash flows and financial condition. Texas Transmission Rates - Affecting AEP, TCC and TNC On June 28, 2001, the Supreme Court of Texas ruled that the transmission pricing mechanism created by the PUCT in 1996 and used for the period January 1, 1997 through August 31, 1999 was invalid. The court upheld an appeal filed by unaffiliated Texas utilities that the PUCT exceeded its statutory authority to set such rates during that period. TCC and TNC 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 unfavorable impact on results of operations and cash flows for TCC and TNC. FERC Wholesale Fuel Complaints - Affecting AEP and TNC In May 2000, certain TNC wholesale customers filed a complaint with FERC alleging that TNC had overcharged them through the fuel adjustment clause for certain purchased power costs related to 1999 unplanned outages at TNC's Oklaunion generation station. In November 2001, certain TNC wholesale customers filed an additional complaint at FERC asserting that since 1997 TNC 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 TNC 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. In response to the November 2001 complaint, negotiations to settle the complaint and update the contracts are continuing. In March 2002, TNC recorded a provision for refund of $2.2 million before income taxes. The actual refund and final resolution of this matter could differ materially from this estimate and may have a negative impact on future results of operations, cash flows and financial condition. FERC Transmission Rates - Affecting AEP, PSO, SWEPCo, TCC and TNC In November 2001, FERC issued an order resulting from a remand by an appeals court of a tariff compliance filing order issued in 1998 that had been appealed by certain customers. The order required PSO, SWEPCo, TCC and TNC to submit revised open access transmission tariffs and calculate and issue refunds for overcharges from January 1, 1997. In July 2002, FERC approved a revised open access transmission tariff and refunds of $1.3 million were issued to unaffiliated entities. Under FERC rules, the new tariffs resulted in a reallocation of previously received transmission revenues among affiliates resulting in the following income statement impact: Increase (Decrease) Revenues ---------------------------- 2001 2002 Total (in millions) PSO $ 2.8 $ 2.5 $ 5.3 SWEPCo 3.2 2.8 6.0 TCC (6.0) (2.8) (8.8) TNC (2.6) (1.2) (3.8) ----- ----- ----- AEP Total $(2.6) $ 1.3 $(1.3) ===== ===== ===== Fuel and Purchased Power - Affecting AEP, PSO, SWEPCo, TCC and TNC PSO has Under-Recovered Fuel Costs of $75.7 million at December 31, 2002, representing fuel and purchased power costs recorded but not yet collected from retail customers in Oklahoma. The first significant item causing the under-recovery is approximately $44 million in reallocation of purchased power costs for periods prior to January 1, 2002, as described below. The other significant item impacting the under-recovered fuel costs are natural gas price increases that were not expected when PSO set its quarterly factors during 2002. The Corporation Commission of the State of Oklahoma (OCC) is currently reviewing the reasons for the large under-recovered balance. The AEP West electric operating companies' power is dispatched real-time on an economic basis and is later allocated among the AEP West electric operating companies using the Interchange Cost Reconstruction (ICR) system based on dispatch information from internal and external sources. ICR is designed to allocate the cost of power under the terms and conditions of the AEP West Operating Agreement. During 2002, two ICR adjustments were made. The adjustments were related to a 2002 true-up and a reallocation of years prior to 2002. During the third quarter of 2002, AEP reallocated purchased power costs among the four AEP West electric operating companies for the periods prior to January 1, 2002 (the ICR Adjustments). The effects of the reallocation on pre-tax income were insignificant to PSO and TCC and increased pre-tax income at SWEPCo and TNC by $2.4 million and $1.9 million, respectively. The formation of the ERCOT single control zone increased the need for data estimation and true-up which has resulted in extended true-up periods associated with allocations being performed on estimated data. ERCOT can make adjustments to companies' settlements for up to six months. A true-up process for 2002 was completed and recorded in the fourth quarter of 2002 resulting in insignificant changes in PSO's and SWEPCo's pre-tax income. TCC's pre-tax income was reduced by $3.7 million and TNC's pre-tax income was increased by $4.8 million. As ERCOT notifies TCC and TNC of further adjustments, they will be recorded. PSO implemented new fuel rates in December 2002 following the OCC's review and approval. The new fuel factors were designed to recover estimated fuel costs for the next three months and to begin recovery of the under-recovered amount. Recovery of the under-recovered amount is expected to occur over several months and is subject to OCC review and approval. For SWEPCo, the true-up process described above and the ICR Adjustments resulted in a net increase in fuel costs recoverable from customers of $8 million included in Regulatory Assets on AEP's and SWEPCo's Consolidated Balance Sheets. The amount is recoverable from customers pursuant to the applicable fuel recovery mechanisms and review of the state regulatory commissions in Arkansas, Louisiana and Texas. To the extent the OCC and/or the AEP West Commissions regulating SWEPCo do not permit recovery of the revised fuel and purchased power costs, there could be an adverse effect on results of operations and cash flows. PSO Rate Review - Affecting AEP and PSO In February 2003, the Director of the OCC filed an application requiring PSO to file all documents necessary for a general rate review before August 1, 2003. Management is unable to predict the result of this review as the documents and data have not been assembled. Louisiana Compliance Filing - Affecting AEP and SWEPCo On October 15, 2002, SWEPCo filed with the Louisiana Public Service Commission (LPSC) detailed financial information typically utilized in a revenue requirement filing, including a jurisdictional cost of service. This filing was required by the LPSC as a result of their order approving the merger between AEP and CSW. The LPSC's merger order also provides that SWEPCo's base rates are capped at the present level through mid 2005. The filing indicates that SWEPCo's current rates should not be reduced. If the LPSC disagrees with our conclusion, they could order SWEPCo to file all documents for a full cost of service revenue requirement review in order to determine whether SWEPCo's capped rates should be reduced which would adversely impact results of operations and cash flows. FERC Long-term Contracts - Affecting AEP and AEP East and AEP West companies In September 2002, the FERC voted to hold hearings to consider requests from certain wholesale customers located in Nevada and Washington to break long-term contracts which they allege are "high-priced". At issue are long-term contracts entered during the California energy price spike in 2000 and 2001. The complaints allege that AEP sold power at unjust and unreasonable prices. The FERC delayed hearings to allow the parties to hold settlement discussions. In January 2003, the FERC settlement judge assigned to the case indicated that the parties' settlement efforts were not progressing and he recommended that the complaint be placed back on the schedule for a hearing. In February 2003, AEP and one of our customers agreed to terminate their contract with the customer withdrawing its FERC complaint. In a similar complaint, a FERC administrative law judge (ALJ) ruled in favor of AEP and dismissed, in December 2002, a complaint filed by two Nevada utilities. In 2000 and 2001, AEP agreed to sell power to the utilities for future delivery. In late 2001, the utilities filed complaints that the prices for power supplied under those contracts should be lowered because the market for power was allegedly dysfunctional at the time such contracts were entered. The ALJ rejected the utilities' complaint, held that the markets for future delivery were not dysfunctional, and that the utilities had failed to demonstrate that the public interest required that changes be made to the contracts. The ALJ's order is preliminary and is subject to review by the FERC. The FERC will likely rule on the ALJ's order in 2003. Management is unable to predict the outcome of these proceedings or their impact on results of operations. Environmental Surcharge Filing - Affecting AEP and KPCo In September 2002, KPCo filed with the KPSC to revise its environmental surcharge tariff to recover the cost of emissions control equipment being installed at Big Sandy Plant. See NOx Reductions in Note 9 "Commitments and Contingencies". The surcharge request, as filed, would increase annual revenues by approximately $21 million and must be approved by the KPSC before its inclusion in customers' bills. If the KPSC does not approve an increase in the environmental surcharge, results of operations and cash flows would be negatively impacted. 7. 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 business in Arkansas, Ohio, Texas, Virginia and West Virginia 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 West Virginia 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. These assets are classified as "transition regulatory assets". As discussed in Note 8, "Customer Choice and Industry Restructuring" 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. These assets are also classified as "transition regulatory assets." The Texas jurisdiction generation-related regulatory assets that are eligible for recovery through securitization have been classified as "regulatory assets designated for or subject to securitization." See Note 8 "Customer Choice and Industry Restructuring" for further details. AEP's recognized regulatory assets and liabilities are comprised of the following at: December 31, ----------- 2002 2001 ---- ---- (in millions) Regulatory Assets: Amounts Due From Customers For Future Income Taxes $ 791 $ 814 Transition Regulatory Assets 743 847 Regulatory Assets Designated for or Subject to Securitization 336 959 Texas Wholesale Clawback (a) 262 - Deferred Fuel Costs 143 139 Unamortized Loss on Reacquired Debt 83 99 Cook Plant Restart Costs 40 80 DOE Decontamination and Decommissioning Assessment 26 31 Other 264 193 ------ ------ Total Regulatory Assets $2,688 $3,162 ====== ====== Regulatory Liabilities: Deferred Investment Tax Credits $ 455 $ 491 Texas Retail Clawback (a) 66 - Other 419 393 ------ ----- Total Regulatory Liabilities $ 940 $ 884 ====== ===== (a) See "Texas Restructuring" section of Note 8. 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/ Refund Refund 2002 2001 Period 2002 2001 Period ---- ---- -------- ---- ---- -------- (in thousands) Regulatory Assets: Amounts Due From Customers For Future Income Taxes $209,884 $189,794 Note 1 Transition - Regulatory Assets Virginia 39,670 46,981 Jun. 2007 Transition - Regulatory Assets West Virginia 119,038 127,998 Jun. 2011 Deferred Fuel Costs 5,367 11,732 Unamortized Loss on Reacquired Debt $ 4,970 $ 5,207 Note 2 9,147 10,421 Note 2 Deferred Storm Damage - 6 Other 12,447 10,451 Note 3 ------- ------- -------- -------- Total Regulatory Assets $ 4,970 $ 5,207 $395,553 $397,383 ======= ======= ======== ======== Regulatory Liabilities: Deferred Investment Tax Credits $52,943 $56,304 Note 4 $ 33,691 $ 38,328 Note 4 WV Rate Stabilization 75,601 75,601 Note 5 Amounts Due To Customers For Future Income Taxes 16,670 22,725 Note 1 Other 72 112 Note 3 ------- ------- -------- -------- Total Regulatory Liabilities $69,613 $79,029 $109,364 $114,041 ======= ======= ======== ========
Note 1: This amount fluctuates from month to month and has no fixed recovery/refund period. Note 2: Unamortized loss on reacquired debt varies in its recovery period for each registrant and ranges from one to thirty-six years recovery period across all registrants. Note 3: Other may include items not earning a return and would have various recovery/refund periods. Note 4: Generally amortized over the life of the related plant assets as approved by the various state commissions. Note 5: Amortization will be determined by the WVPSC to offset market prices.
CSPCo I&M ------------------------------- ------------------------------- Recovery/ Recovery/ Refund Refund 2002 2001 Period 2002 2001 Period ---- ---- -------- ---- ---- -------- (in thousands) Regulatory Assets: Amounts Due From Customers For Future Income Taxes $ 26,290 $ 28,361 Note 1 $163,928 $171,605 Note 1 Transition - Regulatory Assets 204,961 223,830 Dec. 2008 Deferred Fuel Costs 37,501 75,002 Dec. 2003 Unamortized Loss on Reacquired Debt 5,978 7,010 Note 2 14,994 16,255 Note 2 Cook Plant Restart Costs 40,000 80,000 Dec. 2003 Incremental Nuclear Refueling Outage Expenses (Net) 29,572 2,995 Note 5 DOE Decontamination and Decommissioning Assessment 23,375 27,784 Dec. 2008 Other 20,453 3,066 Note 3 38,842 35,286 Note 3 -------- -------- -------- -------- Total Regulatory Assets $257,682 $262,267 $348,212 $408,927 ======== ======== ======== ======== Regulatory Liabilities: Deferred Investment Tax Credits $ 33,907 $ 37,176 Note 4 $ 97,709 $105,449 Note 4 Other - 31 Note 3 65,983 52,479 Note 3 -------- -------- -------- -------- Total Regulatory Liabilities $ 33,907 $ 37,207 $163,692 $157,928 ======== ======== ======== ========
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-six years recovery period across all registrants. Note 3: Other may include items not earning a return and would have various recovery/refund periods. Note 4: Generally amortized over the life of the related plant assets as approved by the various state commissions. Note 5: Amortized over the period beginning with the commencement of an outage and ending with the beginning of the next outage.
KPCo OPCo ------------------------------ ---------------------------- Recovery/ Recovery/ Refund Refund 2002 2001 Period 2002 2001 Period ---- ---- -------- ---- ---- -------- (in thousands) Regulatory Assets: Amounts Due From Customers For Future Income Taxes $ 87,261 $83,027 Note 1 $165,106 $186,740 Note 1 Transition - Regulatory Assets 375,409 442,707 Dec. 2007 Deferred Fuel Costs - 1,542 Unamortized Loss on Reacquired Debt 152 51 Note 2 4,899 5,502 Note 2 Other 14,563 13,072 Note 3 23,227 9,676 Note 3 -------- ------- -------- -------- Total Regulatory Assets $101,976 $97,692 $568,641 $644,625 ======== ======= ======== ======== Regulatory Liabilities: Deferred Investment Tax Credits $ 9,165 $10,405 Note 4 $ 18,748 $ 21,925 Note 4 Other 12,152 6,551 Note 3 1,237 1,237 Note 3 -------- ------- -------- -------- Total Regulatory Liabilities $ 21,317 $16,956 $ 19,985 $ 23,162 ======== ======= ======== ========
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-six years recovery period across all registrants. Note 3: Other may include items not earning a return and would have various recovery/refund periods. Note 4: Generally amortized over the life of the related plant assets as approved by the various state commissions.
PSO SWEPCo ----------------------------- ------------------------------ Recovery/ Recovery/ Refund Refund 2002 2001 Period 2002 2001 Period ---- ---- -------- ---- ---- -------- (in thousands) Regulatory Assets: Amounts Due From Customers For Future Income Taxes $ 19,855 $ 16,532 Note 1 Deferred Fuel Costs $ 76,470 $ 756 Note 1 2,865 8,839 Note 1 Unamortized Loss on Reacquired Debt 11,138 12,381 Note 2 17,031 20,045 Note 2 Other 15,012 22,683 Note 3 12,347 15,731 Note 3 -------- ------- -------- -------- Total Regulatory Assets $102,620 $35,820 $ 52,098 $ 61,147 ======== ======= ======== ======== Regulatory Liabilities: Deferred Investment Tax Credits $ 32,201 $33,992 Note 4 $ 44,190 $ 48,714 Note 4 Ammounts Due To Customers For Future Income Taxes 27,893 26,085 Note 1 Deferred Fuel Costs - 9,476 Note 1 17,226 5,487 Note 1 Other 4,391 22,444 Note 3 7,094 10,889 Note 3 -------- ------- -------- -------- Total Regulatory Liabilities $ 64,485 $91,997 $ 68,510 $ 65,090 ======== ======= ======== ========
Note 1: This amount fluctuates from month to month and has no fixed recovery/refund period. Note 2: Unamortized loss on reacquired debt varies in its recovery period for each registrant and ranges from one to thirty-six years recovery period across all registrants. Note 3: Other may include items not earning a return and would have various recovery/refund periods. Note 4: Generally amortized over the life of the related plant assets as approved by the various state commissions.
TCC TNC ---------------------------- ------------------------------- Recovery/ Recovery/ Refund Refund 2002 2001 Period 2002 2001 Period ---- ---- -------- ---- ---- -------- (in thousands) Regulatory Assets: Amounts Due From Customers For Future Income Taxes $162,247 $ 200,496 Note 1 Regulatory Assets - Designated For or Subject To Securitization 336,444 959,294 Note 5 Deferred Fuel Costs $26,680 $ 40,389 Note 5 Texas Wholesale Clawback 262,000 - Note 5 Unamortized Loss on Reacquired Debt 8,661 11,186 Note 2 3,283 8,272 Note 2 Deferred Debt - Restructuring 13,324 - Note 2 10,134 - Note 2 DOE Decontamination and Decommissioning Assessment 3,170 3,170 Dec. 2004 Other 9,150 11,960 Note 3 5,000 5,461 Note 3 -------- ---------- ------- -------- Total Regulatory Assets $794,996 $1,186,106 $45,097 $ 54,122 ======== ========== ======= ======== Regulatory Liabilities: Deferred Investment Tax Credits $117,686 $ 122,892 Note 4 $21,510 $ 22,781 Note 4 Deferred Fuel Costs 69,026 52,572 Note 5 Texas Retail Clawback 51,926 - Note 5 14,328 - Note 5 Over - Recovery of Transition Changes 20,870 - Jan. 2016 Purchased Power Conservation 9,560 - Note 1 Excess Earnings 46,111 62,852 Note 5 17,419 17,300 Note 4 Ammounts Due To Customers For Future Income Taxes 12,280 13,591 Note 1 Other 6 6 Note 3 7,285 5,775 Note 3 -------- ---------- ------- -------- Total Regulatory Liabilities $315,185 $ 238,322 $72,822 $ 59,447 ======== ========== ======= ========
Note 1: This amount fluctuates from month to month or year to year and has no fixed recovery/refund 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/refund periods. Note 4: Generally amortized over the life of the related plant assets as approved by the various state commissions. Note 5: Includable in TCC's and TNC's PUCT 2004 true-up proceedings. See "Texas Restructuring" section of Note 8. 8. Customer Choice and Industry Restructuring: Customer choice allowing retail customers to select alternative generation suppliers began on January 1, 2001 in Ohio and on January 1, 2002 in Michigan, Virginia and in the ERCOT area of Texas. Customer choice in the SPP area of Texas, also scheduled to begin on January 1, 2002, was delayed by the PUCT. AEP's subsidiaries operate in both the ERCOT and SPP areas of Texas. Implementation of legislation enacted in Arkansas, Oklahoma and West Virginia to allow retail customers to choose their electricity supplier has been delayed or repealed. In 2001, Oklahoma delayed implementation of customer choice indefinitely. In February 2003, the Arkansas General Assembly passed legislation that repealed customer choice legislation, which is currently awaiting signature by the Govenor of Arkansas. Before West Virginia's choice plan can be effective, tax legislation must be passed to continue consistent funding for state and local governments. No further legislation has been introduced related to restructuring in 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. At January 1, 2003, 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 provided 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 and approval of a transition plan for each electric utility company, changed the taxation of electric companies and addressed certain major transition issues including unbundling of rates and the recovery of stranded costs including regulatory assets and transition costs. In 1999 CSPCo and OPCo filed transition plans. 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, 2002, the remaining amount of regulatory assets to be amortized as recovered was $375 million for OPCo and $205 million for CSPCo. By provisions of the Ohio Act on 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 paid the excise tax based on gross receipts was 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 treated the tax payment as a prepaid expense and amortized it to expense during the privilege year. The stipulation agreement also required the PUCO to consider implementation of a gross receipts tax credit rider as the parties could not reach an agreement. Following a hearing on the gross receipts tax issue, 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. On April 3, 2002, the Ohio Supreme Court rejected the companies' arguments and affirmed the PUCO's order which established the effective date of tax credit riders in rates. This ruling had no impact on 2002 results of operations as the companies had recorded an extraordinary loss ($30 million for CSPCo and $18 million for OPCo, both amounts net of tax) in 2001. On June 27, 2002, the Ohio Consumers' Counsel, Industrial Energy Users - Ohio and American Municipal Power - Ohio filed a complaint with the PUCO alleging that CSPCo and OPCo have violated the PUCO's orders regarding implementation of their transition plan and violated other applicable law by failing to participate in an RTO. The complainants seek, among other relief, an order from the PUCO suspending collection of transition charges by CSPCo and OPCo until transfer of control of their transmission assets has occurred, pricing standard offer electric generation effective January 1, 2006 at the market price used by the companies in their 1999 transition plan filings to estimate transition costs and imposing a $25,000 per company forfeiture for each day AEP fails to comply with its commitment to transfer control of transmission assets to an RTO. Due to the FERC's reversal of its previous approval of our RTO filings, CSPCo and OPCo have been delayed in the implementation of their RTO participation plans. We continue to pursue integration of CSPCo, OPCo and other AEP East companies into PJM. In this regard on December 19, 2002, the companies filed an application with PUCO for approval of the transfer of functional control over certain of their transmission facilities to PJM. Management is unable to predict the timing of FERC's final approval of RTOs, the timing of an RTO being operational or the outcome of these proceedings before the PUCO. In October 2002, the PUCO initiated an investigation of the financial condition of Ohio's regulated public utilities. The PUCO's goal is to identify measures available to the PUCO to ensure that the regulated operations of Ohio's public utilities are not impacted by adverse financial consequences of parent or affiliate company unregulated operations and take appropriate corrective action, if necessary. The utilities and other interested parties were requested to provide comments and suggestions by November 12, 2002, with reply comments by November 22, 2002, on the type of information necessary to accomplish the stated goals, the means to gather the required information from the public utilities and potential courses of action that the PUCO could take. Management is unable to predict the outcome of the PUCO's investigation or its impact on results of operations and business practices, if any. Virginia Restructuring - Affecting AEP and APCo In Virginia, choice of electricity supplier for retail customers began on January 1, 2002 under its restructuring law. Presently, APCo continues to service all its previous customers under capped rates. A finding by the Virginia SCC that an effective competitive market exists would be required to end the transition period prior to its scheduled end on June 30, 2007. 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. 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. In July 2002, APCo filed with the Virginia SCC requesting an increase in fuel rates effective January 1, 2003. A public hearing was held on September 23, 2002 related to this filing. On November 8, 2002, a decision was issued in this proceeding approving an annual increase of approximately $24 million. The Virginia restructuring law also required filings to be made that outline the functional separation of generation from transmission and distribution and a rate unbundling plan. In January 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 did not and will not collect a wires charge in 2002 or 2003, respectively. The settlement agreements and related Virginia SCC order addressed functional separation leaving decisions related to corporate separation for later consideration. Texas Restructuring - Affecting AEP, SWEPCo, TCC and TNC In preparation for the start of competition in Texas, CPL, SWEPCo, and WTU, the integrated electric utility companies operating in Texas, were required to make PUCT filings and legal and operational changes to their business. AEP formed new subsidiaries, Mutual Energy CPL L.P. and Mutual Energy WTU L.P., to act as retail electric providers (REP) in Texas beginning on January 1, 2002, the effective date of customer choice in Texas. The CPL and WTU names continued to be used by the registrant subsidiaries which owned the generation, transmission and distribution assets located in the ERCOT areas of Texas and WTU's entire operations in SPP throughout most of 2002. In December 2002, WTU transferred its SPP retail customers to Mutual Energy SWEPCO L.P. AEP sold the new subsidiaries that serve ERCOT retail customers to Centrica in December 2002, along with the Central Power and Light and West Texas Utilities brand names. CPL and WTU changed their names to AEP Texas Central Company (TCC) and AEP Texas North Company (TNC), respectively. 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 TNC's service territory are located in the SPP. TCC 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 provides for an earnings test for each of the years 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 and; o provides for a 2004 true-up proceeding to quantify and reconcile the amount of stranded costs, final fuel balances, net regulatory assets, certain environmental costs, accumulated excess earnings, excess of price-to-beat revenues over market prices subject to certain conditions and limitations (Retail clawback), and the difference between the price of power obtained through the legislatively-mandated capacity auctions and the power costs used in the PUCT's ECOM model for 2002 and 2003 (Wholesale clawback) and other issues. Under the Texas Legislation, electric utilities were required to submit a plan to structurally unbundle business activities into a retail electric provider, a power generation company and a transmission and distribution (T&D) utility. In 2000, SWEPCo, TCC and TNC filed their business separation plans with the PUCT. The PUCT approved the plans for TCC and TNC but determined that competition in the SPP areas of Texas should be delayed indefinitely and abated SWEPCo's plan. Operations for TCC and TNC have been functionally separated consistent with the approved plans. The delivery of electricity in ERCOT continues to be the responsibility of TCC and TNC at regulated prices. Texas Legislation provides electric utilities an opportunity to recover regulatory assets and stranded costs resulting from the unbundling of the T&D utility from the generation facilities. Stranded costs are the difference between regulatory net book value of generation assets and the market value of the assets based on one of several methodologies authorized by the Texas Legislation. Stranded costs can be refinanced through securitization (a financing structure designed to provide lower financing costs than are available through conventional financings). In 1999, TCC 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). TCC issued its securitization bonds in February 2002. The annual cost of the bonds are recovered through a PUCT approved transition charge in distribution rates. TCC 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 Production on AEP's Consolidated Balance Sheets. These STP costs had previously been identified as excess cost over market (ECOM) by the PUCT for regulatory purposes. They were 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 TCC's stranded costs was negative $615 million. TCC disagreed with the ruling (see discussion of appeal ruling below). The ruling indicated that TCC's costs were below market after securitization of regulatory assets. The final amount of TCC's stranded costs including regulatory assets and ECOM will be established by the PUCT in the 2004 true-up proceeding. If TCC'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 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, stock valuation or the use of an ECOM model. TCC decided to obtain a market value of generating assets for purposes of determining stranded costs for the 2004 true-up proceeding and filed a plan of divestiture with the PUCT, in December 2002, seeking approval of a sales process for all of its generating facilities. Such sales quantify the actual stranded costs. The amount of stranded costs under this market valuation methodology will be the amount by which net book value of TCC's generating assets, including regulatory assets and liabilities that were not securitized, exceeds the market value of the generation assets as measured by the net proceeds from the sale of the assets. It is anticipated that any such sale will result in significant stranded costs for purposes of the 2004 true-up proceeding. The filing included a request for the PUCT to issue a declaratory order that TCC's 25% ownership interest in its nuclear plant, STP, can be sold to value stranded costs. Intervenors to this proceeding, including the PUCT Staff, have made filings to dismiss TCC's filing claiming that the PUCT does not have the authority to issue a declaratory order. The intervenors also argued that the proper time to address the sales process is after the plants are sold during the 2004 true-up proceeding. Since the bidding process is not expected to be completed before mid 2004, TCC requested that the 2004 true-up proceeding be scheduled after completion of the divestiture of the generating assets. Texas Legislation also requires that electric utilities and their affiliated power generation companies (PGC) sell at auction in 2002 and 2003 at least 15% of the PGC's Texas jurisdictional installed generation capacity in order to promote competitiveness in the wholesale market through increased availability of generation and liquidity. Actual market power prices received in the state mandated auctions wil replace the PUCT's earlier estimates of those market prices used in the ECOM model to calculate the stranded cost for the 2004 true-up proceeding. The decision to determine stranded costs using market prices, instead of using the PUCT's ECOM model estimates, enabled TCC to record a $262 million regulatory asset and related revenues which represents the quantifiable amount of stranded costs for the year 2002 related to the wholesale prices. Prior to the decision to pursue a sale of TCC's generating assets, the PUCT's ECOM estimate prohibited the recognition of the regulatory assets and revenues as there was no way to quantify stranded costs. As discussed above, a defined process is required in order to determine the amount of stranded costs related to generation facility for the 2004 true-up proceedings. TCC's plan of divestiture filed with the PUCT during December 2002 provided such a process. When the divestiture and the 2004 true-up processing is completed, TCC will securitize stranded costs which exceed current securitized amounts. The annual costs of securitization will be recovered through a non-bypassable rate surcharge by the regulated T&D utility over the life of the securitization bonds. Any stranded costs and other true-up amounts not recovered through the sale of securitization bonds may be recovered through a separate non-bypassable competitive transition charge to T&D utility customers. The Texas Legislation provides for an earnings test each year 1999 through 2001 and requires PUCT approval of the annual earnings test calculation. The PUCT issued final orders for the 1999 earnings test in February 2001 and for the 2000 earnings test in September 2001. The 1999 excess earnings were none for SWEPCo, $24 million for TCC and $1 million for TNC. Excess earnings for 2000 were $1 million for SWEPCo, $23 million for TCC and $17 million for TNC. Adjustments were recorded in results of operations as the orders were received. The PUCT issued its final order for the 2001 earnings test in December 2002. An estimate of 2001 excess earnings of $8 million for TCC, $2 million for SWEPCo and none for TNC had been recorded in 2001. Adjustments to reflect the PUCT staff's estimate of excess earnings ($2 million for SWEPCo, $0.7 million for TNC and none for TCC) were recorded prior to September 30, 2002. The PUCT's final order regarding 2001 excess earnings required only minor adjustments to prior estimates. Due to TCC's and TNC's disagreement with the PUCT's final order for the 2000 excess earnings, the companies filed an appeal in district court in 2001 seeking judicial review of the PUCT's determination of excess earnings. The district court upheld the PUCT's order and the companies appealed that decision. A ruling on the appeal is expected in 2003. On January 28, 2003, the TCC and TNC filed an appeal in District Court seeking judicial review of the PUCT order for the 2001 excess earnings. The PUCT ruled that prior to the 2004 true-up proceeding, no adjustments would be made to the amount of stranded costs authorized by the PUCT to be securitized. Final stranded cost amounts and the treatment of excess earnings will be determined in the 2004 true-up proceeding. To the extent that the final 2004 true-up proceeding determines that TCC should recover additional stranded costs, the additional amount recoverable can also be securitized. 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 TCC to reduce distribution rates by approximately $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. Since excess earnings amounts were expensed 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 TCC will have stranded costs in 2004. TCC has appealed the PUCT's refund of excess earnings to the Travis County District Court and, depending on the outcome of that appeal (and the final outcome of the rulemaking challenge discussed below), the PUCT may revise the treatment of excess earnings in the final calculation of the stranded cost balance. In the same appeal, TCC and certain unaffiliated parties also challenged various elements of the PUCT's order determining the estimated stranded costs of TCC, with the unaffiliated parties contending, among other things, that the entire $615 million of negative stranded costs should be refunded presently. Prior to the Court hearing on this issue, however, TCC agreed to give up its claims concerning errors in the calculation of the stranded cost estimate, while the unaffiliated parties agreed to give up claims that there should be a refund of negative stranded costs. The Travis County District Court subsequently heard oral arguments concerning the remaining issues in the appeal, but has not yet issued a decision. The PUCT's stranded cost estimate that is the subject of this appeal will be superceded by a final determination of stranded costs to be accomplished as part of the 2004 true-up proceeding. In a separate appeal challenging the PUCT's substantive rule governing the 2004 true-up proceeding, the Texas Third Court of Appeals ruled in February 2003, that the Texas Legislation does not contemplate the refunding of negative stranded costs to customers. The Court of Appeals held that the PUCT was justified in using any negative stranded cost balance determined in the 2004 true-up proceeding only as an offset to prevent an over-recovery of stranded costs via securitization. In addition, the Court of Appeals ruled that negative stranded costs cannot be offset against other true-up balances, including final under-recovered fuel amounts. This ruling may be further appealed to the Supreme Court of Texas. Beginning January 1, 2002, fuel costs are not subject to PUCT fuel reconciliation proceedings for TCC and TNC's ERCOT retail customers. Due to the delay of competition for SWEPCo's SPP area of Texas, SWEPCo continues to record and request recovery of fuel costs subject to Texas fuel proceedings. Final deferred fuel balances related to ERCOT customers of TCC and TNC at December 31, 2001 will be included in the 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. Under the Texas Legislation, retail electric providers (REPs) associated with integrated utilities are required 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 the AEP REPs in TCC's and TNC's ERCOT area. Customers with a peak usage of more than 1000 KW are subject to market rates. The Texas Restructuring Legislation also provides that a REP associated with integrated utilities may request an adjustment of its fuel portion of the price-to-beat rate up to two times annually to reflect changes in market prices of fuel and purchased energy costs based upon changes in NYMEX gas prices. As part of the 2004 true-up proceedings the price-to-beat rates charged by AEP REPs for 2002 and 2003 will be compared to the market rates for the same period. If market rates are lower, the excess of the price-to-beat, reduced by non- bypassable delivery charges, over the prevailing market prices must be returned to the distribution company, subject to a per customer maximum. During 2002, AEP provided for such potential liabilities at the maximum amount via a charge to revenues, and recorded a regulatory liability for TCC and TNC. These amounts were $52 million for TCC and $14 million for TNC. 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. A Joint Stipulation approved by the WVPSC in 2000 in connection with a base rate filing, allowed 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. Management expects that the approved Joint Stipulation provides for the recovery of existing regulatory assets and other stranded costs. In order for customer choice to become effective in WV, the WV Legislature needed to enact additional legislation to preserve the revenues of state and local government. In the subsequent two legislative sessions, which usually end in March each year, the West Virginia Legislature has not enacted the required legislation. Due to the lack of legislative activity, the WVPSC closed two proceedings related to electricity restructuring in the summer of 2002. The two closed proceedings related to the respective dockets intended originally to determine whether West Virginia should deregulate the generation business, and to develop the WVPSC's Deregulation Plan and related rules to implement the Plan. Management has reviewed these two proceedings and has concluded that at this time it is not clear that APCo meets the requirements to reapply SFAS 71. Management will monitor developments to determine when it is appropriate to reapply SFAS 71 to APCo's generation business. Arkansas Restructuring - Affecting AEP and SWEPCo In 1999, Arkansas enacted legislation to restructure its electric utility industry. In February 2003, the Arkansas General Assembly passed legislation that repealed customer choice legislation, which is currently awaiting signature by the Governor of Arkansas. Discontinuance of the Application of SFAS 71 Regulatory Accounting in Arkansas, Ohio, Texas, Virginia and West Virginia - Affecting AEP, APCo, CSPCo, OPCo, SWEPCo, TCC and TNC 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 resulted in AEP and certain subsidiaries discontinuing 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 resulted in recognition of extraordinary gains or losses. 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. 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 companies 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 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 December 31, 2002, none of I&M's customers have elected to change suppliers and no alternative electric suppliers are registered to compete in I&M's Michigan service territory. Management has concluded that as of December 31, 2002 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. 9. Commitments and Contingencies: Construction and Other Commitments - Affecting AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC The AEP System has substantial construction commitments to support its operations. Aggregate construction expenditures for 2003-2005 for consolidated domestic and foreign operations are estimated to be $4.7 billion. The following table shows the estimated construction expenditures of the subsidiary registrants for 2003 - 2005: (in millions) AEGCo $ 70.9 APCo 1,005.7 CSPCo 418.9 I&M 601.5 KPCo 148.3 OPCo 733.4 PSO 262.3 SWEPCo 351.3 TCC 419.6 TNC 130.8 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. Certificates have been issued by both the West Virginia Public Service Commission and the Virginia State Corporation Commission authorizing construction and operation of the line. On December 31, 2002, the U.S. Forest Service issued a final environmental impact statement and record of decision to allow the use of federal lands in the Jefferson National Forest for construction of a portion of the line. We expect additional state and federal permits to be issued in the first half of 2003. Through December 31, 2002, we had invested approximately $51 million in this effort. The line is estimated to cost $287 million including amounts spent to date with completion scheduled in 2006. If the required permits are not obtained and the line is not constructed, the $51 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 2007 for APCo, 2005 for CSPCo, 2007 for I&M, 2005 for KPCo, 2012 for OPCo, 2014 for PSO, 2006 for SWEPCo and 2006 for TNC. 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 unit contingent contracts to supply approximately 250 MW of capacity to unaffiliated entities through December 31, 2009. The commitment is pursuant to a unit power agreement requiring the delivery of energy only if the unit capacity is available. Power Generation Facility - Affecting AEP and OPCo AEP has entered into agreements with Katco Funding L.P. (Katco) an unrelated unconsolidated special purpose entity. Katco has an aggregate financing commitment of $525 million and a capital structure of which 3% is equity from investors with no relationship to AEP or any of its subsidiaries and 97% is debt from a syndicate of banks. Katco was formed to develop, construct, finance and lease a power generation facility to AEP. Katco will own the power generation facility and lease it to AEP after construction is completed. The lease will be accounted for as an operating lease (see Note 22), therefore neither the facility nor the related obligations are reported on AEP's balance sheet. Payments under the operating lease are expected to commence in the first quarter of 2004. AEP will in turn sublease the facility to Dow Chemical Company (DOW), which will use the energy produced by the facility and sell excess energy. AEP has agreed to purchase the excess energy from DOW for resale. The use of Katco allows AEP to limit its risk associated with the power generation facility once the construction phase has been completed. AEP is the construction agent for Katco, and is responsible for completing construction by December 31, 2003, subject to unforeseen events beyond AEP's control. In the event the project is terminated before completion of construction, AEP has the option to either purchase the facility for 100% of project costs or terminate the project and make a payment to Katco for 89.9% of project costs. The operating lease between Katco and AEP commences on the commercial operation date of the facility and continues until November 2006. The lease contains extension options subject to the approval of Katco, and if all extension options were exercised, the total term of the lease would be 30 years. AEP's lease payments to Katco are sufficient for Katco to make required debt payments and provide a return to the investors of Katco. At the end of each lease term, AEP may renew the lease at fair market value subject to Katco's approval, purchase the facility at its original construction cost, or sell the facility, on behalf of Katco, to an independent third party. If the facility is sold and the proceeds from the sale are insufficient to repay Katco, AEP may be required to make a payment to Katco for the difference between the proceeds from the sale and the obligations of Katco, up to 82% of the project's cost. AEP has guaranteed a portion of the obligations of its subsidiaries to Katco during the construction and post-construction periods. As of December 31, 2002, project costs subject to these agreements totaled $360 million, and total costs for the completed facility are expected to be approximately $510 million. For the 30-year extended lease term, the lease rental 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 during the initial term calculated using the indexed LIBOR rate (1.38% at December 31, 2002). The Power Generation Facility collateralizes the debt obligation of Katco. AEP's maximum exposure to loss as a result of its involvement with Katco is 100% during the construction phase and up to 82% once the construction is completed. Maximum loss is deemed to be remote due to the collateralization. It is reasonably possible that AEP will consolidate Katco in the third quarter of 2003, as a result of the issuance of FASB Interpretation No. 46 "Consolidation of Variable Interest Entities" (FIN 46). Upon consolidation, AEP would record the assets, liabilities, depreciation expense, minority interest and debt interest expense. AEP would eliminate operating lease expense. The sublease to DOW would not be affected by this consolidation. OPCo has entered into a 30-year power purchase agreement for electricity produced by an unaffiliated entity's three-unit natural gas fired plant. The plant was completed in 2002 and the agreement will terminate in 2032. Under the terms of the agreement, OPCo has the option to run the plant until December 31, 2005 taking 100% of the power generated and making monthly capacity payments. The capacity payments are fixed through December 2005 at $1.2 million per month. For the remainder of the 30-year contract term, OPCo will pay the variable costs to generate the electricity it purchases (up to 20% of the plant's capacity). Nuclear Plants - Affecting AEP, I&M and TCC I&M owns and operates the two-unit 2,110 MW Cook Plant under licenses granted by the NRC. TCC 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 TCC 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 from customers is not possible, results of operations, cash flows and financial condition would be adversely affected. Nuclear Incident Liability - Affecting AEP, I&M and TCC 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. TCC 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. Under an industry-wide program insuring workers at nuclear facilities, I&M and TCC are also obligated for assessments of up to $6.2 million and $1.6 million, respectively, for potential claims. These obligations will remain in effect until December 31, 2007. 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. I&M and STPNOC jointly purchase $1 billion of excess coverage for property damage, decommissioning 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 TCC which is assessable if the insurer's financial resources would be inadequate to pay for losses. The current Price-Anderson Act expired in August 2002. Its contingent financial obligations still apply to reactors licensed by the NRC as of its expiration date. It is anticipated that the Price-Anderson Act will be renewed with increased third party financial protection requirements for nuclear incidents. SNF Disposal - Affecting AEP, I&M and TCC 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 $224 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, 2002, funds collected from customers towards payment of the pre-April 1983 fee and related earnings thereon are in external funds and exceed the liability amount. TCC 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, I&M and TCC 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 using the prompt decontamination and dismantlement (DECON) method. 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 recovering 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 2002 and 2001 and $28 million in 2000. 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 DECON method. TCC estimates its portion of the costs of decommissioning STP to be $289 million in 1999 nondiscounted dollars. TCC 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 2002 and 2001 I&M deposited in its decommissioning trust an additional $12 million each year 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 TCC's balance sheets, the nuclear decommissioning liability of $98 million is included in Electric Utility Plant-Accumulated Depreciation and Amortization. The decommissioning liability for both nuclear plants combined totals $719 million and $699 million at December 31, 2002 and 2001, respectively. Federal EPA Complaint and Notice of Violation - Affecting AEP, APCo, CSPCo, I&M, and OPCo Since 1999 AEPSC, 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 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. Management believes its maintenance, repair and replacement activities were in conformity with the Clean Air Act and intends to vigorously pursue its defense. 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 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 the 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, CSPCo, I&M, KPCo, OPCo, SWEPCo and TCC 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. 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 imposed 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. In August 2001 the D.C. Circuit Court issued an order tolling the compliance schedule until Federal EPA responded to the Court's remand. On April 30, 2002, Federal EPA announced that May 31, 2004 is the compliance date for the Section 126 Rule. Federal EPA published a notice in the Federal Register in May 2002 advising that no changes in the growth factors used to set the NOx budgets were warranted. In June 2002 AEP subsidiaries joined other utilities and industrial organizations in seeking a review of Federal EPA's action in the D.C. Circuit Court. This action is pending. In 2000 the Texas Commission on Environmental Quality (formerly the Texas Natural Resource Conservation Commission) adopted rules requiring significant reductions in NOx emissions from utility sources, including SWEPCo and TCC. The compliance date is May 2003 for TCC and May 2005 for SWEPCo. AEP is installing a variety of emission control technologies to reduce NOx emissions to comply with the applicable state and Federal NOx requirements. This includes selective catalytic reduction (SCR) technolocy on certain units and non-SCR technologies on a larger number of units. During 2001 SCR technology commenced operations on OPCo's Gavin Plant. Installation of SCR technology on Amos and Mountaineer plants was completed and commenced operation in May 2002. Construction of SCR technology at certain other AEP generating units continues. Non-SCR technologies have been installed and commenced operation on a number of units across the AEP System and additional units will be equipped with these technologies. The AEP NOx compliance plan is a dynamic plan that is continually reviewed and revised as new information becomes available on the performance of installed technologies and the cost of planned technologies. Certain compliance steps may or may not be necessary as a result of this new information. Consequently, the plan has a range of possible outcomes. Our current estimates indicate that compliance with the NOx Rule, the Texas Commission on Environmental Quality rule and the Section 126 Rule could result in required capital expenditures in the range of $1.3 billion to $2 billion of which $843 million has been spent through December 31, 2002 for the AEP System. The range of cost estimate reflects the uncertainty over the need for certain SCR projects. Estimated compliance cost ranges and amounts spent by registrant subsidiaries at December 31, 2002, are as follows: Estimated Amount Spent Compliance Costs ---------------- ------------ (in millions) AEGCo $30 - 198 $ 1 APCo 445 234 CSPCo 93 45 I&M 42 - 210 5 KPCo 163 135 OPCo 535 - 864 387 SWEPCo 40 24 TCC 5 5 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 results of operations, cash flows and possibly financial condition. Merger Litigation - Affecting AEP, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC 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 support and explain its conclusions that the 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 On October 15, 2002, certain subsidiaries of AEP filed claims against Enron and its subsidiaries in the bankruptcy proceeding filed by the Enron entities which are pending in the U.S. Bankruptcy Court for the Southern District of New York. 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 Company (HPL) from Enron. Various HPL related contingencies and indemnities remained unsettled at the date of Enron's bankruptcy. The timing of the resolution of the claims by the Bankruptcy Court is not certain. In connection with the 2001 acquisition of HPL, we acquired exclusive rights to use and operate the underground Bammel gas storage facility pursuant to an agreement with BAM Lease Company, a now-bankrupt subsidiary of Enron. This exclusive right to use the referenced facility is for a term of 30 years, with a renewal right for another 20 years and includes the use of the Bammel storage reservoir and the related compression, treating and delivery systems. We have engaged in preliminary discussions with Enron concerning the possible purchase of the residual interest held by Enron in the Bammel storage facility and the possible resolution of outstanding issues between AEP and Enron relating to our acquisition of its interest in the Bammel storage facility. We are unable to predict whether these discussions will lead to an agreement on these subjects. If these discussions do not lead to an agreement, there may be a dispute with Enron concerning our ability to continue utilization of the Bammel storage facility under the existing agreement. We also entered into an agreement with BAM Lease Company which grants HPL the right to use approximately 65 billion cubic feet of cushion gas (or pad gas) required for the normal operation of the Bammel gas storage facility. The Bammel Gas Trust, which purportedly owned approximately 55 billion cubic feet of the gas, had entered into a financing arrangement in 1997 with Enron and a group of banks. These banks purported to have certain rights to the gas in certain events of default. In connection with AEP's acquisition of HPL, the banks entered into an agreement granting HPL's use of the cushion gas and released HPL from liabilities and obligations under the financing arrangement. HPL was thereafter informed by the banks of a purported default by Enron under the terms of the referenced financing arrangement. In July 2002 the banks filed a lawsuit against HPL seeking a declaratory judgment that they have a valid and enforceable security interest in this cushion gas which would permit them to cause the withdrawal of this gas from the storage facility. In September 2002 HPL filed a general denial and certain counterclaims against the banks. Management is unable to predict the outcome of this lawsuit or its impact on results of operations and cash flows. In 2001 AEP expensed $47 million ($31 million net of tax) for our estimated loss from the Enron bankruptcy. In 2002 AEP expensed an additional $6 million for a cumulative loss of $53 million ($34 million net of tax). The amounts for certain subsidiary registrants were: Amounts Amounts Net of Registrant Expensed Tax -------- ----- (in millions) APCo $5.3 $3.4 CSPCo 2.7 1.8 I&M 2.8 1.8 KPCo 1.1 0.7 OPCo 3.6 2.3 The additional 2002 expense did not materially change the cumulative expense per registrant subsidiary. The amounts expensed were based on an analysis of contracts where AEP and Enron entities are counterparties, the offsetting of receivables and payables, the application of deposits from Enron entities and management's analysis of the HPL related purchase contingencies and indemnifications. Enron has recently instituted proceedings against other energy trading counter-parties challenging the practice of utilizing offsetting receivables and payables and related collateral across various Enron entities. We believe that we have the right to utilize similar procedures in dealing with payables, receivables and collateral with Enron entities by offsetting approximately $110 million of trading payables owed to various Enron entities against trading receivables due to us. We believe we have legal defenses to any challenge that may be made to the utilization of such offsets but at this time are unable to predict the ultimate resolution of this issue. Shareholder Lawsuits - Affecting AEP In the fourth quarter of 2002 lawsuits alleging securities law violations and seeking class action certification were filed in federal District Court, Columbus, Ohio against AEP, certain AEP executives, and in some of the lawsuits, members of the AEP Board of Directors and certain investment banking firms. The lawsuits claim that AEP failed to disclose that alleged "round trip" trades resulted in an overstatement of revenues, that AEP failed to disclose that AEP traders falsely reported energy prices to trade publications that published gas price indices and that AEP failed to disclose that it did not have in place sufficient management controls to prevent round trip trades or false reporting of energy prices. The plaintiffs seek recovery of an unstated amount of compensatory damages, attorney fees and costs. The cases are presently pending a decision by the Court on competing motions by certain plaintiffs and groups of plaintiffs' for designation as lead plaintiff. Once the Court selects a lead plaintiff, that lead plaintiff will file an amended complaint. AEP intends to vigorously defend against these actions. Also in the fourth quarter of 2002, two shareholder derivative actions were filed in state court in Columbus, Ohio against AEP and its Board of Directors alleging a breach of fiduciary duty for failure to establish and maintain adequate internal controls over AEP's gas trading operations; and, a lawsuit was filed against AEP, certain AEP executives and AEP's ERISA Plan Administrator in federal District Court for the Southern District of New York (subsequently transferred to federal District Court in Columbus, Ohio) alleging violations of the Employee Retirement Income Security Act in the selection of AEP stock as a investment alternative and in the allocation of assets to AEP stock. These cases are in the initial pleading stage. AEP intends to vigorously defend against these actions. California Lawsuit - Affecting AEP In November 2002, Cruz Bustamante, Lieutenant Governor of California, filed a lawsuit in Los Angeles County, California Superior Court against forty energy companies including AEP and two publishing companies alleging violations of California law through alleged fraudulent reporting of false natural gas price and volume information with an intent to affect the market price of natural gas and electricity. This case is in the initial pleading stage. AEP intends to vigorously defend against this action. Arbitration of Williams Claim - Affecting AEP In October 2002, AEP filed its demand for arbitration with the American Arbitration Association to initiate formal arbitration proceedings in a dispute with the Williams Companies (Williams). The proceeding results from Williams' repudiation of its obligations to provide physical power deliveries to AEP and Williams' failure to provide the monetary security required for natural gas deliveries by AEP. Consequently, both parties claimed default and terminated all outstanding natural gas and electric power trading deals among the various Williams and AEP affiliates. Williams claimed that AEP owes approximately $130 million in connection with the termination and liquidation of all trading deals. AEP believes it has valid claims arising from Williams' actions and is seeking, in part, a determination that either no amount is due or that a lesser amount is due from AEP to Williams (which is fully reserved by AEP) and the extent of any other damages and legal or equitable relief available. Although management is unable to predict the outcome of this matter, it is not expected to have a material impact on results of operations, cash flows or financial condition. Energy Market Investigations - Affecting AEP In February 2002, the FERC issued an order directing its Staff to conduct a fact-finding investigation into whether any entity, including Enron, manipulated short-term prices in electric energy or natural gas markets in the West or otherwise exercised undue influence over wholesale prices in the West, for the period January 1, 2000, forward. In April 2002 AEP furnished certain information to the FERC in response to their related data request. Pursuant to the FERC's February order, on May 8, 2002, the FERC issued further data requests, including requests for admissions, with respect to certain trading strategies engaged in by Enron and, allegedly, traders of other companies active in the wholesale electricity and ancillary services markets in the West, particularly California, during the years 2000 and 2001. This data request was issued to AEP as part of a group of over 100 entities designated by the FERC as all sellers of wholesale electricity and/or ancillary services to the California Independent System Operator and/or the California Power Exchange. The May 8, 2002 FERC data request required senior management to conduct an investigation into our trading activities during 2000 and 2001 and to provide an affidavit as to whether we engaged in certain trading practices that the FERC characterized in the data request as being potentially manipulative. Senior management complied with the order and denied our involvement with those trading practices. On May 21, 2002, the FERC issued a further data request with respect to this matter to us and over 100 other market participants requesting information for the years 2000 and 2001 concerning "wash", "round trip" or "sale/buy back" trading in the Western System Coordinating Council (WSCC), which involves the sale of an electricity product to another company together with a simultaneous purchase of the same product at the same price (collectively, "wash sales"). Similarly, on May 22, 2002, the FERC issued an additional data request with respect to this matter to us and other market participants requesting similar information for the same period with respect to the sale of natural gas products in the WSCC and Texas. After reviewing our records, we responded to the FERC that we did not participate in any "wash sale" transactions involving power or gas in the relevant market. We further informed the FERC that certain of our traders did engage in trades on the Intercontinental Exchange, an electronic electricity trading platform owned by a group of electricity trading companies, including us, on September 21, 2001, the day on which all brokerage commissions for trades on that exchange were donated to charities for the victims of the September 11, 2001 terrorist attacks, which do not meet the FERC criteria for a "wash sale" but do have certain characteristics in common with such sales. In response to a request from the California attorney general for a copy of AEP's responses to the FERC inquires, we provided the pertinent information. The PUCT also issued similar data requests to AEP and other power marketers. AEP responded to such data request by the July 2, 2002 response date. The U.S. Commodity Futures Trading Commission (CFTC) issued a subpoena to us on June 17, 2002 requesting information with respect to "wash sale" trading practices. AEP responded to CFTC. In addition, the U.S. Department of Justice made a civil investigation demand to AEP and other electric generating companies concerning their investigation of the Intercontinental Exchange. AEP has completed a review of our trading activities in the United States for the last three years involving sequential trades with the same terms and counterparties. The revenue from such trading is not material to our financial statements. AEP believes that substantially all these transactions involve economic substance and risk transference and do not constitute "wash sales". In August 2002, AEP received an informal data request from the SEC asking us to voluntarily provide documents related to "round trip" or "wash" trades. AEP has provided the requested information to the SEC. In September 2002, AEP received a subpoena from FERC requesting information about our natural gas transactions and their potential impact on gas commodity prices in the New York City area. AEP responded to the subpoena in October 2002. In October 2002, AEP dismissed several employees involved in natural gas marketing and trading after the Company determined that they provided inaccurate price information for use in indexes compiled and published by trade publications. AEP, subsequently, instituted measures that require all price information for use in market indexes be verified and reported through AEP's chief risk officer's organization. AEP has and will continue to provide to the FERC, the SEC and the CFTC information relating to price data given to energy industry publications. FERC Proposed Standard Market Design - Affecting AEP System In July 2002, the FERC issued its Standard Market Design (SMD) notice of proposed rulemaking, one of the most sweeping rulemaking proposals in its history. The proposed SMD rule seeks to standardize the structure and operation of wholesale electricity markets across the country. Key elements of FERC's proposal include standard rules and processes for all users of the electricity transmission grid, new transmission rules and policies, and the creation of certain markets to be operated by independent administrators of the grid in all regions. The FERC recently indicated that it would issue a white paper on the proposal in April 2003, in response to the numerous comments FERC received on its proposal. The FERC is expected to issue its final rule in mid to late 2003. Because the rule is not yet finalized, management cannot predict the effect of the final rule on cash flows and results of operations. FERC Proposed Security Standards - Affecting AEP System The FERC published for comment its proposed security standards as part of the SMD. These standards are intended to ensure all market participants have a basic security program that effectively protects the electric grid and related market activities. They require compliance by January 1, 2004. The impact of these proposed standards is far-reaching and includes significant penalties for non-compliance. These standards apply to market operations and transmission owners. For the AEP System this includes: power generation plants, transmission systems, distribution systems and related areas of business. FERC is considering new proposals to modify the scope and timetable for compliance with the standards. Unless FERC changes the scope and timing of the original proposed standards, those standards could result in significant expenditures and operational changes in a compressed time frame, and may adversely affect results of operations and cash flows if such costs are not recovered from customers. FERC Market Power Mitigation - Affecting AEP System A FERC order issued in November 2001 on AEP's triennial market based wholesale power rate authorization update required certain mitigation actions that AEP would need to take for sales/purchases within its control area and required AEP to post information on its website regarding its power system's status. As a result of a request for rehearing filed by AEP and other market participants, FERC issued an order delaying the effective date of the mitigation plan until after a planned technical conference on market power determination. No such conference has been held and management is unable to predict the timing of any further action by the FERC or its affect on future results of operations and cash flows. Other - AEP and its 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. 10. Guarantees: In November 2002, the FASB issued FASB Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" (FIN 45) which clarifies the accounting to recognize a liability related to issuing a guarantee, as well as additional disclosures of guarantees. This new guidance is an interpretation of SFAS 5, 57, and 107 and a rescission of FIN 34. The initial recognition and initial measurement provisions of FIN 45 is effective on a prospective basis to guarantees issued or modified after December 31, 2002. The disclosure requirements of FIN 45 are effective for financial statements of interim or annual periods ending after December 15, 2002. There are no liabilities recorded for all of the guarantees described below in accordance with FIN 45 as these guarantees were entered into prior to December 31, 2002. There is no collateral held in relation to these guarantees and there is no recourse to third parties in the event these guarantees are drawn. Certain AEP subsidiaries have entered into standby letters of credit (LOC) with third parties. These LOCs cover gas and electricity trading contracts, construction contracts, insurance programs, security deposits, debt service reserves, drilling funds and credit enhancements for issued bonds. All of these LOCs were issued at a subsidiary level of AEP in the subsidiaries' ordinary course of business. TCC issued one of the LOCs for credit enhancement of issued bonds. The maximum future payments of all the LOCs are approximately $166 million with maturities ranging from January 2003 to December 2007. TCC's LOC was for $40.9 million with a maturity date of November 2003. Since AEP is the parent to all these subsidiaries, it holds all assets of the subsidiary as collateral. There is no recourse to third parties in the event these letters of credit are drawn. The following AEP subsidiaries have entered into guarantees of third parties obligations: CSW Energy and CSW International have guaranteed 50% of the required debt service reserve of Sweeny Cogeneration (Sweeny), an IPP of which CSW Energy is a 50% owner. The guarantee was provided in lieu of Sweeny funding the debt reserve as a part of financing. In the event that Sweeny does not make the required debt payments, CSW Energy and CSW International have a maximum future payment exposure of approximately $3.7 million, which expires June 2020. Additionally, CSW guaranteed 50% of the required debt service reserve for Polk Power Partners, another IPP of which CSW Energy owns 50%. In the event that Polk Power does not make the required debt payments, CSW has a maximum future payment exposure of approximately $4.7 million, which expires July 2010. In connection with reducing the cost of the lignite mining contract for its Henry W. Pirkey Power Plant, SWEPCo has agreed under certain conditions, to assume the revolving credit agreement, capital lease obligations, and term loan payments of the mining contractor. In the event the mining contractor defaults under any of these agreements, SWEPCo's total future maximum payment exposure is approximately $74 million with maturity dates ranging from April 2003 to February 2012. 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 approximately $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, 2002 the cost to reclaim the mine is estimated to be approximately $36 million. This guarantee ends upon depletion of reserves estimated at 2035 plus 6 years to complete reclamation. In connection with the ability for Mutual Energy CPL L.P. (former subsidiary of AEP sold to Centrica on December 23, 2002) to compete in the CPL territory and to secure transition charges, AEP provided a guarantee that AEP would pay transition charges if Mutual Energy CPL failed to meet certain obligations. At the time of sale this guarantee (matures in February 2003) was not revoked. The future maximum payment exposure is $12.2 million. In February 2003, the guarantee matured and no payments under the guarantee were required. In connection with the ERCOT transmission congestion auction, AEP has guaranteed the obligations of Mutual Energy CPL L.P. (former subsidiary of AEP sold to Centrica on December 23, 2002) and Mutual Energy WTU L.P. (former subsidiary of AEP sold to Centrica on December 23, 2002). At the time of sale these guarantees were not revoked. The total future maximum payment exposure for both companies is approximately $0.6 million. In January 2003 these guarantees matured and no payments under the guarantees were required. See Note 26 "Minority Interest in Finance Subsidiary" for disclosure for the guaranteed support of AEP for Caddis Partners, LLC. AEP and all its registrant and non-registrant subsidiaries enter into several types of contracts, which would require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. At this time AEP cannot estimate the maximum potential payment for any of these indemnifications due to the uncertainty of future events. In addition, as of December 31, 2002, there are no liabilities required for any indemnifications. AEP and its regulated and non-regulated subsidiaries lease certain equipment under a master operating lease. Under the lease agreement, the lessor is guaranteed to receive up to 87% of the unamortized balance of the equipment at the end of the lease term. If the fair market value of the leased equipment is below the unamortized balance at the end of the lease term, we have committed to pay the difference between the fair market value and the unamortized balance, with the total guarantee not to exceed 87% of the unamortized balance. At December 31, 2002, the maximum potential loss for these lease agreements was approximately $50 million assuming the fair market value of the equipment is zero at the end of the lease term. The maximum potential loss by registrant is as follows: Registrant Maximum Potential Loss - ---------- ---------------------- (in millions) APCo $ 0.7 CSPCo 0.8 I&M 2.0 KPCo - OPCo 0.7 PSO 3.3 SWEPCo 3.4 TCC 6.7 TNC 2.5 Other AEP non-registrant Subsidiaries 29.9 ----- Total $50.0 ===== 11. Sustained Earnings Improvement Initiative: In response to difficult conditions in AEP's business, a Sustained Earnings Improvement (SEI) initiative was undertaken company-wide in the fourth quarter of 2002, as a cost-saving and revenue-building effort to build long-term earnings growth. Termination benefits expense relating to 1,120 terminated employees totaling $75.4 million pre-tax was recorded in the fourth quarter of 2002. Of this amount, AEP paid $9.5 million to these terminated employees in the fourth quarter of 2002. The termination benefits expense was classified as Maintenance and Other Operation expense on AEP's Consolidated Statements of Operations and as Other Operation expense on the other registrant's statements of operations. We determined that the termination of the employees under our SEI initiative did not constitute a curtailment under the provisions of SFAS No. 88 "Employers' Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits". The following table shows the staff reductions, termination benefits expense and the remaining termination benefits expense accrual as of December 31, 2002: Total Total Number Total Termination of Expense Benefits Terminated Recorded in Accrued at Employees 2002 12/31/02 --------- --------- ----------- (in millions) (in millions) AEGCo - $ 0.3 $ 0.3 APCo 93 13.1 12.2 CSPCo 19 5.0 4.5 I&M 146 15.0 13.1 KPCo 16 2.6 2.5 OPCo 33 7.5 7.1 PSO 17 3.1 3.0 SWEPCo 8 3.3 3.1 TCC 37 6.0 5.5 TNC 20 2.0 1.6 Other AEP Subsidiaries 731 17.5 13.0 ----- ----- ----- Totals 1,120 $75.4 $65.9 ===== ===== ===== Approximately $48 million of severance expense associated with 701 AEP Service Corporation employees (included in the 731 figure above) was allocated among all AEP subsidiaries. AEGCo has no employees but receives allocated expenses. In addition, certain buildings and corporate aircraft are being sold in an effort to reduce ongoing operating expenses. 12. Acquisitions, Dispositions and Discontinued Operations: Acquisitions SFAS 141 "Business Combinations" applies to all business combinations initiated and consummated after June 30, 2001. 2002 Acquisition of Nordic Trading In January 2002 AEP acquired for $2.2 million and other assumed liabilities the trading operations, including key staff, of Enron's Norway and Sweden-based energy trading businesses (Nordic Trading). Results of operations are included in AEP's Consolidated Statements of Operations from the date of acquisition. The excess of cost over fair value of the net assets acquired was approximately $4.0 million which was recorded as Goodwill. Subsequently in the fourth quarter of 2002, a decision was made to exit the non-core trading business in Europe and to close or sell Nordic Trading as discussed under the "Discontinued Operations" section of this note. Acquisition of USTI In January 2002, AEP acquired 100% of the stock of United Sciences Testing, Inc. (USTI) for $12.5 million. USTI provides equipment and services related to automated emission monitoring of combustion gases to both AEP affiliates and external customers. Results of operations are included in AEP's Consolidated Statements of Operations from the date of acquisition. 2001 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 determined by independent appraisal or by Company's management based on information currently available and on current assumptions as to future operations. Based on a final purchase price allocation the excess of cost over fair value of the net assets acquired was approximately $153 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. 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 and assumed the existing mine reclamation liabilities at its jointly owned lignite reserves in Louisiana. o Quaker Coal Company as part of a bankruptcy proceeding settlement. AEP also 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 continues to operate the mines and facilities which employ over 800 individuals. See Note 13b "Asset Impairments and Investment Value Losses". o MEMCO Barge Line added 1,200 hopper barges and 30 towboats to AEP's existing barging fleet. MEMCO's 450 employees operate the barge line. MEMCO added major barging operations on the Mississippi and Ohio rivers to AEP's barging operations on the Ohio and Kanawha rivers. o U.K. Generation added 4,000 megawatts of coal-fired generation from 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. See Note 13b "Asset Impairments and Investment Value Losses". o A 20% equity interest in Caiua, a Brazilian electric operating company which is a subsidiary of Vale. See Note 21, "Power and Distribution Projects". AEP converted a total of $66 million on an existing loan and accrued interest on that loan into Caiua equity. See Note 13b "Asset Impairments and Investment Value Losses". o Indian Mesa Wind Project consisting of 160 megawatts of wind generation located near Fort Stockton, Texas. o Acquired existing contracts and hired key staff from Enron's London-based international coal trading group. Regarding the 2002 and 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. Dispositions 2002 In 2002, AEP completed a number of disposals of assets determined to be non-core: Disposal of SEEBOARD On June 18, 2002, AEP, through a wholly owned subsidiary, entered into an agreement, subject to European Union (EU) approval, to sell its consolidated subsidiary SEEBOARD, a U.K. electricity supply and distribution company. EU approval was received July 25, 2002 and the sale was completed on July 29, 2002. AEP received approximately $941 million in net cash from the sale, subject to a working capital true up, and the buyer assumed SEEBOARD debt of approximately $1.12 billion, resulting in a net loss of $345 million at June 30, 2002. In accordance with SFAS 144 the results of operations of SEEBOARD have been classified as Discontinued Operations for all years presented. A net loss of $22 million was classified as Discontinued Operations in the second quarter of 2002. The remaining $323 million of the net loss has been classified as a transitional impairment loss from the adoption of SFAS 142 (see Notes 2 and 3) and has been reported as a Cumulative Effect of Accounting Change retroactive to January 1, 2002. A $59 million reduction of the net loss was recognized in the second half of 2002 to reflect changes in exchange rates to closing, settlement of working capital true-up and selling expenses. The net total loss recognized on the disposal of SEEBOARD was $286 million. Proceeds from the sale of SEEBOARD were used to pay down bank facilities and short-term debt. The assets and liabilities of SEEBOARD were aggregated on AEP's Consolidated Balance Sheets as Assets of Discontinued Operations and Liabilities of Discontinued Operations as of December 31, 2001. The major classes of SEEBOARD's assets and liabilities of discontinued operations were: December 31, 2001 ----------- (in millions) Assets: Current Assets $ 324 Plant,Property and Equipment, Net 1,283 Goodwill 1,129 Other Assets 96 ------ Total Assets of Discontinued Operations $2,832 Liabilities: Current Liabilities $ 752 Long-term Debt 701 Deferred Income Taxes 268 Other Liabilities 77 ------ Total Liabilities of Discontinued Operations $1,798 Disposal of CitiPower On July 19, 2002, AEP, through a wholly owned subsidiary entered into an agreement to sell CitiPower, a retail electricity and gas supply and distribution subsidiary in Australia. AEP completed the sale on August 30, 2002 and received net cash of approximately $175 million and the buyer assumed CitiPower debt of approximately $674 million. AEP recorded a net charge totaling $125 million as of June 30, 2002. The charge included an impairment loss of $98 million on the remaining carrying value of an intangible asset related to a distribution license for CitiPower. The remaining $27 million of net loss was classified as a transitional goodwill impairment loss from the adoption of SFAS 142 (see Notes 2 and 3) and was recorded as a Cumulative Effect of Accounting Change retroactive to January 1, 2002. The loss on the sale of CitiPower increased $24 million to $149 million in the second half of 2002 based on actual closing amounts and exchange rates. CitiPower's results of operations have been reclassified as Discontinued Operations in accordance with SFAS 144. The assets and liabilities of CitiPower have been aggregated on the December 31, 2001, AEP balance sheet as Assets of Discontinued Operations and Liabilities of Discontinued Operations. The major classes of CitiPower's assets and liabilities of discontinued operations are: December 31, 2001 ------------------- (in millions) Assets: Current Assets $ 138 Plant, Property and Equipment, Net 495 Goodwill/Intangibles 466 Other Assets 23 ------ Total Assets of Discontinued Operations $1,122 ====== Liabilities: Current Liabilities $ 83 Long-term Debt 612 Deferred Income Taxes 55 Other Liabilities 34 ---- Total Liabilities of Discontinued Operations $784 Total revenues and pretax profit (loss) of the discontinued operations of SEEBOARD and CitiPower were: SEEBOARD (in millions) Revenues: 12 months ended 12/31/02 $ 694 12 months ended 12/31/01 1,451 12 months ended 12/31/00 1,596 Pretax Profit: 12 months ended 12/31/02 $ 180 12 months ended 12/31/01 104 12 months ended 12/31/00 91 CitiPower (in millions) Revenues: 12 months ended 12/31/02 $ 204 12 months ended 12/31/01 350 12 months ended 12/31/00 338 Pretax Profit (Loss): 12 months ended 12/31/02 $ (190) 12 months ended 12/31/01 (4) 12 months ended 12/31/00 20 Disposition of Texas REPs In April 2002, AEP reached a definitive agreement, subject to regulatory approval, to sell two of its Texas retail electric providers (REPs) to Centrica, a provider of retail energy and other consumer services. PUCT regulatory approval for the sale was obtained in December 2002. On December 23, 2002 AEP sold to Centrica, the general partner interests and the limited partner interests in Mutual Energy CPL L.P. and Mutual Energy WTU L.P. for a base purchase price paid in cash at closing and certain additional payments, including a net working capital payment. Centrica paid a base purchase price of $145.5 million which was based on a fair market value per customer established by an independent appraiser and an agreed customer count. AEP recorded a net gain totaling $83.7 million in Other Income. AEP (through TCC and TNC) will provide Centrica with a power supply contract for the two REPs and back-office services related to these customers for a two-year period. In addition, AEP retained the right to share in earnings from the two REPs above a threshold amount through 2006 in the event the Texas retail market develops increased earnings opportunities. Under the Texas Legislation, REPs are subject to a clawback liability if customer change does not attain thresholds required by the legislation. AEP is responsible for a portion of such liability, if any, for the period it operated the REPs in the Texas competitive retail market (January 1, 2002 through December 23, 2002). In addition, AEP retained responsibility for regulatory obligations arising out of operations before closing. AEP's wholly-owned subsidiary Mutual Energy Service Company LLC (MESC) received an up-front payment of approximately $30 million from Centrica associated with the back-office service agreement, and MESC deferred its right to receive payment of an additional amount of approximately $9 million to secure certain contingent obligations. These prepaid service revenues were deferred on the books of MESC to be amortized over the two-year term of the back office service agreement. 2001 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 the results of operations and cash flows of OPCo and AEP. In December 2001, AEP completed the sale of its ownership interests in the Virginia and West Virginia PCS (personal communications services) Alliances for stock, resulting in an after tax gain of approximately $7 million. During 2002, due to decreasing market value of the shares, AEP reduced the value of them to zero. 2000 In December 2000, AEP, 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 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 writedown is included in Other Income on AEP's Consolidated Statements of Operations. 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 Accumulated Other Comprehensive Income. In the second quarter of 2000 AEP management 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). Discontinued Operations The operations shown below, affecting AEP, were discontinued or classified as held for sale in 2002. Results of operations of these businesses have been reclassified as shown in the following table:
SEE-BOARD CitiPower Pushan Eastex Total --------- --------- ------ ------ ----- (in millions) 2002 Revenue $ 694 $204 $57 $ 73 $1,028 2001 Revenue 1,451 350 57 - 1,858 2000 Revenue 1,596 338 57 - 1,991 2002 Earnings (Loss) After Tax 96 (123) (7) (156) (190) 2001 Earnings (Loss) After Tax 88 (6) 4 - 86 2000 Earnings (Loss) After Tax 99 17 7 (1) 122
13. Asset Impairments and Investment Value Losses: In 2002 AEP recorded pre-tax impairments of assets (including goodwill) and investments totaling $1.426 billion (consisting of approximately $866.6 million related to Asset Impairments, $321.1 million related to Investment Value and Other Impairment Losses, and $238.7 million related to Discontinued Operations) that reflected downturns in energy trading markets, projected long-term decreases in electricity prices, and other factors. These impairments exclude the transitional impairment loss from adoption of SFAS142 (see Notes 2 and 3). The categories of impairments included: 2002 Pre-Tax Estimated Loss ---- (in millions) Asset Impairments Held for Sale $ 483.1 Asset Impairments Held and Used 651.4 Investment Value Losses 291.9 ---------- Total $1,426.4 ======== a. Assets Held for Sale In 2002, AEP (and its registrant subsidiaries, as applicable) recorded the following estimated loss on disposal of assets (including Goodwill) held for sale:
2002 Pre-Tax Assets Estimated Loss Held for Sale on Disposal Business Registrant ------------- ----------- -------- ---------- (in millions) Eastex $218.7 Wholesale AEP Pushan Power 20.0 Other AEP ------- Total Impairment Losses Included in Discontinued Operations $238.7 Telecommunication - AEPC/C3 $158.5 Other AEP Newgulf Facility 11.8 Wholesale AEP Nordic Trading 5.3 Wholesale AEP Excess Equipment 23.9 Wholesale AEP Excess Real Estate 15.7 Wholesale AEP -------- Total Included in Asset Impairment Losses $215.2 Telecommunications - AFN $ 13.8 Other AEP Water Heater AEP, APCo, CSPCo, Program 3.2 Wholesale I&M, KPCo and OPCo Gas Power Systems 12.2 Wholesale AEP -------- Total Included in Investment Value and Other Impairment Losses $ 29.2 ------- Total-All Held for Sale Losses $483.1 ======
Eastex In 1998, CSW began construction of a natural gas-fired cogeneration facility (Eastex) located near Longview, Texas and commercial operations commenced in December 2001. In June 2002, AEP requested that the FERC allow it to modify the FERC Merger Order and substitute Eastex as a required divestiture under the order, due to the fact that the agreed upon market-power related divestiture of a plant in Oklahoma was no longer feasible. The FERC approved the request at the end of September 2002. Subsequently, in the fourth quarter of 2002 AEP solicited bids for the sale of Eastex and several interested buyers were identified by December 2002. A sale of assets is expected to be completed by the end of 2003 with an estimated pre-tax loss on sale of $218.7 million included in Discontinued Operations in AEP's Consolidated Statements of Operations. The estimated loss was based on the estimated fair value of the facility and indicative bids by interested buyers. Results of operations of Eastex have been reclassified as Discontinued Operations in accordance with SFAS 144 as shown in Note 12. The assets and liabilities of Eastex have been included on AEP's Consolidated Balance Sheets as held for sale. The major classes of assets and liabilities held for sale are: 2002 2001 ---- ---- (in millions) Assets: Current Assets $15 $ - Property, Plant and Equipment, Net - 217 Other Assets - 3 ------ ------ Total Assets Held for Sale $15 $220 === ==== Liabilities: Current Liabilities $ 8 $ 5 Other Liabilities 4 1 ----- ------ Total Liabilities Held for Sale $12 $ 6 === ====== Pushan Power Plant In the fourth quarter of 2002, AEP began active negotiations to sell its interest in the Pushan Power Plant (Pushan) in Nanyang, China to the minority interest partner. Negotiations are expected to be completed by the second quarter of 2003 with an estimated pre-tax loss on disposal of $20.0 million, based on an indicative price expression. The estimated pre-tax loss on disposal is classified in Discontinued Operations in AEP's Consolidated Statements of Operations. Results of operations of Pushan have been reclassified as Discontinued Operations in accordance with SFAS 144 as discussed in Note 12. The assets and liabilities of Pushan have been classified on AEP's Consolidated Balance Sheets as held for sale. The major classes of assets and liabilities held for sale are: 2002 2001 ---- ---- (in millions) Assets: Current Assets $ 19 $ 17 Property, Plant and Equipment, Net 132 161 ----- ----- Total Assets Held for Sale $151 $178 ==== ==== Liabilities: Current Liabilities $ 28 $ 27 Long-term Debt 25 30 Other Liabilities 26 24 ------ ----- Total Liabilities Held for Sale $ 79 $ 81 ===== ===== Telecommunications AEP had developed businesses to provide telecommunication services to businesses and to other telecommunication companies through broadband fiber optic networks operated in conjunction with AEP's electric transmission and distribution lines. The businesses included AEP Communications, LLC (AEPC), C3 Communications, Inc. (C3), and a 50% share of AFN Networks, LLC (AFN), a joint venture. Due to the difficult economic conditions in these businesses and the overall telecommunications industry, and other operating problems, the AEP Board approved in December 2002 a plan to cease operations of these businesses. AEP took steps to market the assets of the businesses to potential interested buyers in the fourth quarter of 2002. A number of potential buyers have made offers for the assets of C3. Potential buyers have indicated interest in the assets of AFN. A formal offering of the assets of AEPC will begin early in 2003. The complete sale of all telecommunication assets is expected to be completed by the end of 2003 with an estimated pre-tax impairment loss of $158.5 million (related to AEPC and C3) classified in Asset Impairments in AEP's Consolidated Statements of Operations and an estimated pre-tax loss in value of the investment in AFN of $13.8 million classified in Investment Value and Other Impairment Losses in AEP's Consolidated Statements of Operations. The estimated losses are based on indicative bids by potential buyers. $6 million and $182 million of Property, Plant and Equipment, net of accumulated depreciation of the telecommunication businesses have been classified on AEP's Consolidated Balance Sheets as held for sale in 2002 and 2001, respectively. Newgulf Facility In 1995, CSW purchased an 85 MW gas-fired peaking electrical generation facility located near Newgulf, Texas (Newgulf). In October 2002 AEP began negotiations with a likely buyer of the facility. A sale is now expected to be completed by the end of 2003 with an estimated pre-tax loss on sale of $11.8 million based on an indicative bid by the likely buyer. The estimated loss on disposal is classified in Asset Impairments on AEP's Consolidated Statements of Operations. Newgulf's Property, Plant and Equipment, net of accumulated depreciation, of $6 million in 2002 and $17 million in 2001 has been classified on AEP's Consolidated Balance Sheets as held for sale. Nordic Trading In October 2002 AEP announced that its ongoing energy trading operations would be centered around its generation assets. As a result, AEP took steps to exit its coal, gas, and electricity trading activities in Europe, except for those activities necessary to support the U.K. Generation operations. The Nordic Trading business acquired earlier in 2002 (see Note 12) was made available for sale to potential buyers. The estimated pre-tax loss on disposal in 2002 of $5.3 million, consisted of impairment of goodwill of $4.0 million (see Note 3) and impairment of assets of $1.3 million. The estimated loss of $5.3 million is included in Asset Impairments on AEP's Consolidated Statements of Operations. Management's determination of a zero fair value was based on discussions with a potential buyer. There are no assets and liabilities of Nordic Trading to be classified on AEP's Consolidated Balance Sheets as held for sale. Excess Equipment In November 2002, as a result of a cancelled development project, AEP obtained title to a surplus gas turbine generator. AEP has been unsuccessful in finding potential buyers of the unit, including its own internal generation operators, due to an over-supply of generation equipment available for sale. Sale of the turbine is now projected before the end of 2003 with an estimated 2002 pre-tax loss on disposal of $23.9 million, based on market prices of similar equipment. The loss is included in Asset Impairments on AEP's Consolidated Statements of Operations. The Other asset of $12 million in 2002 and $31 million in 2001 has been classified on AEP's Consolidated Balance Sheets as held for sale. Excess Real Estate In the fourth quarter of 2002, AEP began to market an under-utilized office building in Dallas, TX obtained through the merger with CSW. One prospective buyer has executed an option to purchase the building. Sale of the facility is projected by second quarter 2003 and an estimated 2002 pre-tax loss on disposal of $15.7 million has been recorded, based on the option sale price. The estimated loss is included in Asset Impairments on AEP's Consolidated Statements of Operations. The Property asset of $18 million in 2002 and $36 million in 2001 has been classified on AEP's Consolidated Balance Sheets as held for sale. Water Heater Program AEP, APCo, CSPCo, I&M, KPCo and OPCo operated a program to lease electric water heaters to residential and commercial customers until a decision was reached in the fourth quarter of 2002 to discontinue the program and to offer the assets for sale. Negotiations are underway with a qualified buyer, and sale of the assets is projected by the end of the first quarter of 2003. AEP's estimated 2002 pre-tax loss on disposal of $3.20 million ($50 thousand for APCo, $615 thousand for CSPCo, $643 thousand for I&M, $11 thousand for KPCo, $1.757 million for OPCo and $126 thousand for other AEP non-registrant subsidiaries) was based on the expected contract sales price. The loss is included in Investment Value and Other Impairment Losses on AEP's Consolidated Statements of Operations and in Nonoperating Expenses on the statements of income of the registrant subsidiaries. The assets and liabilities have been classified on AEP's Consolidated Balance Sheets as held for sale. The major classes of assets held for sale are: 2002 2001 ---- ---- (in millions) Assets: Current Assets $ 1 $ 2 Property, Plant and Equipment, Net 38 48 ---- ---- Total Assets Held for Sale $39 $50 === === Gas Power Systems AEP acquired in 2001 a 75% interest in a startup company seeking to develop low-cost peaking generator sets powered by surplus jet turbine engines. The first quarter of 2002, AEP recognized a goodwill impairment loss of $12.2 million due to technological and operating problems (See Note 3). The loss was recorded in Investment Value and Other Impairment Losses on AEP's Consolidated Statements of Operations. The fair values of the remaining assets and liabilities were excluded from AEP's Consolidated Balance Sheets as held for sale, as the impact was insignificant. AEP's remaining interest was sold in January 2003. b. Assets Held and Used In 2002, AEP recorded the following impairments related to assets (including Goodwill) held and used to Asset Impairments on AEP's Consolidated Statements of Operations: Assets Business Held and Used 2002 Pre-Tax Loss Segment Registrant ------------- ------------------ ------- ---------- (in millions) U.K. Generation $548.7 Wholesale AEP AEP Coal 59.9 Wholesale AEP Texas Plants 38.1 Wholesale AEP and TNC Ft. Davis Wind Farm 4.7 Wholesale AEP and TNC ------- Total - ALL Held and Used Losses $51.4 ===== U.K. Generation Plants In December 2001, AEP acquired two coal-fired generation plants (U.K. Generation) in the U.K. for a cash payment of $942.3 million and assumption of certain liabilities. Subsequently and continuing through 2002, wholesale U.K. electric power prices declined sharply as a result of domestic over-capacity and static demand. External industry forecasts and AEP's own projections made during the fourth quarter of 2002 indicate that this situation may extend many years into the future. As a result, the U.K. Generation fixed asset carrying value at year-end 2002 was substantially impaired. A December 2002 probability-weighted discounted cash flow analysis of the fair value of our U.K. Generation indicated a 2002 pre-tax impairment loss of $548.7 million, including a goodwill impairment of $166.1 million as discussed in Note 3. The cash flow analysis used a discount rate of 6% over the remaining life of the assets and reflected assumptions for future electricity prices and plant operating costs. This impairment loss is included in Asset Impairments on AEP's Consolidated Statements of Operations. AEP Coal In October 2001, AEP acquired out of bankruptcy certain assets and assumed certain liabilities of nineteen coal mine companies formerly known as "Quaker Coal" and re-identified as "AEP Coal". During 2002 the coal operations suffered a decline in forward prices and adverse mining factors that culminated in the fourth quarter of 2002 and significantly reduced mine productivity and revenue. Based on an extensive review of economically accessible reserves and other factors, future mine productivity and production is expected to continue to be below historical levels. In December 2002, a probability-weighted discounted cash flow analysis of fair value of the mines was performed which indicated a 2002 pre-tax impairment loss of $59.9 million including a goodwill impairment of $3.6 million as discussed in Note 3. This impairment loss is included in Asset Impairments on AEP's Consolidated Statements of Operations. Texas Plants In September 2002, AEP proposed closing 16 gas-fired power plants in the ERCOT control area of Texas (8 TNC plants and 8 TCC plants). ERCOT indicated that it may designate some of those plants as "reliability must run" (RMR) status. In October ERCOT designated seven RMR plants (3 TNC plants and 4 TCC plants) and approved AEP's plan to inactivate nine other plants (5 TNC plants and 4 TCC plants). The process of moving the plants to inactive status took approximately two months. Employees of the plants moved to inactive status (approximately 180) were eligible for severance and outplacement services. As a result of the decision to inactivate TNC plants, a write-down of utility assets of approximately $34.2 million (pre-tax) was recorded in Asset Impairments expense during the third quarter 2002 on AEP's and TNC's Statements of Operations. The decision to inactivate the TCC plants resulted in a write-down of utility assets of approximately $95.6 million (pre-tax), which was deferred and recorded in Regulatory Assets during the third quarter 2002 in AEP's Consolidated Balance Sheets (in Regulatory Assets Designated For or Subject to Securitization on TCC's Consolidated Balance Sheets). During the fourth quarter 2002, evaluations continued as to whether assets remaining at the inactivated plants, including materials, supplies and fuel oil inventories, could be utilized elsewhere within the AEP System. As a result of such evaluations, TNC recorded an additional asset impairment charge to Asset Impairments expense of $3.9 million (pre-tax) in the fourth quarter 2002. In addition TNC recorded related inventory write-downs of $2.6 million [$1.2 million in Fuel and Purchased Energy: Electricity on AEP (Fuel Expense on TNC) and $1.4 million in Maintenance and Other Operation expense on AEP (Other Operation on TNC)]. Similarly, TCC recorded an additional asset impairment write-down of $6.7 million (pre-tax), which was deferred and recorded in Regulatory Assets on AEP (in Regulatory Assets Designated For or Subject to Securitization on TCC's Consolidated Balance Sheets) in the fourth quarter 2002. TCC also recorded related inventory write-downs of $14.9 million which was deferred and recorded in Regulatory Assets on AEP (in Regulatory Assets Designated For or Subject to Securitization on TCC's Consolidated Balance Sheets) in the fourth quarter 2002. The total Texas plant asset impairment of $38.1 million in 2002 (all related to TNC) is included in Asset Impairments on AEP's and TNC's Consolidated Statements of Operations. RMR plants are required to ensure the reliability of the power grid, even if electricity from those plants is not required to meet market needs. ERCOT and AEP negotiated interim contracts for the seven RMR plants through December 2003, however, ERCOT has the right to terminate the plants from RMR status upon 90 days written notice. In December 2002, TCC filed a plan of divestiture with the PUCT proposing to sell all of its power generation assets, including the eight gas-fired generating plants that were either inactivated or designated as RMR status. See Texas Restructuring section of the "Customer Choice and Industry Restructuring" Note 8 for further discussion of the divestiture plan and anticipated timeline. Ft. Davis Wind Farm In the 1990's, CSW developed a 6 MW facility wind energy project located on a lease site near Ft. Davis, Texas. In the fourth quarter of 2002 AEP engineering staff determined that operation of the facility was no longer technically feasible and the lease of the underlying site should not be renewed. Dismantling of the facility will be complete by the end of 2003 with an estimated 2002 pre-tax loss on abandonment of $4.7 million. The loss was recorded in Asset Impairments on AEP's Consolidated Statements of Operations and TNC's Statements of Operations. The facility will continue to be classified as held and used until disposal is complete. c. Investment Values In 2002, AEP recorded the following declines in fair value on investments accounted for under APB 18 that were considered to be other than temporarily impaired as shown in the table below: Investment Value Impairment 2002 Pre-Tax Business Loss Items Estimated Loss Segment Registrant ---------- -------------- ------- ---------- (in millions) Grupo Rede Investment - Brazil $217.0 Other AEP South Coast Power 63.2 Other AEP Misc. Technology Investments 11.7 Other AEP ------ Total $291.9 Grupo Rede Investment In December 2002, AEP recorded an other than temporary impairment totaling $141.0 million ($217.0 million net of federal income tax benefit of $76.0 million) of its 44% equity investment in Vale and its 20% equity interest in Caiua, both Brazilian electric operating companies (referred to as Grupo Rede). This amount is included in Investment Value and Other Impairment Losses on AEP's Consolidated Statements of Operations. As of September 30, 2002, AEP had not recognized its cumulative equity share of operating and foreign currency translation losses of approximately $88 million and $105 million, respectively, due to the existence of a put option that permits AEP to require Grupo Rede to purchase our equity at a minimum price equal to the U.S. dollar equivalent of the original purchase price. In January 2002 AEP evaluated through an independent credit assessment the ability of Grupo Rede to fulfill its responsibilities under the put option and concluded that the carrying value of the original investment was reasonable. During 2002, there has been a continuing decline in the Brazilian power industry and the value of the local currency. Events in the fourth quarter of 2002 led us to change our view that Grupo Rede would be able to fulfill its responsibilities under the put option. These events included two downgrades of Caiua debt by Moody's, resulting in a rating of Caa1. Caiua is an intermediate holding company which owns substantially all of the utility companies in the Grupo Rede system. The downgrading of Caiua's credit ratings to a level well below investment grade casts significant doubt on the ability of Grupo Rede to honor the put option. Grupo Rede is in the process of restructuring some of its debt s, and as a condition for participating in the restructuring, during November 2002 a creditor of Grupo Rede requested that AEP agree not to exercise the put option prior to March 31, 2007. AEP agreed and in exchange received an extension of the put option from the previous end date of 2009 through 2019. Based on the factors noted above, AEP could no longer reasonably believe that our investment could be recovered, resulting in the recording of the impairment. South Coast Power Investment South Coast Power is a 50% owned joint venture that was formed in 1996 to build and operate a merchant closed-cycle gas turbine generator at Shoreham, U.K.. South Coast Power is subject to the same adverse wholesale electric power rates described for U.K. Generation above. A December 2002 projected cash flow estimate of the fair value of the investment indicated a 2002 pre-tax other than temporary impairment of the equity interest (which included the fair value of supply contracts held by South Coast Power and accounted for in accordance with SFAS 133) in the amount of $63.2 million. This loss of investment value is included in Investment Value and Other Impairment Losses on AEP's Consolidated Statements of Operations. Technology Investments AEP previously made investments totaling $11.7 million in four early-stage or startup technologies involving pollution control and procurement. An analysis in December 2002 of the viability of the underlying technologies and the projected performance of the investee companies indicated that the investments were unlikely to be recovered, and an other than temporary impairment of the entire amount of the equity interest under APB 18 was recorded. The loss of investment value is included in Investment Value and Other Impairment Losses on AEP's Consolidated Statements of Operations. 14. Benefit Plans: Pension and Other Postretirement Benefits 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 either one qualified plan or both a qualified and a nonqualified pension plan. Other postretirement benefit (OPEB) plans are sponsored by the AEP System to provide medical and death benefits for retired employees in the U.S. AEP also has a foreign pension plan for employees of AEP Energy Services U.K. Generation Limited (Genco) in the U.K. Genco employees participate in their existing pension plan acquired as part of AEP's purchase of two generation plants in the U.K. in December 2001. 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, 2002, and a statement of the funded status as of December 31 for both years: U.S. U.S. Pension Plans OPEB Plans ------------- ---------- 2002 2001 2002 2001 ---- ---- ---- ---- (in millions) Reconciliation of Benefit Obligation: Obligation at January 1 $3,292 $3,161 $ 1,645 $1,668 Service Cost 72 69 34 30 Interest Cost 241 232 114 114 Participant Contributions - - 13 8 Plan Amendments (2) - - 7 (a) Actuarial (Gain) Loss 258 121 152 192 Divestitures - - - (287) (b) Benefit Payments (278) (291) (81) (88) Curtailments - - - 1 ------ ------ ------- ------ Obligation at December 31 $3,583 $3,292 $ 1,877 $1,645 ====== ====== ======= ====== Reconciliation of Fair Value of Plan Assets: Fair Value of Plan Assets at January 1 $3,438 $3,911 $ 711 $ 704 Actual Return on Plan Assets (371) (182) (57) (31) Company Contributions 6 - 137 118 Participant Contributions - - 13 8 Benefit Payments (278) (291) (81) (88) ------ ------ ------- ------ Fair Value of Plan Assets at December 31 $2,795 $3,438 $ 723 $ 711 ====== ====== ======= ====== Funded Status: Funded Status at December 31 $ (788) $ 146 $(1,154) $ (934) Unrecognized Net Transition (Asset) Obligation (7) (15) 233 263 Unrecognized Prior-Service Cost (13) (12) 6 7 Unrecognized Actuarial (Gain) Loss 1,020 35 896 649 ------ ------ ------- ------ Prepaid Benefit (Accrued Liability) $ 212 $ 154 $ (19) $ (15) ====== ====== ======= ====== (a) Related to the purchase of Houston Pipe Line Company and MEMCO Barge Line. (b) Related to the sale 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 2001 and 2002 were recorded in 2002. U.S. U.S. Pension Plans OPEB Plans ------------- ---------- 2002 2001 2002 2001 ---- ---- ---- ---- (in millions) Prepaid Benefit Costs $ 255 $ 205 $ - $ 1 Accrued Benefit Liability (44) (51) (19) (16) Additional Minimum Liability (944) (15) N/A N/A Intangible Asset 45 9 N/A N/A Accumulated Other Comprehensive Income 900 6 N/A N/A ----- ----- ---- ------ Net Asset (Liability) $ 212 $ 154 $(19) $ (15) ===== ===== ==== ===== Other Comprehensive (Income) Expense Attributable to Change in Additional Pension Liability Recognition $ 894 $(4) N/A N/A ===== === ==== ====== N/A = Not Applicable The value of our qualified plans' assets has decreased from $3.438 billion at December 31, 2001 to $2.795 billion at December 31, 2002. The qualified plans paid $272 million in benefits to plan participants during 2002 (nonqualified plans paid $6 million in benefits). The investment returns and declining discount rates have changed the status of our qualified plans from overfunded (plan assets in excess of projected benefit obligations) by $146 million at December 31, 2001 to an underfunded position (plan assets are less than projected benefit obligations) of $788 million at December 31, 2002. Due to the qualified plans currently being underfunded, the Company recorded a charge to Other Comprehensive Income (OCI) of $585 million, and a Deferred Income Tax Asset of $315 million, offset by a Minimum Pension Liability of $662 million and reduction to prepaid costs and intangible assets of $238 million. The charge to OCI does not affect earnings or cash flow. The OCI charge for each AEP subsidiary registrant is recorded in Minimum Pension Liability in the respective registrant's Consolidated Statements of Comprehensive Income. Also, because of the recent reductions in the funded status of our qualified plans, we expect to make cash contributions to our qualified plans of approximately $66 million in 2003 increasing to approximately $108 million per year by 2005. The AEP System's qualified pension plans had accumulated benefit obligations in excess of plan assets of $661 million at December 31, 2002. The AEP System's nonqualified pension plans had accumulated benefit obligations in excess of plan assets of $72 million at December 31, 2002 and $66 million at December 31, 2001. There are no assets in the nonqualified plans. The AEP System's OPEB plans had accumulated benefit obligations in excess of plan assets of $1,154 million and $934 million at December 31, 2002 and 2001, respectively. The Genco pension plan had $7 million and $10 million at December 31, 2002 and 2001, respectively, of accumulated benefit obligations in excess of plan assets. The following table provides the components of AEP's net periodic benefit cost (credit) for the plans for fiscal years 2002, 2001 and 2000: U.S. U.S. Pension Plans OPEB Plans ------------- ---------- 2002 2001 2000 2002 2001 2000 ---- ---- ---- ---- ---- ---- (in millions) Service Cost $ 72 $ 69 $ 60 $ 34 $ 30 $ 29 Interest Cost 241 232 227 114 114 106 Expected Return on Plan Assets (337) (338) (321) (62) (61) (57) Amortization of Transition (Asset) Obligation (9) (8) (8) 29 30 41 Amortization of Prior-service Cost (1) - 13 - - - Amortization of Net Actuarial (Gain) Loss (10) (24) (39) 27 18 4 ---- ----- ----- ---- ---- ---- Net Periodic Benefit Cost (Credit) (44) (69) (68) 142 131 123 Curtailment Loss (a) - - - - 1 79 ---- ----- ----- ---- ---- ---- Net Periodic Benefit Cost (Credit) After Curtailments $ (44) $ (69) $ (68) $142 $132 $202 ===== ===== ===== ==== ==== ==== (a) Curtailment charges were recognized during 2000 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 and other non-registrant subsidiaries for fiscal years 2002, 2001 and 2000:
U.S. U.S. Pension Plans OPEB Plans ------------- ---------- 2002 2001 2000 2002 2001 2000 ---- ---- ---- ---- ---- ---- (in thousands) APCo $ (9,988) $(13,645) $(14,047) $ 25,107 $ 22,810 $ 22,139 CSPCo (8,328) (10,624) (10,905) 11,494 10,328 9,643 I&M (4,206) (7,805) (8,565) 17,608 15,077 14,155 KPCo (1,406) (1,922) (2,075) 2,986 2,438 2,364 OPCo (11,360) (14,879) (15,041) 22,608 34,444 116,205 PSO (3,819) (2,480) (2,196) 8,436 6,187 4,277 SWEPCo (2,245) (3,051) (2,606) 8,371 6,399 4,152 TCC (4,786) (3,411) (2,986) 10,733 8,214 6,656 TNC (1,104) (1,644) (1,585) 4,798 3,729 2,929 Other Non-Registrant Subsidiaries 3,657 (9,139) (7,546) 29,722 22,278 19,798 -------- -------- -------- -------- -------- -------- Total $(43,585) $(68,600) $(67,552) $141,863 $131,904 $202,318 ======== ======== ======== ======== ======== ========
The weighted-average assumptions as of December 31, used in the measurement of AEP's benefit obligations are shown in the following tables: U.S. U.S. Pension Plans OPEB Plans ------------- ---------- 2002 2001 2000 2002 2001 2000 ---- ---- ---- ---- ---- ---- % % % % % % Discount Rate 6.75 7.25 7.50 6.75 7.25 7.50 Expected Return on Plan Assets 9.00 9.00 9.00 8.75 8.75 8.75 Rate of Compensation Increase 3.7 3.7 3.2 N/A N/A N/A In determining the discount rate in the calculation of future pension obligations we review the interest rates of long-term bonds that receive one of the two highest ratings given by a recognized rating agency. As a result of a decrease in this benchmark rate during 2002, we determined that a decrease in our discount rate from 7.25% at December 31, 2001 to 6.75% at December 31, 2002 was appropriate. For OPEB measurement purposes, a 10% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2003. The rate was assumed to decrease gradually each year to a rate of 5% through 2008 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 $ 21 $ (17) Effect on the health care component of the accumulated postretirement benefit obligation 237 (193) AEP Savings Plans AEP sponsors various defined contribution retirement savings plans eligible to substantially all non-United Mine Workers of America (UMWA) U.S. employees. These plans include features under Section 401(k) of the Internal Revenue Code and provide for company matching contributions. Beginning in 2001, AEP's contributions to the two largest plans increased to 75 cents for every dollar of the first 6% of eligible employee compensation from the previous rate of 50 cents. The cost for contributions to these plans totaled $60.1 million in 2002, $55.6 million in 2001 and $36.8 million in 2000. The following table provides the cost for contributions to the savings plans by the following AEP registrant and other non-registrant subsidiaries for fiscal years 2002, 2001 and 2000: 2002 2001 2000 ---- ---- ---- (in thousands) APCo $ 6,722 $7,031 $ 3,988 CSPCo 2,784 2,789 1,638 I&M 8,039 7,833 4,231 KPCo 1,043 1,016 544 OPCo 5,785 6,398 3,713 PSO 2,260 2,235 2,306 SWEPCo 2,765 2,776 2,880 TCC 3,054 3,046 3,161 TNC 1,574 1,558 1,708 Other Non- Registrant Subsidiaries 26,094 20,869 12,677 ------- ------- ------ Total $60,120 $55,551 $36,846 ======= ======= ======= On January 1, 2003, the two major AEP Savings Plans merged into a single plan. 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 2002, 2001 and 2000. In July 2001, OPCo sold certain coal mines in Ohio and West Virginia. 15. Stock-Based Compensation: The American Electric Power System 2000 Long-Term Incentive Plan (the Plan) was approved by shareholders at AEP's annual meeting in 2000 and authorizes the use of 15,700,000 shares of AEP common stock for various types of stock-based compensation awards, including stock option awards, to key employees. The Plan was adopted in 2000. Under the Plan, the exercise price of all stock option grants must equal or exceed the market price of AEP's common stock on the date of grant. AEP generally grants options that have a ten-year life and vest, subject to the participant's continued employment, in approximately equal 1/3 increments on January 1st following the first, second and third anniversary of the grant date. 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. Outstanding CSW stock options will continue in effect until all options are exercised, cancelled or expired. Under the CSW stock option plan, the option price was equal to the fair market value of the stock on the grant date. All CSW options fully vested upon the completion of the merger and expire 10 years after their original grant date. A summary of AEP stock option transactions in fiscal periods 2002, 2001 and 2000 is as follows:
2002 2001 2000 ---- ---- ---- 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 6,822 $37 6,610 $36 825 $40 Granted 2,923 $27 645 $45 6,046 $36 Exercised (600) $36 (216) $38 (26) $36 Forfeited (358) $41 (217) $37 (235) $39 ----- ----- ----- Outstanding at end of year 8,787 $34 6,822 $37 6,610 $36 ===== ===== ===== Options exercisable at end of year 2,481 $36 395 $43 588 $41 ===== === === Weighted average Exercise price of options: -Granted above Market Price $27 N/A N/A -Granted at Market Price $27 $45 $36
The following table summarizes information about AEP stock options outstanding at December 31, 2002: Options Outstanding - ---------------------------------------------- Range of Exercise Number Life in Exercise Prices Outstanding Years Price - --------------------------------------------- $27.06-35.625 8,047,058 8.4 $ 32.54 40.69-49.00 739,483 7.1 44.84 - --------------------------------------------- $27.06-49.00 8,786,541 8.3 $ 33.58 - --------------------------------------------- Options Exercisable Range of Exercise Number Weighted-Average Prices Outstanding Exercise Price $27.06-35.625 2,230,000 $35.51 40.69-49.00 251,327 43.66 - --------------------------------------------- $27.06-49.00 2,481,327 $36.33 - --------------------------------------------- If compensation expense for stock options had been determined based on the fair value at the grant date, AEP net income and earnings per share would have been the pro forma amounts shown in the following table: - ------------------------------------------------------------- 2002 2001 2000 ---- ---- ---- (in millions except per share amounts) Net (loss) income: As reported $ (519) $ 971 $ 267 Pro forma (528) 959 264 Basic (loss) earnings per share: As reported $(1.57) $3.01 $0.83 Pro forma (1.59) 2.98 0.82 Diluted (loss) earnings per share: As reported $(1.57) $3.01 $0.83 Pro forma (1.59) 2.97 0.82 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 AEP options granted: 2002 2001 2000 - ------------------------------------------------------------- Risk Free Interest Rate 3.53% 4.87% 5.02% Expected Life 7 years 7 years 7 years Expected Volatility 29.78% 28.40% 24.75% Expected Dividend Yield 6.15% 6.05% 6.02% Weighted average fair value of options: -Granted above Market Price $4.58 N/A N/A -Granted at Market Price $4.37 $8.01 $5.50 - ---------------------------- ---------- ---------- ---------- 16. Business Segments: In 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 and 2002, we moved toward a goal of functionally and structurally separating 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 Gas pipeline and storage services o Marketing and trading of electricity, gas, coal and other commodities o Coal mining, bulk commodity barging operations and other energy supply related businesses Energy Delivery o Domestic electricity transmission o Domestic electricity distribution Other o Energy services Segment results of operations for the twelve months ended December 31, 2002, 2001 and 2000 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 income and deductions from income. It differs from net income in that it does not take into account interest expense, income taxes and the effect of discontinued operations, extraordinary items and the cumulative effect of a change in accounting principle. EBIT is believed to be a reasonable gauge of results of operations. By excluding interest expense 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 Statements of Operations. By excluding discontinued operations, extraordinary items, and the cumulative effect of changes in accounting principles, EBIT gives more focused guidance on segment operating performance.
Energy Reconciling AEP Year Wholesale Delivery Other Adjustments Consolidated - ---- --------- -------- ----- ----------- ------------ (in millions) 2002 Revenues from: External unaffiliated customers $10,988 $ 3,551 $ 16 $ - $14,555 Transactions with other operating segments 2,314 20 46 (2,380) - Segment EBIT 645 970 (549) - 1,066 Depreciation, depletion and amortization expense 842 519 16 - 1,377 Total assets 22,622 11,624 248 247(a) 34,741 Investments in equity method subsidiaries 115 - 57 - 172 Gross property additions 1,072 638 12 - 1,722 2001 Revenues from: External unaffiliated customers $ 9,297 $ 3,356 $ 114 $ - $12,767 Transactions with other operating segments 2,708 20 1,155 (3,883) - Segment EBIT 1,302 986 42 - 2,330 Depreciation, depletion and amortization expense 597 632 14 - 1,243 Total assets 21,947 12,455 220 4,675(a) 39,297 Investments in equity method subsidiaries 242 - 370 - 612 Gross property additions 610 844 200 - 1,654 2000 Revenues from: External unaffiliated customers $ 7,834 $3,174 $ 105 $ - $11,113 Transactions with other operating segments 1,726 2 750 (2,478) - Segment EBIT 686 1,017 89 - 1,792 Depreciation, depletion and amortization expense 556 506 29 - 1,091 Total assets 24,172 14,876 2,625 4,960(a) 46,633 Investments in equity method subsidiaries 140 - 296 - 436 Gross property additions 366 961 141 - 1,468 (a) Reconciling adjustments for Total Assets include Assets Held for Sale and/or Assets of Discontinued Operations
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, 2002 December 31, 2001 ----------------- ----------------- Segment Segment Total Revenues EBIT Total Assets Revenues EBIT Assets -------- ------- ------------ -------- ------- ------ (in thousands) (in thousands) Wholesale Segment APCo $1,220,381 $215,735 $2,586,966 $1,189,223 $164,844 $2,505,877 CSPCo 907,882 282,974 1,762,074 867,100 232,372 1,742,328 I&M 1,205,043 42,410 3,160,575 1,212,587 117,396 3,027,509 KPCo 246,629 6,568 591,655 247,842 4,935 507,516 OPCo 1,523,452 364,071 2,861,415 1,545,392 240,128 2,820,995 PSO 518,100 34,322 840,374 695,123 52,086 827,235 SWEPCo 736,484 70,547 1,082,251 768,322 82,409 1,127,331 TCC 1,135,946 395,060 3,117,447 1,265,655 303,966 2,847,743 TNC 377,387 (58,930) 376,308 387,422 7,930 371,031 Energy Delivery Segment APCo $ 594,089 $217,360 $2,040,881 $ 595,036 $213,733 $1,976,908 CSPCo 492,278 63,071 991,166 483,219 130,503 980,060 I&M 321,721 170,342 1,426,616 314,410 111,206 1,366,553 KPCo 132,054 51,697 573,021 131,183 54,033 491,532 OPCo 589,673 71,225 1,595,617 552,713 118,261 1,573,078 PSO 275,547 69,543 936,316 261,877 79,787 921,676 SWEPCo 348,236 107,081 1,126,424 333,004 107,197 1,173,345 TCC 554,547 148,918 2,238,991 473,182 109,587 2,045,287 TNC 73,353 53,995 500,867 169,036 33,226 493,844 Registrant Subsidiaries Company Total APCo $1,814,470 $433,095 $4,627,847 $1,784,259 $378,577 $4,482,785 CSPCo 1,400,160 346,045 2,753,240 1,350,319 362,875 2,722,388 I&M 1,526,764 212,752 4,587,191 1,526,997 228,602 4,394,062 KPCo 378,683 58,265 1,164,676 379,025 58,968 999,048 OPCo 2,113,125 435,296 4,457,032 2,098,105 358,389 4,394,073 PSO 793,647 103,865 1,776,690 957,000 131,873 1,748,911 SWEPCo 1,084,720 177,628 2,208,675 1,101,326 189,606 2,300,676 TCC 1,690,493 543,978 5,356,438 1,738,837 413,553 4,893,030 TNC 450,740 (4,935) 877,175 556,458 41,156 864,875
Twelve Months Ended December 31, 2000 ------------------- Revenues Segment EBIT Total Assets -------- ------------ ------------ (in thousands) Wholesale Segment APCo $1,184,335 $154,525 $3,674,081 CSPCo 906,363 235,860 2,481,594 I&M 1,177,190 (146,297) 3,978,360 KPCo 268,529 22,379 759,228 OPCo 1,672,744 289,084 3,976,532 PSO 711,274 54,072 1,011,474 SWEPCo 773,324 27,055 1,302,611 TCC 1,291,588 273,650 3,182,202 TNC 394,860 13,910 466,539 Energy Delivery Segment APCo $574,918 $191,560 $2,898,514 CSPCo 398,046 81,896 1,395,897 I&M 311,019 126,241 1,795,748 KPCo 121,346 49,770 735,315 OPCo 467,587 138,418 2,217,443 PSO 245,124 85,524 1,126,949 SWEPCo 344,950 129,842 1,355,778 TCC 478,814 136,069 2,285,499 TNC 176,204 50,201 620,965 Registrant Subsidiaries Company Total APCo $1,759,253 $346,085 $6,572,595 CSPCo 1,304,409 317,756 3,877,491 I&M 1,488,209 (20,056) 5,774,108 KPCo 389,875 72,149 1,494,543 OPCo 2,140,331 427,502 6,193,975 PSO 956,398 139,596 2,138,423 SWEPCo 1,118,274 156,897 2,658,389 TCC 1,770,402 409,719 5,467,701 TNC 571,064 64,111 1,087,504
17. 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 Executive Committee and are administered by the Chief Risk Officer. The Risk Executive 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. of 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 Trading and rates hedging Credit Risk Non-performance Guarantees on contracts and 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 other commodities and as a result we are subject to price risk. The amount of risk taken by the traders is controlled by the management of the trading operations and the Chief Risk Officer and his staff. If the risk from trading activities exceeds certain pre-determined limits, the positions are modified or hedged to reduce the risk to be within the limits unless specifically approved by the Risk Executive Committee. 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 a settlement agreement in Michigan, capped in Indiana and fixed (subject to future commission action) in West Virginia. To the extent all fuel supply for 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 Arkansas, Kentucky, Louisiana, Oklahoma, Virginia and the SPP area of Texas. We enter into currency and interest rate forward and swap transactions to hedge the currency and interest rate exposures created by commodity transactions. These transactions are marked-to-market to match the change in value in the transactions they hedge which are also marked-to-market. We employ forward contracts as cash flow hedges and swaps as cash flow or fair value hedges to mitigate changes in interest rates or fair values on Short-Term Debt 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. 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 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. Option 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, the implied volatility curve and the implied correlation curve. Volatility and correlation prices may be quoted in the market. Significant estimates in valuing these contracts include forward price curves, volumes, and other volatilities. Futures and options traded on exchanges (primarily oil and gas on NYMEX) are valued at the exchange price. 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. When this occurs, we use our best judgment to estimate the curve values. 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 curve to the market. All fair value amounts are net of adjustments for items such as credit quality of the counterparty (credit risk) and liquidity risk. 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. Results of Risk Management Activities The amounts of net revenue margins (sales less purchases) in 2002, 2001, and 2000 for trading activities were: 2002 2001 2000 ---- ---- ---- (in millions) Net Revenue Margins $53 $402 $233 The amounts of revenues recorded in 2002, 2001 and 2000 for the registrant subsidiaries were: 2002 2001 2000 ---- ---- ---- (in thousands) APCo $29,044 $ 52,871 $ 27,924 CSPCo 24,503 36,120 16,999 I&M 11,833 19,130 26,575 KPCo 3,801 6,150 10,704 OPCo 39,114 43,789 26,840 PSO (1,357) (7,345) 5,233 SWEPCo (4,999) 2,317 1,562 TCC (7,708) 10,500 (1,752) TNC (1,098) 1,508 222 ------- -------- -------- Total $93,133 $165,040 $114,307 ======= ======== ======== 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 internally developed price curves for open long-term trading contracts. The following table does not reflect derivative contracts designated as hedges or firm transmission rights contracts. As a result, the totals will not agree to the Consolidated Balance Sheets. The fair values of trading contracts at December 31 are: 2002 2001 ------------------ ------------------- Fair Fair Value Value (in millions) (in millions) Trading Assets Electricity and Other Physicals $ 846 $ 966 Financials 226 170 ------ ------- Total Trading Assets $1,072 $ 1,136 ====== ======= Gas Physicals $ 105 $ 196 Financials 685 1,587 ------ ------- Total Trading Assets $ 790 $ 1,783 ====== ======= Trading Liabilities Electricity and Other Physicals $ (534) $ (760) Financials (126) (87) ------ ------- Total Trading Liabilities $ (660) $ (847) ====== ======= Gas Physicals $ (191) $ (38) Financials (761) (1,586) ------ ------- Total Trading Liabilities $ (952) $(1,624) ====== ======= The fair values of trading contracts for the registrant subsidiaries at December 31 are: 2002 2001 ----------------- ----------------- Fair Fair Value Value (in thousands) (in thousands) APCo Trading Assets Electricity and Other Physicals $ 168,687 $ 217,914 Financials 39,585 39,466 Trading Liabilities Electricity and Other Physicals $(100,045) $(164,624) Financials (11,375) (17,055) CSPCo Trading Assets Electricity and Other Physicals $ 113,397 $ 133,425 Financials 26,611 24,206 Trading Liabilities Electricity and Other Physicals $ (67,244) $ (98,749) Financials (7,647) (10,433) I&M Trading Assets Electricity and Other Physicals $ 121,706 $ 165,162 Financials 28,474 26,630 Trading Liabilities Electricity and Other Physicals $ (70,061) $(117,795) Financials (9,258) (12,652) 2002 2001 ---------------- ------------------ Fair Fair Value Value (in thousands) (in thousands) KPCo Trading Assets Electricity and Other Physicals $ 43,532 $ 53,651 Financials 10,216 9,732 Trading Liabilities Electricity and Other Physicals $ (25,815) $ (46,476) Financials (2,935) (4,178) OPCo Trading Assets Electricity and Other Physicals $ 158,473 $ 180,989 Financials 35,304 32,997 Trading Liabilities Electric and Other Physicals $ (89,526) $(132,603) Financials (10,145) (15,937) PSO Trading Assets Electricity Physicals $ 8,165 $ 47,613 Trading Liabilities Electricity Physicals $ (4,620) $ (45,179) SWEPCo Trading Assets Electricity Physicals $ 9,329 $ 54,647 Trading Liabilities Electricity Physicals $ (5,278) $ (51,747) TCC Trading Assets Electricity Physicals $ 26,752 $ 62,520 Trading Liabilities Electricity Physicals $ (21,136) $ (58,663) Financials (202) - TNC Trading Assets Electricity Physicals $ 6,323 $ 18,567 Trading Liabilities Electricity Physicals $ (4,047) $ (17,652) Financials (233) - Credit Risk 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 counterparties depending upon credit quality 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 are not material to our financial condition at December 31, 2002. At December 31, 2002, less than 7% of our exposure was below investment grade as expressed in terms of Net Mark to Market Assets. Net Mark to Market Assets represents the aggregate difference between the forward market price for the remaining term of the contract and the contractual price per counterparty. The following table approximates counterparty credit quality and exposure for AEP based on netting across AEP entities, commodities and instruments at December 31, 2002: Futures, Forward and Counterparty Swap Credit Quality Contracts Options Total ----------- ------- ----- (in millions) AAA/Exchanges $ 26 $ 2 $ 28 AA 307 33 340 A 448 26 474 BBB 700 101 801 Below Investment Grade 107 11 118 ------- ------ ------ Total $1,588 $ 173 $1,761 ====== ===== ====== We enter into transactions for electricity and natural gas as part of wholesale trading operations. Electricity 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 U.S. 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, 2002 and 2001 were $109 million and $55 million. These margin accounts are restricted and therefore are not included in Cash and Cash Equivalents on the Consolidated Balance Sheets. AEP and its subsidiaries can be subject to further margin requirements should related commodity prices change. The margin deposits at December 31, 2002 for the registrants were: (in thousands) APCo $1,010 CSPCo 673 I&M 727 KPCo 261 OPCo 1,400 PSO 91 SWEPCo 105 TCC 121 TNC 37 Financial Derivatives and Hedging In the first quarter of 2001, AEP adopted SFAS 133, "Accounting for Derivative Instruments and Hedging Activities," as amended. AEP recorded a favorable transition adjustment to Accumulated 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. Certain derivatives may be designated for accounting purposes as a hedge of either the fair value of an asset, liability, 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 to determine whether the hedge will be or 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 the 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. 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 (Loss) on AEP's Consolidated Balance Sheets at December 31, 2002 are: Accumulated Other Comprehensive Hedging Assets Hedging Liabilities Income (Loss) After Tax -------------- ------------------- ----------------------- (in millions) lectricity and Gas $6 $ (8) $ (2) nterest Rate - (13)* (12) oreign Currency - (2) (2) ---- $(16) * Includes $6 million loss recorded in an equity investment. The following table represents the activity in Other Comprehensive Income (Loss) related to the effect of adopting SFAS 133 for derivative contracts that qualify as cash flow hedges at December 31, 2002: (in millions) AEP Consolidated Beginning Balance, January 1, 2002 $ (3) Changes in fair value (56) Reclasses from OCI to net loss 43 ------- Accumulated OCI derivative loss, December 31, 2002 $ (16) ======= (in thousands) APCo Beginning Balance, January 1, 2002 $ (340) Effective portion of changes in fair value (1,310) Reclasses from OCI to net income (270) ------- Accumulated OCI derivative loss, December 31, 2002 $(1,920) ======= CSPCo Beginning Balance, January 1, 2002 $ - Effective portion of changes in fair value 62 Reclasses from OCI to net income (329) ------- Accumulated OCI derivative Loss, December 31, 2002 $ (267) ======= I&M Beginning Balance, January 1, 2002 $(3,835) Effective portion of changes in fair value 34 Reclasses from OCI to net income 3,515 ------- Accumulated OCI derivative loss, December 31, 2002 $ (286) ======= KPCo Beginning Balance, January 1, 2002 $(1,903) Effective portion of changes in fair value 343 Reclasses from OCI to net income 1,882 ------- Accumulated OCI derivative gain, December 31, 2002 $ 322 ======= OPCo Beginning Balance, January 1, 2002 $ (196) Effective portion of changes in fair value (103) Reclasses from OCI to net income (439) ------- Accumulated OCI derivative loss, December 31, 2002 $ (738) ======= PSO Beginning Balance, January 1, 2002 $ - Effective portion of changes in fair value 2 Reclasses from OCI to net income (44) ------- Accumulated OCI derivative loss, December 31, 2002 $ (42) ======= SWEPCo Beginning Balance, January 1, 2002 $ - Effective portion of changes in fair value 1 Reclasses from OCI to net income (49) ------- Accumulated OCI derivative loss, December 31, 2002 $ (48) ======= TCC Beginning Balance, January 1, 2002 $ - Effective portion of changes in fair value 30 Reclasses from OCI to net income (66) ------- Accumulated OCI derivative loss, December 31, 2002 $ (36) ======= TNC Beginning Balance, January 1, 2002 $ - Effective portion of changes in fair value 3 Reclasses from OCI to net income (18) ------- Accumulated OCI derivative loss, December 31, 2002 $ (15) ======= Approximately $9 million of net losses from cash flow hedges in Accumulated Other Comprehensive Income (Loss) at December 31, 2002 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 five years. 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 at December 31, 2002 and 2001 are summarized in the following tables. 2002 2001 ---- ---- Book Value Fair Value Book Value Fair Value ---------- ---------- ---------- ---------- (in millions) (in millions) AEP Long-term Debt $ 10,125 $ 10,470 $ 9,505 $ 9,542 Preferred Stock 84 77 95 93 Trust Preferred Securities 321 324 321 321 (in thousands) (in thousands) AEGCo Long-term Debt $ 44,802 $ 48,103 $ 44,793 $ 45,268 APCo Long-term Debt $1,893,861 $1,953,087 $1,556,559 $1,439,531 Preferred Stock 10,860 9,774 10,860 10,860 CSPCo Long-term Debt $ 621,626 $ 643,715 $ 791,848 $ 802,194 Preferred Stock - - 10,000 10,100 I&M Long-term Debt $1,617,062 $1,673,363 $1,652,082 $1,672,392 Preferred Stock 64,945 58,948 64,945 62,795 KPCo Long-term Debt $ 466,632 $ 475,455 $ 346,093 $ 350,233 OPCo Long-term Debt $1,067,314 $1,095,197 $1,203,841 $1,227,880 Preferred Stock 8,850 7,965 8,850 8,837 PSO Long-term Debt $ 545,437 $ 570,761 $ 451,129 $ 462,903 Trust Preferred Securities 75,000 75,900 75,000 74,730 SWEPCo Long-term Debt $ 693,448 $ 727,085 $ 645,283 $ 656,998 Trust Preferred Securities 110,000 110,880 110,000 109,780 TCC Long-term Debt $1,438,565 $1,522,373 $1,253,768 $1,278,644 Trust Preferred Securities 136,250 136,959 136,250 135,760 TNC Long-term Debt $ 132,500 $ 144,060 $ 255,967 $ 266,846 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 on AEP's Consolidated Balance Sheets, are recorded at market value in accordance with SFAS 115 "Accounting for Certain Investments in Debt and Equity Securities". At December 31, 2002 and 2001, the fair values of the trust investments were $969 million and $933 million, respectively, and had a cost basis of $909 million and $839 million, respectively. The change in market value in 2002, 2001, and 2000 was a net unrealized holding loss of $33 million and $11 million and a net unrealized holding gain of $6 million, respectively. 18. Income Taxes: The details of AEP's consolidated income taxes before discontinued operations, extraordinary items, and cumulative effect as reported are as follows: Year Ended December 31, ---------------------- 2002 2001 2000 ---- ---- ---- (in millions) Federal: Current $ 330 $404 $ 793 Deferred (192) 60 (236) ----- ---- ----- Total 138 464 557 ----- ---- ----- State: Current 32 61 47 Deferred 30 34 (6) ----- ---- ----- Total 62 95 41 ----- ---- ----- International: Current 13 (13) 4 Deferred 1 - - ----- ---- ------ Total 14 (13) 4 ----- ---- ----- Total Income Tax as Reported Before Discontinued Operations, Extraordinary Items and Cumulative Effect $ 214 $546 $ 602 ===== ==== =====
The details of the registrant subsidiaries income taxes as reported are as follows: AEGCo APCo CSPCo I&M KPCo Year Ended December 31, 2002 (in thousands) Charged (Credited) to Operating Expenses (net): Current $ 6,607 $ 99,140 $ 81,539 $ 66,063 $ 680 Deferred (5,028) 17,626 25,771 (19,870) 9,451 Deferred Investment Tax Credits 2 (3,229) (3,096) (7,340) (1,173) -------- -------- -------- --------- ------- Total 1,581 113,537 104,214 38,853 8,958 -------- -------- -------- --------- ------- Charged (Credited) to Nonoperating Income (net): Current (173) (354) 9,442 3,435 1,583 Deferred - (849) (2,479) 2,949 388 Deferred Investment Tax Credits (3,363) (1,408) (174) (400) (67) -------- -------- -------- --------- -------- Total (3,536) (2,611) 6,789 5,984 1,904 -------- -------- -------- --------- -------- Total Income Tax as Reported $ (1,955) $110,926 $111,003 $ 44,837 $ 10,862 ======== ======== ======== ========= ========
OPCo PSO SWEPCo TCC TNC Year Ended December 31, 2002 (in thousands) Charged (Credited) to Operating Expenses (net): Current $ 86,026 $(49,673) $ 41,354 $ 30,495 $ 109 Deferred 30,048 75,659 (3,134) 113,726 (10,652) Deferred Investment Tax Credits (2,493) (1,791) (4,524) (5,207) (1,271) -------- -------- -------- --------- -------- Total 113,581 24,195 33,696 139,014 (11,814) -------- -------- -------- --------- -------- Charged (Credited) to Nonoperating Income (net): Current 2,732 (1,812) 1,772 3,223 1,334 Deferred 15,962 - - (71) (1,623) Deferred Investment Tax Credits (684) - - - - -------- -------- -------- --------- -------- Total 18,010 (1,812) 1,772 3,152 (289) -------- -------- -------- --------- -------- Total Income Tax as Reported $131,591 $ 22,383 $ 35,468 $ 142,166 $(12,103) ======== ======== ======== ========= ========
AEGCo APCo CSPCo I&M KPCo Year Ended December 31, 2001 (in thousands) Charged (Credited) to Operating Expenses (net): Current $ 9,126 $ 71,623 $ 88,013 $ 107,286 $ 7,726 Deferred (6,224) 27,198 14,923 (45,785) 2,812 Deferred Investment Tax Credits - (3,237) (3,899) (7,377) (1,180) -------- -------- -------- --------- -------- Total 2,902 95,584 99,037 54,124 9,358 -------- -------- -------- --------- -------- Charged (Credited) to Nonoperating Income (net): Current (56) (19,165) (13,803) (10,590) (2,725) Deferred - 21,832 17,885 16,580 3,481 Deferred Investment Tax Credits (3,414) (1,528) (159) (947) (72) -------- -------- -------- --------- -------- Total (3,470) 1,139 3,923 5,043 684 -------- -------- -------- --------- -------- Total Income Tax as Reported $ (568) $ 96,723 $102,960 $ 59,167 $ 10,042 ======== ======== ======== ========= ========
OPCo PSO SWEPCo TCC TNC Year Ended December 31, 2001 (in thousands) Charged (Credited) to Operating Expenses (net): Current $(62,298) $ 53,030 $ 77,965 $ 190,671 $ 19,424 Deferred 166,166 (16,726) (31,396) (72,568) (11,891) Deferred Investment Tax Credits (2,495) (1,791) (4,453) (5,207) (1,271) -------- -------- -------- --------- -------- Total 101,373 34,513 42,116 112,896 6,262 -------- -------- -------- --------- -------- Charged (Credited) to Nonoperating Income (net): Current (21,600) 352 542 (398) (691) Deferred 20,014 - - - - Deferred Investment Tax Credits (794) - - - - -------- -------- -------- --------- -------- Total (2,380) 352 542 (398) (691) -------- -------- -------- --------- -------- Total Income Tax as Reported $ 98,993 $ 34,865 $ 42,658 $ 112,498 $ 5,571 ======== ======== ======== ========= ========
AEGCo APCo CSPCo I&M KPCo Year Ended December 31, 2000 (in thousands) Charged (Credited) to Operating Expenses (net): Current $ 8,746 $129,165 $120,494 $ 134,796 $ 17,878 Deferred (5,842) 3,838 (7,746) (126,748) 2,521 Deferred Investment Tax Credits - (2,947) (3,379) (7,524) (1,187) -------- -------- -------- --------- -------- Total 2,904 130,056 109,369 524 19,212 -------- -------- -------- --------- -------- Charged (Credited) to Nonoperating Income (net): Current (44) 327 3,777 2,950 (50) Deferred - 4,764 3,683 1,569 1,244 Deferred Investment Tax Credits (3,396) (1,968) (103) (330) (65) -------- -------- -------- --------- -------- Total (3,440) 3,123 7,357 4,189 1,129 -------- -------- -------- --------- -------- Total Income Tax as Reported $ (536) $133,179 $116,726 $ 4,713 $ 20,341 ======== ======== ======== ========= ========
OPCo PSO SWEPCo TCC TNC Year Ended December 31, 2000 (in thousands) Charged (Credited) to Operating Expenses (net): Current $ 259,608 $ 11,597 $ 16,073 $ 89,403 $ 6,774 Deferred (70,263) 25,453 14,653 16,263 9,401 Deferred Investment Tax Credits (1,824) (1,791) (4,482) (5,207) (1,271) --------- -------- -------- --------- -------- Total 187,521 35,259 26,244 100,459 14,904 --------- -------- -------- --------- -------- Charged (Credited) to Nonoperating Income (net): Current 15,426 (1,306) (1,476) (5,073) (222) Deferred 4,307 - - - (1,237) Deferred Investment Tax Credits ( 1,575) - - - - --------- -------- -------- --------- --------- Total 18,158 (1,306) (1,476) (5,073) (1,459) --------- -------- -------- --------- -------- Total Income Tax as Reported $ 205,679 $ 33,953 $24,768 $ 95,386 $ 13,445 ========= ======== ======= ========= ========
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, ---------------------- 2002 2001 2000 ---- ---- ---- (in millions) Net Income (Loss) $(519) $ 971 $267 Discontinued Operations (net of income tax Of $73 million in 2002, $22 million in 2001 and $5 million in 2000) 190 (86) (122) Extraordinary Items (net of income tax of $20 million in 2001 and $44 million in 2000) - 50 35 Cumulative Effect of Accounting Change (net of income tax of $2 million in 2001) 350 (18) - Preferred Stock Dividends 11 10 11 ----- ------ ---- Income Before Preferred Stock Dividends of Subsidiaries 32 927 191 Income Taxes Before Discontinued Operations, Extraordinary Items and Cumulative Effect 214 546 602 ----- ------ ---- Pre-Tax Income $ 246 $1,473 $793 ===== ====== ==== Income Taxes on Pre-Tax Income at Statutory Rate (35%) $ 86 $ 516 $278 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 32 48 77 Corporate Owned Life Insurance - 4 247 Investment Tax Credits (net) (35) (37) (36) Tax Effects of International Operations 123 (12) (1) Energy Production Credits (14) - - Merger Transaction Costs - - 49 State Income Taxes 40 62 26 Other (18) (35) (38) ----- ------ ---- Total Income Taxes as Reported Before Discontinued Operations, Extraordinary Items and Cumulative Effect $ 214 $ 546 $602 ===== ====== ==== Effective Income Tax Rate 87.0% 37.1% 75.9% ===== ====== ==== 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 CSPCo I&M KPCo Year Ended December 31, 2002 (in thousands) Net Income $ 7,552 $205,492 $181,173 $ 73,992 $ 20,567 Income Taxes (1,955) 110,926 111,003 44,837 10,862 -------- -------- -------- -------- -------- Pre-Tax Income $ 5,597 $316,418 $292,176 $118,829 $ 31,429 ======== ======== ======== ======== ======== Income Tax on Pre-Tax Income at Statutory Rate (35%) $ 1,959 $110,746 $102,262 $ 41,590 $ 11,000 Increase (Decrease) in Income Tax Resulting from the Following Items: Depreciation 870 3,082 2,899 21,812 2,057 Corporate Owned Life Insurance - (93) 719 268 305 Nuclear Fuel Disposal Costs - - - (3,814) - Allowance for Funds Used During Construction (446) - - (3,453) - Rockport Plant Unit 2 Investment Tax Credit (748) - - - - Removal Costs - - - - (735) Investment Tax Credits (net) (3,361) (4,637) (3,270) (7,740) (1,240) State Income Taxes 335 6,469 11,387 124 1,058 Other (564) (4,641) (2,994) (3,950) (1,583) -------- -------- -------- -------- -------- Total Income Taxes as Reported $ (1,955) $110,926 $111,003 $ 44,837 $ 10,862 ======== ======== ======== ======== ======== Effective Income Tax Rate N.M. 35.1% 38.0% 37.7% 34.6% ==== ===== ===== ===== =====
OPCo PSO SWEPCo TCC TNC Year Ended December 31, 2002 (in thousands) Net Income (Loss) $220,023 $ 41,060 $ 82,992 $ 275,941 $(13,677) Income Taxes 131,591 22,383 35,468 142,166 (12,103) -------- -------- -------- --------- -------- Pre-Tax Income (Loss) $351,614 $ 63,443 $118,460 $ 418,107 $(25,780) ======== ======== ======== ========= ======== Income Tax on Pre-Tax Income (Loss) at Statutory Rate (35%) $123,065 $ 22,205 $ 41,461 $ 146,337 $ (9,023) Increase (Decrease) in Income Tax Resulting from the Following Items: Depreciation 4,227 (583) (2,790) (295) (32) Corporate Owned Life Insurance (84) - - - - Investment Tax Credits (net) (3,177) (1,791) (4,524) (5,207) (1,271) State Income Taxes 18,051 2,639 3,987 2,202 (1,577) Other (10,491) (87) (2,666) (871) (200) -------- -------- -------- --------- -------- Total Income Taxes as Reported $131,591 $ 22,383 $ 35,468 $ 142,166 $(12,103) ======== ======== ======== ========= ======== Effective Income Tax Rate 37.4% 35.3% 29.9% 34.0% 47.0% ===== ===== ===== ===== =====
AEGCo APCo CSPCo I&M KPCo Year Ended December 31, 2001 (in thousands) Net Income $ 7,875 $161,818 $161,876 $ 75,788 $ 21,565 Extraordinary Loss - - 30,024 - - Income Taxes (568) 96,723 102,960 59,167 10,042 ------- -------- -------- --------- -------- Pre-Tax Income $ 7,307 $258,541 $294,860 $ 134,955 $ 31,607 ======= ======== ======== ========= ======== Income Tax on Pre-Tax Income at Statutory Rate (35%) $ 2,557 $ 90,489 $103,201 $ 47,234 $ 11,062 Increase (Decrease) in Income Tax Resulting from the Following Items: Depreciation 230 2,977 2,757 21,224 1,581 Corporate Owned Life Insurance - 450 544 (148) 334 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 - - - - (420) Investment Tax Credits (net) (3,414) (4,765) (4,058) (8,324) (1,252) State Income Taxes 1,050 9,613 5,727 6,137 318 Other (287) (2,041) (5,211) (2,058) (1,581) -------- -------- -------- --------- -------- Total Income Taxes as Reported $ (568) $ 96,723 $102,960 $ 59,167 $ 10,042 ======== ======== ======== ========= ======== Effective Income Tax Rate N.M. 37.4% 34.9% 43.8% 31.8% ==== ===== ===== ===== =====
OPCo PSO SWEPCo TCC TNC Year Ended December 31, 2001 (in thousands) Net Income $ 147,445 $ 57,759 $ 89,367 $ 182,278 $ 12,310 Extraordinary Loss 18,348 - - 2,509 - Income Taxes 98,993 34,865 42,658 112,498 5,571 --------- -------- -------- --------- -------- Pre-Tax Income $ 264,786 $ 92,624 $132,025 $ 297,285 $ 17,881 ========= ======== ======== ========= ======== Income Tax on Pre-Tax Income at Statutory Rate (35%) $ 92,675 $ 32,418 $ 46,209 $ 104,050 $ 6,258 Increase (Decrease) in Income Tax Resulting from the Following Items: Depreciation 7,972 1,127 (501) 8,477 1,463 Corporate Owned Life Insurance 1,852 - - - - Investment Tax Credits (net) (3,289) (1,791) (4,453) (5,207) (1,271) State Income Taxes 9,752 5,137 5,451 9,652 1,283 Other (9,969) (2,026) (4,048) (4,474) (2,162) --------- -------- -------- --------- -------- Total Income Taxes as Reported $ 98,993 $ 34,865 $ 42,658 $ 112,498 $ 5,571 ========= ======== ======== ========= ======== Effective Income Tax Rate 37.4% 37.6% 32.3% 37.8% 31.2% ==== ==== ==== ===== =====
AEGCo APCo CSPCo I&M KPCo Year Ended December 31, 2000 (in thousands) Net Income (Loss) $ 7,984 $ 73,844 $ 94,966 $(132,032) $ 20,763 Extraordinary (Gains) Loss (1,066) 39,384 - - Income Tax Benefit - (7,872) (14,148) - - Income Taxes (536) 133,179 116,726 4,713 20,341 ------- -------- -------- --------- -------- Pre-Tax Income (Loss) $ 7,448 $198,085 $236,928 $(127,319) $ 41,104 ======= ======== ======== ========= ======== Income Tax on Pre-Tax Income (Loss) at Statutory Rate (35%) $ 2,607 $ 69,330 $ 82,925 $ (44,562) $ 14,386 Increase (Decrease) in Income Tax Resulting from the Following Items: Depreciation 452 7,606 10,529 20,378 1,827 Corporate Owned Life Insurance - 54,824 29,259 42,587 5,149 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) - - (420) Investment Tax Credits (net) (3,396) (4,915) (3,482) (7,854) (1,252) State Income Taxes 784 9,950 89 6,004 1,597 Other (287) (2,419) (2,594) (5,672) (946) -------- -------- -------- --------- -------- Total Income Taxes as Reported $ (536) $133,179 $116,726 $ 4,713 $ 20,341 ======== ======== ======== ========= ======== Effective Income Tax Rate N.M. 67.2% 49.3% N.M. 49.5% ==== ==== ==== ==== =====
OPCo PSO SWEPCo TCC TNC Year Ended December 31, 2000 (in thousands) Net Income $ 83,737 $ 66,663 $ 72,672 $ 189,567 $ 27,450 Extraordinary Loss 40,157 - - - - Income Tax Benefit (21,281) - - - - Income Taxes 205,679 33,953 24,768 95,386 13,445 --------- -------- -------- --------- -------- Pre-Tax Income $ 308,292 $100,616 $ 97,440 $ 284,953 $ 40,895 ========= ======== ======== ========= ======== Income Tax on Pre-Tax Income at Statutory Rate (35%) $ 107,902 $ 35,216 $ 34,104 $ 99,734 $ 14,313 Increase (Decrease) in Income Tax Resulting from the Following Items: Depreciation 27,577 695 (1,012) 7,556 1,204 Corporate Owned Life Insurance 84,453 - - - - Investment Tax Credits (net) (3,398) (1,791) (4,482) (5,207) (1,271) State Income Taxes (1,988) 3,037 1,650 2,296 - Other (8,867) (3,204) (5,492) (8,993) (801) --------- -------- -------- --------- -------- Total Income Taxes as Reported $ 205,679 $ 33,953 $ 24,768 $ 95,386 $ 13,445 ========= ======== ======== ========= ======== Effective Income Tax Rate 66.7% 33.7% 25.4% 33.5% 32.9% ==== ==== ==== ===== ====
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, 2002 2001 - -------------- ---- ---- (in millions) Deferred Tax Assets $ 2,189 $ 1,216 Deferred Tax Liabilities (6,105) (5,716) ------- ------- Net Deferred Tax Liabilities $(3,916) $(4,500) ======= ======= Property Related Temporary Differences $(3,612) $(3,674) Amounts Due From Customers For Future Federal Income Taxes (360) (245) Deferred State Income Taxes (422) (314) Transition Regulatory Assets (234) (268) Regulatory Assets Designated for Securitization (310) (332) Asset Impairments and Investment Value Losses 417 - Deferred Income Taxes on Other Comprehensive Loss 326 3 All Other (net) 279 330 ------- ------- Net Deferred Tax Liabilities $(3,916) $(4,500) ======= =======
AEGCo APCo CSPCo I&M KPCo December 31, 2002 (in thousands) Deferred Tax Assets $ 73,094 $ 213,972 $ 72,990 $ 348,672 $ 36,948 Deferred Tax Liabilities (102,096) (915,773) (510,761) (704,869) (215,261) --------- --------- --------- --------- --------- Net Deferred Tax Liabilities $ (29,002) $(701,801) $(437,771) $(356,197) $(178,313) ========== ========= ========= ========= ========= Property Related Temporary Differences $ (74,291) $(555,824) $(331,381) $(343,587) $(127,073) Amounts Due From Customers For Future Federal Income Taxes 7,626 (58,246) (8,895) (38,752) (20,488) Deferred State Income Taxes (5,119) (77,693) (23,448) (52,528) (28,722) Transition Regulatory Assets - (28,735) (71,752) - - Asset Impairments and Investment Value Losses - 18 215 225 4 Deferred Income Taxes on Other Comprehensive Loss - 38,823 31,961 21,800 5,089 Net Deferred Gain on Sale and Leaseback-Rockport Plant Unit 2 38,866 - - 25,860 - Accrued Nuclear Decommissioning Expense - - - 65,856 - Deferred Fuel and Purchased Power - (1,878) (273) (13,144) 415 Deferred Cook Plant Restart Costs - - - (14,000) - Nuclear Fuel - - - (5,153) - All Other (net) 3,916 (18,266) (34,198) (2,774) (7,538) --------- -------- --------- --------- --------- Net Deferred Tax Liabilities $ (29,002) $(701,801) $(437,771) $(356,197) $(178,313) ========= ========= ========= ========= =========
OPCo PSO SWEPCo TCC TNC December 31, 2002 (in thousands) Deferred Tax Assets $ 155,334 $ 70,649 $ 82,113 $ 130,210 $ 35,970 Deferred Tax Liabilities (949,721) (412,045) (423,177) (1,391,462) (153,491) --------- --------- --------- ----------- --------- Net Deferred Tax Liabilities $(794,387) $(341,396) $(341,064) $(1,261,252) $(117,521) ========= ========= ========= =========== ========= Property Related Temporary Differences $(620,634) $(303,888) $(315,821) $ (709,246) $(142,034) Amounts Due From Customers For Future Federal Income Taxes (53,256) 9,490 (4,078) (198,595) 5,726 Deferred State Income Taxes (46,990) (57,911) (48,372) (66,333) (4,080) Transition Regulatory Assets (131,833) - - - - Asset Impairments and Investment Value Losses 615 - - - 14,996 Deferred Income Taxes on Other Comprehensive Loss 39,246 29,332 28,906 39,394 16,565 Deferred Fuel and Purchased Power 540 (28,696) 3,192 2,655 (9,933) Regulatory Assets Designated For Securitization - - - (310,410) - All Other (net) 17,925 10,277 (4,891) (18,717) 1,239 --------- --------- --------- ----------- --------- Net Deferred Tax Liabilities $(794,387) $(341,396) $(341,064) $(1,261,252) $(117,521) ========= ========= ========= =========== =========
AEGCo APCo CSPCo I&M KPCo December 31, 2001 (in thousands) Deferred Tax Assets $ 75,856 $ 162,334 $ 74,767 $ 332,225 $ 30,927 Deferred Tax Liabilities (103,831) (865,909) (518,489) (732,756) (199,231) --------- --------- --------- --------- --------- Net Deferred Tax Liabilities $ (27,975) $(703,575) $(443,722) $(400,531) $(168,304) ========= ========= ========= ========= ========= Property Related Temporary Differences $ (70,581) $(530,298) $(323,139) $(306,151) $(118,147) Amounts Due From Customers For Future Federal Income Taxes 9,292 (55,206) (9,839) (46,756) (20,215) Deferred State Income Taxes (3,822) (56,747) (8,968) (38,015) (25,267) Transition Regulatory Assets - (34,783) (78,298) - - Deferred Income Taxes on Other Comprehensive Loss - 183 - 2,065 1,025 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 - (4,106) (39) (26,270) 57 Deferred Cook Plant Restart Costs - - - (28,000) - Nuclear Fuel - - - (16,062) - All Other (net) (3,680) (22,618) (23,439) (12,206) (5,757) --------- --------- --------- --------- --------- Net Deferred Tax Liabilities $ (27,975) $(703,575) $(443,722) $(400,531) $(168,304) ========= ========= ========= ========= =========
OPCo PSO SWEPCo TCC TNC December 31, 2001 (in thousands) Deferred Tax Assets $ 135,938 $ 59,421 $ 56,189 $ 130,863 $ 22,888 Deferred Tax Liabilities (933,827) 356,298) (425,970) (1,294,658) (167,937) --------- -------- --------- ----------- --------- Net Deferred Tax Liabilities $(797,889) $(296,877) $(369,781) $(1,163,795) $(145,049) ========= ========= ========= =========== ========= Property Related Temporary Differences $(595,974) $(320,900) $(362,884) $ (808,922) $(149,309) Amounts Due From Customers For Future Federal Income Taxes (61,130) 10,199 (6,441) (70,174) 4,757 Deferred State Income Taxes (18,440) (35,038) (48,729) (66,333) (4,079) Transition Regulatory Assets (154,947) - - - - Deferred Income Taxes on Other Comprehensive Loss 106 - - - - Deferred Fuel and Purchased Power 12 3,052 (2,778) 18,032 (11,756) Provision for Mine Shutdown Costs 20,323 - - - - Regulatory Assets Designated For Securitization - - - (332,198) - All Other (net) 12,161 45,810 51,051 95,800 15,338 --------- --------- -------- ------------ --------- Net Deferred Tax Liabilities $(797,889) $(296,877) $(369,781) $(1,163,795) $(145,049) ========= ========= ========= =========== =========
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 recorded in 2000 for affected registrant subsidiaries were as follows: (in millions) APCo $ 82 CSPCo 41 I&M 66 KPCo 8 OPCo 118 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. 19. Basic and Diluted Earnings Per Share: The calculation of AEP's basic and diluted earnings (loss) per common share (EPS) is based on the amounts of Net Income (Loss) and weighted average common shares shown in the table below: 2002 2001 2000 ---- ---- ---- (in millions - except per share amounts) Income: Income Before Discontinued Operations, Extraordinary Items and Cumulative Effect $ 21 $ 917 $ 180 Discontinued Operations (190) 86 122 ------ ----- ----- Income (Loss) Before Extraordinary Item And Cumulative Effect (169) 1,003 302 Extraordinary Losses (net of tax): Discontinuance of Regulatory Accounting For Generation - (48) (35) Loss on Reacquired Debt - (2) - Cumulative Effect of Accounting Change (net of tax) (350) 18 - ----- ----- ----- Net Income (Loss) $(519) $ 971 $ 267 ===== ====== ===== Weighted Average Shares: Average Common Shares Outstanding 332 322 322 Assumed Conversion of Dilutive Stock Options (see Note 15) - 1 - ----- ----- ----- Diluted Average Common Shares Outstanding 332 323 322 ===== ===== ===== Basic and Diluted Earnings Per Common Share: Income Before Discontinued Operations, Extraordinary Items and Cumulative Effect $ 0.06 $2.85 $0.56 Discontinued Operations (0.57) 0.26 0.38 ------ ----- ----- Income (Loss) Before Extraordinary Item and Cumulative Effect (0.51) 3.11 0.94 Extraordinary Losses (net of tax): Discontinuance of Regulatory Accounting For Generation - (0.15) (0.11) Loss on Reacquired Debt - (0.01) - Cumulative Effect of Accounting Change (net of tax) (1.06) 0.06 - ------ ----- ----- $(1.57) $3.01 $0.83 ====== ===== ===== The assumed conversion of stock options does not affect net earnings (loss) for purposes of calculating diluted earnings per share. AEP's basic and diluted EPS are the same in 2002, 2001 and 2000 since the effect on weighted average common shares outstanding is minimal. Had AEP recognized net income in fiscal 2002, incremental shares attributable to the assumed exercise of outstanding stock options would have increased diluted common shares outstanding by 398,000 shares. Options to purchase 8.8 million, 0.7 million and 6.4 million shares of common stock were outstanding at December 31, 2002, 2001 and 2000, respectively, but were not included in the computation of diluted earnings per share because the options' exercise prices were greater than the year-end market price of the common shares and, therefore, the effect would be antidilutive. In addition, there is no effect on diluted earnings per share related to our equity units (issued in 2002) unless the market value of AEP common stock exceeds $49.08 per share. There were no dilutive effects from equity units at December 31, 2002. If our common stock value exceeds $49.08 we would apply the treasury stock method to the equity units to calculate diluted earnings per share. This method of calculation theoretically assumes that the proceeds received as a result of the forward purchase contracts are used to repurchase outstanding shares. Also see Note 27. 20. Supplementary Information:
Year Ended December 31, ----------------------- 2002 2001 2000 ---- ---- ---- (in millions) AEP Consolidated Purchased Power - Ohio Valley Electric Corporation (44.2% owned by AEP System) $142 $127 $86 Cash was paid for: Interest (net of capitalized amounts) $792 $972 $842 Income Taxes $336 $569 $449 Noncash Investing and Financing Activities: Acquisitions under Capital Leases $ 6 $17 $118 Assumption of Liabilities Related to Acquisitions $1 $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, 2002, 2001, and 2000 were: APCo CSPCo I&M OPCo ---- ----- --- ---- (in thousands) Year Ended December 31, 2002 $53,386 $14,885 $23,282 $50,135 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 21. Power and Distribution 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 1,113 MW. Investments in power projects that are 50% or less owned are accounted for by the equity method and reported in Investments in Power and Distribution Projects on AEP's Consolidated Balance Sheets (see "Eastex" within the Assets Held for Sale section of Note 13), except for Eastex Cogeneration which, due to its structure, is consolidated. At December 31, 2002, six domestic power projects and three international power investments 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 either Qualifying Facilities (QFs) or Exempt Wholesale Generators (EWGs) under PURPA. The three international power investments are classified as Foreign Utility Companies (FUCO) under the Energy Policies Act of 1992. Two of the international investments are power projects and the other international investment is a company which owns an interest in four additional power projects. All of the power projects accounted for under the equity method have unrelated third-party partners. Seven of the above power projects have project-level financing, which is non-recourse to AEP. AEP or AEP subsidiaries have guaranteed $58 million of domestic partnership obligations for performance under power purchase agreements and for debt service reserves in lieu of cash deposits. Distribution Projects AEP owns a 44% equity interest in Vale, a Brazilian electric operating company which was purchased for a total of $149 million. On December 1, 2001 AEP 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 AEP's investment has been affected by the devaluation of the Brazilian Real. In December 2002, AEP recorded an other than temporary impairment totaling $141.1 million (after federal income tax benefit of $76 million) of its 44% equity investment in Vale and its 20% equity interest in Caiua. See "Grupo Rede Investment" within the Investment Values section of Note 13 "Asset Impairments and Investment Value Losses", for further information on the 2002 impairment of AEP's Vale and Caiua investments. 22. Leases: Leases of property, plant and equipment are for periods up to 99 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 CSPCo I&M KPCo OPCo Year Ended December 31, 2002 (in thousands) Lease Payments on Operating Leases $346,000 $76,143 $ 6,634 $ 5,209 $110,833 $ 1,597 $68,816 Amortization of Capital Leases 65,000 238 9,729 6,010 8,319 2,171 12,637 Interest on Capital Leases 14,000 19 2,240 1,717 2,221 469 4,501 -------- ------- ------- ------- -------- ------- ------- Total Lease Rental Costs $425,000 $76,400 $18,603 $12,936 $121,373 $ 4,237 $85,954 ======== ======= ======= ======= ======== ======= =======
PSO SWEPCo TCC TNC Year Ended December 31, 2002 (in thousands) Lease Payments on Operating Leases $ 4,403 $3,240 $ 7,184 $ 1,981 Amortization of Capital Leases - - - - Interest on Capital Leases - - - - ------- ------ ------- ------- Total Lease Rental Costs $ 4,403 $3,240 $ 7,184 $ 1,981 ======= ====== ======= =======
AEP AEGCo APCo CSPCo I&M KPCo OPCo Year Ended December 31, 2001 (in thousands) Lease Payments on Operating Leases $293,000 $76,262 $ 6,142 $ 7,063 $104,574 $ 1,191 $63,913 Amortization of Capital Leases 82,000 281 12,099 7,206 17,933 2,740 14,443 Interest on Capital Leases 22,000 55 3,789 2,396 4,424 808 5,818 -------- ------- ------- ------- -------- ------- ------- Total Lease Rental Costs $397,000 $76,598 $22,030 $16,665 $126,931 $ 4,739 $84,174 ======== ======= ======= ======= ======== ======= =======
PSO SWEPCo TCC TNC Year Ended December 31, 2001 (in thousands) Lease Payments on Operating Leases $ 4,010 $ 2,277 $ 5,948 $ 1,534 Amortization of Capital Leases - - - - Interest on Capital Leases - - - - -------- ------- ------- ------- Total Lease Rental Costs $ 4,010 $ 2,277 $ 5,948 $ 1,534 ======== ======= ======= =======
AEP AEGCo APCo CSPCo I&M KPCo OPCo Year Ended December 31, 2000 (in thousands) Lease Payments on Operating Leases $246,000 $73,858 $ 7,128 $ 7,683 $ 81,446 $ 1,978 $51,981 Amortization of Capital Leases 118,000 281 13,900 7,776 26,341 3,931 37,280 Interest on Capital Leases 36,000 55 3,930 2,690 10,908 1,054 9,584 -------- ------- ------- ------ -------- ------- ------- Total Lease Rental Costs $400,000 $74,194 $24,958 $18,149 $118,695 $ 6,963 $98,845 ======== ======= ======= ======= ======== ======= =======
PSO SWEPCo TCC TNC Year Ended December 31, 2000 (in thousands) Lease Payments on Operating Leases $ 3,269 $ 1,401 $ 5,410 $ 1,210 Amortization of Capital Leases - - - - Interest on Capital Leases - - - - -------- ------- ------- ------- Total Lease Rental Costs $ 3,269 $ 1,401 $ 5,410 $ 1,210 ======== ======= ======= =======
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 Year Ended December 31, 2002 (in thousands) Property, Plant and Equipment Under Capital Leases Production $ 40,000 $ 1,793 $ 3,368 $ 6,380 $ 5,728 $ 1,138 Distribution 15,000 - - - 14,589 - Other: Mining Assets and Other 687,000 - 67,395 46,791 70,140 14,258 -------- ------ ------- ------- -------- ------- Total Property, Plant and Equipment 742,000 1,793 70,763 53,171 90,457 15,396 Accumulated Amortization 299,000 1,294 37,452 26,551 41,141 8,168 -------- ------- ------- ------- -------- ------ Net Property, Plant and Equipment Under Capital Leases $443,000 $ 499 $33,311 $26,620 $ 49,316 $ 7,228 ======== ======= ======= ======= ======== ======= Obligations Under Capital Leases: Noncurrent Liability $170,000 $ 301 $23,991 $21,643 $ 42,619 $ 5,093 Liability Due Within One Year 58,000 198 9,598 5,967 8,229 2,155 -------- ------- ------- ------- -------- ------ Total Obligations Under Capital Leases $228,000 $ 499 $33,589 $27,610 $ 50,848 $ 7,248 ======== ======= ======= ======= ======== =======
OPCo SWEPCo Year Ended December 31, 2002 (in thousands) Property, Plant and Equipment Under Capital Leases Production $ 21,360 $ - Distribution - - Other: Mining Assets and Other 103,018 45,699 Total Property, Plant and Equipment 124,378 45,699 Accumulated Amortization 63,810 45,699 Net Property, Plant and Equipment Under Capital Leases $ 60,568 $ - ======== ======= Obligations Under Capital Leases: Noncurrent Liability $ 51,266 $ - Liability Due Within One Year 14,360 - -------- ------- Total Obligations Under Capital Leases $ 65,626 $ - ======== =======
AEP AEGCo APCo CSPCo I&M KPCo OPCo Year Ended December 31, 2001 (in thousands) Property, Plant and Equipment Under Capital Leases Production $ 39,000 $ 1,983 $ 2,712 $ 6,380 $ 4,826 $ 1,138 $ 22,477 Distribution 15,000 - - - 14,593 - - Other: Mining Assets and Other 723,000 129 82,292 54,999 86,267 17,658 114,944 -------- ------- ------- ------- --------- ------- ------- Total Property, Plant and Equipment 777,000 2,112 85,004 61,379 105,686 18,796 137,421 Accumulated Amortization 250,000 1,801 38,745 26,044 43,768 9,213 57,429 -------- ------- ------- ------- --------- ------- -------- Net Property, Plant and Equipment Under Capital Leases $527,000 $ 311 $46,259 $35,335 $ 61,918 $ 9,583 $ 79,992 ======== ======= ======= ======= ========= ======= ======== Obligations Under Capital Leases: Noncurrent Liability $219,000 $ 76 $33,928 $27,052 $ 51,093 $ 6,742 $ 64,261 Liability Due Within One Year 75,000 235 12,357 7,835 10,840 2,841 16,405 -------- ------- ------- ------- --------- ------- -------- Total Obligations Under Capital Leases $294,000 $ 311 $46,285 $34,887 $ 61,933 $ 9,583 $ 80,666 ======== ======= ======= ======= ========= ======= ========
Future minimum lease payments consisted of the following at December 31, 2002: AEP AEGCo APCo CSPCo I&M KPCo OPCo Capital (in thousands) - ------- 2003 $ 70,000 $ 249 $12,483 $ 7,365 $ 10,373 $ 2,623 $ 17,363 2004 53,000 114 10,515 6,231 9,122 1,957 14,634 2005 37,000 58 6,799 5,279 6,506 1,581 11,442 2006 29,000 31 5,117 3,898 5,561 948 10,220 2007 21,000 29 2,668 2,969 4,024 788 8,694 Later Years 59,000 79 4,829 8,321 10,732 725 20,302 -------- ---------- ------- ------- --------- ------- -------- Total Future Minimum Lease Payments 269,000 560 42,411 34,063 46,318 8,622 82,655 Less Estimated Interest Elemen 41,000 61 8,822 6,453 (4,530) 1,374 17,029 -------- ---------- ------- ------- --------- ------- -------- Estimated Present Value of Future Minimum Lease Payments $228,000 $ 499 $33,589 $27,610 $ 50,848 $ 7,248 $ 65,626 ======== ========== ======= ======= ========= ======= ========
AEP AEGCo APCo CSPCo I&M KPCo OPCo (in thousands) Noncancellable Operating Leases 2003 $ 305,000 $ 73,854 $ 4,482 $ 4,608 $ 95,213 $ 1,031 $ 62,784 2004 271,000 73,854 3,723 5,111 81,246 865 62,837 2005 252,000 73,854 3,114 4,013 78,968 747 62,169 2006 242,000 73,854 2,742 1,630 77,741 576 62,481 2007 237,000 73,854 1,962 1,374 76,461 875 62,880 Later Years 2,462,000 1,107,810 4,384 2,670 1,117,725 1,492 180,548 ---------- ---------- -------- ------- ---------- ------- -------- Total Future Minimum Lease Payments $3,769,000 $1,477,080 $20,407 $19,406 $1,527,354 $ 5,586 $493,699 ========== ========== ======= ======= ========== ======= ========
PSO SWEPCo TCC TNC (in thousands) Noncancellable Operating Leases 2003 $ 2,260 $ 912 $ 1,815 $ 448 2004 1,998 617 1,565 296 2005 1,714 433 1,388 192 2006 1,391 317 1,086 169 2007 1,256 301 603 167 Later Years - - - - ---------- ---------- ------- ------- Total Future Minimum Lease Payments $ 8,619 $ 2,580 $ 6,457 $ 1,272 ========== ========== ======= ======= OPCo has entered into an agreement with JMG Funding LLP (JMG) an unrelated unconsolidated special purpose entity. JMG has a capital structure of which 3% is equity from investors with no relationship to AEP or any of its subsidiaries and 97% is debt from pollution control bonds and other bonds. JMG was formed to design, construct and lease the Gavin Scrubber for the Gavin Plant to OPCo. JMG owns the Gavin Scrubber and leases it to OPCo. The lease is accounted for as an operating lease with the payment obligations included in the lease footnote. Payments under the operating lease are based on JMG's cost of financing (both debt and equity) and include an amortization component plus the cost of administration. Neither OPCo nor AEP has an ownership interest in JMG and does not guarantee JMG's debt. At any time during the lease, OPCo has the option to purchase the Gavin Scrubber for the greater of its fair market value or adjusted acquisition cost (equal to the unamortized debt and equity of JMG) or sell the Gavin Scrubber. The initial 15-year lease term is non-cancelable. At the end of the initial term, OPCo can renew the lease, purchase the Gavin Scrubber (terms previously mentioned), or sell the Gavin Scrubber. In case of a sale at less than the adjusted acquisition cost, OPCo must pay the difference to JMG. The use of JMG allows AEP to enter into an operating lease while keeping the tax benefits otherwise associated with a capital lease. As of December 31, 2002, unless the structure of this arrangement is changed, it is reasonably possible that AEP will consolidate JMG in the third quarter of 2003 as a result of the issuance of FIN 46. Upon consolidation, AEP would record the assets, liabilities, depreciation expense, minority interest and debt interest expense of JMG. AEP would eliminate operating lease expense. AEP's maximum exposure to loss as a result of its involvement with JMG is approximately $560 million of outstanding debt and equity of JMG as of December 31, 2002. AEGCo and I&M entered into a sale and leaseback transaction in 1989 with Wilmington Trust Company (Owner Trustee) an unrelated unconsolidated trustee for Rockport Plant Unit 2 (the plant). Owner Trustee was capitalized with equity from six owner participants with no relationship to AEP or any of its subsidiaries and debt from a syndicate of banks and securities in a private placement to certain institutional investors. The gain from the sale was deferred and is being amortized over the term of the lease, which expires in 2022. The Owner Trustee owns the plant and leases it to AEGCo and I&M. The lease is accounted for as an operating lease with the payment obligations included in the lease footnote. The lease term is for 33 years with potential renewal options. At the end of the lease term, AEGCo and I&M have the option to renew the lease or the Owner Trustee can sell the plant. AEGCo, I&M nor AEP has ownership interest in the Owner Trustee and do not guarantee its debt. 23. Lines of Credit and Sale of Receivables: Lines of Credit - AEP System The AEP System uses short-term debt, primarily commercial paper and revolving credit facilities, to meet fluctuations in working capital requirements and other interim capital needs. AEP has established a utility money pool and a non-utility money pool to coordinate short-term borrowings for certain subsidiaries. Utility money participants include AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC. AEP also incurs borrowings outside of the money pool for other subsidiaries. As of December 31, 2002, AEP had revolving credit facilities totaling $3.5 billion to support its commercial paper program. At December 31, 2002, AEP had $3.2 billion outstanding in short-term borrowings of which $1.4 billion was commercial paper supported by the revolving credit facilities. The maximum amount of commercial paper outstanding during the year, which had a weighted average interest rate during 2002 of 2.47%, was $3.3 billion during April 2002. On December 11, 2002, Moody's Investor Services placed AEP's Prime-2 short-term rating for commercial paper under review for possible downgrade. On January 24, 2003, Standard & Poor's Rating Services placed AEP's A-2 short-term rating for commercial paper under review for possible downgrade. On February 10, 2003, Moody's Investor Services downgraded AEP's short-term rating for commercial paper to Prime-3 from Prime-2. As a result, AEP's access to the commercial paper market will be limited and AEP will use other sources of funds as necessary. The registrant subsidiaries incurred interest expense for amounts borrowed from the AEP money pool as follows: Year Ended December 31, ---------------------- 2002 2001 2000 ---- ---- ---- (in millions) AEGCo $0.4 $ 0.8 $ - APCo 4.9 9.8 - CSPCo 3.2 5.0 1.4 I&M 0.4 13.1 0.8 KPCo 1.8 2.3 - OPCo 6.9 14.6 9.2 PSO 5.4 6.3 7.5 SWEPCo 4.6 3.4 4.2 TCC 11.1 11.4 16.9 TNC 3.8 3.1 2.7 Interest income earned from amounts advanced to the AEP money pool by the registrant subsidiaries were: Year Ended December 31, ---------------------- 2002 2001 2000 ---- ---- ---- (in millions) AEGCo $0.1 $ - $ - APCo 2.0 1.7 - CSPCo 1.3 0.8 1.1 I&M 2.0 1.6 9.0 KPCo - 0.1 1.8 OPCo 0.8 8.6 3.4 PSO 1.1 - - SWEPCo 1.6 0.1 - TCC 2.0 0.1 - Outstanding short-term debt for AEP Consolidated consisted of: December 31, ----------- 2002 2001 ---- ---- (in millions) Balance Outstanding: Notes Payable $1,747 $1,063 Commercial paper 1,417 2,948 ------ ------ Total $3,164 $4,011 ====== ====== Sale of Receivables - AEP Credit AEP Credit entered into a sale of receivables agreement with a group of banks and commercial paper conduits. Under the sale of receivables agreement, which expires May 28, 2003, AEP Credit sells an interest in the receivables it acquires 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 and allowing AEP Credit to repay any debt obligations. 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. This off-balance sheet transaction was entered into to allow AEP credit to repay its outstanding debt obligations, continue to purchase the AEP operating companies' receivables, and accelerate its cash collections. At December 31, 2002, the sale of receivables agreement provided the banks and commercial paper conduits would purchase a maximum of $600 million of receivables from AEP Credit, of which $454 million was outstanding. As collections from receivables sold occur and are remitted, the outstanding balance for sold receivables is reduced and as new receivables are sold, the outstanding balance of sold receivables increases. All of the receivables sold represented affiliate receivables. The commitment's new term under the sale of receivables agreement will remain at $600 million until May 28, 2003. 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 receivables less an allowance for anticipated uncollectible accounts. AEP Credit purchases accounts receivable through purchase agreements with affiliated companies and, until the first quarter of 2002, with non-affiliated companies. As a result of the restructuring of electric utilities in the State of Texas, the purchase agreement between AEP Credit and Reliant Energy, Incorporated was terminated as of January 25, 2002 and the purchase agreement between AEP Credit and Texas-New Mexico Power Company, the last remaining non-affiliated company, was terminated on February 7, 2002. In addition, the purchase agreements between AEP Credit and its Texas affiliates AEP Texas Central Company (formerly Central Power and Light Company) and AEP Texas North Company (formerly West Texas Utilities Company) were terminated effective March 20, 2002. Comparative accounts receivable information for AEP Credit: Year Ended December 31, ---------------------- 2002 2001 ---- ---- (in millions) Proceeds from Sale of Accounts Receivable $5,513 $1,134 Accounts Receivable Retained Interest Less Uncollectible Accounts and Amounts Pledged as Collateral 76 143 Deferred Revenue from Servicing Accounts Receivable 1 5 Loss on Sale of Accounts Receivable 4 8 Average Variable Discount Rate 1.92% 2.28% Retained Interest if 10% Adverse change in Uncollectible Accounts 74 142 Retained Interest if 20% Adverse change in Uncollectible Accounts 72 140 Historical loss and delinquency amount for the AEP System's customer accounts receivable managed portfolio:
Face Value Year Ended December 31, ---------------------- 2002 2001 (in millions) Customer Accounts Receivable Retained $ 466 $ 343 Miscellaneous Accounts Receivable Retained 1,394 1,365 Allowance for Uncollectible Accounts Retained (119) (69) ------ ------ Total Net Balance Sheet Accounts Receivable 1,741 1,639 Customer Accounts Receivable Securitized (Affiliate) 454 560 Customer Accounts Receivable Securitized (Non-Affiliate) - 485 ------ ------ Total Accounts Receivable managed $2,195 $2,684 ====== ====== Net Uncollectible Accounts Written Off 48 72 ------ ------
Customer accounts receivable retained and securitized for the domestic electric operating companies are managed by AEP Credit. Miscellaneous account receivable have been fully retained and not securitized. At December 31, 2002, delinquent customer accounts receivable was $30 million. Under the factoring arrangement certain of 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. The amount of factored accounts receivable and accrued utility revenues for each registrant subsidiary was as follows: December 31, ----------- 2002 2001 ---- ---- Company (in millions) - ------- APCo $ 67.6 $ 61.2 CSPCo 114.3 105.7 I&M 103.7 94.9 KPCo 29.5 26.2 OPCo 109.8 100.2 PSO 83.7 70.7 SWEPCo 65.2 81.6 TCC - 145.3 TNC - 35.5 The fees paid by the registrant subsidiaries to AEP Credit for factoring customer accounts receivable were: Year Ended December 31, ---------------------- 2002 2001 2000 ---- ---- ---- (in millions) APCo $ 4.8 $ 5.2 $ - CSPCo 15.8 15.2 10.8 I&M 7.4 8.5 6.8 KPCo 2.7 2.7 1.9 OPCo 11.4 12.8 8.4 PSO 7.2 9.6 8.3 SWEPCo 5.4 7.4 9.2 TCC 2.2 14.7 15.7 TNC 1.4 3.8 4.0 24. Unaudited Quarterly Financial Information: The unaudited quarterly financial information for AEP Consolidated follows: 2002 Quarterly Periods Ended ---------------------------- March 31 June 30 Sept. 30 Dec. 31 -------- ------- -------- ------- (In Millions - Except Per Share Amounts) Revenues $3,169 $3,575 $3,870 $3,941 Operating Income (Loss) 459 427 782 (405) Income (Loss) Before Discontinued Operations, Extraordinary Items and Cumulative Effect 159 158 386 (682) Net Income (Loss) (169) 62 425 (837) Earnings (Loss) per Share Before Discontinued Operations,Extraordinary Items and Cumulative Effect* 0.49 0.49 1.14 (2.01) Earnings (Loss) per Share** (0.53) 0.19 1.25 (2.47) 2001 Quarterly Periods Ended ---------------------------- March 31 June 30 Sept. 30 Dec. 31 -------- ------- -------- ------- (In Millions - Except Per Share Amounts) Revenues $2,910 $3,259 $3,733 $2,865 Operating Income 521 622 824 215 Income Before Discontinued Operations, Extraordinary Items and Cumulative Effect 230 251 399 37 Net Income 266 232 421 52 Earnings per Share Before Discontinued Operations, Extraordinary Items and Cumulative Effect*** 0.72 0.77 1.23 0.12 Earnings per Share**** 0.83 0.72 1.31 0.16 * Amounts for 2002 do not add to $0.06 earnings per share before Discontinued Operations, Extraordinary Items and Cumulative Effect due to rounding and the dilutive effect of shares issued in 2002. **Amounts for 2002 do not add to $(1.57) earnings per share due to rounding. ***Amounts for 2001 do not add to $2.85 earnings per share before Discontinued Operations, 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 CSPCo I&M KPCo (in thousands) 2002 March 31 Operating Revenues $49,875 $462,605 $314,826 $352,235 $ 99,185 Operating Income 1,767 81,554 45,548 30,363 15,484 Income Before Extraordinary Items 1,893 55,341 33,858 11,058 10,246 Net Income 1,893 55,341 33,858 11,058 10,246 June 30 Operating Revenues $53,356 $432,015 $343,813 $369,043 $ 92,164 Operating Income 1,504 65,224 58,040 19,865 9,550 Income Before Extraordinary Items 1,718 46,608 51,721 7,494 5,246 Net Income 1,718 46,608 51,721 7,494 5,246 September 30 Operating Revenues $55,988 $474,282 $428,437 $421,472 $100,359 Operating Income 1,436 81,365 89,033 57,004 11,119 Income Before Extraordinary Items 1,947 53,947 76,117 35,312 5,994 Net Income 1,947 53,947 76,117 35,312 5,994 December 31 Operating Revenues $54,062 $445,568 $313,084 $384,014 $ 86,975 Operating Income 1,422 73,920 27,158 43,957 6,044 Income (Loss) Before Extraordinary Items 1,994 49,596 19,477 20,128 (919) Net Income (Loss) 1,994 49,596 19,477 20,128 (919)
Quarterly Periods Ended OPCo PSO SWEPCo TCC TNC ----------------------- ---- --- ------ --- --- (in thousands) 2002 March 31 Operating Revenues $520,652 $148,986 $222,259 $278,910 $103,626 Operating Income 83,716 8,410 22,469 55,445 11,145 Income (Loss) Before Extraordinary Items 64,051 (1,648) 8,159 24,445 3,992 Net Income (Loss) 64,051 (1,648) 8,159 24,445 3,992 June 30 Operating Revenues $521,365 $158,330 $263,074 $360,391 $104,452 Operating Income 61,046 20,201 31,988 64,319 5,547 Income Before Extraordinary Items 55,348 11,620 18,155 33,535 675 Net Income 55,348 11,620 18,155 33,535 675 September 30 Operating Revenues $566,366 $230,098 $362,423 $546,260 $152,667 Operating Income (Loss) 97,210 50,710 60,254 118,204 (308) Income (Loss) Before Extraordinary Items 80,258 41,002 45,794 93,383 (4,193) Net Income (Loss) 80,258 41,002 45,794 93,383 (4,193) December 31 Operating Revenues $504,742 $256,233 $236,964 $504,932 $ 89,995 Operating Income (Loss) 56,357 5,400 27,758 155,765 (8,513) Income (Loss) Before Extraordinary Items 20,366 (9,914) 10,884 124,578 (14,151) Net Income (Loss) 20,366 (9,914) 10,884 124,578 (14,151)
Quarterly Periods Ended AEGCo APCo CSPCo I&M KPCo ----------------------- ----- ---- ----- --- ---- (in thousands) 2001 March 31 Operating Revenues $60,507 $501,204 $327,437 $387,813 $100,681 Operating Income 1,807 88,152 51,932 52,698 12,604 Income Before Extaordinary Items 1,980 61,787 37,671 32,363 7,075 Net Income 1,980 61,787 37,671 32,363 7,075 June 30 Operating Revenues $52,217 $430,412 $333,995 $382,234 $ 89,541 Operating Income 1,882 59,362 62,894 47,340 8,364 Income Before Extrodinary Items 2,063 36,419 47,418 27,374 2,742 Net Income 2,063 36,419 21,011 27,374 2,742 September 30 Operating Revenues $57,417 $434,450 $375,691 $398,457 $ 96,197 Operating Income 1,615 60,381 76,920 44,509 12,587 Income Before Extraordinary Items 2,051 30,317 65,318 25,064 5,312 Net Income 2,051 30,317 65,318 25,064 5,312 December 31 Operating Revenues $57,407 $418,193 $313,196 $358,493 $ 92,606 Operating Income 1,673 67,091 60,431 15,158 14,123 Income (Loss) Before Extraordinary Items 1,781 33,295 41,493 (9,013) 6,436 Net Income (Loss) 1,781 33,295 37,876 (9,013) 6,436
Quarterly Periods Ended OPCo PSO SWEPCo TCC TNC ----------------------- ---- --- ------ --- --- (in thousands) 2001 March 31 Operating Revenues $552,503 $225,080 $267,117 $432,910 $141,649 Operating Income 64,756 8,340 33,986 64,152 5,392 Income (Loss) Before Extraordinary Items 53,397 (1,560) 19,869 35,031 891 Net Income (Loss) 53,397 (1,560) 19,869 35,031 891 June 30 Operating Revenues $512,196 $265,360 $271,748 $470,420 $139,228 Operating Income 47,067 21,942 32,649 82,351 12,428 Income Before Extraordinary Items 32,094 11,921 17,784 52,518 6,133 Net Income 10,579 11,921 17,784 52,518 6,133 September 30 Operating Revenues $535,535 $325,373 $331,441 $527,117 $181,433 Operating Income 69,668 59,914 60,194 112,598 17,745 Income Before Extraordinary Items 51,378 51,069 46,357 83,702 14,067 Net Income 51,378 51,069 46,357 83,702 14,067 December 31 Operating Revenues $497,871 $141,187 $231,020 $308,390 $ 94,148 Operating Income (Loss) 59,219 6,792 19,378 36,630 (2,175) Income (Loss) Before Extraordinary Items 28,924 (3,671) 5,357 13,536 (8,781) Net Income (Loss) 32,091 (3,671) 5,357 11,027 (8,781)
Income Before Discontinued Operations, Extraordinary Items and Cumulative Effect for the fourth quarter 2002 decreased $896 million from the prior year due to the impairment loss and impairment value losses of approximately $1,188 million (pre-tax) to reduce the valuation of under-performing assets. In addition to the impairments that were recorded during the fourth quarter, a change in AEP's Accumulated Other Comprehensive Income (Loss) of $585 million for pension liability had a negative effect on each registrant's Consolidated Balance Sheets. 25. Trust Preferred Securities: The following Trust Preferred Securities issued by the wholly-owned statutory business trusts of PSO, SWEPCo and TCC were outstanding at December 31, 2002 and December 31, 2001. They are classified on AEP's, PSO's, SWEPCo's and TCC's Balance Sheets as Certain Subsidiary 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. TCC reacquired 490,000 trust preferred units during 2001.
Units Issued/ Description of Outstanding Underlying Business Trust Security At 12/31/02 Amount at December 31, Debentures of Registrant - -------------- -------- ----------- ---------------------- ------------------------ 2002 2001 (in millions) CPL Capital I 8.00%, Series A 5,450,000 $136 $136 TCC, $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, ---------- ---- ---- 7.875%, Series A 12,850,000 $321 $321 ========== ==== ====
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. 26. Minority Interest in Finance Subsidiary: In August 2001, AEP formed AEP Energy Services Gas Holding Co. II, LLC (SubOne) and Caddis Partners, LLC (Caddis). SubOne is a wholly owned consolidated subsidiary of AEP that was capitalized with the assets of Houston Pipe Line Company, Louisiana Interstate Gas Company (AEP subsidiaries) and $321.4 million of AEP Energy Services Gas Holding Company (AEP Gas Holding is an AEP subsidiary and parent of SubOne) preferred stock, that is convertible into AEP common stock at market price on a dollar-for-dollar basis. Caddis was capitalized with $2 million cash and a subscription agreement that represents an unconditional obligation to fund $83 million from SubOne and $750 million from Steelhead Investors LLC ("Steelhead" - non-controlling preferred member interest). As managing member, SubOne consolidates Caddis. Steelhead is an unconsolidated special purpose entity and has a capital structure of $750 million of which 3% is equity from investors with no relationship to AEP or any of its subsidiaries and 97% is debt from a syndicate of banks. The use of Steelhead allows AEP to limit its risk associated with Houston Pipe Line Company and Louisiana Intrastate Gas Company. Under the provisions of the Caddis formation agreements, Steelhead receives a quarterly preferred return equal to an adjusted floating reference rate (4.784% and 4.413% for the quarters ended December 31, 2002 and 2001, respectively). Caddis has the right to redeem Steelhead's interest at any time. The $750 million invested in Caddis by Steelhead was loaned to SubOne. This intercompany loan to SubOne is due August 2006, and is supported by the natural gas pipeline assets of SubOne, a cash reserve fund of SubOne and SubOne's $321.4 million of preferred stock in AEP Gas Holding. The preferred stock is convertible into AEP common stock upon the occurrence of certain events including AEP's stock price closing below $18.75 for ten consecutive trading days. AEP can elect not to have the transaction supported by such preferred stock if SubOne were to reduce its loan with Caddis by $225 million. The credit agreement between Caddis and SubOne contains covenants that restrict certain incremental liens and indebtedness, asset sales, investments, acquisitions, and distributions. The credit agreement also contains covenants that impose minimum financial ratios. Non-performance of these covenants may result in an event of default under the credit agreement. Through December 31, 2002, we have complied with the covenants contained in the credit agreement. In addition, a default under any other agreement or instrument relating to AEP and certain subsidiaries' debt outstanding in excess of $50 million is an event of default under the credit agreement. The initial period of Steelhead's investment in Caddis is through August 2006. At the end of the initial period, Caddis will either reset Steelhead's return rate, re-market Steelhead's interests to new investors, redeem Steelhead's interests, in whole or in part including accrued return, or liquidate Caddis in accordance with the provisions of applicable agreements. Steelhead has certain rights as a preferred member in 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 AEP Gas Holding preferred stock into AEP common stock. If Steelhead exercised its rights to force Caddis to liquidate under these conditions, then AEP would evaluate whether to refinance at that time or relinquish the assets that support the intercompany loan to Caddis. Liquidation of Caddis could negatively impact AEP's liquidity. Caddis and SubOne 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 SubOne are consolidated with AEP for financial reporting purposes. Steelhead's investment in Caddis and payments made to Steelhead from Caddis are currently reported on AEP's consolidated statements of operation and consolidated balance sheets as Minority Interest in Finance Subsidiary. AEP's maximum exposure to loss as a result of its involvement with Steelhead is $321.4 million of preferred stock, $83 million under the subscription agreement to Caddis for any losses incurred by Caddis and the cash reserve fund balance of $34 million (as of December 31, 2002) due Caddis for default under the intercompany loan agreement. AEP can reduce its maximum exposure related to the preferred stock by a reduction of $225 million of the intercompany loan. As of December 31, 2002, we are continuing to review the application of FIN 46 as it relates to the Steelhead transaction. 27. Equity Units In June 2002, AEP issued 6.9 million equity units at $50 per unit and received proceeds of $345 million. Each equity unit consists of a forward purchase contract and a senior note. The forward purchase contracts obligate the holders to purchase shares of AEP common stock on August 16, 2005. The purchase price per equity unit is $50. The number of shares to be purchased under the forward purchase contract will be determined under a formula based upon the average closing price of AEP common stock near the stock purchase date. Holders may satisfy their obligation to purchase AEP common stock under the forward purchase contracts by allowing the senior notes to be remarketed or by continuing to hold the senior notes and using other resources as consideration for the purchase of stock. If the holders elect to allow the notes to be remarketed, the proceeds from the remarketing will be used to purchase a portfolio of U.S. treasury securities that the holders will pledge to AEP in order to meet their obligations under the forward purchase contracts. The senior notes have a principal amount of $50 each and mature on August 16, 2007. The senior notes are the collateral that secures the holders' requirement to purchase common stock under the forward purchase contracts. AEP will make quarterly interest payments on the senior notes at the initial annual rate of 5.75%. The interest rate can be reset through a remarketing, which is initially scheduled for May 2005. AEP will make contract adjustment payments to the purchaser at the annual rate of 3.50% on the forward purchase contracts. The present value of the contract adjustment payments has been recorded as a $31 million liability in Equity Unit Senior Notes offset by a charge to Paid-in Capital. Interest payments on the senior notes are reported as interest expense. Accretion of the contract adjustment payment liability is reported as interest expense. AEP applies the treasury stock method to the equity units to calculate diluted earnings per share. This method of calculation theoretically assumes that the proceeds received as a result of the forward purchase contract are used to repurchase outstanding shares. 28. Jointly Owned Electric Utility Plant: CSPCo, PSO, SWEPCo, TCC and TNC 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, --------------- 2002 2001 -------------------------- --------------------------- Percent Utility Construction Utility Construction of Plant Work Plant Work Ownership in Service in Progress in Service in Progress --------- ------------ ------------- ------------ ------------ (in thousands) (in thousands) CSPCo: W.C. Beckjord Generating Station (Unit No. 6) 12.5 $ 15,487 $ 49 $ 14,292 $ 884 Conesville Generating Station (Unit No. 4) 43.5 81,960 279 81,697 494 J.M. Stuart Generating Station 26.0 197,276 44,865 193,760 27,758 Wm. H. Zimmer Generating Station 25.4 705,620 14,077 704,951 2,634 Transmission (a) 61,187 2,281 61,476 91 ---------- ------- ---------- ------- $1,061,530 $61,551 $1,056,176 $31,861 ========== ======= ========== ======= PSO: Oklaunion Generating Station (Unit No. 1) 15.6 $ 83,562 $ 777 $ 82,646 $ 634 ========== ======= ========== ======== SWEPCo: Dolet Hills Generating Station (Unit No. 1) 40.2 $ 235,366 1,313 $ 234,747 $ 675 Flint Creek Generating Station (Unit No. 1) 50.0 91,567 1,052 83,953 213 Pirkey Generating Station (Unit No. 1) 85.9 451,136 2,197 439,430 10,577 ---------- ------- ---------- ------- $ 778,069 $ 4,562 $ 758,130 $11,465 ========== ======= ========== ======== TCC: Oklaunion Generating Station (Unit No. 1) 7.8 $ 38,055 $ 369 $ 37,728 $ 318 South Texas Project Generating Station (Units No. 1 and 2) 25.2 2,364,359 43,887 2,360,452 41,571 ---------- ------- ---------- ------- $2,402,414 $44,256 $2,398,180 $41,889 ========== ======= ========== ======== TNC: Oklaunion Generating Station (Unit No. 1) 54.7 $ 277,946 $ 3,650 $ 279,419 $ 1,651 ========== ======= ========== ======= (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, ----------- 2002 2001 ---- ---- (in thousands) CSPCo $436,683 $410,756 PSO 49,085 35,653 SWEPCo 450,057 392,728 TCC 927,193 863,130 TNC 102,542 100,430 29. 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 preceeding 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, under certain conditions 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. 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. PSO, SWEPCo, TCC, TNC 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 operating companies that have capacity in excess of the required margins to make such capacity available for sale to other operating companies 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, under certain conditions TCC and TNC would no longer be parties to the CSW Operating Agreement. 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, 2002, 2001 and 2000:
APCo CSPCo I&M KPCo OPCo AEGCo Related Party Revenues (in thousands) 2002 Sales to East System Pool $106,651 $42,986 $ 197,525 $ 22,369 $397,248 $ - Sales to West System Pool 18,300 12,107 13,036 4,717 16,265 - Direct Sales To East Affiliates 58,213 - - - 50,599 213,071 Direct Sales To West Affiliates - - - - - - Other 3,313 2,109 3,577 878 1,090 - -------- ------- ---------- -------- -------- -------- Total Revenues $186,477 $57,202 $ 214,138 $ 27,964 $465,202 $213,071 ======== ======= ========== ======== ======== ======== 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 ======== ======= ========== ======== ======== ========
PSO SWEPCo TCC TNC Related Party Revenues (in thousands) 2002 Sales to East System Pool $ - $ - $ - $ - Sales to West System Pool 674 1,334 18,416 1,280 Direct Sales To East Affiliates 611 270 366 (23) Direct Sales To West Affiliates 6,047 75,674 956,751 228,404 Other 2,107 (4,979) 32,911 10,764 ------- ------- ---------- -------- Total Revenues $ 9,439 $72,299 $1,008,444 $240,425 ======= ======= ========== ======== 2001 Sales to East System Pool $ 4 $ - $ - $ - Sales to West System Pool 3,317 8,073 19,865 322 Direct Sales To East Affiliates 2,833 3,238 3,697 1,228 Direct Sales To West Affiliates 30,668 67,930 12,617 9,350 Other (51) (4) 5,583 7,781 ------- ------- ---------- -------- Total Revenues $36,771 $79,237 $ 41,762 $ 18,681 ======= ======= ========== ======== 2000 Sales to East System Pool $ - $ - $ - $ - Sales to West System Pool 7,323 5,546 23,421 194 Direct Sales To East Affiliates (1,990) (3,008) (3,348) (1,116) Direct Sales To West Affiliates 21,995 62,178 12,516 7,645 Other (12,680) (1,592) 5,163 11,931 ------- ------- ---------- -------- Total Revenues $14,648 $63,124 $ 37,752 $ 18,654 ======= ======= ========== ======== The following table shows the purchased power expense incurred from purchases from the Pools and affiliates for the years ended December 31, 2002, 2001, and 2000:
APCo CSPCo I&M KPCo OPCo Related Party Purchases (in thousands) 2002 Purchases from East System Pool $233,677 $309,999 $ 83,918 $ 68,846 $70,338 Purchases from West System Pool 337 219 237 86 297 Direct Purchases from East Affiliates 583 387 149,569 64,070 519 Direct Purchases from West Affiliates - - - - - -------- -------- -------- -------- ------- Total Purchases $234,597 $310,605 $233,724 $133,002 $71,154 ======== ======== ======== ======== ======= 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 ======== ======== ======== ======== =======
PSO SWEPCo TCC TNC Related Party Purchases (in thousands) 2002 Purchases from East System Pool $ 343 $ - $ - $ - Purchases from West System Pool 874 (456) 1,366 15,475 Direct Purchases from East Affiliates 29,029 17,242 8,236 2,669 Direct Purchases from West Affiliates 59,208 25,236 13,804 19,438 ------- ------- ------- ------- Total Purchases $89,454 $42,022 $23,406 $37,582 ======= ======= ======= ======= 2001 Purchases from East System Pool $ 1,327 $ - $ - $ 4 Purchases from West System Pool 5,877 3,810 415 11,689 Direct Purchases from East Affiliates 1,951 2,352 12,657 4,614 Direct Purchases from West Affiliates 34,603 9,696 45,569 40,349 ------- ------- ------- ------- Total Purchases $43,758 $15,858 $58,641 $56,656 ======= ======= ======= ======= 2000 Purchases from East System Pool $20,100 $ - $ - $ - Purchases from West System Pool 5,386 4,379 1,696 18,444 Direct Purchases from East Affiliates 2,117 695 251 71 Direct Purchases from West Affiliates 33,185 8,264 30,644 39,258 ------- ------- ------- ------- Total Purchases $60,788 $13,338 $32,591 $57,773 ======= ======= ======= =======
The above summarized related party revenues and expenses are reported in their entirety, without elimination, and are presented as operating revenues affiliated and purchased power affiliated on the statements of operations 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, 2002, 2001 and 2000: 2002 2001 2000 ---- ---- ---- (in thousands) APCo $(13,400) $ (3,100) $ (3,400) CSPCo 42,200 40,200 38,300 I&M (36,100) (41,300) (43,800) KPCo (5,400) (4,600) (6,000) OPCo 12,700 8,800 14,900 PSO, SWEPCo, TCC, TNC 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. The following table shows the net (credits) or charges allocated among the parties to the Transmission Agreement during the years ended December 31, 2002, 2001 and 2000: 2002 2001 2000 ---- ---- ---- (in thousands) PSO $(4,200) $ (4,000) $ (3,300) SWEPCo (5,000) (5,400) (5,900) TCC 3,600 3,900 3,400 TNC 5,600 5,500 5,800 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 unless it is sold to another utility. 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. This unit power agreement extends until December 31, 2009 for Unit 1 and until December 7, 2022 for Unit 2 if AEP's restructuring settlement agreement filed with the FERC becomes operative. 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, 2002 2001 2000 ---- ---- ---- Company (in millions) I&M - revenues $34.3 $30.2 $23.5 AEGCo - expense 7.8 8.5 8.8 APCo - expense 12.8 11.5 7.8 OPCo - expense 7.9 10.2 6.9 Memco - expense 5.7 - - AEP Energy Services 0.1 - - 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 PUHCA. 30. Subsequent Events (Unaudited): Common Stock Offering - On February 27, 2003, AEP priced its offering of 50 million shares of common stock at a public offering price of $20.95 per share. AEP has granted the underwriters an option to purchase an additional 7.5 million shares of common stock to cover overallotments. The net proceeds from the sale of these securities will be used to reduce debt and for general corporate purposes. Senior Notes Offering - During March 2003, AEP completed an offering of 5.375% Series C Senior Notes which have a principal amount of $500 million and a maturity date of March 15, 2010. The net proceeds from the offering will be used to repay or redeem current maturities of long-term debt, a portion of our minority interest in a financing subsidiary, and for general corporate purposes. REGISTRANTS' COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION, ACCOUNTING POLICIES AND OTHER MATTERS The following is a combined presentation of management's discussion and analysis of financial condition, accounting policies and other matters for AEP and 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, accounting policies and other matters and the registrant to which they apply: Financial Condition AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC Critical Accounting AEP, AEGCo, APCo, Policies CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC Market Risks AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC Industry Restructuring AEP, APCo, CSPCo I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC Litigation AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC Environmental Concerns AEP, AEGCo, APCo, and Issues CSPCo, I&M, KPCo OPCo, PSO, SWEPCo, TCC, TNC Other Matters AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC Financial Condition We measure our financial condition by the strength of the balance sheets and the liquidity provided by cash flows and earnings. Balance sheet capitalization ratios and cash flow ratios are principal determinants of our credit quality. Credit Ratings The rating agencies have been conducting credit reviews of AEP and its registrant subsidiaries. The agencies are also reviewing most companies in the energy sector due to issues which impact the entire industry, not only AEP and its subsidiaries. In February 2003, Moody's Investors Service (Moody's) completed their review of AEP and its rated subsidiaries. The results of that review were downgrades of the following ratings for unsecured debt: AEP to Baa3 from Baa2, APCo from Baa1 to Baa2, TCC from Baa1 to Baa2, PSO from A2 to Baa1, SWEPCo from A2 to Baa1. TNC, which had no senior unsecured notes outstanding at the time of the ratings action, had its mortgage bond debt downgraded from A2 to A3. AEP's commercial paper was also concurrently downgraded from P-2 to P-3. The completion of this review was a culmination of earlier ratings action in 2002 that had included a downgrade of AEP from Baa1 to Baa2 and the placement of five of the registrant subsidiaries on negative outlook. With the completion of the reviews, Moody's has placed AEP and its rated subsidiaries on stable outlook. In February 2003, Standard & Poor's placed AEP's senior unsecured debt and commercial paper ratings on credit watch with negative implications, and did the same with the subsidiaries. S&P indicated that resolution regarding these actions would come within a short time (see additional discussion in Financing - Credit Ratings in Item 1 of Part I). In 2002, Fitch Ratings Service downgraded both PSO and SWEPCo from A to A- for the senior unsecured notes. Fitch has AEP and its subsidiaries on stable outlook and the commercial paper rating is stable at F-2 (see additional discussion in Financing - Credit Ratings in Item 1 of Part I). Current ratings of AEP's subsidiaries' first mortgage bonds are listed in the following table: Company Moody's S&P Fitch - ------- ------- --- ----- APCo Baa1 BBB+ A- CSPCo A3 BBB+ A I&M Baa1 BBB+ BBB+ KPCo Baa1 BBB+ BBB+ OPCo A3 BBB+ A- PSO A3 BBB+ A SWEPCO A3 BBB+ A TCC Baa1 BBB+ A TNC A3 BBB+ A Current short-term ratings are as follows: Company Moody's S&P Fitch - ------- ------- --- ----- AEP P-3 A-2 F-2 The current ratings for senior unsecured debt are listed in the following table: Company Moody's S&P Fitch - ------- ------- --- ----- AEP Baa3 BBB+ BBB+ AEP Resources* Baa3 BBB+ BBB+ APCo Baa2 BBB+ BBB+ CSPCo A3 BBB+ A- I&M Baa2 BBB+ BBB KPCo Baa2 BBB+ BBB OPCo A3 BBB+ BBB+ PSO Baa1 BBB+ A- SWEPCO Baa1 BBB+ A- TCC Baa2 BBB+ A- TNC Baa1 BBB+ A- * The rating is for a series of senior notes issued with a Support Agreement from AEP. AEP's common equity to total capitalization declined to 32% in 2002 from 36% in 2001 and 37% in 2000. Total capitalization includes long-term debt due within one year, equity unit senior notes, minority interest and short-term debt. Preferred stock at 1% remained unchanged. In 2002, long-term debt including equity unit senior notes and trust preferred securities increased from 43% to 50% while Short-term Debt decreased from 17% to 14% and Minority Interest in Finance Subsidiary remained unchanged at 3%. In 2001 Long-term Debt remained unchanged while Short-term Debt decreased from 20% to 17% and Minority Interest in Finance Subsidiary increased to 3%. In 2002, 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. Common stock was issued in 2002 for stock options exercised and under an equity offering (discussed in Financing Activity). Liquidity - --------- Liquidity, or access to cash, has become a more critical factor in determining the financial stability of a company due to volatility in wholesale power markets and the potential limitations that credit rating downgrades place on a company's ability to raise capital. Management is committed to preserving an adequate liquidity position and addressing AEP and its subsidiaries' financial needs in 2003. As of December 31, 2002, we had an available liquidity position of $3.5 billion as illustrated in the table below: Credit Facilities - ----------------- (in millions) Maturity Commercial Paper Backup Lines of Credit $2,500* 5/03 Commercial Paper Backup Lines of Credit 1,000 5/05 Corporate Separation Revolving Credit 1,725 4/03 Euro Revolving Credit Facilities 315 10/03 ------ Total 5,540 Cash Liquidity Reserve 1,000** ------ Total Credit Facilities and Cash 6,540 Less: Commercial Paper Outstanding Corporate Separation 1,415 Loans 1,300 Euro Revolving Credit Loans 305 ------ Total Available Liquidity $3,520 ====== * Contains one year term-out provision. ** Unrestricted and excludes $213 million of operational cash on hand. AEP and its subsidiaries' goal for 2003 is to use cash from operations to fund capital expenditures, dividend payments and working capital requirements. Short-term debt is used as an interim bridge for timing differences in the need for cash or to fund debt maturities until permanent financing is arranged. Short-term funding comes from the parent company's commercial paper program and revolving credit facilities. Proceeds are loaned to the subsidiaries through intercompany notes. AEP and its subsidiaries also operate a non-utility and utility money pool to minimize the AEP System's external short-term funding requirements and sell accounts receivable to provide liquidity for the domestic electric subsidiaries. The commercial paper program is backed by $3.5 billion in bank facilities of which $1 billion matures in May 2005. The remaining $2.5 billion matures in May 2003 and has a one-year term-out provision at AEP's option. At December 31, 2002, approximately $1.4 billion of commercial paper was outstanding. A portion of the commercial paper balance is related to funding of debt maturities of the Ohio and Texas subsidiaries pending a permanent financing program. The Ohio and Texas subsidiaries issued $2,025 million of senior unsecured notes in February 2003 with maturity dates ranging from 2005 to 2033. The commercial paper balance outstanding decreased in early 2003 due to repayment with proceeds from these issuances. AEP also has a $1.725 billion bank facility maturing in April 2003 that is available for debt refinancing. At December 31, 2002, $1.3 billion was outstanding under that facility. With the issuance of the permanent financing for the Ohio and Texas subsidiaries mentioned above, this facility was repaid and cancelled in February 2003. AEP also has revolving credit facilities in place for 300 million Euros to support the wholesale business in Europe. At December 31, 2002, the majority of these facilities were drawn. AEP also maintains a minimum $300 million cash liquidity reserve fund to support its marketing operations in the U.S. and keeps additional cash on hand as market conditions change. At December 31, 2002, AEP had $1 billion of cash available for liquidity. On December 6, 2002, we closed a 364-day, $425 million facility and used it to partially repay the maturing interim financing for the U.K. generation plants (FFF). The facility was secured by a pledge of the shares of AEP companies in the FFF ownership chain and guaranteed by the parent company. A portion ($213 million) of the facility is due in May 2003. The remainder of the FFF interim financing was repaid using a combination of existing funds and draws against the Euro revolving credit facilities. In total, we had approximately $6.5 billion in liquidity sources of which $3.5 billion were unused and available at December 31, 2002. During 2002, cash flow from operations was $1.7 billion, including $21 million from Net Income Before Discontinued Operations, Extraordinary Items and Cumulative Effect, approximately $1.3 billion from depreciation, amortization, deferred taxes, and deferred investment tax credits, approximately $1.1 billion associated with asset, investment value and other impairments, offset by additional working capital requirements of approximately $700 million. These additional working capital requirements reflect the one time impact of the discontinuance of the sale of accounts receivable for Texas companies and billing delays related to the transition to customer choice in Texas, higher margin requirements for gas trading, seasonal fuel inventory growth, and other miscellaneous items. Construction expenditures were $1.7 billion including major expenditures for emission control technology on several coal-fired generating units (see discussion in Note 9). Dividends on common stock were $793 million. Cash from operations, proceeds from the sale of SEEBOARD, CitiPower and the Texas REPs and the issuance of common stock, common equity units, 15-year notes for a wind generation project and transition funding bonds provided funds to reduce debt, fund construction and pay dividends. During 2001, AEP's cash flow from operations was $2.8 billion, including $885 million from Net Income Before Discontinued Operations, Extraordinary Items and Cumulative Effect and $1.4 billion from depreciation, amortization, deferred taxes and deferred investment tax credits. Capital expenditures including acquisitions were $3.9 billion and dividends on common stock were $773 million. Cash from operations less dividends on common stock financed 51% of capital expenditures. During 2001, the proceeds of AEP's $1.25 billion global notes issuance and proceeds from the sale of a U.K. 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. Asset purchases include HPL, coal mines, a barge line, a wind generating facility and two coal-fired generating plants in the U.K. These acquisitions accounted for the increase in total debt during 2001. Long-term funding arrangements for specific assets are often complex and typically not completed until after the acquisition. The loss for 2002 resulted in a negative dividend payout ratio of 153% reflecting the losses on sale and impairments of assets. 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. AEP and its subsidiaries 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. AEP's revolving credit agreements include covenants that require performance of certain actions, including maintaining specified financial ratios. Non-performance of these covenants may result in an event of default under these credit agreements. At December 31, 2002, AEP complied with the covenants contained in these credit agreements. In addition, a default under any other agreement or instrument relating to debt outstanding in excess of $50 million is an event of default under these credit agreements. An event of default under these credit agreements would cause all amounts outstanding thereunder to be immediately payable. Financing Activity - ------------------ Common Stock In June 2002, AEP issued 16 million shares of common stock at $40.90 per share through an equity offering and received net proceeds of $634 million. Proceeds from the sale of equity units and common stock were used to pay down short-term debt and establish a cash liquidity reserve fund. Equity Units In June 2002, AEP issued 6.9 million equity units at $50 per unit ($345 million). See Note 27 for additional information. Debt In February 2002, TCC issued $797 million of securitization notes that were approved by the PUCT as part of Texas restructuring to recover generation related regulatory assets. The proceeds were used to reduce TCC's debt and equity. In April 2002, AEP closed on a bridge loan facility consisting of a $1.125 million 364-day revolving credit facility and a $600 million 364-day term loan facility to prepare for corporate separation. At year-end, $600 million was borrowed under the term loan facility and $700 million was borrowed under the revolving credit facility. Those amounts were repaid and the facility terminated when bonds were issued by CSPCo, OPCo, TCC and TNC in February 2003. In February 2003, CSPCo issued $250 million of unsecured senior notes due 2013 at a coupon of 5.50% and $250 million of unsecured senior notes due 2033 at a coupon of 6.60%. OPCo issued $250 million of unsecured senior notes due 2013 at a coupon of 5.50% and $250 million of unsecured senior notes due 2033 at a coupon of 6.60%. TCC issued $100 million of unsecured senior notes due 2005 at a variable rate, $150 million of unsecured senior notes due 2005 at a coupon of 3.0%, $275 million of unsecured senior notes due 2013 at a coupon of 5.50% and $275 million of unsecured senior notes due 2033 at a coupon of 6.65%. TNC issued $225 million of unsecured senior notes due 2013 at a coupon of 5.50%. The use of proceeds from the above bonds was repayment of the bridge loan facility mentioned above, repayment of short-term debt, and for general corporate purposes. In 2002, the following issuances were completed by the subsidiaries of AEP: - ------------ ---------------- ----------- ----------- ------- Principal Amount (in mil- Com-pany Type of Debt lions) Interest Due Rate Date - ------------ ---------------- ----------- ----------- ------- - ------------ ---------------- ----------- ----------- ------- Senior APCo Unsecured Notes $450 4.80% 2005 - ------------ ---------------- ----------- ----------- ------- - ------------ ---------------- ----------- ----------- ------- Senior APCo Unsecured Notes 200 4.32%* 2007 - ------------ ---------------- ----------- ----------- ------- - ------------ ---------------- ----------- ----------- ------- Installment I&M Purchase 50 4.90% 2025 Contracts - ------------ ---------------- ----------- ----------- ------- - ------------ ---------------- ----------- ----------- ------- Senior I&M Unsecured Notes 150 6.0% 2032 - ------------ ---------------- ----------- ----------- ------- - ------------ ---------------- ----------- ----------- ------- Senior I&M Unsecured Notes 100 6 3/8% 2012 - ------------ ---------------- ----------- ----------- ------- - ------------ ---------------- ----------- ----------- ------- Senior KPCo Unsecured Notes 125 5.50% 2007 - ------------ ---------------- ----------- ----------- ------- - ------------ ---------------- ----------- ----------- ------- Senior KPCo Unsecured Notes 80 4.32%* 2007 - ------------ ---------------- ----------- ----------- ------- - ------------ ---------------- ----------- ----------- ------- Senior KPCo Unsecured Notes 70 4.37%* 2007 - ------------ ---------------- ----------- ----------- ------- - ------------ ---------------- ----------- ----------- ------- Senior PSO Unsecured Notes 200 6.00% 2032 - ------------ ---------------- ----------- ----------- ------- - ------------ ---------------- ----------- ----------- ------- Senior SWEPCo Unsecured Notes 200 4.50% 2005 - ------------ ---------------- ----------- ----------- ------- - ------------ ---------------- ----------- ----------- ------- Other Notes Payable 121 6.20%- 2017 Subsid-iaries 6.60% - ------------ ---------------- ----------- ----------- ------- - ------------ ---------------- ----------- ----------- ------- Other Revolving 305 Variable 2003 Subsid-iariesCredit - ------------ ---------------- ----------- ----------- ------- - ------------------------------------------------------------- * Interest rate payable by subsidiary in U.S. dollars. While these companies do not have an Australian rate obligation, there is an underlying interest rate to Australian investors in Australian dollars of either 6% or a variable rate. - ------------------------------------------------------------- The subsidiaries also redeemed approximately $2 billion of long-term debt in 2002. See the Schedule of Long-term Debt for each registrant in sections B to K for details. AEP uses money pools to meet the short-term borrowings for the majority of its subsidiaries In addition, AEP also funds the short-term debt requirements of other subsidiaries that are not included in the money pool. As of December 31, 2002, AEP had credit facilities totaling $3.5 billion to support its commercial paper program. At December 31, 2002, AEP had $1.4 billion outstanding in short-term borrowings subject to these credit facilities. AEP Credit purchases, without recourse, the accounts receivable of most of the domestic utility operating companies. AEP Credit's financing for the purchase of receivables changed in December 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 AEP's and the subsidiaries' Balance Sheets. At December 31, 2002, AEP Credit had $454 million sold under this agreement. See Note 23 for further discussion. Off-balance Sheet and Minority Interest Arrangements AEP and its subsidiaries enter into off-balance sheet arrangements for various reasons ranging from accelerating cash collections, reducing operational expense to spreading risk of loss to third parties. The following identifies significant off-balance sheet arrangements: Power Generation Facility AEP has entered into agreements with Katco Funding L.P. (Katco), an unrelated unconsolidated special purpose entity. Katco has an aggregate financing commitment of $525 million and a capital structure of which 3% is equity from investors with no relationship to AEP or any of its subsidiaries and 97% is debt from a syndicate of banks. Katco was formed to develop, construct, finance and lease a power generation facility to AEP. Katco will own the power generation facility and lease it to AEP after construction is completed. The lease will be accounted for as an operating lease (see Note 22), therefore neither the facility nor the related obligations are reported on AEP's Consolidated Balance Sheets. Payments under the operating lease are expected to commence in the first quarter of 2004. AEP will in turn sublease the facility to Dow Chemical Company (DOW), which will use the energy produced by the facility and sell excess energy. AEP has agreed to purchase the excess energy from DOW for resale. The use of Katco allows AEP to limit its risk associated with the power generation facility once the construction phase has been completed. AEP is the construction agent for Katco, and is responsible for completing construction by December 31, 2003, subject to unforeseen events beyond AEP's control. In the event the project is terminated before completion of construction, AEP has the option to either purchase the facility for 100% of project costs or terminate the project and make a payment to Katco for 89.9% of project costs. The operating lease between Katco and AEP commences on the commercial operation date of the facility and continues until November 2006. The lease contains extension options subject to the approval of Katco, and if all extension options were exercised, the total term of the lease would be 30 years. AEP's lease payments to Katco are sufficient for Katco to make required debt payments and provide a return to the investors of Katco. At the end of each lease term, AEP may renew the lease at fair market value subject to Katco's approval, purchase the facility at its original construction cost, or sell the facility, on behalf of Katco, to an independent third party. If the facility is sold and the proceeds from the sale are insufficient to repay Katco, AEP may be required to make a payment to Katco for the difference between the proceeds from the sale and the obligations of Katco, up to 82% of the project's cost. AEP has guaranteed a portion of the obligations of its subsidiaries to Katco during the construction and post-construction periods. As of December 31, 2002, project costs subject to these agreements totaled $360 million, and total costs for the completed facility are expected to be approximately $510 million. For the 30-year extended lease term, the lease rental 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 during the initial term calculated using the indexed LIBOR rate (1.38% at December 31, 2002). The Power Generation Facility collateralizes the debt obligation of Katco. AEP's maximum exposure to loss as a result of its involvement with Katco is 100% during the construction phase and up to 82% once the construction is completed. Maximum loss is deemed to be remote due to the collateralization. It is reasonably possible that AEP will consolidate Katco in the third quarter of 2003, as a result of the issuance of FASB Interpretation No. 46 "Consolidation of Variable Interest Entities" (FIN 46). Upon consolidation, AEP would record the assets, liabilities, depreciation expense, minority interest and debt interest expense. AEP would eliminate operating lease expense. The sublease to DOW would not be affected by this consolidation. The lease payments and the guarantee of construction commitments are included in the Other Commercial Commitments table below. Minority Interest in Finance Subsidiary - --------------------------------------- In August 2001, AEP formed AEP Energy Services Gas Holding Co. II, LLC (SubOne) and Caddis Partners, LLC (Caddis). SubOne is a wholly owned consolidated subsidiary of AEP that was capitalized with the assets of Houston Pipe Line Company, Louisiana Interstate Gas Company (AEP subsidiaries) and $321.4 million of AEP Energy Services Gas Holding Company (AEP Gas Holding is an AEP subsidiary and parent of SubOne) preferred stock, that is convertible into AEP common stock at market price on a dollar-for-dollar basis. Caddis was capitalized with $2 million cash and a subscription agreement that represents an unconditional obligation to fund $83 million from SubOne and $750 million from Steelhead Investors LLC ("Steelhead" - non-controlling preferred member interest). As managing member, SubOne consolidates Caddis. Steelhead is an unconsolidated special purpose entity and has a capital structure of $750 million of which 3% is equity from investors with no relationship to AEP or any of its subsidiaries and 97% is debt from a syndicate of banks. The use of Steelhead allows AEP to limit its risk associated with Houston Pipe Line Company and Louisiana Intrastate Gas Company. Under the provisions of the Caddis formation agreements, Steelhead receives a quarterly preferred return equal to an adjusted floating reference rate (4.784% and 4.413% for the quarters ended December 31, 2002 and 2001, respectively). Caddis has the right to redeem Steelhead's interest at any time. The $750 million invested in Caddis by Steelhead was loaned to SubOne. This intercompany loan to SubOne is due August 2006, and is supported by the natural gas pipeline assets of SubOne, a cash reserve fund of SubOne and SubOne's $321.4 million of preferred stock in AEP Gas Holding. The preferred stock is convertible into AEP common stock upon the occurrence of certain events including AEP's stock price closing below $18.75 for ten consecutive trading days. AEP can elect not to have the transaction supported by such preferred stock if SubOne were to reduce its loan with Caddis by $225 million. The credit agreement between Caddis and SubOne contains covenants that restrict certain incremental liens and indebtedness, asset sales, investments, acquisitions, and distributions. The credit agreement also contains covenants that impose minimum financial ratios. Non-performance of these covenants may result in an event of default under the credit agreement. Through December 31, 2002, we have complied with the covenants contained in the credit agreement. In addition, a default under any other agreement or instrument relating to AEP and certain subsidiaries' debt outstanding in excess of $50 million is an event of default under the credit agreement. The initial period of Steelhead's investment in Caddis is through August 2006. At the end of the initial period, Caddis will either reset Steelhead's return rate, re-market Steelhead's interests to new investors, redeem Steelhead's interests, in whole or in part including accrued return, or liquidate Caddis in accordance with the provisions of applicable agreements. Steelhead has certain rights as a preferred member in 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 AEP Gas Holding preferred stock into AEP common stock. If Steelhead exercised its rights to force Caddis to liquidate under these conditions, then AEP would evaluate whether to refinance at that time or relinquish the assets that support the intercompany loan to Caddis. Liquidation of Caddis could negatively impact AEP's liquidity. Caddis and SubOne 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 SubOne are consolidated with AEP for financial reporting purposes. Steelhead's investment in Caddis and payments made to Steelhead from Caddis are currently reported on AEP's income statement and balance sheet as Minority Interest in Finance Subsidiary. AEP's maximum exposure to loss as a result of its involvement with Steelhead is $321.4 million of preferred stock, $83 million under the subscription agreement to Caddis for any losses incurred by Caddis and the cash reserve fund balance of $34 million (as of December 31, 2002) due Caddis for default under the intercompany loan agreement. AEP can reduce its maximum exposure related to the preferred stock by a reduction of $225 million of the intercompany loan. As of December 31, 2002, management is continuing to review the application of FIN 46 as it relates to the Steelhead transaction. AEP Credit - ---------- AEP Credit entered into a sale of receivables agreement with a group of banks and commercial paper conduits. Under the sale of receivables agreement, which expires May 28, 2003, AEP Credit sells an interest in the receivables it acquires 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 and allowing AEP Credit to repay any debt obligations. 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. This off-balance sheet transaction was entered into to allow AEP Credit to repay its outstanding debt obligations, continue to purchase the AEP operating companies' receivables, and accelerate its cash collections. At December 31, 2002, the sale of receivables agreement provided the banks and commercial paper conduits would purchase a maximum of $600 million of receivables from AEP Credit, of which $454 million was outstanding. As collections from receivables sold occur and are remitted, the outstanding balance for sold receivables is reduced and as new receivables are sold, the outstanding balance of sold receivables increases. All of the receivables sold represented affiliate receivables. The commitment's new term under the sale of receivables agreement will remain at $600 million until May 28, 2003. 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 receivables less an allowance for anticipated uncollectible accounts. See Note 23 "Lines of Credit and Sale of Receivables" for further disclosure. Gavin Plant's flue gas desulfurization system (Gavin Scrubber) - ------------------------------------------------------------- OPCo has entered into an agreement with JMG Funding LLP (JMG) an unrelated unconsolidated special purpose entity. JMG has a capital structure of which 3% is equity from investors with no relationship to AEP or any of its subsidiaries and 97% is debt from pollution control bonds and other bonds. JMG owns the Gavin Scrubber and leases it to OPCo. The lease is accounted for as an operating lease with the payment obligations included in the lease footnote. Payments under the operating lease are based on JMG's cost of financing (both debt and equity) and include an amortization component plus the cost of administration. Neither OPCo nor AEP has an ownership interest in JMG and does not guarantee JMG's debt. At any time during the lease, OPCo has the option to purchase the Gavin Scrubber for the greater of its fair market value or adjusted acquisition cost (equal to the unamortized debt and equity of JMG) or sell the Gavin Scrubber. The initial 15-year lease term is non-cancelable. At the end of the initial term, OPCo can renew the lease, purchase the Gavin Scrubber (terms previously mentioned), or sell the Gavin Scrubber. In case of a sale at less than the adjusted acquisition cost, OPCo must pay the difference to JMG. The use of JMG allows OPCo to enter into an operating lease while keeping the tax benefits otherwise associated with a capital lease. As of December 31, 2002, unless the structure of this arrangement is changed, it is reasonably possible that AEP and OPCo will consolidate JMG in the third quarter of 2003 as a result of the issuance of FIN 46. Upon consolidation, AEP and OPCo would record the assets, liabilities, depreciation expense, minority interest and debt interest expense of JMG. AEP and OPCo would eliminate operating lease expense. AEP's and OPCo's maximum exposure to loss as a result of their involvement with JMG is approximately $560 million of outstanding debt and equity of JMG as of December 31, 2002. Rockport Plant Unit 2 - --------------------- AEGCo and I&M entered into a sale and leaseback transaction in 1989 with Wilmington Trust Company (Owner Trustee) an unrelated unconsolidated trustee for Rockport Plant Unit 2 (the plant). Owner Trustee was capitalized with equity from six owner participants with no relationship to AEP or any of its subsidiaries and debt from a syndicate of banks and securities in a private placement to certain institutional investors. The gain from the sale was deferred and is being amortized over the term of the lease, which expires in 2022. The Owner Trustee owns the plant and leases it to AEGCo and I&M. The lease is accounted for as an operating lease with the payment obligations included in the lease footnote. The lease term is for 33 years with potential renewal options. At the end of the lease term, AEGCo and I&M have the option to renew the lease or the Owner Trustee can sell the plant. AEGCo, I&M nor AEP has ownership interest in the Owner Trustee and do not guarantee its debt. Summary Obligation Information The contractual obligations of AEP and its subsidiaries include amounts reported on the Consolidated Balance Sheets and other obligations disclosed in the footnotes. The following table summarizes AEP's contractual cash obligations at December 31, 2002:
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 $1,633 $1,817 $2,316 $4,354 $10,120 Short-term Debt 3,164 - - - 3,164 Equity Unit Senior Notes - - 376 - 376 Trust Preferred Securities - - - 321 321 Minority Interest In Finance Subsidiary (a) - - 759 - 759 Preferred Stock Subject to Mandatory Redemption - - - 84 84 Capital Lease Obligations 70 90 50 18 228 Unconditional Purchase Obligations (b) 1,405 1,810 989 1,513 5,717 Noncancellable Operating Leases 305 523 479 2,462 3,769 ------ ------ ------ ------ ------- Total Contractual Cash Obligations $6,577 $4,240 $4,969 $8,752 $24,538 ====== ====== ====== ====== =======
(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. 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 K for the timing of debt payment obligations and the lease footnote (Note 22) in section L for the timing of rent payments. The special purpose entities (SPE), described under "Off-Balance Sheet and Minority Interest Arrangements" above, 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 Scrubber, the permanent financing of HPL, and the sale of accounts receivable all use SPEs. Neither AEP nor any AEP related parties have an ownership interest in the SPE. AEP does not guarantee the debt of these entities. These SPEs are not consolidated in AEP's or the subsidiaries' financial statements in accordance with GAAP. As a result, neither the assets nor the debt of the SPE are included on AEP's Consolidated Balance Sheets. The future cash obligations payable to the SPEs are included in the above table. In addition to the amounts disclosed in the contractual cash obligations table above, AEP and its 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, 2002 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 (a) $ 125 $ 1 $ - $ 40 $ 166 Guarantees of the Performance of Ooutside Parties (b) 13 17 325 137 492 Guarantess of Our Performance 1,159 2 82 9 1,252 Construction of Generating and Transmission Facilities for Third Parties (c) 671 83 47 67 868 Other Commercial Commitments (d) 14 53 11 - 78 ------ ---- ---- ---- ------ Total Commercial Commitments $1,982 $156 $465 $253 $2,856 ====== ==== ==== ==== ======
(a) AEP has standby letters of credit to third parties. These letters of credit cover gas and electricity trading contracts, various construction contracts and credit enhancement for issued bonds. All of these letters of credit were issued at a subsidiary level of AEP in the subsidiaries' ordinary course of business. The maximum future payments of these letters of credit are $166 million with maturities ranging from January 2003 to December 2007. There is no liability recorded for these letters of credit in accordance with FIN 45. Since AEP is the parent to all these subsidiaries, it holds all assets of the subsidiary as collateral. There is no recourse to third parties in the event these letters of credit are drawn. (b) These amounts are the balances drawn, not the maximum guarantee disclosed in Note 10. (c) As construction agent for third party owners of power plants and transmission facilities, AEP has committed by contract terms to complete construction by dates specified in the contracts. Should AEP 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. (d) Represents estimated future payments for power to be generated at facilities under construction. With the exceptions of SWEPCo's guarantee of an unaffiliated mine operator's obligations (payable upon their default) of $148 million at December 31, 2002, and OPCo's obligations under a power purchase agreement of $14 million each year in 2003 through 2005, the obligations in the above table are commitments of AEP and its non-registrant subsidiaries. OPCo has entered into a 30-year power purchase agreement for electricity pro-duced by an unaffiliated entity's three-unit natural gas fired plant. The plant was completed in 2002 and the agreement will terminate in 2032. Under the terms of the agreement, OPCo has the option to run the plant until December 31, 2005 taking 100% of the power generated and making monthly capacity payments. The capacity payments are fixed through December 2005 at $1.2 million per month. 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 are included in the Other Commercial Commitments table shown above. Expenditures for domestic electric utility construction are estimated to be $4 billion for the next three years. Approximately 90% of those construction expenditures are expected to be financed by internally generated funds. Construction expenditures for certain registrant subsidiaries for the next three years are: Construction Projected Expenditures Construction Financed with Expenditures Internal Funds ------------ -------------- (in millions) APCo $1,005 70% I&M 601 90 OPCo 733 100 SWEPCo 351 100 TCC 419 100 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. Certificates have been issued by both the WVPSC and the Virginia SCC authorizing construction and operation of the line. On December 31, 2002, the United States Forest Service issued a final environmental impact statement and record of decision to allow the use of federal lands in the Jefferson National Forest for construction of a portion of the line. APCo expects additional state and federal permits to be issued in the first half of 2003. Through December 31, 2002, APCo has invested approximately $51 million in this effort. The line is estimated to cost $287 million including amounts spent to date with completion in 2006. If the required permits are not obtained and the line is not constructed, the $51 million investment would be written off adversely affecting future results of operations and cash flows. Pension Plans - ------------- AEP maintains qualified defined benefit pension plans (Qualified Plans), which cover substantially all non-union and certain union associates, and unfunded excess plans to provide benefits in excess of amounts permitted to be paid under the provisions of the tax law to participants in the Qualified Plans. Additionally, AEP has entered into individual retirement agreements with certain current and retired executives that provide additional retirement benefits. AEP's pension income for all pension plans approximated $69 million and $44 million for the years ended December 31, 2001 and December 31, 2002, respectively, and is calculated based upon a number of actuarial assumptions, including an expected long-term rate of return on the Qualified Plans' assets of 9%. In developing the expected long-term rate of return assumption, AEP evaluated input from actuaries and investment consultants, including their reviews of asset class return expectations as well as long-term inflation assumptions. Projected returns by such actuaries and consultants are based on broad equity and bond indices. AEP also considered historical returns of the investment markets as well as AEP's 10-year average return (for the period ended 2002) of 8.8%. AEP anticipates that the investment managers will continue to generate long-term returns of at least 9.0%. The expected long-term rate of return on the Qualified Plans' assets is based on an asset allocation assumption of 70% with equity managers, with an expected long-term rate of return of 10.5%, and 28% with fixed income managers, with an expected long-term rate of return of 6%, and 2% in cash and short term investments with an expected rate of return of 3%. Because of market fluctuation, the actual asset allocation as of December 31, 2002 was 67% with equity managers and 32% with fixed income managers and 1% in cash. AEP believes, however, that the long-term asset allocation on average will approximate 70% with equity managers, 28% with fixed income managers and the remaining 2% in cash. AEP regularly reviews the actual asset allocation and periodically rebalances the investments to our targeted allocation when considered appropriate. AEP continues to believe that 9.0% is a reasonable long-term rate of return on the Qualified Plans' assets, despite the recent market downturn in which the Qualified Plans' assets had a loss of 11.2% for the twelve months ended December 31, 2002. AEP will continue to evaluate the actuarial assumptions, including the expected rate of return, at least annually, and will adjust as necessary. AEP bases its determination of pension expense or income on a market-related valuation of assets which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the market-related value of assets. Since the market-related value of assets recognizes gains or losses over a five-year period, the future value of assets will be impacted as previously deferred gains or losses are recorded. As of December 31, 2002 AEP had cumulative losses of approximately $879 million which remain to be recognized in the calculation of the market-related value of assets. These unrecognized net actuarial losses result in increases in the future pension costs depending on several factors, including whether such losses at each measurement date exceed the corridor in accordance with SFAS No. 87, "Employers' Accounting for Pensions." The discount rate that AEP utilizes for determining future pension obligations is based on a review of long-term bonds that receive one of the two highest ratings given by a recognized rating agency. The discount rate determined on this basis has decreased from 7.25% at December 31, 2001 to 6.75% at December 31, 2002. Due to the effect of the unrecognized actuarial losses and based on an expected rate of return on the Qualified Plans' assets of 9.0%, a discount rate of 6.75% and various other assumptions, AEP estimates that the pension expense for all pension plans will approximate $2 million, $46 million and $97 million in 2003, 2004 and 2005, respectively. Future actual pension expense will depend on future investment performance, changes in future discount rates and various other factors related to the populations participating in the pension plans. Lowering the expected long-term rate of return on the Qualified Plans' assets by ..5% (from 9.0% to 8.5%) would have reduced pension income for 2002 by approximately $19 million. Lowering the discount rate by 0.5% would have reduced pension income for 2002 by approximately $8 million. The value of the Qualified Plans' assets has decreased from $3.438 billion at December 31, 2001 to $2.795 billion at December 31, 2002. The Qualified Plans paid out $272 million in benefits to plan participants during 2002 (nonqualified plans paid out $6 million in benefits). The investment returns and declining discount rates have changed the status of the Qualified Plans from overfunded (plan assets in excess of projected benefit obligations) by $146 million at December 31, 2001 to an underfunded position (plan assets are less than projected benefit obligations) of $788 million at December 31, 2002. Due to the Qualified Plans currently being underfunded, AEP recorded a charge to Other Comprehensive Income (OCI) of $585 million, and a Deferred Income Tax Asset of $315 million, offset by a Minimum Pension Liability of $662 million and a reduction to prepaid costs and intangible assets of $238 million. The charge to OCI does not affect earnings or cash flow. AEP is in full compliance with all regulations governing such plans including all Employee Retirement Income Security Act of 1974 laws. Because of the recent reductions in the funded status of the Qualified Plans, AEP expects to make cash contributions to the Qualified Plans of approximately $66 million in 2003 increasing to approximately $108 million per year by 2005. Critical Accounting Policies In the ordinary course of business, AEP and its registrant subsidiaries have made a number of estimates and assumptions relating to the reporting of results of operations and financial condition in the preparation of their financial statements in conformity with accounting principles generally accepted in the United States of America. Actual results could differ significantly from those estimates under different assumptions and conditions. They believe that the following discussion addresses the most critical accounting policies, which are those that are most important to the portrayal of the financial condition and results and require management's most difficult, subjective and complex judgments, often as a result of the need to make estimates about the effect of matters that are inherently uncertain. Revenue Recognition - ------------------- Regulatory Accounting - The consolidated financial statements of AEP and the financial statements of electric operating subsidiary companies with cost-based rate-regulated operations (I&M, KPCo, PSO, and a portion of APCo, OPCo, CSPCo, TCC, TNC and SWEPCo) 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 to be recovered in the future) and regulatory liabilities (deferred 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 and by matching income with its passage to customers through regulated revenues in the same accounting period. Regulatory liabilities are also recorded to provide for refunds to customers that have not yet been made. When regulatory assets are probable of recovery through regulated rates, they record them as assets on the balance sheet. They test for probability of recovery whenever new events occur, for example, issuance of a regulatory commission order or passage of new legislation. If they determine that recovery of a regulatory asset is no longer probable, they write-off that regulatory asset as a charge against earnings. 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 - Revenues are recognized on the accrual or settlement basis for normal retail and wholesale electricity supply sales and electricity transmission and distribution delivery services. The revenues are recognized in our statement of operations when the energy is delivered to the customer and include unbilled as well as billed amounts. In general, expenses are recorded when purchased electricity is received and when expenses are incurred. Domestic Gas Pipeline and Storage Activities - Revenues are recognized from domestic gas pipeline and storage services when gas is delivered to contractual meter points or when services are provided. Transportation and storage revenues also include the accrual of earned, but unbilled and/or not yet metered gas. Substantially all of the forward gas purchase and sale contracts, excluding wellhead purchases of natural gas, swaps and options for the domestic pipeline operations, qualify as derivative financial instruments as defined by SFAS 133. Accordingly, net gains and losses resulting from revaluation of these contracts to fair value during the period are recognized currently in the results of operations, appropriately discounted and net of applicable credit and liquidity reserves. Energy Marketing and Trading Activities -In 2000, 2001 and throughout the majority of 2002, AEP engaged in broad non-regulated wholesale electricity, natural gas and other commodity marketing and trading transactions (trading activities). AEP's trading activities involved the purchase and sale of energy under forward contracts at fixed and variable prices and the buying and selling of financial energy contracts which include exchange traded futures and options and over-the-counter options and swaps. We used the mark-to-market method of accounting for trading activities as required by EITF Issue No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" (EITF 98-10). Under the mark-to-market method of accounting, gains and losses from settlements of forward trading contracts are recorded net in revenues. For energy contracts not yet settled, whether physical or financial, changes in fair value are recorded net as revenues. Such fair value changes are referred to as unrealized gains and losses from mark-to-market valuations. When positions are settled and gains and losses are realized, the previously recorded unrealized gains and losses from mark-to-market valuations are reversed. Unrealized mark-to-market gains and losses are included in the Balance Sheets as "Energy Trading and Derivative Contracts." In October 2002, management announced plans to focus on wholesale markets where we own assets. A portion of the revenues and costs associated with AEP's wholesale electricity trading activities is allocated to TCC, SWEPCo, PSO and TNC and to members of the AEP Power Pool (APCo, CSPCo, I&M, KPCo and OPCo); however, TCC, SWEPCo, PSO and TNC are only allocated a portion of the forward transactions. AEP's cost-based rate-regulated electric public utility companies (I&M, KPCo, PSO, and a portion of TNC and SWEPCo) defer, as regulatory liabilities (unrealized gains) or regulatory assets (unrealized losses), changes in the fair value of physical forward sale and purchase contracts in AEP's traditional marketing area. AEP's traditional marketing area is up to two transmission systems from the AEP service territory. For contracts which are outside of AEP's traditional marketing area, the change in fair value is included in nonoperating income on a net basis. The majority of trading activities represent physical forward contracts that are typically settled by entering into offsetting contracts. An example of our energy trading activities is when, in January, we enter into a forward sales contract to deliver energy 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 a gain or loss in cash and reverse to revenues the previously recorded cumulative 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 for a sales contract and the realized cost for a purchase contract are included on a net basis in revenues with the prior change in unrealized fair value reversed out of revenues. For I&M, KPCo, PSO and a portion of TNC and SWEPCo, 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 for sales and the cost of purchased energy are included in revenues on a net basis. 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 contracts with delivery points outside of AEP's traditional marketing area only the difference between the accumulated unrealized net gains or losses recorded in prior periods and the cash proceeds is recognized in the income statement as nonoperating income. 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. For APCo, CSPCo and OPCo, depending on whether the delivery point for the electricity is in AEP's traditional marketing area or not determines where the contract is reported in the income statement. Physical forward trading sale and purchase contracts with delivery points in AEP's traditional marketing area are included in revenues on a net basis. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts in AEP's traditional marketing area are also included in revenues on a net basis. Physical forward sale and purchase contracts for delivery outside of AEP's traditional marketing area are included in nonoperating income 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 for AEP, APCo, CSPCo, OPCo, TCC, and a portion of TNC and SWEPCo, assume that later in January or sometime in February through July we enter into an offsetting forward contract to buy energy 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. Mark-to-market accounting for these contracts from this point forward will have no further impact on operating results but has an offsetting and equal effect on trading contract assets and liabilities. 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 MTM accounting. For AEP, the trading of energy 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 cumulative unrealized net gain or loss. APCo, CSPCo, I&M, KPCo and OPCo also have financial transactions, but record the unrealized gains and losses, as well as the net proceeds upon settlement, in nonoperating income. The fair values of open short-term trading contracts are based on exchange prices and broker quotes. We mark-to-market open long-term trading contracts based primarily on valuation models that 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 the appropriate valuation adjustments for items such as discounting, liquidity and credit quality. Credit risk is the risk that the counterparty to the contract will fail to perform or fail to pay amounts due to 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. Unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a contract's term and at the time contracts settle. Therefore, there could be significant adverse or favorable effects on future results of operations and cash flows if market prices are not consistent with AEP's approach at estimating current market consensus for forward prices in the current period. This is particularly true for long-term contracts. AEP applies MTM accounting to 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. Volatility in energy commodities markets affects the fair values of all of our open trading and derivative contracts exposing us to market risk and causing our results of operations to be subject to volatility. See Note 17, "Risk Management, Financial Instruments and Derivatives" for a discussion of the policies and procedures used to manage our exposure to market and other risks from trading activities. Given the previously discussed reduction in AEP's trading activities, the impact of mark-to-market accounting on our financial statements is expected to decline in future periods. Long-Lived Assets - ----------------- Long-lived assets, including fixed assets and intangibles, are evaluated periodically for impairment whenever events or changes in circumstances indicate that the carrying amount of any such assets may not be recoverable. If the sum of the undiscounted cash flows is less than the carrying value, we recognize an impairment loss, measured as the amount by which the carrying value exceeds the fair value of the asset. The estimate of cash flow is based upon, among other things, certain assumptions about expected future operating performance. Our estimates of undiscounted cash flow may differ from actual cash flow due to, among other things, technological changes, economic conditions, changes to its business model or changes in its operating performance. Pension Benefits - ---------------- AEP sponsors pension and other retirement plans in various forms covering substantially all employees who meet eligibility requirements. Several statistical and other factors which attempt to anticipate future events are used in calculating the expense and liability related to the plans. These factors include assumptions about the discount rate, expected return on plan assets and rate of future compensation increases as determined by management, within certain guidelines. In addition, AEP's actuarial consultants also use subjective factors such as withdrawal and mortality rates to estimate these factors. The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates or longer or shorter life spans of participants. These differences may result in a significant impact to the amount of pension expense recorded. New Accounting Pronouncements - ----------------------------- See Note 1 to the consolidated financial statements for a discussion of significant accounting policies and new accounting pronouncements. Market Risks As a major power producer and marketer of wholesale electricity and natural gas, we have certain market risks inherent in our business activities. These risks include commodity 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 have been 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 Executive Committee and administered by a Chief Risk Officer. The Risk Executive 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 in the trading portfolio. 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, 2002 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, ----------- 2002 2001 ---- ---- High Average Low High Average Low ---- ------- --- ---- ------- --- (in millions) AEP $24 $12 $4 $28 $14 $5 APCo 4 1 - 4 1 - CSPCo 3 1 - 2 1 - I&M 3 1 - 3 1 - KPCo 1 - - 1 - - OPCo 4 1 - 3 1 - PSO - - - 2 1 - SWEPCo - - - 3 1 - TCC - - - 3 1 - TNC - - - 1 1 - After the October announcement of our strategy to reduce trading activity, the related VaRs were substantially reduced. The average AEP trading VaR for the fourth quarter 2002 was $7 million as compared to $13 million for fourth quarter 2001. In 2003 we will continue to adjust our VaR limit structure commensurate with our anticipated level of trading activity. 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 $527 million at December 31, 2002 and $673 million at December 31, 2001. 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, ----------- 2002 2001 ---- ---- (in millions) Company AEGCo $ 3 $5 APCo 87 100 CSPCo 33 60 I&M 85 86 KPCo 30 16 OPCo 34 59 PSO 70 17 SWEPCo 70 36 TCC 65 80 TNC 5 20 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 TCC and TNC) or frozen by settlement agreements in Michigan and West Virginia or capped in Indiana. 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 other commodities and as a result we are 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 be within the limits unless specifically approved by the Risk Executive 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 certain power trading 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. Credit Risk 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 counterparties depending upon credit quality 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 our financial condition at December 31, 2002. At December 31, 2002 approximately 7% of our exposure was below investment grade as expressed in terms of net MTM assets. Net MTM assets represents the aggregate difference between the forward market price for the remaining term of the contract and the contractual price per counterparty. As of December 31, 2002, the following table approximates counterparty credit quality and exposure for AEP based on netting across AEP entities, commodities and instruments: Futures, Forward and Counterparty Swap Credit Quality: Contracts Options Total - -------------- ------- ------- ------ (in millions) AAA/Exchanges $ 26 $ 2 $ 28 AA 307 33 340 A 448 26 474 BBB 700 101 801 Below Investment Grade 107 11 118 --------- ----- -------- Total $ 1,588 $173 $1,761 ======= ==== ====== 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, 2002 and 2001 were $109 million and $55 million, respectively. These margin accounts are restricted and therefore are not included in Cash and Cash Equivalents on the Balance Sheets. 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, in accordance with generally accepted accounting principles and include the net change in mark-to-market amounts on a net discounted basis in revenues. The marking-to-market of open trading contracts contributed an unrealized $180 million to revenues in 2002. The mark-to-market 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 internally developed valuation models. The gross value is present valued and reduced by appropriate valuation adjustments for counterparty credit risks and liquidity risk to arrive at fair value. 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 liquid portion of these curves are validated on a regular basis by the middle-office through the market data. Illiquid portions of the curves are validated through a review of the underlying market assumptions and variables for consistency and reasonableness. The end of the month liquidity reserve is based on the difference in price between the price curve and the bid price if we have a long position and the price curve and the ask price if we have a short position. This provides for a more accurate valuation of energy contracts. 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 prices, at the time of settlement, do not correlate with our interally developed price models. The effect on the Statements of Operations of marking to market open electricity trading contracts in AEP's regulated jurisdictions, specifically I&M, KPCo, PSO and a portion of SWEPCO, is deferred as regulatory assets (losses) or liabilities (gains) 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, ----------- 2002 2001 2000 ---- ---- ---- (in millions) Revenues (including Mark- To- Market Adjustment) $14,555 $12,767 $11,113 Fuel and Purchased Energy Expense 6,307 4,944 3,880 ------- ------- ------- Net Revenues $ 8,248 $ 7,823 $ 7,233 ======= ======= ======= Mark-to-Market Revenues $180 $207 $187 === ==== ==== Percentage of Net Revenues Represented by Mark-to-Market On Open Trading Positions 2% 3% 3% == == == The following tables analyze the changes in fair values of trading assets and liabilities. The first table "Net Fair Value of Mark-to-Market Energy Trading and Derivative Contracts" shows how the net fair value of energy trading contracts was derived from the amounts included in the Consolidated Balance Sheets line item "Energy Trading and Derivative Contracts." The next table "Mark-to-Market Energy Trading and Derivative 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 and related derivatives at December 31, 2001 of $448 million to December 31, 2002 of $250 million. Contracts realized/settled during the period include both sales and purchase contracts. The third table "Mark-to-Market Energy Trading and Derivative 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 Mark-to-Market Energy Trading and Derivative Contracts - AEP December 31 ---------------------- 2002 2001 ---- ---- (in millions) Energy Trading and Derivative Contracts: Current Asset $1,046 $ 2,125 Long-term Asset 824 795 Current Liability (1,147) (1,877) Long-term Liability (484) (603) ------ ------- Net Fair Value of Energy Trading and Derivative Contracts 239 440 Non-trading related derivative liabilities 11* - Assets held for sale (CitiPower) - 8 ------ ------- Net Fair Value of Energy Trading and Derivative Contracts $ 250 $ 448 ====== ======= * Excludes $6 million Loss recorded in an equity investment.
The above net fair value of energy trading and derivative contracts includes $180 million at December 31, 2002, in unrealized mark-to-market gains that are recognized in the Consolidated Statements of Operations at December 31, 2002.
Mark-to-Market Energy Trading and Derivative Contracts - AEP Total ----- (in millions) Net Fair Value of Energy Trading and Derivative Contracts at December 31, 2001 $ 448 (Gain) Loss from Contracts Realized/Settled During the Period (182) (a) Fair Value of New Open Contracts When Entered Into During the Period 68 (b) Net Option Premiums Paid/(Received) (130) (c) Change in fair value due to Methodology Changes 1 (d) Change in Market Value of Energy Trading Contracts Allocated to Regulated Jurisdictions (2) (e) Changes in Market Value of Contracts 47 (f) ----- Net Fair Value of Energy Trading and Derivative Contracts at December 31, 2002 $ 250 =====
Mark-to-Market Energy Trading and Derivative Contracts - Registrant Subsidiaries APCo CSPCo I&M ---- ----- --- Net Fair Value of Energy Trading Contracts at December 31, 2001 $ 75,701 $48,449 $ 61,345 (Gain) Loss from Contracts Realized/Settled During the Period (a) (19,143) (13,812) (9,611) Change in Fair Value Due To Methodology Changes (d) 350 228 247 Changes in Fair Market Value of Energy Trading Contracts Allocated To Regulated Jurisdictions (e) - - 1,502 Fair Value Of New Open Contracts When Entered Into during The Period (b) 10,865 7,039 2,774 Net Option Premium Payments (c) (1,797) (1,208) (1,292) Changes In Market Value Of Contracts (f) 30,876 24,421 15,896 -------- ------- -------- Net Fair Value of Energy Trading Contracts at December 31, 2002 (g) $ 96,852 $65,117 $ 70,861 ======== ======= ========
KPCo OPCo PSO ---- ---- --- Net Fair Value of Energy Trading Contracts at December 31, 2001 $12,729 $ 65,446 $ 2,434 (Gain) Loss From Contracts Realized/Settled During Period (a) 1,153 (18,337) 6,476 Change in Fair Value Due To Methodology Changes (d) 90 311 32 Changes In Fair Market Value Of Energy Trading Contracts Allocated To Regulated Jurisdiction (e) 5,136 - (5,397) Fair Value of New Open Contracts When Entered Into During Period (b) 1,013 18,443 - Net Option Premium Payments (c) (464) (1,603) - Changes In Market Value Of Contracts (f) 5,341 29,846 - ------- -------- ------- Net Fair Value of Energy Trading Contracts at December 31, 2002 (g) $24,998 $ 94,106 $ 3,545 ======= ======== =======
SWEPCo TCC TNC ------ --- --- Net Fair Value of Energy Trading Contracts at December 31, 2001 $ 2,900 $ 3,857 $ 915 (Gain) Loss From Contracts Realized/Settled During The Period (a) 6,971 7,138 2,413 Change in Fair Value Due To Methodology Changes (d) 36 42 12 Changes In Fair Market Value Of Energy Trading Contracts Allocated To Regulated jurisdiction (e) (2,485) - (336) Fair Value Of New Open Contracts When Entered Into During The Period (b) 428 1,919 1,627 Net Option Premium Payments (c) - - - Changes In Market Value Of Contracts (f) (3,800) (7,542) (2,588) ------- ------- ------- Net Fair Value of Energy Trading Contracts at December 31, 2002 (g) $ 4,050 $ 5,414 $ 2,043 ======= ======= =======
(a) "(Gain) Loss from Contracts Realized/Settled During the Period" include realized gains from energy trading contracts and related derivatives that settled during 2002 that were entered into prior to 2002. (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 2002. 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) Net Option Premiums Paid/(Received)" reflects the net option premiums paid/(received) as they relate to unexercised and unexpired option contracts that were entered into in 2002. (d) The Company changed the discount rate applied to its trading portfolio from BBB+ Utility to LIBOR in the second quarter which increased fair value by $10 million. In addition, the Company changed its methodology in valuing a spread option model so as to more accurately reflect the exercising of power transactions at optimal prices which reduced fair value by $9 million. (e)"Change in Market Value of Energy Trading Contracts Allocated to Regulated Jurisdictions" relates to the net gains of those contracts that are not reflected in the Consolidated Statements of Operations. These net gains are recorded as regulatory liabilities for those subsidiaries that operate in regulated jurisdictions. (f)"Changes 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. (g)"Net Fair Value of Energy Trading Contracts" does not reflect the changes in fair value associated with derivative contracts designated as hedges and therefore will not agree to the net fair value of the Energy Trading and Derivative Contracts line items on the individual registrants' balance sheets.
Mark-to-Market Energy Trading and Derivative Contract Maturities - AEP Fair Value of Contracts at December 31, 2002 -------------------------------------------- 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) $(32) $ 69 $ - $ - $ 37 Prices Provided by Other External Sources (b) 24 189 11 - 224 Prices Based on Models and Other Valuation Methods (c) (84) 13 36 24 (11) ---- ---- --- --- ---- Total $(92) $271 $47 $24 $250 ==== ==== === === ====
Mark-to-Market Energy Trading and Derivative Contract Maturities- Registrant Subsidiaries Fair Value of Contracts at December 31, 2002 -------------------------------------------- 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 Prices Provided by Other External Sources (b) $14,352 $43,307 $ 3,018 $ - $ 60,677 Prices Based on Models and Other Valuation Methods (c) 11,492 9,475 8,183 7,025 36,175 ------- ------- ------- ------ -------- Total $25,844 $52,782 $11,201 $7,025 $ 96,852 ======= ======= ======= ====== ======== CSPCo Prices Provided by Other External Sources (b) $ 9,657 $29,113 $ 2,028 $ - $ 40,798 Prices Based on Models and Other Valuation Methods (c) 7,726 6,370 5,501 4,722 24,319 ------- ------- ------- ------ -------- Total $17,383 $35,483 $ 7,529 $4,722 $ 65,117 ======= ======= ======= ====== ======== KPCo Prices Provided by Other External Sources (b) $ 3,707 $11,176 $ 779 $ - $ 15,662 Prices Based On Models and Other Valuation Methods (c) 2,966 2,442 2,114 1,814 9,336 ------- ------- ------- ------ -------- Total $ 6,673 $13,618 $ 2,893 $1,814 $ 24,998 ======= ======= ======= ====== ======== I&M Prices Provided by Other External Sources (b) $12,105 $30,961 $ 2,171 $ - $ 45,237 Prices Based on Models and Other Valuation Methods (c) 7,913 6,772 5,886 5,053 25,624 ------- ------- ------- ------ -------- Total $20,018 $37,733 $ 8,057 $5,053 $ 70,861 ======= ======= ======= ====== ======== OPCo Prices Provided by Other External Sources (b) $20,775 $38,622 $ 2,691 $ - $ 62,088 Prices Based on Models and Other Valuation Methods (c) 10,003 8,453 7,298 6,264 32,018 ------- ------- ------- ------ -------- Total $30,778 $47,075 $ 9,989 $6,264 $ 94,106 ======= ======= ======= ====== ======== PSO Prices Provided by Other External Sources (b) $ 373 $1,736 $ 125 $ - $ 2,234 Prices Based on Models and Other Valuation Methods (c) 296 390 336 289 1,311 ------- ------ ------- ------- -------- Total $ 669 $2,126 $ 461 $ 289 $ 3,545 ======= ====== ======= ======= ======== SWEPCo Prices Provided by Other External Sources (b) $ 427 $1,983 $ 141 $ - $ 2,551 Prices Based on Models and Other Valuation Methods (c) 338 446 385 330 1,499 ------- ------ ------- ------- -------- Total $ 765 $2,429 $ 526 $ 330 $ 4,050 ======= ====== ======= ======= ======== TCC Prices Provided by Other External Sources (b) $ 1,536 $ 1,605 $ 115 $ - $ 3,256 Prices Based on Models and Other Valuation Methods (c) 1,219 361 311 267 2,158 ------- ------- -------- ------- -------- Total $ 2,755 $ 1,966 $ 426 $ 267 $ 5,414 ======= ======= ======== ======= ======== TNC Prices Provided by Other External Sources (b) $ 201 $1,016 $ 73 $ - $ 1,290 Prices Based on Models and Other Valuation Methods (c) 159 229 197 168 753 ------- ------ -------- ------ -------- Total $ 360 $1,245 $ 270 $ 168 $ 2,043 ======= ====== ======== ====== ========
(a)"Prices Actively Quoted" represents the Company's exchange traded futures positions. (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. 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 17, "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 operating and maintaining utility plant assets. 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 Four of the eleven state retail jurisdictions (Michigan, Ohio, Texas and Virginia) in which AEP's domestic electric utility companies operate have implemented retail restructuring legislation. Three other states (Arkansas, Oklahoma and West Virginia) initially adopted retail restructuring legislation, but have since delayed the implementation of that legislation or repealed the legislation (Arkansas). In general, retail restructuring legislation provides for a transition from cost-based rate 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, CSPCo, OPCo, SWEPCo, TCC and TNC) have discontinued the application of SFAS 71 regulatory accounting for the generation business. AEP has not discontinued its regulatory accounting for its subsidiaries doing business in Michigan (I&M) and Oklahoma (PSO). 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 our state regulatory jurisdictions affected by restructuring legislation is presented in Note 8 of the Notes to Financial Statements. Corporate Separation AEP and its subsidiaries have filed with the FERC and SEC seeking approval to separate their regulated and unregulated operations. The plan for corporate separation allows AEP and its subsidiaries to meet the requirements of Texas and Ohio restructuring legislation. In Texas, TCC and TNC intended to transfer the generation assets from the integrated electric operating companies (CPL and WTU) which operated in ERCOT prior to the effective date of the Texas Restructuring Legislation to unregulated generation companies. In Ohio, CSPCo and OPCo intended to transfer transmission and distribution assets from the integrated companies to two new wires companies leaving CSPCo and OPCo as generating companies. AEP and its subsidiaries proposed amendments to the power pooling agreements to remove the four Ohio and Texas generating companies. Only those operating companies that continue to exist as integrated utilities would have been included in the amended power pooling agreements, which would govern energy exchanges among members and the allocation of their off-system purchases and sales. In connection with corporate seperation, certain new interim power supply agreements have been proposed to provide power to distribution companies who will no longer own generation assets. Several state commissions, wholesale customer groups and other interested parties intervened in the FERC proceeding. Negotiated settlement agreements with the state regulatory commissions and other major intervenors were filed with the FERC in December 2001. In September 2002, the FERC conditionally approved our corporate separation plan as modified by the settlement agreements. Terms in the settlement agreements would be effective upon implementation of corporation separation. In addition, SEC approval of AEP's corporate separation plan is required for its implementation. The Arkansas Commission intervened with the SEC, which has extended the length of time needed for the SEC's review. In order to execute this separation, AEP and its subsidiaries may be required to retire various debt securities and transfer assets between legal entities. With the changes in AEP's business strategy in response to current energy market/business conditions, management is evaluating changes to the corporate separation plans, including determining whether legal corporate separation is appropriate. 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 required the transfer of functional control of the subsidiaries' transmission systems to RTOs. AEP East companies initially participated in the formation of the Alliance RTO. In December 2001, the FERC reversed prior approvals and rejected the Alliance RTO's filing. Subsequently, in May 2002, AEP announced an agreement with the PJM Interconnection to pursue terms for AEP East companies to participate in PJM with final agreements to be negotiated. In July 2002, the FERC conditionally approved AEP's decision for AEP East companies to join PJM subject to certain conditions being met. The performance of these conditions are only partially under AEP's control. In December 2002, AEP East companies in Indiana, Kentucky, Ohio and Virginia filed for state regulatory commission approval of their plans to transfer functional control of their transmission assets to PJM based on statutory or regulatory requirements in those states. Those proceedings are currently pending. In February 2003, the Virginia Legislature enacted legislation that would prohibit the transfer to an RTO, until at least July 2004, which is currently awaiting signature by the Governor of Virginia. AEP West companies are members of ERCOT or the SPP. In May 2002, FERC accepted, conditionally, filings related to a proposed consolidation of the MISO and the SPP. In that order the FERC required the AEP West companies in SPP to file reasons why they should not be required to join MISO. In August 2002, AEP, SWEPCo and TNC notified the FERC of their intent that the transmission assets in SPP would participate in MISO. AEP's SPP companies are also regulated by state public utility commissions, and the Louisiana and Arkansas commissions also filed responses to the FERC's RTO order indicating that additional analysis was required. Regulatory activities concerning various RTO issues are ongoing in Arkansas and Louisiana. 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 and its subsidiaries' transmission operations or future results of operations and cash flows. FERC Proposed Standard Market Design and Security Standards In 2002, the FERC issued its Standard Market Design (SMD) notice of proposed rulemaking seeking to standardize the structure and operation of wholesale electricity markets across the country. The FERC published for comment its proposed security standards as part of the SMD. These standards are intended to ensure all market participants have a basic security program that effectively protects the electric grid and related market activities. Because the rule is not yet finalized, management cannot predict the effect of the final rule on AEP or its subsidiaries' operations and financial results. See Note 9 for a complete discussion of these proposals. Litigation AEP and its subsidiaries are involved in various litigation. The details of significant litigation contingencies are disclosed in Note 9 and summarized below. Enron Bankruptcy - Affecting AEP, APCo, CSPCo, I&M, KPCo and OPCo In 2002, certain subsidiaries of AEP filed claims in the bankruptcy proceeding of the Enron Corp. and its subsidiaries which are pending in the U.S. Bankruptcy Court for the Southern District of New York. At the date of Enron's bankruptcy, AEP and its subsidiaries had open trading contracts and trading accounts receivables and payables with Enron and various HPL related contingencies and indemnities including issues related to the underground Bammel gas storage facility and the cushion gas (or pad gas) required for its normal operation. In 2001, AEP expensed $47 million ($31 million net of tax) for our estimated loss from the Enron bankruptcy. In 2002 AEP expensed an additional $6 million for a cumulative loss of $53 million ($34 million net of tax). The amounts for certain subsidiary registrants were: Amounts Amounts Net of Registrant Expensed Tax -------- ----- (in millions) APCo $5.3 $3.4 CSPCo 2.7 1.8 I&M 2.8 1.8 KPCo 1.1 0.7 OPCo 3.6 2.3 The additional 2002 expense did not materially change the cumulative expense per registrant subsidiary. The amounts expensed were based on an analysis of contracts where AEP entities and Enron are counterparties. Management believes that we have the right to utilize offsetting receivables and payables and related collateral across various Enron entities by offsetting approximately $110 million of trading payables owed to various Enron entities against trading receivables due to us. Management believes we have legal defenses to any challenge that may be made to the utilization of such offsets. At this time management is unable to predict the ultimate resolution of these issues or their impact on results of operations and cash flows. See Note 9 for further discussion. COLI - Affecting AEP, APCo, CSPCo, I&M, KPCo and OPCo A decision by the 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 a COLI program resulted in a $319 million reduction in AEP's Net Income for 2000. The earnings reductions for affected registrant subsidiaries were as follows: (in millions) APCo $ 82 CSPCo 41 I&M 66 KPCo 8 OPCo 118 AEP has appealed the Court's decision. See Note 18 for further discussion. Shareholders' Litigation - Affecting AEP In 2002, lawsuits alleging securities law violations, a breach of fiduciary duty for failure to establish and maintain adequate internal controls and violations of the Employee Retirement Income Security Act were filed against AEP, certain AEP executives, members of the AEP Board of Directors and certain investment banking firms. These cases are in the initial pleading stage. AEP intends to vigorously defend against these actions. See Note 9 for further discussion. California Lawsuit - Affecting AEP In 2002, the Lieutenant Governor of California filed a lawsuit in California Superior Court against forty energy companies, including AEP, and two publishing companies alleging violations of California law through alleged fraudulent reporting of false natural gas price and volume information with an intent to affect the market price of natural gas and electricity. AEP intends to vigorously defend against this action. See Note 9 for further discussion. FERC Wholesale Fuel Complaints - Affecting AEP and TNC In May 2000 and November 2001, certain TNC wholesale customers filed a complaints with FERC alleging that TNC had overcharged them through the fuel adjustment clause for certain purchased power costs. The final resolution of this matter could have a negative impact on futute results of operations, cash flow and financial condition. See Note 6 for further discussion. Merger Litigation - Affecting AEP and all Subsidiary Registrants In January 2002, a federal court ruled that the SEC did not properly find 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. See Note 9 for further discussion. Arbitration of Williams Claim - Affecting AEP In 2002, AEP filed its demand for arbitration with the American Arbitration Association to initiate formal arbitration proceedings in a dispute with the Williams Companies (Williams). The proceeding results from Williams' repudiation of its obligations to provide physical power deliveries to AEP and Williams' failure to provide the monetary security required for natural gas deliveries. Although management is unable to predict the outcome of this matter, it is not expected to have a material impact on results of operations, cash flows or financial condition. See Note 9 for further discussion. Energy Market Investigations - Affecting AEP During 2002, the FERC, the California attorney general, the PUCT, the SEC, the Department of Justice and the U.S. Commodity Futures Trading Commission (CFTC) initiated investigations into whether any entity, including Enron, manipulated short-term prices in electric energy or natural gas markets, exercised undue influence over wholesale prices or participated in fraudulent trading practices. AEP and its subsidiaries have and will continue to provide information to the FERC, the SEC, state officials and the CFTC as required. See Note 9 for further discussion. FERC Market Power Mitigation - Affecting the AEP System A FERC order on our triennial market based wholesale power rate authorization update required certain mitigation actions that AEP and its subsidiaries would need to take for sales/purchases within their control area and required the posting of information on our website regarding the status of AEP's power system. As a result of a request for rehearing filed by AEP and other market participants, FERC issued an order delaying the effective date of the mitigation plan until after a planned technical conference on market power determination. No such conference has been held and management is unable to predict the timing of any further action by the FERC or its affect on future results of operations and cash flows. Other Litigation - Affecting AEP and all Subsidiary Registrants AEP and its 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 results of operations, cash flows or financial condition. Environmental Concerns and Issues AEP and its subsidiaries will confront several new environmental requirements over the next decade with the potential for substantial control costs and premature retirement of some generating plants. These policies include: stringent controls on sulfur dioxide (S02), nitrogen oxide (NOx) and mercury (Hg) emissions from future regulations or laws, or an adverse decision in the New Source Review litigation; a new Clean Water Act rule to reduce fish killed at once-through cooled power plants; and a possible future requirement to reduce carbon dioxide (CO2) emissions as the world endeavors to stabilize atmospheric concentrations of greenhouse gas emissions and avert global climatic changes. AEP and its subsidiaries' environmental policy require full compliance with all applicable legal requirements. In support of this policy, AEP and its subsidiaries invest in research through groups like the Electric Power Research Institute and directly through demonstration projects for new emission control technologies. AEP and its subsidiaries intend 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 many of their facilities with pollution control technologies. Multi-pollutant control legislation has been introduced in Congress and is supported by the Bush Administration. The legislation would regulate NOx, SO2, Hg and possibly CO2 emissions from electric generating plants. AEP and its subsidiaries are advocates of comprehensive, multi-pollutant legislation so that compliance planning can be coordinated and collateral emission reductions maximized. Optimally, such legislation would establish reasonable emission reduction targets and compliance timetables based on sound science, utilize nationwide cap-and-trade programs for achieving compliance as cost-effectively as possible, protect fuel diversity and preserve the reliability of the nation's electric supply. Management is unable to predict the timing or magnitude of additional pollution control laws or regulations. If additional control technology is required on AEP System facilities and their costs are not recoverable from customers through regulated rates or market prices, those costs could adversely affect future results of operations and cash flows. The following discussions explain 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 AEPSC, 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 special interest groups alleged that AEP System companies modified certain units at coal fired generating plants in violation of the Clean Air Act over a 20 year period. Management believes its maintenance, repair and replacement activities were in conformity with the Clean Air Act and intends to vigorously pursue its defense. Management is unable to estimate the loss or range of loss related to the contingent liability 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. If the AEP System companies do not prevail, any capital and operating costs of additional pollution control equipment or any penalties imposed would adversely affect future results of operations, cash flows and possibly financial condition unless such costs can be recovered. See Note 9 for further discussion. NOx Reductions - Affecting AEP, APCo, I&M, OPCo, SWEPCo and TCC Federal EPA issued a NOx Rule and adopted a revised rule (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. The compliance date for these rules is May 31, 2004. In 2000, the Texas Commission on Environmental Quality (formerly the Texas Natural Resource Conservation Commission) adopted rules requiring significant reductions in NOx emissions from utility sources, including TCC and SWEPCo. The compliance date is May 2003 for TCC and May 2005 for SWEPCo. AEP and its subsidiaries are installing a variety of emission control technologies to reduce NOx emissions to comply with the applicable state and Federal NOx requirements including selective catalytic reduction (SCR) and non-SCR technologies. The AEP System NOx compliance plan is a dynamic plan that is continually reviewed and revised. Current estimates indicate that compliance with the NOx Rule, the Texas Commission on Environmental Quality rule and the Section 126 Rule could result in required capital expenditures in the range of $1.3 billion to $2 billion of which $843 million has been spent through December 31, 2002 for the AEP System. The following table shows the estimated compliance cost ranges and amounts spent by certain of AEP's registrant subsidiaries through December 31, 2002. Estimated Amounts Compliance Costs Spent ---------------- ------- (in millions) Company APCo $445 $234 I&M 42-210 5 OPCo 535-864 387 SWEPCo 40 24 TCC 5 5 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. See Note 9 for further discussion. Superfund and State Remediation - Affecting AEP, APCo, CSPCo, I&M, OPCo, SWEPCo and TCC 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. AEP and its subsidiaries 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 2002 subsidiaries of AEP are 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 six additional sites for which APCo, CSPCo, I&M, KPCo, OPCo and SWEPCo have received information requests which could lead to PRP designation. HPL, OPCo, SWEPCo and TCC have also been named potentially liable at six sites under state law. 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 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 superfund liability has been interpreted by the courts as 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 AEP subsidiaries 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 CO2, 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 in 2003. 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 that 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. AEP has for many years been a leader in pursuing voluntary actions to control greenhouse gas emissions. AEP recently expanded its commitment in this area by joining the Chicago Climate Exchange, a pilot greenhouse gas emission reduction and trading program, under which AEP and its subsidiaries are obligated to reduce or offset 18 million tons of CO2 emissions during 2003-2006. The acquisition of 4,000 MW of coal-fired generation in the United Kingdom in December 2001 exposes these assets to potential CO2 emission control obligations since the U.K has become a party to the Kyoto Protocol. Control of Mercury Emissions In December 2000, Federal EPA issued a regulatory determination listing the electric generating sector as a source category under the Clean Air Act for development of maximum achievable control technology standards to control emissions of hazardous air pollutants, including Hg. Federal EPA is expected to issue proposed regulations in 2003 and develop a final rule in 2004. Management cannot predict the outcome of these regulatory proceedings, or the costs to comply with any new standards adopted by Federal EPA. The costs associated with compliance could be material. However, 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. Costs for Spent Nuclear Fuel and Decommissioning - Affecting AEP, I&M and TCC I&M, as the owner of the Cook Plant, and TCC, 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 I&M and TCC participate in the DOE's SNF disposal program which is described in Note 9 of the Notes to Financial Statements. Since 1983 I&M has collected $303 million from customers for the disposal of nuclear fuel consumed at the Cook Plant. $117 million of these funds have been deposited in external trust funds to provide for the future disposal of SNF and $186 million has been remitted to the DOE. TCC has collected and remitted to the DOE, $53 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 TCC 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. On January 17, 2003, the U.S. Court of Federal Claims ruled in favor of I&M on the issue of liability. The case continues on the issue of damages owed to I&M by the DOE. 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 of SNF 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 (now Exelon Generation Company, LLC). The settlement adjusted the fees Exelon was required to pay to DOE for disposal of SNF. The fee adjustment allowed Exelon to skip payments to the DOE to make up for Exelon's damages from DOE's breach of its contract obligation to dispose of SNF from commercial nuclear power plants. The companies believe the settlement was unlawful as it would force other utilities (rather than DOE) to compensate Exelon for the damages it had incurred from DOE's breach of contract. In September 2002, the U.S. Court of Appeals for the Eleventh Circuit found that DOE acted improperly by adopting the fee adjustment provision of this settlement, that the fee adjustment provisions of the settlement harmed other utilities who pay into the fund and violated the federal nuclear waste management laws and that the fee adjustment provisions of the settlement were null and void. 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, 2002, the total decom-missioning trust fund balance for Cook Plant was $618 million which includes earnings on the trust investments. Studies completed in 1999 for STP estimate TCC'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, 2002, the total decommission-ing trust fund for TCC's share of STP was $98 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. I&M and TCC will work with regulators and customers to recover the remaining estimated costs of decommissioning Cook Plant and STP. However, AEP's, I&M's and TCC'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. Other Environmental Concerns - Affecting AEP and all Subsidiaries 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. Other Matters Seasonality Sale of electric power is generally a seasonal business. In many parts of the country, demand for power peaks during the hot summer months, with market prices also peaking at that time. In other areas, power demand peaks during the winter. The pattern of this fluctuation may change depending on the nature and location of facilities AEP and its subsidiaries acquire and the terms of power sale contracts they enter. In addition, AEP and its subsidiaries have historically sold less power, and consequently earned less income, when weather conditions are milder. AEP and its subsidiaries expect that unusually mild weather in the future could diminish their results of operations and may impact their financial condition. Sustained Earnings Improvement Initiative In response to difficult conditions in AEP's business, a Sustained Earnings Improvement (SEI) initiative was undertaken company-wide in the fourth quarter of 2002, as a cost-saving and revenue-building effort to build long-term earnings growth. Termination benefits expense relating to 1,120 terminated employees totaling $75.4 million pre-tax was recorded in the fourth quarter of 2002. We determined that the termination of the employees under our SEI initiative did not constitute a curtailment under the provisions of SFAS No. 88 "Employers' Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits". In addition, certain buildings and corporate aircraft are being sold in an effort to reduce ongoing operating expenses. See Note 11 for additional information. Non-Core Wholesale Investments Additional market deterioration associated with AEP's non-core wholesale investments, including AEP's U.K. operations, could have an adverse impact on AEP's future results of operations and cash flows. Significant long-term changes in external market conditions could lead to additional write-offs and potential divestitures of AEP's wholesale investments, including, but not limited to, AEP's U.K. operations. Elk City Referendum - Affecting AEP and PSO In October 2002, the City Commission of Elk City, Oklahoma voted to hold a referendum seeking voter approval of a $20.4 million acquisition of PSO's distribution assets within the city limits. The vote occurred in December 2002 with the referendum being defeated. Snohomish Settlement - Affecting AEP In February 2003, AEP and the Public Utility District No. 1 of Snohomish County, Washington (Snohomish) agreed to terminate their long-term contract signed in January 2001. Snohomish also agreed to withdraw its complaint before the FERC regarding this contract. 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, 2002, AEP's investment in EWGs and FUCOs was $2.0 billion, including guarantees of debt, compared to AEP's limit of $2.8 billion. SEC rules under PUHCA permit AEP to invest up to 15% of consolidated capitalization (such amount was $3.2 billion at December 31, 2002) in energy-related companies, including marketing and/or trading of electricity, gas and other energy commodities. 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 2003 at no cost to shareholders. Please address requests for copies to: R. Todd Rimmer 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 Trust Company, N.A. P.O. Box 43069 Providence, RI 02940-3069 Phone Number: 1-800-328-6955 Hearing Impaired Number: TDD: 1-800-952-9245 Website: http://www.equiserve.com EX-23 8 x23.txt AUDITOR D&T EXHIBIT 23 INDEPENDENT AUDITORS' CONSENT We consent to the incorporation by reference in Post-Effective Amendment No. 1 to Registration Statement No. 333-100632 of Southwestern Electric Power Company on Form S-3 of our reports dated February 21, 2003, appearing in and incorporated by reference in this Annual Report on Form 10-K of Southwestern Electric Power Company for the year ended December 31, 2002. /s/ Deloitte & Touche LLP Deloitte & Touche LLP Columbus, Ohio March 20, 2003 EX-24 9 x24.txt Exhibit 24 POWER OF ATTORNEY Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2002 The undersigned directors of the following companies (each respectively the "Company") Company State of Incorporation AEP Generating Company Ohio Appalachian Power Company Virginia AEP Texas Central Company Texas AEP Texas North 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 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, 2002, 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 26th day of February, 2003. /s/ E. Linn Draper, Jr. /s/ Robert P. Powers - ------------------------------- ---------------------------------- E. Linn Draper, Jr. Robert P. Powers /s/ Henry W. Fayne /s/ Thomas V. Shockley, III - ------------------------------- ---------------------------------- Henry W. Fayne Thomas V. Shockley, III /s/ Thomas M. Hagan /s/ Susan Tomasky - ------------------------------- ---------------------------------- Thomas M. Hagan Susan Tomasky /s/ Armando A. Pena - ------------------------------- Armando A. Pena EX-99 10 x99a.txt (A) CERTIFICATE OF CEO Exhibit 99(a) Certification Pursuant to Section 1350 of Chapter 63 Of Title 18 of the United States Code I, E. Linn Draper, Jr., the chief executive officer of American Electric Power Company, Inc. AEP Generating Company AEP Texas Central Company AEP Texas North Company Appalachian Power Company Columbus Southern Power Company Indiana Michigan Power Company Kentucky Power Company Ohio Power Company Public Service Company of Oklahoma Southwestern Electric Power Company (the "Companies"), certify that (i) the Annual Reports of the Companies on Form 10-K for the year ended December 31, 2002 (the "Reports") fully comply with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Reports fairly presents, in all material respects, the financial condition and results of operations of the Companies. /s/ E. Linn Draper, Jr. E. Linn Draper, Jr. March 20, 2003 EX-99 11 x99b.txt (B) CERTIFICATE OF CFO Exhibit 99(b) Certification Pursuant to Section 1350 of Chapter 63 Of Title 18 of the United States Code I, Susan Tomasky, the chief financial officer of American Electric Power Company, Inc. AEP Generating Company AEP Texas Central Company AEP Texas North Company Appalachian Power Company Columbus Southern Power Company Indiana Michigan Power Company Kentucky Power Company Ohio Power Company Public Service Company of Oklahoma Southwestern Electric Power Company (the "Companies"), certify that (i) the Annual Reports of the Companies on Form 10-K for the year ended December 31, 2002 (the "Reports") fully comply with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Reports fairly presents, in all material respects, the financial condition and results of operations of the Companies. /s/ Susan Tomasky Susan Tomasky March 20, 2003 -----END PRIVACY-ENHANCED MESSAGE-----