-----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, IVsq0nz49ClhaHDyPcXRbhGJAQhtAhHjFXV/cqAt37qxOEQWivme6yRVVCp55QEB SBEWFx3UQRuv3jjIwTSWAg== 0000004904-01-000036.txt : 20010402 0000004904-01-000036.hdr.sgml : 20010402 ACCESSION NUMBER: 0000004904-01-000036 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 16 CONFORMED PERIOD OF REPORT: 20001231 FILED AS OF DATE: 20010330 FILER: COMPANY DATA: COMPANY CONFORMED NAME: AMERICAN ELECTRIC POWER COMPANY INC CENTRAL INDEX KEY: 0000004904 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 134922640 STATE OF INCORPORATION: NY FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K405 SEC ACT: SEC FILE NUMBER: 001-03525 FILM NUMBER: 1586713 BUSINESS ADDRESS: STREET 1: 1 RIVERSIDE PLZ CITY: COLUMBUS STATE: OH ZIP: 43215 BUSINESS PHONE: 6142231000 FORMER COMPANY: FORMER CONFORMED NAME: KINGSPORT UTILITIES INC DATE OF NAME CHANGE: 19660906 10-K405 1 0001.txt AMERICAN ELECTRIC POWER 2000 10-K 1 - -------------------------------------------------------------------------------- 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, 2000 [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from _____________ to ______________
COMMISSION REGISTRANT; STATE OF INCORPORATION; I.R.S. EMPLOYER FILE NUMBER ADDRESS AND TELEPHONE NUMBER IDENTIFICATION NO. - ----------- ---------------------------- ------------------ 1-3525 AMERICAN ELECTRIC POWER COMPANY, INC. (A New York Corporation) 13-4922640 1 Riverside Plaza, Columbus, Ohio 43215 Telephone (614) 223-1000 0-18135 AEP GENERATING COMPANY (An Ohio Corporation) 31-1033833 1 Riverside Plaza, Columbus, Ohio 43215 Telephone (614) 223-1000 1-3457 APPALACHIAN POWER COMPANY (A Virginia Corporation) 54-0124790 40 Franklin Road, Roanoke, Virginia 24011 Telephone (540) 985-2300 0-346 CENTRAL POWER AND LIGHT COMPANY (A Texas Corporation) 74-0550600 539 North Carancahua Street, Corpus Christi, Texas 78401-2802 Telephone (361) 881-5300 1-2680 COLUMBUS SOUTHERN POWER COMPANY (An Ohio Corporation) 31-4154203 1 Riverside Plaza, Columbus, Ohio 43215 Telephone (614) 223-1000 1-3570 INDIANA MICHIGAN POWER COMPANY (An Indiana Corporation) 35-0410455 One Summit Square, P. O. Box 60, Fort Wayne, Indiana 46801 Telephone (219) 425-2111 1-6858 KENTUCKY POWER COMPANY (A Kentucky Corporation) 61-0247775 1701 Central Avenue, Ashland, Kentucky 41101 Telephone (800) 572-1141 1-6543 OHIO POWER COMPANY (An Ohio Corporation) 31-4271000 301 Cleveland Avenue, S.W., Canton, Ohio 44701 Telephone (330) 456-8173 0-343 PUBLIC SERVICE COMPANY OF OKLAHOMA (An Oklahoma Corporation) 73-0410895 212 East 6th Street, Tulsa, Oklahoma 74119-1212 Telephone (918) 599-2000 1-3146 SOUTHWESTERN ELECTRIC POWER COMPANY (A Delaware Corporation) 72-0323455 428 Travis Street, Shreveport, Louisiana 71156-0001 Telephone (318) 673-3000 0-340 WEST TEXAS UTILITIES COMPANY (A Texas Corporation) 75-0646790 301 Cypress Street, Abilene, Texas 79601-5820 Telephone (915) 674-7000
AEP Generating Company, Columbus Southern Power Company, Kentucky Power Company, Public Service Company of Oklahoma and West Texas Utilities Company meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and are therefore filing this Form 10-K with the reduced disclosure format specified in General Instruction I(2) to such Form 10-K. 2 SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
NAME OF EACH EXCHANGE REGISTRANT TITLE OF EACH CLASS ON WHICH REGISTERED ---------- ------------------- ------------------- AEP Generating Company None American Electric Common Stock, Power Company, Inc. $6.50 par value............................................ New York Stock Exchange Appalachian Power 4-1/2% Cumulative Preferred Stock, Company Voting, no par value....................................... Philadelphia Stock Exchange 8-1/4% Junior Subordinated Deferrable Interest Debentures, Series A, Due 2026.................. New York Stock Exchange 8% Junior Subordinated Deferrable Interest Debentures, Series B, Due 2027.................. New York Stock Exchange 7.20% Senior Notes, Series A, Due 2038......................... New York Stock Exchange 7.30% Senior Notes, Series B, Due 2038......................... New.York Stock Exchange Columbus Southern 8-3/8% Junior Subordinated Deferrable Power Company Interest Debentures, Series A, Due 2025................... New York Stock Exchange 7.92% Junior Subordinated Deferrable Interest Debentures, Series B, Due 2027................... New York Stock Exchange CPL Capital I 8.00% Cumulative Quarterly Income Preferred Securities, Series A, Liquidation Preference $25 per Preferred Security..................................... New York Stock Exchange Indiana Michigan 8% Junior Subordinated Deferrable Power Company Interest Debentures, Series A, Due 2026................... New York Stock Exchange 7.60% Junior Subordinated Deferrable Interest Debentures, Series B, Due 2038................... New York Stock Exchange Kentucky Power 8.72% Junior Subordinated Deferrable Company Interest Debentures, Series A, Due 2025................... New York Stock Exchange Ohio Power Company 8.16% Junior Subordinated Deferrable Interest Debentures, Series A, Due 2025................... New York Stock Exchange 7.92% Junior Subordinated Deferrable Interest Debentures Series B, Due 2027................... New York Stock Exchange 7 3/8% Senior Notes, Series A, Due 2038........................ New York Stock Exchange PSO Capital I 8.00% Trust Originated Preferred Securities, Series A, Liquidation Preference $25 per Preferred Security...................... New York Stock Exchange SWEPCo Capital I 7.875% Trust Preferred Securities, Series A, Liquidation amount $25 per Preferred Security..................................... New York Stock Exchange
3 SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
REGISTRANT TITLE OF EACH CLASS ---------- ------------------- AEP Generating Company None American Electric Power Company, Inc. None Appalachian Power Company None Central Power and Light Company 4.00% Cumulative Preferred Stock, Non-Voting, $100 par value 4.20% Cumulative Preferred Stock, Non-Voting, $100 par value Columbus Southern Power Company None Indiana Michigan Power Company 4-1/8% Cumulative Preferred Stock, Non-Voting, $100 par value Kentucky Power Company None Ohio Power Company 4-1/2% Cumulative Preferred Stock, Voting, $100 par value Public Service Company of Oklahoma None Southwestern Electric Power Company 4.28% Cumulative Preferred Stock, Non-Voting, $100 par value 4.65% Cumulative Preferred Stock, Non-Voting, $100 par value 5.00% Cumulative Preferred Stock, Non-Voting, $100 par value West Texas Utilities Company None
AGGREGATE MARKET VALUE OF VOTING AND NON-VOTING NUMBER OF SHARES COMMON EQUITY HELD OF COMMON STOCK BY NON-AFFILIATES OF OUTSTANDING OF THE REGISTRANTS AT THE REGISTRANTS AT FEBRUARY 1, 2001 FEBRUARY 1, 2001 ---------------- ---------------- AEP Generating Company None 1,000 ($1,000 par value) American Electric Power Company, Inc. $13,853,503,196 322,024,714 ($6.50 par value) Appalachian Power Company None 13,499,500 (no par value) Central Power and Light Company None 6,755,535 ($25 par value) Columbus Southern Power Company None 16,410,426 (no par value) Indiana Michigan Power Company None 1,400,000 (no par value) Kentucky Power Company None 1,009,000 ($50 par value) Ohio Power Company None 27,952,473 (no par value) Public Service Company of Oklahoma None 9,013,000 ($15 par value) Southwestern Electric Power Company None 7,536,640 ($18 par value) West Texas Utilities Company None 5,488,560 ($25 par value)
NOTE ON MARKET VALUE OF COMMON EQUITY HELD BY NON-AFFILIATES American Electric Power Company, Inc. owns all of the common stock of AEP Generating Company, Appalachian Power Company, Central Power and Light Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company, Ohio Power Company, Public Service Company of Oklahoma, Southwestern Electric Power Company and West Texas Utilities Company (see Item 12 herein). 4 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 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. [X] DOCUMENTS INCORPORATED BY REFERENCE
PART OF FORM 10-K INTO WHICH DOCUMENT DESCRIPTION IS INCORPORATED - ----------- --------------- Portions of Annual Reports of the following companies for the fiscal year ended Part II December 31, 2000: AEP Generating Company American Electric Power Company, Inc. Appalachian Power Company Central Power and Light Company Columbus Southern Power Company Indiana Michigan Power Company Kentucky Power Company Ohio Power Company Public Service Company of Oklahoma Southwestern Electric Power Company West Texas Utilities Company Portions of Proxy Statement of American Electric Power Company, Inc. for 2001 Annual Part III Meeting of Shareholders, to be filed within 120 days after December 31, 2000 Portions of Information Statements of the following companies for 2001 Annual Part III Meeting of Shareholders, to be filed within 120 days after December 31, 2000 Appalachian Power Company Ohio Power Company
------------------------------------- THIS COMBINED FORM 10-K IS SEPARATELY FILED BY AEP GENERATING COMPANY, AMERICAN ELECTRIC POWER COMPANY, INC., APPALACHIAN POWER COMPANY, CENTRAL POWER AND LIGHT COMPANY, COLUMBUS SOUTHERN POWER COMPANY, INDIANA MICHIGAN POWER COMPANY, KENTUCKY POWER COMPANY, OHIO POWER COMPANY, PUBLIC SERVICE COMPANY OF OKLAHOMA, SOUTHWESTERN ELECTRIC POWER COMPANY AND WEST TEXAS UTILITIES COMPANY. INFORMATION CONTAINED HEREIN RELATING TO ANY INDIVIDUAL REGISTRANT IS FILED BY SUCH REGISTRANT ON ITS OWN BEHALF. EXCEPT FOR AMERICAN ELECTRIC POWER COMPANY, INC., EACH REGISTRANT MAKES NO REPRESENTATION AS TO INFORMATION RELATING TO THE OTHER REGISTRANTS. - ------------------------------------------------------------------------------ ============================================================================== 5 TABLE OF CONTENTS
PAGE NUMBER ------ Glossary of Terms............................................................................... i Forward-Looking Information..................................................................... 1 PART I Item 1. Business..................................................................... 2 Item 2. Properties................................................................... 35 Item 3. Legal Proceedings............................................................ 38 Item 4. Submission of Matters to a Vote of Security Holders.......................... 39 Executive Officers of the Registrants.................................................... 39 PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters..................................................... 41 Item 6. Selected Financial Data...................................................... 42 Item 7. Management's Discussion and Analysis of Results of Operations and Financial Condition...................................... 42 Item 7A. Quantitative and Qualitative Disclosures About Market Risk .................. 42 Item 8. Financial Statements and Supplementary Data.................................. 42 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.................................. 42 PART III Item 10. Directors and Executive Officers of the Registrants.......................... 43 Item 11. Executive Compensation....................................................... 44 Item 12. Security Ownership of Certain Beneficial Owners and Management.......................................................... 46 Item 13. Certain Relationships and Related Transactions............................... 47 PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K............................................................. 48 Signatures...................................................................................... 49 Index to Financial Statement Schedules.......................................................... S-1 Independent Auditors' Report.................................................................... S-2 Exhibit Index................................................................................... E-1
6 GLOSSARY OF TERMS The following abbreviations or acronyms used in this Form 10-K are defined below:
ABBREVIATION OR ACRONYM DEFINITION ----------------------- ---------- AEGCo.......................................... AEP Generating Company, an electric utility subsidiary of AEP. AEP ........................................... American Electric Power Company, Inc. AEP System or the System....................... The American Electric Power System, an integrated electric utility system, owned and operated by AEP's electric utility subsidiaries. AFUDC.......................................... Allowance for funds used during construction. Defined in regulatory systems of accounts as the net cost of borrowed funds used for construction and a reasonable rate of return on other funds when so used. APCo........................................... Appalachian Power Company, an electric utility subsidiary of AEP. Btu............................................ British thermal unit. Buckeye........................................ Buckeye Power, Inc., an unaffiliated corporation. C3............................................. C3 Communications, Inc. CAA............................................ Clean Air Act. CAAA........................................... Clean Air Act Amendments of 1990. CCD Group...................................... CSPCo, CG&E and DP&L. CERCLA......................................... Comprehensive Environmental Response, Compensation and Liability Act of 1980. CG&E........................................... The Cincinnati Gas & Electric Company, an unaffiliated utility company. CO2............................................ Carbon dioxide. Cook Plant..................................... The Donald C. Cook Nuclear Plant, owned by I&M, located near Bridgman, Michigan. CPL............................................ Central Power and Light Company, an electric utility subsidiary of AEP. CSPCo.......................................... Columbus Southern Power Company, an electric utility subsidiary of AEP. CSW........................................... Central and South West Corporation. DOE............................................ United States Department of Energy. DP&L........................................... The Dayton Power and Light Company, an unaffiliated utility company. East Zone Companies of AEP..................... APCo, CSPCo, I&M, KEPCo and OPCo. EWG............................................ Exempt wholesale generator. Federal EPA.................................... United States Environmental Protection Agency. FERC........................................... Federal Energy Regulatory Commission (an independent commission within the DOE). FUCO........................................... Foreign utility company as defined by PUHCA. I&M............................................ Indiana Michigan Power Company, an electric utility subsidiary of AEP. IURC........................................... Indiana Utility Regulatory Commission. KEPCo.......................................... Kentucky Power Company, an electric utility subsidiary of AEP. NOx............................................ Nitrogen oxide. NPDES.......................................... National Pollutant Discharge Elimination System. NRC............................................ Nuclear Regulatory Commission. Ohio EPA....................................... Ohio Environmental Protection Agency. OPCo.......................................... Ohio Power Company, an electric utility subsidiary of AEP. OVEC........................................... Ohio Valley Electric Corporation, an electric utility company in which AEP and CSPCo own a 44.2% equity interest. PCBs........................................... Polychlorinated biphenyls. PSO............................................ Public Service Company of Oklahoma, an electric utility subsidiary of AEP. PUCO........................................... The Public Utilities Commission of Ohio.
i 7
ABBREVIATION OR ACRONYM DEFINITION ----------------------- ---------- PUHCA.......................................... Public Utility Holding Company Act of 1935, as amended. QF............................................. Qualifying facility as defined in the Public Utility Regulatory Policies Act of 1978. RCRA........................................... Resource Conservation and Recovery Act of 1976, as amended. Rockport Plant................................. A generating plant, consisting of two 1,300,000-kilowatt coal-fired generating units, near Rockport, Indiana. SEC............................................ Securities and Exchange Commission. SEEBOARD....................................... SEEBOARD Group plc, Crawley, West Sussex, United Kingdom. Service Corporation............................ American Electric Power Service Corporation, a service subsidiary of AEP. SO2............................................ Sulfur dioxide. SO2 Allowance.................................. An allowance to emit one ton of sulfur dioxide granted under the Clean Air Act Amendments of 1990. STP............................................ South Texas Project Nuclear Generating Plant, owned 25.2% by CPL, located near Bay City, Texas. STPNOC......................................... STP Nuclear Operating Company, a non-profit Texas corporation which operates STP on behalf of its joint owners including CPL. SWEPCo......................................... Southwestern Electric Power Company, an electric utility subsidiary of AEP. TVA ........................................... Tennessee Valley Authority. Vale........................................... Empresa De Electricidade Vale Paranapanema SA, a Brazilian Electric Distribution Company. VEPCo.......................................... Virginia Electric and Power Company, an unaffiliated utility company. Virginia SCC................................... Virginia State Corporation Commission. West Virginia PSC.............................. Public Service Commission of West Virginia. West Zone Companies of AEP..................... CPL, PSO, SWEPCo and WTU. WTU............................................ West Texas Utilities Company, an electric utility subsidiary of AEP. Zimmer or Zimmer Plant......................... Wm. H. Zimmer Generating Station, commonly owned by CSPCo, CG&E and DP&L.
ii 8 FORWARD-LOOKING INFORMATION This report made by AEP and certain of its subsidiaries includes forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. These forward-looking statements reflect assumptions and involve a number of risks and uncertainties. Among the factors that could cause actual results to differ materially from forward-looking statements are: - Electric load and customer growth. - Abnormal weather conditions. - Available sources of and prices for coal and gas. - Availability of generating capacity. - The impact of the merger with CSW, including the ability of the combined companies to realize the synergies expected as a result of the combination. - The timing of the implementation of AEP's restructuring plan. - Risks related to energy trading and construction under contract. - The speed and degree to which competition is introduced to our power generation business. - The structure and timing of a competitive market for electricity and its impact on prices. - The ability to recover net regulatory assets, other stranded costs and implementation costs in connection with deregulation of generation in certain states. - New legislation and government regulations. - The ability of AEP to successfully control its costs. - The success of new business ventures. - International developments affecting AEP's foreign investments. - The effects of fluctuations in foreign currency exchange rates. - The economic climate and growth in AEP's service and trading territories, both domestic and foreign. - The ability of AEP to comply with or to challenge successfully new environmental regulations and to litigate successfully claims that AEP violated the CAA. - Inflationary trends. - Changes in electricity and gas market prices. - Successful resolution of litigation regarding municipal franchise fees in Texas. - Successful appeal of decision in connection with COLI litigation. - Interest rates. - Other risks and unforeseen events. 1 9 PART I ======================================================================== Item 1. BUSINESS - ------------------------------------------------------------------------------ GENERAL AEP was incorporated under the laws of the State of New York in 1906 and reorganized in 1925. It is a public utility holding company which owns, directly or indirectly, all of the outstanding common stock of its domestic electric utility subsidiaries and varying percentages of other subsidiaries. Substantially all of the operating revenues of AEP and its subsidiaries are derived from the furnishing of electric service. In addition, in recent years AEP has been pursuing various unregulated business opportunities worldwide as discussed in New Business Development. The service area of AEP's domestic electric utility subsidiaries covers portions of the states of Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia. The generating and transmission facilities of AEP's subsidiaries are physically interconnected, and their operations are coordinated, as a single integrated electric utility system. Transmission networks are interconnected with extensive distribution facilities in the territories served. The electric utility subsidiaries of AEP, which do business as "American Electric Power," have traditionally provided electric service, consisting of generation, transmission and distribution, on an integrated basis to their retail customers. At December 31, 2000, the subsidiaries of AEP had a total of 26,376 employees. AEP, as such, has no employees. The operating subsidiaries of AEP are: APCo (organized in Virginia in 1926) is engaged in the generation, sale, purchase, transmission and distribution of electric power to approximately 909,000 retail customers in the southwestern portion of Virginia and southern West Virginia, and in supplying electric power at wholesale to other electric utility companies and municipalities in those states and in Tennessee. At December 31, 2000, APCo and its wholly owned subsidiaries had 2,846 employees. Among the principal industries served by APCo are coal mining, primary metals, chemicals and textile mill products. In addition to its AEP System interconnections, APCo also is interconnected with the following unaffiliated utility companies: Carolina Power & Light Company, Duke Energy Corporation and VEPCo. A comparatively small part of the properties and business of APCo is located in the northeastern end of the Tennessee Valley. APCo has several points of interconnection with TVA and has entered into agreements with TVA under which APCo and TVA interchange and transfer electric power over portions of their respective systems. CPL (organized in Texas in 1945) is engaged in the generation, sale, purchase, transmission and distribution of electric power to approximately 680,000 customers in southern Texas, and in supplying electric power at wholesale to other utilities, municipalities and rural electric cooperatives. At December 31, 2000, CPL had 1,444 employees. Among the principal industries served by CPL are oil and gas extraction, food processing, apparel, metal refining, chemical and petroleum refining, plastics, and machinery equipment. CSPCo (organized in Ohio in 1937, the earliest direct predecessor company having been organized in 1883) is engaged in the generation, sale, purchase, transmission and distribution of electric power to approximately 668,000 customers in Ohio, and in supplying electric power at wholesale to other electric utilities and to municipally owned distribution systems within its service area. At December 31, 2000, CSPCo had 1,264 employees. CSPCo's service area is comprised of two areas in Ohio, which include portions of twenty-five counties. One area includes the City of Columbus and the other is a predominantly rural area in south central Ohio. Approximately 80% of CSPCo's retail revenues are derived from the Columbus area. Among the principal industries served are food processing, chemicals, primary metals, electronic machinery and paper products. In addition to its AEP 2 10 System interconnections, CSPCo also is interconnected with the following unaffiliated utility companies: CG&E, DP&L and Ohio Edison Company. I&M (organized in Indiana in 1925) is engaged in the generation, sale, purchase, transmission and distribution of electric power to approximately 565,000 customers in northern and eastern Indiana and southwestern Michigan, and in supplying electric power at wholesale to other electric utility companies, rural electric cooperatives and municipalities. At December 31, 2000, I&M had 2,965 employees. Among the principal industries served are primary metals, transportation equipment, electrical and electronic machinery, fabricated metal products, rubber and miscellaneous plastic products and chemicals and allied products. Since 1975, I&M has leased and operated the assets of the municipal system of the City of Fort Wayne, Indiana. In addition to its AEP System interconnections, I&M also is interconnected with the following unaffiliated utility companies: Central Illinois Public Service Company, CG&E, Commonwealth Edison Company, Consumers Energy Company, Illinois Power Company, Indianapolis Power & Light Company, Louisville Gas and Electric Company, Northern Indiana Public Service Company, PSI Energy Inc. and Richmond Power & Light Company. KEPCo (organized in Kentucky in 1919) is engaged in the generation, sale, purchase, transmission and distribution of electric power to approximately 172,000 customers in an area in eastern Kentucky, and in supplying electric power at wholesale to other utilities and municipalities in Kentucky. At December 31, 2000, KEPCo had 451 employees. In addition to its AEP System interconnections, KEPCo also is interconnected with the following unaffiliated utility companies: Kentucky Utilities Company and East Kentucky Power Cooperative Inc. KEPCo is also interconnected with TVA. Kingsport Power Company (organized in Virginia in 1917) provides electric service to approximately 45,000 customers in Kingsport and eight neighboring communities in northeastern Tennessee. Kingsport Power Company has no generating facilities of its own. It purchases electric power distributed to its customers from APCo. At December 31, 2000, Kingsport Power Company had 62 employees. OPCo (organized in Ohio in 1907 and re-incorporated in 1924) is engaged in the generation, sale, purchase, transmission and distribution of electric power to approximately 696,000 customers in the northwestern, east central, eastern and southern sections of Ohio, and in supplying electric power at wholesale to other electric utility companies and municipalities. At December 31, 2000, OPCo and its wholly owned subsidiaries had 3,532 employees. Among the principal industries served by OPCo are primary metals, rubber and plastic products, stone, clay, glass and concrete products, petroleum refining and chemicals. In addition to its AEP System interconnections, OPCo also is interconnected with the following unaffiliated utility companies: CG&E, The Cleveland Electric Illuminating Company, DP&L, Duquesne Light Company, Kentucky Utilities Company, Monongahela Power Company, Ohio Edison Company, The Toledo Edison Company and West Penn Power Company. PSO (organized in Oklahoma in 1913) is engaged in the generation, sale, purchase, transmission and distribution of electric power to approximately 499,000 customers in eastern and southwestern Oklahoma, and in supplying electric power at wholesale to other utilities, municipalities and rural electric cooperatives. At December 31, 2000, PSO had 1,005 employees. Among the principal industries served by PSO are natural gas and oil production, oil refining, steel processing, aircraft maintenance, paper manufacturing and timber products, glass, chemicals, cement, plastics, aerospace manufacturing, telecommunications, and rubber goods. SWEPCo (organized in Oklahoma in 1912) is engaged in the generation, sale, purchase, transmission and distribution of electric power to approximately 428,000 customers in northeastern Texas, northwestern Louisiana, and western Arkansas, and in supplying electric power at wholesale to other utilities, municipalities and 3 11 rural electric cooperatives. At December 31, 2000, SWEPCo had 1,243 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. Wheeling Power Company (organized in West Virginia in 1883 and reincorporated in 1911) provides electric service to approximately 42,000 customers in northern West Virginia. Wheeling Power Company has no generating facilities of its own. It purchases electric power distributed to its customers from OPCo. At December 31, 2000, Wheeling Power Company had 75 employees. WTU (organized in Texas in 1927) is engaged in the generation, sale, purchase, transmission and distribution of electric power to approximately 190,000 customers in west and central Texas, and in supplying electric power at wholesale to other utilities, municipalities and rural electric cooperatives. At December 31, 2000, WTU had 718 employees. The principal industry served by WTU is agriculture. The territory served by WTU also includes several military installations and correctional facilities. Another principal electric utility subsidiary of AEP is AEGCo, which was organized in Ohio in 1982 as an electric generating company. AEGCo sells power at wholesale to I&M and KEPCo. AEGCo has no employees. See Item 2 for information concerning the properties of the subsidiaries of AEP. The Service Corporation provides accounting, administrative, information systems, engineering, financial, legal, maintenance and other services at cost to the AEP System companies. The executive officers of AEP and its public utility subsidiaries are all employees of the Service Corporation. The AEP System is an integrated electric utility system and, as a result, the member companies of the AEP System have contractual, financial and other business relationships with the other member companies, such as participation in the AEP System savings and retirement plans and tax returns, sales of electricity, transportation and handling of fuel, sales or rentals of property and interest or dividend payments on the securities held by the companies' respective parents. AEP-CSW MERGER On June 15, 2000, CSW merged with and into a wholly owned merger subsidiary of AEP with CSW being the surviving corporation. The merger was pursuant to an Agreement and Plan of Merger, dated as of December 21, 1997, that AEP and CSW had entered into. As a result of the merger, each outstanding share of common stock, par value $3.50 per share, of CSW (other than shares owned by AEP or CSW) was converted into 0.6 of a share of common stock, par value $6.50 per share, of AEP. CSW's four wholly-owned domestic electric utility subsidiaries are CPL, PSO, SWEPCo and WTU. CSW also has the following principal subsidiaries: CSW International, CSW Energy, SEEBOARD, AEP Credit, Inc., C3 and CSW Energy Services, Inc. AEP intends to comply with the following conditions imposed by the FERC as part of the FERC's order approving the merger: - Transfer operational control of AEP's east and west transmission systems to fully-functioning, FERC-approved regional transmission organizations by December 15, 2001. See Transmission Services for Non-Affiliates. - Two interim transmission-related mitigation measures consisting of market monitoring and independent calculation and posting of available transmission capacity to monitor the operation of AEP's east transmission system. - Divestiture of 550 MW of generating capacity comprised of 300 MW of capacity in the Southwest Power Pool (SPP) and 250 MW of capacity in the Electric Reliability Council of Texas (ERCOT). AEP must complete divestiture of the SPP capacity by 4 12 July 1, 2002. AEP has completed divestiture of the ERCOT capacity. The FERC found that certain energy sales of SPP and ERCOT capacity would be reasonable and effective interim mitigation measures until completion of the required SPP and ERCOT divestitures. As required by the FERC, the proposed interim energy sales were in effect when the merger was consummated. REGULATION General AEP and its subsidiaries are subject to the broad regulatory provisions of PUHCA administered by the SEC. The public utility subsidiaries' retail rates and certain other matters are subject to regulation by the public utility commissions of the states in which they operate. Such subsidiaries are also subject to regulation by the FERC under the Federal Power Act in respect of rates for interstate sale at wholesale and transmission of electric power, accounting and other matters and construction and operation of hydroelectric projects. I&M and CPL are subject to regulation by the NRC under the Atomic Energy Act of 1954, as amended, with respect to the operation of the Cook Plant and STP, respectively. Possible Change to PUHCA The provisions of PUHCA, administered by the SEC, regulate all aspects of a registered holding company system, such as the AEP System. PUHCA requires that the operations of a registered holding company system be limited to a single integrated public utility system and such other businesses as are incidental or necessary to the operations of the system. In addition, PUHCA governs, among other things, financings, sales or acquisitions of assets and intra-system transactions. On June 20, 1995, the SEC released a report from its Division of Investment Management recommending a conditional repeal of PUHCA, including its limits on financing and on geographic and business diversification. Specific federal authority, however, would be preserved over access to the books and records of registered holding company systems, audit authority over registered holding companies and their subsidiaries and oversight over affiliate transactions. This authority would be transferred to the FERC. Following the report, legislation was introduced in Congress to repeal PUHCA and transfer certain federal authority to the FERC as recommended in the SEC report. Since 1997, such PUHCA repeal language has been part of broader legislation regarding changes in the electric industry. Such legislation, both as a separate bill and as part of broader electricity restructuring legislation, was reintroduced in 1999 and 2000. Legislative hearings were held but no PUHCA repeal legislation was passed by either the House of Representatives or Senate. It is expected that a number of bills contemplating PUHCA repeal separately and the restructuring of the electric utility industry will be introduced in the current Congress. See Competition and Business Change. If PUHCA is repealed, registered holding company systems, including the AEP System, will be able to compete in the changing industry without the constraints of PUHCA. Management of AEP believes that removal of these constraints would be beneficial to the AEP System. PUHCA and the rules and orders of the SEC currently require that transactions between associated companies in a registered holding company system be performed at cost with limited exceptions. Over the years, the AEP System has developed numerous affiliated service, sales and construction relationships and, in some cases, invested significant capital and developed significant operations in reliance upon the ability to recover its full costs under these provisions. Legislation has been introduced in Congress to repeal PUHCA or modify its provisions governing intra-system transactions. The effect of repeal or amendment of PUHCA on AEP's intra-system transactions depends on whether the assurance of full cost recovery is eliminated immediately or phased in and whether it is eliminated for all intra-system transactions or only some. If the cost recovery assurance is eliminated immediately for all intra-system transactions, it could have a material adverse effect on results of operations and financial condition of AEP and OPCo. Current legislation grandfathers transactions legally authorized on the effective date of PUHCA repeal. 5 13 Conflict of Regulation Public utility subsidiaries of AEP can be subject to regulation of the same subject matter by two or more jurisdictions. In such situations, it is possible that the decisions of such regulatory bodies may conflict or that the decision of one such body may affect the cost of providing service, and so the rates, in another jurisdiction. In a case involving OPCo, the U.S. Court of Appeals for the District of Columbia held that the determination of costs to be charged to associated companies by the SEC under PUHCA precluded the FERC from determining that such costs were unreasonable for ratemaking purposes. The U.S. Supreme Court also has held that a state commission may not conclude that a FERC approved wholesale power agreement is unreasonable for state ratemaking purposes. Certain actions that would overturn these decisions or otherwise affect the jurisdiction of the SEC and FERC are under consideration by the U.S. Congress and these regulatory bodies. Such conflicts of jurisdiction often result in litigation and, if resolved adversely to a public utility subsidiary of AEP, could have a material adverse effect on the results of operations or financial condition of such subsidiary or AEP. CLASSES OF SERVICE The principal classes of service from which the domestic electric utility subsidiaries of AEP derive revenues and the amount of such revenues (from kilowatt-hour sales) during the year ended December 31, 2000 are as follows:
AEP SYSTEM(a) AEGCO APCO --------- ----- ---- (IN THOUSANDS) Retail Residential...................................... $3,517,058 $0 $593,636 Commercial....................................... 2,451,068 0 310,478 Industrial....................................... 2,443,750 0 362,303 Miscellaneous.................................... 213,620 0 37,070 ---------- -------- --------- Total Retail............................... 8,625,496 0 1,303,487 Wholesale (sales for resale)........................ 1,795,041 228,304 506,365 ---------- ------- --------- Total from KWH Sales....................... 10,420,537 228,304 1,809,852 Other Operating Revenues and Refunds................ 406,895 212 54,135 ----------- -------- ---------- Total Electric Operating Revenues.......... $10,827,432 $228,516 $1,863,987 =========== ======== ==========
CPL CSPCO --- ----- (IN THOUSANDS) Retail Residential...................................... $651,580 $473,986 Commercial....................................... 460,433 434,785 Industrial....................................... 370,161 145,326 Miscellaneous.................................... 49,204 18,176 ------ ------ Total Retail............................... 1,531,378 1,072,273 Wholesale (sales for resale)........................ 140,671 243,827 ------- ------- Total from KWH Sales....................... 1,672,049 1,316,100 Other Operating Revenues and Refunds................ 99,128 42,250 ------ ------ Total Electric Operating Revenues.......... $1,771,177 $1,358,350 ========== ==========
I&M KEPCO OPCO PSO ------ ------- ------- ------- (IN THOUSANDS) Retail Residential...................................... $340,484 $112,707 $429,491 $361,853 Commercial....................................... 269,650 62,431 278,224 278,940 Industrial....................................... 334,622 93,111 548,599 198,498 Miscellaneous.................................... 6,689 950 8,426 11,372 ---------- -------- ---------- -------- Total Retail............................... 951,445 269,199 1,264,740 850,663 Wholesale (sales for resale)........................ 557,235 120,482 894,253 93,993 ---------- -------- ---------- -------- Total from KWH Sales....................... 1,508,680 389,681 2,158,993 944,656 Other Operating Revenues and Refunds................ 41,907 20,722 80,638 17,953 ---------- -------- ---------- -------- Total Electric Operating Revenues.......... $1,550,587 $410,403 $2,239,631 $962,609 ========== ======== ========== ========
SWEPCO WTU -------- -------- (IN THOUSANDS) Retail Residential...................................... $328,873 $164,973 Commercial....................................... 219,318 97,583 Industrial....................................... 273,430 65,517 Miscellaneous.................................... 31,782 46,060 ---------- -------- Total Retail............................... 853,403 374,133 Wholesale (sales for resale)........................ 240,792 150,986 ---------- -------- Total from KWH Sales....................... 1,094,195 525,119 ------- Other Operating Revenues and Refunds................ 30,015 47,675 ---------- -------- Total Electric Operating Revenues.......... $1,124,210 $572,794 ========== ========
- ------------------------ (a) Includes revenues of other subsidiaries not shown and elimination of intercompany transactions. SALE OF POWER AEP's electric utility subsidiaries own or lease generating stations with total generating capacity of 38,033 megawatts. See Item 2 for more information regarding the generating stations. They operate their generating plants as a single interconnected and coordinated electric utility system and, in the east zone, share the costs and benefits in the AEP System Power Pool. Most of the electric power generated at these stations is sold, in combination with transmission and distribution services, to retail customers of AEP's utility subsidiaries in their service territories. These sales are made at rates that are established by the public utility commissions of the state in which they operate. See Rates and 6 14 Regulation. Some of the electric power is sold at wholesale to non-affiliated companies. AEP System Power Pool APCo, CSPCo, I&M, KEPCo and OPCo are parties to the Interconnection Agreement, dated July 6, 1951, as amended (the Interconnection Agreement), defining how they share the costs and benefits associated with their generating plants. This sharing is based upon each company's "member-load-ratio," which is calculated monthly on the basis of each company's maximum peak demand in relation to the sum of the maximum peak demands of all five companies during the preceding 12 months. In addition, since 1995, APCo, CSPCo, I&M, KEPCo and OPCo have been parties to the AEP System Interim Allowance Agreement which provides, among other things, for the transfer of SO2 Allowances associated with transactions under the Interconnection Agreement. Power marketing and trading transactions (trading activities) are conducted by the AEP Power Pool and shared among the parties under the Interconnection Agreement. Trading activities involve the purchase and sale of electricity under physical forward contracts at fixed and variable prices and the trading of electricity contracts including exchange traded futures and options and over-the-counter options and swaps. The majority of these transactions represent physical forward contracts in the AEP System's traditional marketing area and are typically settled by entering into offsetting contracts. The regulated physical forward contracts are recorded on a net basis in the month when the contract settles. In addition, the AEP Power Pool enters into transactions for the purchase and sale of electricity options, futures and swaps, and for the forward purchase and sale of electricity outside of the AEP System's traditional marketing area. The following table shows the net credits or (charges) allocated among the parties under the Interconnection Agreement and Interim Allowance Agreement during the years ended December 31, 1998, 1999 and 2000:
1998(a) 1999(a) 2000(a) ---- ---- ---- (IN THOUSANDS) APCo................. $(142,500) $(89,100) $(274,000) CSPCo................ (146,800) (184,500) (250,400) I&M.................. (86,100) (61,700) 93,900 KEPCo................ 34,000 23,700 (21,500) OPCo................. 341,400 311,600 452,000
- ----------------------- (a) Includes credits and charges from allowance transfers related to the transactions. CPL, PSO, SWEPCo, WTU, and AEP Service Corporation are parties to a Restated and Amended Operating Agreement originally dated as of January 1, 1997 (CSW Operating Agreement). The CSW Operating Agreement requires the operating companies of the west zone to maintain specified annual planning reserve margins and requires the subsidiaries that have capacity in excess of the required margins to make such capacity available for sale to other AEP subsidiaries as capacity commitments. The CSW Operating Agreement also delegates to AEP Service Corporation the authority to coordinate the acquisition, disposition, planning, design and construction of generating units and to supervise the operation and maintenance of a central control center. The CSW Operating Agreement has been accepted for filing and allowed to become effective by the FERC. Wholesale Sales of Power to Non-Affiliates AEP's electric utility subsidiaries also sell electric power on a wholesale basis to non-affiliated electric utilities and power marketers. Such sales are either made by the AEP System Power Pool and then allocated among APCo, CSPCo, I&M, KEPCo and OPCo based on member-load-ratios or made by individual companies pursuant to various long-term power agreements. Reference is made to the footnote to the financial statements entitled Commitments and Contingencies that is incorporated by reference in Item 8 for information with respect to AEP's long-term agreements to sell power. TRANSMISSION SERVICES AEP's electric utility subsidiaries own and operate transmission and distribution lines and other facilities to deliver electric power. See Item 2 for more information regarding the transmission and distribution lines. AEP's electric utility subsidiaries 7 15 operate their transmission lines as a single interconnected and coordinated system and share the cost and benefits in the AEP System Transmission Pool. Most of the transmission and distribution services are sold, in combination with electric power, to retail customers of AEP's utility subsidiaries in their service territories. These sales are made at rates that are established by the public utility commissions of the state in which they operate. See Rates and Regulation. As discussed below, some transmission services also are separately sold to non-affiliated companies. AEP System Transmission Pool APCo, CSPCo, I&M, KEPCo and OPCo are parties to the Transmission Agreement, dated April 1, 1984, as amended (the Transmission Agreement), defining how they share the costs associated with their relative ownership of the extra-high-voltage transmission system (facilities rated 345 kv and above) and certain facilities operated at lower voltages (138 kv and above). Like the Interconnection Agreement, this sharing is based upon each company's "member-load-ratio." See Sale of Power. The following table shows the net (credits) or charges allocated among the parties to the Transmission Agreement during the years ended December 31, 1998, 1999 and 2000:
1998 1999 2000 ---- ---- ---- (IN THOUSANDS) APCo........... $(2,400) $(8,300) $(3,400) CSPCo.......... 35,600 39,000 38,300 I&M............ (44,100) (43,900) (43,800) KEPCo.......... (6,000) (4,300) (6,000) OPCo........... 16,900 17,500 14,900
CPL, PSO, SWEPCo, WTU, and AEP Service Corporation are parties to a Transmission Coordination Agreement originally dated as of January 1, 1997 (TCA). The TCA establishes a coordinating committee, which is charged with the responsibility of overseeing the coordinated planning of the transmission facilities of the west zone operating subsidiaries, including the performance of transmission planning studies, the interaction of such subsidiaries with independent system operators (ISO) and other regional bodies interested in transmission planning and compliance with the terms of the Open Access Transmission Tariff (OATT) filed with the FERC and the rules of the FERC relating to such tariff. Under the TCA, the west zone operating subsidiaries have delegated to AEP Service Corporation the responsibility of monitoring the reliability of their transmission systems and administering the OATT on their behalf. The TCA also provides for the allocation among the west zone operating subsidiaries of revenues collected for transmission and ancillary services provided under the OATT. The TCA has been accepted for filing by the FERC effective as of January 1, 1997, and is the subject of proceedings commenced to consider the reasonableness of its terms and conditions. Transmission Services for Non-Affiliates AEP's electric utility subsidiaries and other System companies also provide transmission services for non-affiliated companies. On April 24, 1996, the FERC issued orders 888 and 889. These orders require each public utility that owns or controls interstate transmission facilities to file an open access network and point-to-point transmission tariff that offers services comparable to the utility's own uses of its transmission system. The orders also require utilities to functionally unbundle their services, by requiring them to use their own tariffs in making off-system and third-party sales. As part of the orders, the FERC issued a pro-forma tariff which reflects the Commission's views on the minimum non-price terms and conditions for non-discriminatory transmission service. In addition, the orders require all transmitting utilities to establish an Open Access Same-time Information System (OASIS) which electronically posts transmission information such as available capacity and prices, and require utilities to comply with Standards of Conduct which prohibit utilities' system operators from providing non-public transmission information to the utility's merchant employees. The orders also allow a utility to seek recovery of certain prudently-incurred stranded costs that result from unbundled transmission service. In December 1999, FERC issued Order 2000, which provides for the voluntary formation of regional transmission organizations (RTOs), entities created to operate, plan and control utility transmission assets. Order 2000 also prescribes certain characteristics and functions of acceptable RTO proposals. 8 16 On July 9, 1996, the AEP System companies filed a tariff conforming with the FERC's pro-forma transmission tariff. During 1998 and 1999 AEP engaged in discussions with Consumers Energy Company, FirstEnergy Corp., Detroit Edison Company and VEPCo regarding the development of the Alliance RTO which may take the form of an ISO or an independent transmission company (Transco), depending upon the occurrence of certain conditions. The Transco, if formed, would operate transmission assets that it would own, and also would operate other owners' transmission assets on a contractual basis. In 1999, these companies filed with the FERC a proposal to form the RTO. In December 1999, the FERC approved the Alliance RTO, conditioned upon certain changes to the proposal relating to governance of the RTO, resolution of intra-RTO conflicts and establishment of a rate structure. On January 24, 2001, the FERC approved the compliance filing made by the Alliance RTO in September 2000 and generally accepted the responses to the changes proposed in the December 1999 FERC order. The January 2001 FERC order also directed the Alliance companies to file their actual rates no later than 120 days prior to the commencement of operations by the Alliance RTO. COORDINATION OF EAST AND WEST ZONE OPERATING SUBSIDIARIES AEP's System Integration Agreement provides for the integration and coordination of AEP's east and west zone operating subsidiaries, joint dispatch of generation within the AEP System, and the distribution, between the two operating zones, of costs and benefits associated with the System's generating plants. It is designed to function as an umbrella agreement in addition to the AEP Interconnection Agreement and the CSW Operating Agreement, each of which will continue to control the distribution of costs and benefits within each zone. AEP's System Transmission Integration Agreement provides for the integration and coordination of the planning, operation and maintenance of the transmission facilities of AEP's east and west zone operating subsidiaries. Like the System Integration Agreement, the System Transmission Integration Agreement functions as an umbrella agreement in addition to the AEP Transmission Agreement and the Transmission Coordination Agreement. The System Transmission Integration Agreement contains two service schedules that govern: - The allocation of transmission costs and revenues. - The allocation of third-party transmission costs and revenues and System dispatch costs. The Transmission Integration Agreement anticipates that additional service schedules may be added as circumstances warrant. OVEC AEP, CSPCo and several unaffiliated utility companies jointly own OVEC, which supplies the power requirements of a uranium enrichment plant near Portsmouth, Ohio, owned by the DOE. The aggregate equity participation of AEP and CSPCo in OVEC is 44.2%. The DOE demand under OVEC's power agreement, which is subject to change from time to time, is 800,000 kilowatts. On April 1, 2001, it is scheduled to decrease to approximately 600,000 kilowatts. The proceeds from the sale of power by OVEC are designed to be sufficient for OVEC to meet its operating expenses and fixed costs and to provide a return on its equity capital. APCo, CSPCo, I&M and OPCo, as sponsoring companies, are entitled to receive from OVEC, and are obligated to pay for, the power not required by DOE, which averaged 42.1% in 2000. On September 29, 2000, DOE issued a notice of cancellation of the power agreement. DOE will therefore not be entitled to any OVEC capacity beyond August 31, 2001. The sponsoring companies will be entitled to all OVEC capacity in proportion to their power participation ratios (approximately 2,200MW) beginning September 1, 2001. 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 9 17 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 331 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 December 22, 2000, was recorded at 1,304,134 kilowatts. In January 2000, OPCo and National Power Cooperative, Inc. (NPC), an affiliate of Buckeye, entered into an agreement, subject to specified conditions, relating to construction and operation of a 510 mw gas-fired electric generating peaking facility to be owned by NPC. From the commercial operation date (expected in early 2002) until the end of 2005, OPCo will be entitled to 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. AEP Pro Serv, Inc. will provide engineering, procurement and construction for the facility. CERTAIN INDUSTRIAL CUSTOMERS Century Aluminum of West Virginia, Inc. (formerly Ravenswood Aluminum Corporation), operates a major aluminum reduction plant in the Ohio River Valley at Ravenswood, West Virginia. The power requirement of such plant presently is approximately 357,000 kilowatts. OPCo is providing electric service pursuant to a contract approved by the PUCO for the period July 1, 1996 through July 31, 2003. AEGCO Since its formation in 1982, AEGCo's business has consisted of the ownership and financing of its 50% interest in the Rockport Plant and, since 1989, leasing of its 50% interest in Unit 2 of the Rockport Plant. The operating revenues of AEGCo are derived from the sale of capacity and energy associated with its interest in the Rockport Plant to I&M and KEPCo pursuant to unit power agreements. Pursuant to these unit power agreements, AEGCo is entitled to recover its full cost of service from the purchasers and will be entitled to recover future increases in such costs, including increases in fuel and capital costs. See Unit Power Agreements. Pursuant to a capital funds agreement, AEP has agreed to provide cash capital contributions, or in certain circumstances subordinated loans, to AEGCo, to the extent necessary to enable AEGCo, among other things, to provide its proportionate share of funds required to permit continuation of the commercial operation of the Rockport Plant and to perform all of its obligations, covenants and agreements under, among other things, all loan agreements, leases and related documents to which AEGCo is or becomes a party. See Capital Funds Agreement. Unit Power Agreements A unit power agreement between AEGCo and I&M (the I&M Power Agreement) provides for the sale by AEGCo to I&M of all the power (and the energy associated therewith) available to AEGCo at the Rockport Plant. I&M is obligated, whether or not power is available from AEGCo, to pay as a demand charge for the right to receive such power (and as an energy charge for any associated energy taken by I&M) such amounts, as when added to amounts received by AEGCo from any other sources, will be at least sufficient to enable AEGCo to pay all its operating and other expenses, including a rate of return on the common equity of AEGCo as approved by FERC, currently 12.16%. The I&M Power Agreement will continue in effect until the date that the last of the lease terms of Unit 2 of the Rockport Plant has expired unless extended in specified circumstances. Pursuant to an assignment between I&M and KEPCo, and a unit power agreement between KEPCo and AEGCo, AEGCo sells KEPCo 30% of the power (and the energy associated therewith) available to AEGCo from both units of the Rockport Plant. KEPCo has agreed to pay to AEGCo in consideration for the right to receive such power the same amounts which I&M would have paid AEGCo under the terms of the I&M Power Agreement for such entitlement. The KEPCo unit power agreement expires on December 31, 2004. 10 18 Capital Funds Agreement AEGCo and AEP have entered into a capital funds agreement pursuant to which, among other things, AEP has unconditionally agreed to make cash capital contributions, or in certain circumstances subordinated loans, to AEGCo to the extent necessary to enable AEGCo to (i) maintain such an equity component of capitalization as required by governmental regulatory authorities, (ii) provide its proportionate share of the funds required to permit commercial operation of the Rockport Plant, (iii) enable AEGCo to perform all of its obligations, covenants and agreements under, among other things, all loan agreements, leases and related documents to which AEGCo is or becomes a party (AEGCo Agreements), and (iv) pay all indebtedness, obligations and liabilities of AEGCo (AEGCo Obligations) under the AEGCo Agreements, other than indebtedness, obligations or liabilities owing to AEP. The Capital Funds Agreement will terminate after all AEGCo Obligations have been paid in full. SEASONALITY Sales of electricity by the AEP System tend to increase and decrease because of the use of electricity by residential and commercial customers for cooling and heating and relative changes in temperature. FRANCHISES The operating companies of the AEP System hold franchises to provide electric service in various municipalities in their service areas. These franchises have varying provisions and expiration dates. In general, the operating companies consider their franchises to be adequate for the conduct of their business. COMPETITION AND BUSINESS CHANGE General The public utility subsidiaries of AEP, like many other electric utilities, have traditionally provided electric generation and energy delivery, consisting of transmission and distribution services, as a single product to their retail customers. Proposals are being made and legislation has been enacted in Arkansas, Michigan, Ohio, Oklahoma, Texas, Virginia and West Virginia that would also require electric utilities to sell distribution services separately. These measures generally allow competition in the generation and sale of electric power, but not in its transmission and distribution. Competition in the generation and sale of electric power will require resolution of complex issues, including who will pay for the unused generating plant of, and other stranded costs incurred by, the utility when a customer stops buying power from the utility; will all customers have access to the benefits of competition; how will the rules of competition be established; what will happen to conservation and other regulatory-imposed programs; how will the reliability of the transmission system be ensured; and how will the utility's obligation to serve be changed. As competition in generation and sale of electric power is instituted, the public utility subsidiaries of AEP believe that they have a favorable competitive position because of their relatively low costs. If stranded costs are not recovered from customers, however, the public utility subsidiaries of AEP, like all electric utilities, will be required by existing accounting standards to recognize any stranded investment losses. Reference is made to Management's Discussion and Analysis of Results of Operations and Management's Discussion and Analysis of Financial Condition, Contingencies and Other Matters and the footnote to the financial statements entitled Industry Restructuring incorporated by reference in Items 7 and 8, respectively, for further information with respect to competition and business change. AEP Position on Competition AEP favors freedom for customers to purchase electric power from anyone that they choose. Generation and sale of electric power would be in the competitive marketplace. To facilitate reliable, safe and efficient service, AEP supports creation of independent system operators to operate the transmission system in a region of the United States. AEP's working model for industry restructuring envisions a progressive transition to full customer 11 19 choice. Implementation of these measures would require legislative changes and regulatory approvals. The legislatures and/or the regulatory commissions in many states, including some in AEP's service territory, are considering or have adopted "retail customer choice" which, in general terms, means the transmission by an electric utility of electric power generated by an entity of the customer's choice over its transmission and distribution system to a retail customer in such utility's service territory. A requirement to transmit directly to retail customers would have the result of permitting retail customers to purchase electric power, at the election of such customers, not only from the electric utility in whose service area they are located but from another electric utility, an independent power producer or an intermediary, such as a power marketer. Although AEP's power generation would have competitors under some of these proposals, its transmission and distribution would not. If competition develops in retail power generation, the public utility subsidiaries of AEP believe that they should have a favorable competitive position because of their relatively low costs. Legislation to provide for retail competition among electric energy suppliers has been introduced in both the U.S. Senate and House of Representatives. Wholesale The public utility subsidiaries of AEP, like the electric industry generally, face increasing competition to sell available power on a wholesale basis, primarily to other public utilities and also to power marketers. The Energy Policy Act of 1992 was designed, among other things, to foster competition in the wholesale market (a) through amendments to PUHCA, facilitating the ownership and operation of generating facilities by "exempt wholesale generators" (which may include independent power producers as well as affiliates of electric utilities) and (b) through amendments to the Federal Power Act, authorizing the FERC under certain conditions to order utilities which own transmission facilities to provide wholesale transmission services for other utilities and entities generating electric power. The principal factors in competing for such sales are price (including fuel costs), availability of capacity and reliability of service. The public utility subsidiaries of AEP believe that they maintain a favorable competitive position on the basis of all of these factors. However, because of the availability of capacity of other utilities and the lower fuel prices in recent years, price competition has been, and is expected for the next few years to be, particularly important. FERC orders 888 and 889, issued in April 1996, provide that utilities must functionally unbundle their transmission services, by requiring them to use their own tariffs in making off-system and third-party sales. See Transmission Services. The public utility subsidiaries of AEP have functionally separated their wholesale power sales from their transmission functions, as required by orders 888 and 889. Retail The public utility subsidiaries of AEP generally (except in Ohio) have the exclusive right to sell electric power at retail within their service areas, with the exception of Virginia and Texas beginning in 2002 and Ohio. However, they do compete with self-generation and with distributors of other energy sources, such as natural gas, fuel oil and coal, within their service areas. The primary factors in such competition are price, reliability of service and the capability of customers to utilize sources of energy other than electric power. With respect to self-generation, the public utility subsidiaries of AEP believe that they maintain a favorable competitive position on the basis of all of these factors. With respect to alternative sources of energy, the public utility subsidiaries of AEP believe that the reliability of their service and the limited ability of customers to substitute other cost-effective sources for electric power place them in a favorable competitive position, even though their prices may be higher than the costs of some other sources of energy. Significant changes in the global economy in recent years have led to increased price competition for industrial companies in the United States, including those served by the AEP System. Such industrial companies have requested price reductions from their suppliers, including their 12 20 suppliers of electric power. In addition, industrial companies which are downsizing or reorganizing often close a facility based upon its costs, which may include, among other things, the cost of electric power. The public utility subsidiaries of AEP cooperate with such customers to meet their business needs through, for example, various off-peak or interruptible supply options and believe that, as low cost suppliers of electric power, they should be less likely to be materially adversely affected by this competition and may be benefited by attracting new industrial customers to their service territories. AEP Restructuring Plan As a result of deregulating legislation that has been enacted or is being considered in most of the states in which the AEP public utility subsidiaries provide service, AEP has reassessed the corporate ownership of its public utility subsidiaries' assets. Deregulating legislation in some of the states requires the separation of generation assets from transmission and distribution assets. On November 1, 2000, AEP filed with the SEC under PUHCA for approval of a restructuring plan in part to meet the requirements of this legislation. AEP's restructuring plan is designed to align its legal structure and business activities with the requirements of deregulation. AEP's plan contemplates the formation of two first tier subsidiaries that would hold the following public utility assets: - A subsidiary would hold the assets of (i) public utility subsidiaries that remain subject to regulation by at least one state utility commission and (ii) foreign utility subsidiaries subject to regulation as to rates or tariffs. AEP intends for this subsidiary ultimately to hold all transmission and distribution assets. - A subsidiary would hold public utility and non-utility subsidiaries that derive their revenues from competitive activity. AEP intends for this subsidiary to ultimately hold all generation assets not subject to regulation. NEW BUSINESS DEVELOPMENT AEP has expanded its business to non-regulated energy activities through several subsidiaries, including AEP Energy Services, Inc. (AEPES), AEP Resources, Inc. (Resources), AEP Pro Serv, Inc. (formerly AEP Resources Service Company) (Pro Serv) and AEP Communications, LLC (AEP Communications). Wholesale Business Operations Various AEP subsidiaries, including AEPES, engage in wholesale business operations that focus primarily upon the following activities: - Trade and market energy commodities, including electric power, natural gas, natural gas liquids, oil, coal, and SO2 allowances in North America and Europe. - Provide price-risk management services and liquidity through a variety of energy-related financial instruments, including exchange-traded futures and over-the-counter forward, option, and swap agreements. - Enter 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. - Optimize trading and marketing through a diversified portfolio of owned assets and structured third party arrangements, including: - Power generation facilities. - Natural gas pipeline, storage and processing facilities. - Coal mines and related facilities. - Other transportation and fuel supply related assets. - Acquire, develop, engineer, construct, operate and maintain owned and third party exempt wholesale generation and cogeneration facilities and ancillary energy-related assets. 13 21 AEP's subsidiaries are engaged in the engineering and construction for third parties of three power plants in the U. S. with a capacity of 1,910 MW. These plants, which are listed below, will be natural gas-fired facilities that are scheduled to be completed from 2001 to 2003. These projects synchronize the wholesale business through the integration of trading, marketing, engineering, construction and operations. - AEP subsidiaries reached agreement with The Dow Chemical Company to construct a 900MW cogeneration facility in Louisiana. Commercial operation is expected in 2003. - AEP subsidiaries reached agreement with Buckeye (an Ohio electric cooperative) to construct and operate a 510 MW peaking facility in Ohio. This agreement entitles AEP to 100% of the facility's capacity and energy in the upfront operating years through 2005. Commercial operation is expected in 2002. - AEP subsidiaries reached agreement with Twelvepole Creek, LLC, a subsidiary of Columbia Electric, which was subsequently acquired by Orion Power Holdings, Inc., to engineer, procure and construct a 500 MW peaking facility in West Virginia. Commercial operation is expected in May 2001. Houston Pipe Line Company: AEP subsidiaries reached agreement to acquire Houston Pipe Line Company (HPL) and its Bammel Storage Facility (one of the largest natural gas storage facilities in North America). HPL is a Texas intrastate pipeline and, along with Resources' midstream gas assets discussed below which were acquired in 1998, will provide a daily gas capacity of approximately 3.5 billion cubic feet, more than 6,400 miles of natural gas pipeline and a total storage capacity of approximately 128 billion cubic feet of high injection and withdrawal capabilities. ICEX: AEP subsidiaries reached agreement to participate and to make an equity investment in a new internet-based electronic trading system Intercontinental Exchange, L.L.C. (ICEX) that enables participants to initiate, negotiate, and execute trades in the crude oil, natural gas, and spot and forward energy markets. Other investors include global energy companies and leading investment banking firms. This interest, along with an earlier investment in Altra Energy Technologies, Inc., provides additional liquidity trading points for the wholesale trading and marketing platform. CSW Energy: CSW Energy presently owns interests in operating power projects located in Colorado, Florida and Texas. In addition to these projects, CSW Energy has other projects in various stages of development. - CSW Energy has entered into an agreement with Eastman Chemical Company to construct and operate a 440 MW cogeneration facility in Longview, Texas. This facility will be known as the Eastex Cogeneration Project. Construction of the facility began in the fourth quarter of 1999, with expected operation in the second or third quarter of 2001. Excess electricity generated by the plant will be sold in the wholesale market. - In October 1999, GE Capital Structured Finance Group purchased 50% of the equity ownership of Sweeny Cogeneration Limited Partnership. CSW Energy's after-tax earnings from the proceeds of the transaction were approximately $33 million. The agreement between CSW Energy and GE Capital Structured Financial Group provides for additional payments to CSW Energy subject to completion of a planned expansion of the Sweeny cogeneration facility, which may be operational in the second quarter of 2001. CSW International: CSW International currently holds investments in the United Kingdom, Mexico and South America. CSW International and its 50% partner, Scottish Power plc, have entered into a joint venture to construct and operate the South Coast Power Project, a 400 MW combined cycle gas turbine power station in Shoreham, United Kingdom. CSW International has guaranteed approximately Pound Sterling 19 million of the 14 22 Pound Sterling 190 million construction financing. Both the guarantee and the construction financing are denominated in pounds sterling. The U. S. dollar equivalent at December 29, 2000 would be $28.4 million and $284.1 million respectively, using a conversion rate of Pound Sterling 1.00 equals $1.4953. Construction of the project began in March 1999, and commercial operation has begun though it is not yet running at full capacity. Through November 1999, CSW International had purchased a 36% equity interest in Vale for $80 million. In 1998, CSW International also extended $100 million of debt convertible into equity in Vale. In December 1999, CSW International converted $69 million of that $100 million of debt into equity, thereby raising its equity interest in Vale to 44%. CSW International anticipates converting the remaining debt and accrued interest to equity in Caiua, a subsidiary of Vale, on December 1, 2001. CSW International invested $110 million from September through November 1997 for 5% of the common stock of Gener, a Chilean electric company. This investment was sold in December 2000 for $67 million. Resources Resources' primary business is development of, and investment in, exempt wholesale generators, foreign utility companies, qualifying cogeneration facilities and other energy-related domestic and international investment opportunities and projects. Resources has business development offices in London; Beijing; Columbus, Ohio; Sydney and Washington D.C. Resources also indirectly owns CitiPower Pty., an electric distribution and retail sales company in Victoria, Australia. CitiPower serves approximately 250,000 customers in the city of Melbourne. With about 3,100 miles of distribution lines in a service area that covers approximately 100 square miles, CitiPower distributes about 4,800 gigawatt-hours annually. Resources' indirect subsidiary, AEP Pushan Power LDC, has a 70% interest in Nanyang General Light Electric Co., Ltd. (Nanyang Electric), a joint venture organized to develop and build two 125 megawatt coal-fired generating units near Nanyang City in the Henan Province of The Peoples Republic of China. Nanyang Electric was established in 1996 by AEP Pushan Power LDC, Henan Electric Power Development Co. (15% interest) and Nanyang City Hengsheng Energy Development Company Limited (formerly Nanyang Municipal Finance Development Co.) (15% interest). Unit 1 went into service in February 1999 and Unit 2 went into service in June 1999. Resources' share of the total cost of the project of $185,000,000 was approximately $110,000,000. In December 1999, Resources contributed $47,000,000 to acquire a 50% interest in the Bajio power project in Mexico. The Bajio project is a 600 megawatt natural gas-fired, combined cycle plant and related assets located approximately 160 miles from Mexico City. Bechtel Power Corporation, an affiliate of Resources' partner (InterGen), will build the facility, which is estimated to cost $430,000,000. Approximately 80% of the project costs will be provided by third party debt, some of which will be supported by letters of credit issued on behalf of Resources. The facility will be operated and managed by one or more companies jointly owned by Resources and InterGen. Bajio has a 25-year contract to sell 495 megawatts of the plant's output to Mexico's federally owned electric system; the remainder is expected to be sold to industrial customers in the region. The Bajio project was approximately 60% completed as of December 31, 2000 and construction is expected to be completed in the fall of 2001. Resources, through AEP Resources Australia Pty., Ltd., a special purpose subsidiary of Resources, owns a 20% interest in Pacific Hydro Limited. Pacific Hydro is principally engaged in the development and operation of, and ownership of interests in, hydroelectric facilities in the Asia Pacific region. Currently, Pacific Hydro has interests in six hydroelectric units and one wind farm unit that operate or are under construction in Australia and the Philippines. The hydroelectric facilities in which Pacific Hydro had interests as of December 31, 2000 (including those under construction) had total design capacity of approximately 181 megawatts. 15 23 Resources owns midstream gas assets, including: - A 2,000-mile intrastate pipeline system in Louisiana. - Four natural gas processing plants that straddle the pipeline. - A ten billion cubic foot underground natural gas storage facility directly connected to the Henry Hub, the most active gas trading area in North America. The pipeline and storage facilities are interconnected to 15 interstate and 23 intrastate pipelines. U. K. Electric: Resources and another AEP subsidiary have a 50% interest in Yorkshire Electric Group plc (Yorkshire Electricity) with an indirect wholly-owned subsidiary of Xcel Energy, Inc. Yorkshire Electricity is a United Kingdom independent regional electricity company. It is principally engaged in the supply and distribution of electricity. Yorkshire Electricity has two million distribution customers in its authorized service territory which is comprised of 3,860 square miles and located centrally in the east coast of England. In February 2001, AEP entered into an agreement to sell its 50% interest in Yorkshire. The sale is anticipated to be completed in the second quarter of 2001. SEEBOARD, a wholly-owned subsidiary of CSW International, is one of the 12 regional electricity companies formed as a result of the restructuring and subsequent privatization of the United Kingdom electricity industry in 1990. CSW acquired indirect control of SEEBOARD in April 1996. SEEBOARD's principal businesses are the distribution and supply of electricity. In addition, SEEBOARD is engaged in other businesses, including gas supply, electricity generation, and electrical contracting. SEEBOARD's service area covers approximately 3,000 square miles in Southeast England. The area has a population of approximately 4.7 million people with significant portions of the area, such as south London, having a high population density. In a joint venture, SEEBOARD Powerlink won a 30-year contract for $1.6 billion to operate, maintain, finance and renew the high-voltage power distribution network of the London Underground, the largest metropolitan rail system in the world. SEEBOARD's partners in the Powerlink consortium are an international electrical engineering group and an international cable and construction group. On June 30, 1999, SEEBOARD purchased the 50% interest in Beacon Gas held by BP Amoco. Beacon Gas was a joint venture between SEEBOARD and BP Amoco set up for the supply of gas. Pro Serv Pro Serv offers engineering, construction, project management and other consulting services for projects involving transmission, distribution or generation of electric power both domestically and internationally. AEP Communications AEP Communications markets wholesale, high capacity, fiber optic services, colocation, and wireless tower infrastructure services under the C3 brand. In addition to expanding its fiber optic network during 2000, AEP Communications joined with several other energy and telecommunications companies to form AFN Communications, LLC. (AFN). AFN is a super regional telecommunications company that provides long haul fiber optic capacity to competitive local exchange carriers, wireless carriers and long distance companies. AFN does business in New York, Pennsylvania, Virginia, West Virginia, Ohio, Indiana, Michigan, Illinois, and Kentucky, with plans to expand nationally, and has approximately 10,000 route miles of fiber optic network. C3, an entity that was acquired through the merger with CSW, is engaged in providing fiber optic and collocation services in Texas, Louisiana, Oklahoma, Arkansas, and Kansas. C3 does business as C3 Networks and has approximately 5,300 route miles of fiber optic network. AEP Communications also joined with Touch America, Inc. to form American Fiber Touch, LLC, an entity that will construct, own, and market a long haul fiber optic route that interconnects the AEP Communications and C3 through Illinois and Missouri. 16 24 AEP Communications and C3 also operate business units engaged in marketing energy information. AEP Communications offers a portfolio of energy information data and analysis tools designed to help customers identify energy and cost saving opportunities. C3's energy information services include: - Meter reading, validation and settlement services. - Automated meter reading equipment sales and leasing. - Energy information services. - Equipment sales and services. Since the merger of AEP and CSW, a realignment of the energy information business units has taken place through the formation of Datapult Limited Partnership. Energy information services will be offered under the Datapult brand. Evaluation of partnerships and acquisitions will also be a key element of growth for Datapult Limited Partnership in 2001. SEC Limitations AEP has received approval from the SEC under PUHCA to issue and sell securities in an amount up to 100% of its average quarterly consolidated retained earnings balance (such average balance was approximately $3.4 billion for the twelve months ended December 31, 2000) for investment in exempt wholesale generators and foreign utility companies. Resources expects to continue its pursuit of new and existing energy generation and delivery projects worldwide. SEC Rule 58 permits AEP and other registered holding companies to invest up to 15% of consolidated capitalization in energy-related companies. AEPES, an energy-related company under Rule 58, is authorized to engage in energy-related activities, including marketing electricity, gas and other energy commodities. Risk These continuing efforts to invest in and develop new business opportunities offer the potential of earning returns which may exceed those of traditional AEP rate-regulated operations. However, they also involve a higher degree of risk which must be carefully considered and assessed. AEP may make additional substantial investments in these and other new businesses. Reference is made to Market Risks under Item 7A herein for a discussion of certain market risks inherent in AEP business activities. CONSTRUCTION PROGRAM New Generation The AEP System is continuously involved in assessing the adequacy of its generation, transmission, distribution and other facilities to plan and provide for the reliable supply of electric power and energy to its customers. In this assessment process, assumptions are continually being reviewed as new information becomes available, and assessments and plans are modified, as appropriate. Thus, System reinforcement plans are subject to change, particularly with the restructuring of the electric utility industry and the move to increasing competition in the marketplace. See Competition and Business Change. Committed or anticipated capability changes to the AEP System's generation resources include: - Purchase from an independent power producer's hydro project with an expected capacity value of 28 megawatts, commencing June 1, 2001. - Expiration of the Rockport Unit 2 sale of 250 megawatts to Carolina Power & Light Company, an unaffiliated company, on December 31, 2009. Apart from these changes and temporary power purchases that can be arranged, there are no specific commitments for additions of new generation resources on the AEP System. Given the restructuring taking place in the industry, the extent of the need of AEP's operating companies for any additional generation resources in the foreseeable future is highly uncertain. Proposed Transmission Facilities On September 30, 1997, APCo refiled applications in Virginia and West Virginia for certificates to build the Wyoming-Cloverdale 17 25 765,000-volt Project. The preferred route for this line is approximately 132 miles in length, connecting APCo's Wyoming Station in southern West Virginia to APCo's Cloverdale Station near Roanoke, Virginia. APCo's estimated cost for the Wyoming-Cloverdale Project is $283,254,000, assuming a 2004 in-service date. APCo announced this project in 1990. Since then it has been in the process of trying to obtain federal permits and state certificates. At the federal level, the U.S. Forest Service (Forest Service) is directing the preparation of an Environmental Impact Statement (EIS), which is required prior to granting permits for crossing lands under federal jurisdiction. Permits are needed from the (i) Forest Service to cross federal forests, (ii) Army Corps of Engineers to cross the New River and a watershed near the Wyoming Station, and (iii) National Park Service or Forest Service to cross the Appalachian National Scenic Trail. In June 1996, the Forest Service released a Draft EIS and preliminarily identified a "No Action Alternative" as its preferred alternative. If this alternative were incorporated into the Final EIS, APCo would not be authorized to cross federal forests administered by the Forest Service. The Forest Service stated that it would not prepare the Final EIS until after Virginia and West Virginia determined need and routing issues. West Virginia: On May 27, 1998, the West Virginia PSC issued an order granting APCo's application for a certificate with respect to the Wyoming-Cloverdale 765,000-volt Project. On October 27, 2000, APCo filed with the West Virginia PSC a request to amend the certificate by adding the alternative end point of Jacksons Ferry in Virginia as discussed below under Virginia. Virginia: Following several procedural delays and Hearing Examiner's rulings, APCo filed a study in May 1999 identifying the Wyoming-Jacksons Ferry Project as an alternative project to the Wyoming-Cloverdale Project. The Jacksons Ferry Project proposes a line from Wyoming Station in West Virginia to APCo's existing 765,000-volt Jacksons Ferry Station in Virginia. APCo estimates that the Wyoming-Jacksons Ferry line would be between 82-100 miles in length, including 32 miles in West Virginia previously certified. In May 2000, the Virginia SCC held an evidentiary hearing to consider both projects. On October 2, 2000, the Hearing Examiner's report to the Virginia SCC recommended approval of the Wyoming-Jacksons Ferry Alternative Project. The matter is pending before the Virginia SCC. APCo's estimated cost for the Wyoming-Jacksons Ferry Project is $232,455,000, assuming a 2004 in-service date. Proposed Completion Schedule: If the Virginia SCC and West Virginia PSC issue the required certificates, APCo will cooperate with the Forest Service to complete the EIS process and obtain the federal permits. The Forest Service has begun preliminary work on a supplement to the Draft EIS. APCo has also begun required consultation with the U.S. Fish and Wildlife Service under the Endangered Species Act. Management estimates that neither project can be completed before the winter of 2004/2005. However, given the findings in the Draft EIS, APCo cannot presently predict the schedule for completion of the federal permitting process. Construction Expenditures The following table shows construction expenditures during 1998, 1999 and 2000 and current estimates of 2001 construction expenditures, in each case including AFUDC but excluding assets acquired under leases.
1998 1999 2000 2001 ACTUAL ACTUAL ACTUAL ESTIMATE ------ ------ ------ -------- (IN THOUSANDS) AEP System (a).... $792,100 $866,900 $1,773,400 $2,077,400 AEGCo.......... 6,600 8,300 5,200 3,200 APCo........... 204,900 211,400 199,300 394,800 CPL............ 126,600 255,800 199,500 295,000 CSPCo.......... 115,300 115,300 128,000 146,300 I&M............ 148,900 165,300 171,100 127,900 KEPCo.......... 43,800 44,300 36,200 53,400 OPCo........... 185,200 193,900 254,000 447,700 PSO............ 70,100 104,500 176,900 136,600 SWEPCo......... 84,500 112,900 120,200 123,700 WTU............ 37,600 52,600 64,500 77,500
- ----------------------- (a) Includes expenditures of other subsidiaries not shown.. Reference is made to the footnote to the financial statements entitled Commitments and Contingencies incorporated by reference in Item 8, for further information with respect to the construction plans of AEP and its operating subsidiaries for the next three years. 18 26 The System construction program is reviewed continuously and is revised from time to time in response to changes in estimates of customer demand, business and economic conditions, the cost and availability of capital, environmental requirements and other factors. Changes in construction schedules and costs, and in estimates and projections of needs for additional facilities, as well as variations from currently anticipated levels of net earnings, Federal income and other taxes, and other factors affecting cash requirements, may increase or decrease the estimated capital requirements for the System's construction program. From time to time, as the System companies have encountered the industry problems described above, such companies also have encountered limitations on their ability to secure the capital necessary to finance construction expenditures. Environmental Expenditures: Expenditures related to compliance with air and water quality standards, included in the gross additions to plant of the System, during 1998, 1999 and 2000 and the current estimate for 2001 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.
1998 1999 2000 2001 ACTUAL ACTUAL ACTUAL ESTIMATE ------ ------ ------ -------- (IN THOUSANDS) AEGCo................ $800 $8 $70 $100 APCo................. 25,000 24,500 2,100 203,100 CPL.................. (a) (a) (a) 3,300 CSPCo................ 5,300 10,600 6,600 17,700 I&M.................. 13,000 4,500 1,900 7,600 KEPCo................ 4,600 1,900 400 23,300 OPCo................. 27,100 37,400 91,200 271,900 PSO.................. (a) (a) (a) 1,000 SWEPCo............... (a) (a) (a) 13,200 WTU.................. (a) (a) (a) 1,100 ------- ------- -------- -------- AEP System (a)..... $75,800 $78,908 $102,270 $542,300 ======= ======= ======== ========
- ----------------------- (a) Amounts not available for west zone companies of AEP prior to AEP-CSW merger. FINANCING It has been the practice of AEP's operating subsidiaries to finance current construction expenditures in excess of available internally generated funds by initially issuing unsecured short-term debt, principally commercial paper and bank loans, at times up to levels authorized by regulatory agencies, and then to reduce the short-term debt with the proceeds of subsequent sales by such subsidiaries of long-term debt securities and cash capital contributions by AEP. If one or more of the subsidiaries are unable to continue the issuance and sale of securities on an orderly basis, such company or companies will be required to consider the curtailment of construction and other outlays or the use of alternative financing arrangements, if available, which may be more costly. AEP's subsidiaries have also utilized, and expect to continue to utilize, additional financing arrangements, such as unsecured debt and leasing arrangements, including the leasing of utility assets and coal mining and transportation equipment and facilities. Pollution control revenue bonds have been used in the past and may be used in the future in connection with the construction of pollution control facilities; however, Federal tax law has limited the utilization of this type of financing except for purposes of certain financing of solid waste disposal facilities and of certain refunding of outstanding pollution control revenue bonds issued before August 16, 1986. New projects undertaken by AEP's other unregulated subsidiaries are generally financed through equity funds provided by AEP, non-recourse debt incurred on a project-specific basis, debt issued by such subsidiaries or through a combination thereof. See New Business Development and Item 7 for additional information concerning AEP's other unregulated subsidiaries. RATES AND REGULATION General The rates charged by the electric utility subsidiaries of AEP are approved by the FERC or one of the state utility commissions as applicable. The FERC regulates wholesale rates and the state commissions regulate retail rates. In recent years the number of rate increase applications filed by the operating subsidiaries of AEP with their respective state commissions and the FERC has decreased. Under current rate regulation, if increases in operating, construction and capital costs exceed increases in revenues resulting from previously 19 27 granted rate increases and increased customer demand, then it may be appropriate for certain of AEP's electric utility subsidiaries to file rate increase applications in the future. Generally the rates of AEP's operating subsidiaries are determined based upon the cost of providing service including a reasonable return on investment. Certain states served by the AEP System allow alternative forms of rate regulation in addition to the traditional cost-of-service approach. However, the rates of AEP's operating subsidiaries in those states continue to be cost-based. The IURC may approve alternative regulatory plans which could include setting customer rates based on market or average prices, price caps, index-based prices and prices based on performance and efficiency. The Virginia SCC may approve (i) special rates, contracts or incentives to individual customers or classes of customers and (ii) alternative forms of regulation including, but not limited to, the use of price regulation, ranges of authorized returns, categories of services and price indexing. All of the eleven states served by the AEP System, as well as the FERC, either currently permit the incorporation of fuel adjustment clauses in a utility company's rates and tariffs, which are designed to permit upward or downward adjustments in revenues to reflect increases or decreases in fuel costs above or below the designated base cost of fuel set forth in the particular rate or tariff, or currently permit the inclusion of specified levels of fuel costs as part of such rate or tariff. AEP cannot predict the timing or probability of approvals regarding applications for additional rate changes, the outcome of action by regulatory commissions or courts with respect to such matters, or the effect thereof on the earnings and business of the AEP System. In addition, current rate regulation may, and in the case of Ohio, Texas and Virginia will, be subject to significant revision. See Competition and Business Change. FUEL SUPPLY The following table shows the sources of power generated by the AEP System:
1996 1997 1998 1999 2000 ---- ---- ---- ---- ---- Coal........................ 73% 76% 79% 79% 78% Gas......................... 12% 12% 14% 15% 13% Nuclear..................... 11% 8% 3% 3% 5% Hydroelectric and other..... 4% 4% 4% 3% 4%
Variations in the generation of nuclear power are primarily related to refueling outages and, in 1997 through 1999, the shutdown of the Cook Plant to respond to issues raised by the NRC. Natural Gas AEP consumed over 273 billion cubic feet of natural gas during 2000 for the system operating companies, which ranks them as the fourth largest consumer of natural gas in the United States. A majority of the gas fired electric generation plants are connected to at least two natural gas pipelines, which provides greater access to competitive supplies and improves reliability. Natural gas requirements for each plant are supplied by a portfolio of long-term and short-term purchase and transportation agreements which are acquired on a competitive basis and based on market prices. Coal and Lignite The Clean Air Act Amendments of 1990 provide for the issuance of annual allowance allocations covering sulfur dioxide emissions at levels below historic emission levels for many coal-fired generating units of the AEP System. Phase I of this program began in 1995 and Phase II began in 2000, with both phases requiring significant changes in coal supplies and suppliers. The full extent of such changes, particularly in regard to Phase II, however, has not been determined. See Environmental and Other Matters -- Air Pollution Control -- Title IV Acid Rain Program for the current compliance plan. In order to meet emission standards for existing and new emission sources, the AEP System companies will, in any event, have to obtain coal supplies, in addition to coal reserves now owned by System companies, through the acquisition of additional coal reserves and/or by entering into additional supply agreements, either on a long-term or spot basis, at prices and upon terms which cannot now be predicted. No representation is made that any of the coal rights owned or controlled by the System will, in 20 28 future years, produce for the System any major portion of the overall coal supply needed for consumption at the coal-fired generating units of the System. Although AEP believes that in the long run it will be able to secure coal of adequate quality and in adequate quantities to enable existing and new units to comply with emission standards applicable to such sources, no assurance can be given that coal of such quality and quantity will in fact be available. No assurance can be given either that statutes or regulations limiting emissions from existing and new sources will not be further revised in future years to specify lower sulfur contents than now in effect or other restrictions. See Environmental and Other Matters herein. The FERC has adopted regulations relating, among other things, to the circumstances under which, in the event of fuel emergencies or shortages, it might order electric utilities to generate and transmit electric power to other regions or systems experiencing fuel shortages, and to rate-making principles by which such electric utilities would be compensated. In addition, the Federal Government is authorized, under prescribed conditions, to allocate coal and to require the transportation thereof, for the use of power plants or major fuel-burning installations. System companies have developed programs to conserve coal supplies at System plants which involve, on a progressive basis, limitations on sales of power and energy to neighboring utilities, appeals to customers for voluntary limitations of electric usage to essential needs, curtailment of sales to certain industrial customers, voltage reductions and, finally, mandatory reductions in cases where current coal supplies fall below minimum levels. Such programs have been filed and reviewed with officials of Federal and state agencies and, in some cases, the state regulatory agency has prescribed actions to be taken under specified circumstances by System companies, subject to the jurisdiction of such agencies. The mining of coal reserves is subject to Federal requirements with respect to the development and operation of coal mines, and to state and Federal regulations relating to land reclamation and environmental protection, including Federal strip mining legislation enacted in August 1977. Continual evaluation and study is given to possible closure of existing coal mines and divestiture or acquisition of coal properties in light of Federal and state environmental and mining laws and regulations which may affect the System's need for or ability to mine such coal. Western coal purchased by System companies is transported by rail to an affiliated terminal on the Ohio River for transloading to barges for delivery to generating stations on the river. Subsidiaries of AEP own 3,030 coal hopper cars and lease an additional 4,079 coal hopper cars to be used in unit train movements. Subsidiaries of AEP lease 15 towboats, 492 jumbo barges and 145 standard barges. Subsidiaries of AEP also own or lease coal transfer facilities at various other locations. The System generating companies procure coal from coal reserves which are owned or mined by subsidiaries of AEP, and through purchases pursuant to long-term contracts, or on a spot purchase basis, from unaffiliated producers. The following table shows the amount of coal delivered to the AEP System during the past five years, the proportion of such coal which was obtained either from coal-mining subsidiaries, from unaffiliated suppliers under long-term contracts or through spot or short-term purchases, and the average delivered price of spot coal purchased by System companies:
1996(a) 1997(a) 1998(a) 1999(a) 2000 ---- ---- ---- ---- ---- Total coal delivered to AEP operated plants (thousands of tons)........... 51,030 54,292 54,004 54,306 73,259 Sources (percentage): Subsidiaries........................................ 13% 14% 14% 11% 9% Long-term contracts................................. 71% 66% 66% 64% 67% Spot or short-term purchases........................ 16% 20% 20% 24% 24% Average price per ton of spot-purchased coal........... $23.85 $24.38 $25.05 $27.18 $24.03
- -------------------- (a) Includes east zone companies only. 21 29 The average cost of coal consumed during the past five years by all AEP System companies is shown below. AEP System companies data for 1996 and 1997 includes only AEGCo, APCo, CSPCo, I&M, KEPCo and OPCo.
1996 1997 1998 1999 2000 ---- ---- ---- ---- ---- DOLLARS PER TON --------------- AEP System Companies............................. $29.38 $29.68 $29.87 $30.01 $31.39 AEGCo......................................... 18.22 19.30 19.37 20.79 20.65 APCo.......................................... 37.60 36.09 34.81 33.29 32.84 CPL........................................... 28.81 26.93 26.93 26.49 25.95 CSPCo......................................... 31.70 31.69 31.63 29.94 28.50 I&M........................................... 22.99 23.68 22.61 24.54 23.44 KEPCo......................................... 27.25 26.76 27.42 26.76 25.35 OPCo.......................................... 35.96 36.00 38.94 40.56 46.52 PSO........................................... 21.84 21.11 20.37 20.94 21.21 SWEPCo........................................ 23.81 23.16 23.02 21.34 22.59 WTU........................................... 24.41 18.19 21.37 21.72 22.26
1996 1997 1998 1999 2000 ---- ---- ---- ---- ---- CENTS PER MILLION BTU'S ----------------------- AEP System Companies............................. 139.44 140.13 142.17 141.95 149.12 AEGCo......................................... 109.25 115.21 112.63 116.90 116.23 APCo.......................................... 152.54 146.54 141.76 135.40 134.86 CPL........................................... 143.12 136.40 137.00 135.78 137.86 CSPCo......................................... 134.60 134.44 134.15 127.42 120.83 I&M........................................... 121.16 123.36 118.02 121.90 117.99 KEPCo......................................... 114.42 110.37 112.15 109.91 104.88 OPCo.......................................... 151.55 151.66 164.44 169.23 194.77 PSO........................................... 125.87 120.91 116.73 119.54 121.83 SWEPCo........................................ 155.88 152.79 150.62 143.34 144.96 WTU........................................... 146.26 109.13 126.22 129.13 131.56
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, 2000, the System's coal inventory was approximately 35 days of normal System usage. This estimate assumes that the total supply would be utilized by increasing or decreasing generation at particular plants. The following tabulation shows the total consumption during 2000 of the coal-fired generating units of AEP's principal electric utility subsidiaries, coal requirements of these units over the remainder of their useful lives and the average sulfur content of coal delivered in 2000 to these units. Reference is made to Environmental and Other Matters for information concerning current emissions limitations in the AEP System's various jurisdictions and the effects of the Clean Air Act Amendments. 22 30
AVERAGE SULFUR CONTENT ESTIMATED REQUIRE- OF DELIVERED COAL TOTAL CONSUMPTION MENTS FOR REMAINDER -------------------------------- DURING 2000 OF USEFUL LIVES POUNDS OF SO2 (IN THOUSANDS OF TONS) (IN MILLIONS OF TONS) BY WEIGHT PER MILLION BTU'S ---------------------- --------------------- --------- ----------------- AEGCo (a)..................... 4,944 211 0.3% 0.7 APCo.......................... 11,662 384 0.8% 1.2 CPL........................... 2,745 41 0.3% 0.7 CSPCo......................... 6,368 222(b) 2.5% 4.2 I&M (c)....................... 7,342 241 0.7% 1.4 KEPCo......................... 2,794 82 0.9% 1.5 OPCo.......................... 20,723 533(d) 2.1% 3.5 PSO........................... 4,199 47 0.2% 0.5 SWEPCo........................ 12,720 151 0.5% 1.3 WTU........................... 1,519 35 0.4% 0.8 - ------------------------ (a) Reflects AEGCo's 50% interest in the Rockport Plant. (b) Includes coal requirements for CSPCo's interest in Beckjord, Stuart and Zimmer Plants. (c) Includes I&M's 50% interest in the Rockport Plant. (d) Total does not include OPCo's portion of Sporn Plant.
AEGCo: See Fuel Supply -- I&M for a discussion of the coal supply for the Rockport Plant. APCo: Substantially all of the coal consumed at APCo's generating plants is obtained from unaffiliated suppliers under long-term contracts and/or on a spot purchase basis. The average sulfur content by weight of the coal received by APCo at its generating stations approximated 0.8% during 2000, whereas the maximum sulfur content permitted, for emission standard purposes, for existing plants in the regions in which APCo's generating stations are located ranged between 0.78% and 2% by weight depending in some circumstances on the calorific value of the coal which can be obtained for some generating stations. CPL: CPL has coal supply agreements with four coal suppliers which delivered approximately 2,255,000 tons of coal during the year 2000. One contract for Colorado coal extends through 2001 and has 1,000,000 tons to be delivered during that year. Approximately one half of the coal delivered to Coleto Creek is from Wyoming with the other half from Colorado. Both sources supply low sulfur coal with a limit of 1.2 lbs/MMBtu. CSPCo: CSPCo has coal supply agreements with unaffiliated suppliers for the delivery of approximately 3,120,000 tons per year through 2004. Some of this coal is washed to improve its quality and consistency for use principally at Unit 4 of the Conesville Plant. CSPCo has been informed by CG&E and DP&L that, with respect to the CCD Group units partly owned but not operated by CSPCo, sufficient coal has been contracted for or is believed to be available for the approximate lives of the respective units operated by them. Under the terms of the operating agreements with respect to CCD Group units, each operating company is contractually responsible for obtaining the needed fuel. I&M: I&M has two coal supply agreements with unaffiliated Wyoming suppliers for low sulfur coal from surface mines principally for consumption by the Rockport Plant. Under these agreements, the suppliers will sell to I&M, for consumption by I&M at the Rockport Plant or consignment to other System companies, coal with an average sulfur content not exceeding 1.2 pounds of sulfur dioxide per million Btu's of heat input. One contract with remaining deliveries of 45,138,543 tons expires on December 31, 2014 and another contract with remaining deliveries of 26,400,000 tons expires on December 31, 2004. All of the coal consumed at I&M's Tanners Creek Plant is obtained from unaffiliated suppliers under long-term contracts and/or on a spot purchase basis. 23 31 KEPCo: Substantially all of the coal consumed at KEPCo's Big Sandy Plant is obtained from unaffiliated suppliers under long-term contracts and/or on a spot purchase basis. KEPCo has coal supply agreements with unaffiliated suppliers pursuant to which KEPCo will receive approximately 1,600,000 tons of coal in 2001. To the extent that KEPCo has additional coal requirements, it may purchase coal from the spot market and/or suppliers under contract to supply other System companies. OPCo: The coal consumed at OPCo's generating plants is obtained from both affiliated and unaffiliated suppliers. The coal obtained from unaffiliated suppliers is purchased under long-term contracts and/or on a spot purchase basis. OPCo and certain of its coal-mining subsidiaries own or control coal reserves in the State of Ohio containing approximately 145,000,000 tons of clean recoverable coal and ranging in sulfur content between 3.8% and 4.5% sulfur by weight (weighted average, 4.1%), which reserves are presently being mined. OPCo and certain of its mining subsidiaries own an additional 113,000,000 tons of clean recoverable coal in Ohio which ranges in sulfur content between 2.4% and 3.4% sulfur by weight (weighted average 2.7%). Recovery of this coal would require substantial development. OPCo and certain of its coal-mining subsidiaries also own or control coal reserves in the State of West Virginia which contain approximately 96,000,000 tons of clean recoverable coal ranging in sulfur content between 1.4% and 4.0% sulfur by weight (weighted average, 2.0%) of which approximately 19,000,000 tons can be recovered based upon existing mining plans and projections and employing current mining practices and techniques. PSO: The coal contract under which coal is supplied to PSO provides the entire plant requirements with at least 20,285,000 tons remaining to be delivered. The coal is supplied from Wyoming and has a maximum sulfur content of 1.2 lbs. SO2 per MMBtu. SWEPCo: SWEPCo has one coal contract with a Wyoming producer that provides the majority of its coal requirements. The coal is supplied from Wyoming and has a maximum sulfur content of 1.2 lbs. SO2 per MMBtu. SWEPCo has remaining deliveries of approximately 31 million tons through 2006 under this contract. In 2000, the remaining coal requirements for SWEPCo were obtained under short term coal agreements with Wyoming producers. SWEPCo also has a mine-mouth lignite operation in East Texas that provides a low cost source to the Pirkey Plant. North American Coal Company's Sabine Mining Company operates the mine. WTU: WTU has one coal contract designed to supply approximately two thirds of the coal requirements for the Oklaunion Power Station. This contract has approximately 10,920,000 tons remaining to be delivered between 2001 and the middle of 2006. The remaining one third of the coal requirements delivered in 2000 for Oklaunion were under two contracts with Wyoming suppliers. Both were low sulfur coal contracts. Nuclear I&M and STPNOC have made commitments to meet certain of the nuclear fuel requirements of the Cook Plant and STP, respectively. The nuclear fuel cycle consists of: - Mining and milling of uranium ore to uranium concentrates. - Conversion of uranium concentrates to uranium hexafluoride. - Enrichment of uranium hexafluoride. - Fabrication of fuel assemblies. - Utilization of nuclear fuel in the reactor. - Disposition of spent fuel. Steps currently are being taken, based upon the planned fuel cycles for the Cook Plant, to review and evaluate I&M's requirements for the supply of nuclear fuel. I&M has made and will make 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. 24 32 CPL and the other STP participants have entered into contracts with suppliers for 100% of the uranium concentrate sufficient for the operation of both STP units through Fall 2005 and with an additional 50% of the uranium concentrate needed for STP through Spring 2006. In addition, CPL and the other STP participants have entered into contracts with suppliers for 100% of the nuclear fuel conversion service sufficient for the operation of both STP units through Spring 2003, with additional flexible contracts to provide at least 50% of the conversion service needed for STP through 2005. CPL and the other STP participants have entered into flexible contracts to provide for 100% of enrichment through Spring 2003, with additional flexible contracts to provide at least 40% of enrichment services through Fall 2005. Also, fuel fabrication services have been contracted for operation through 2028 for Unit 1 and 2029 for Unit 2. For purposes of the storage of high-level radioactive waste in the form of spent nuclear fuel, I&M has completed modifications to its spent nuclear fuel storage pool. AEP anticipates that the Cook Plant has storage capacity to permit normal operations through 2012. STP has on-site storage facilities with the capability to store the spent nuclear fuel generated by the STP units over their licensed lives. The costs of nuclear fuel consumed by I&M and CPL do not assume any residual or salvage value for residual plutonium and uranium. Nuclear Waste and Decommissioning Reference is made to Management's Discussion and Analysis of Results of Operations and Management's Discussion and Analysis of Financial Condition, Contingencies and Other Matters in the financial statements and Commitments and Contingencies in the footnotes to these statements that are incorporated by reference in Items 7 and 8, respectively, for information with respect to nuclear waste and decommissioning and related litigation. The ultimate cost of retiring the Cook Plant and STP may be materially different from estimates and funding targets as a result of the: - Type of decommissioning plan selected. - Escalation of various cost elements (including, but not limited to, general inflation). - Further development of regulatory requirements governing decommissioning. - Limited availability to date of significant experience in decommissioning such facilities. - Technology available at the time of decommissioning differing significantly from that assumed in these studies. - Availability of nuclear waste disposal facilities. Accordingly, management is unable to provide assurance that the ultimate cost of decommissioning the Cook Plant and STP will not be significantly greater than current projections. Low-Level Waste: The Low-Level Waste Policy Act of 1980 (LLWPA) mandates that the responsibility for the disposal of low-level waste rests with the individual states. Low-level radioactive waste consists largely of ordinary refuse and other items that have come in contact with radioactive materials. To facilitate this approach, the LLWPA authorized states to enter into regional compacts for low-level waste disposal subject to Congressional approval. The LLWPA also specified that, beginning in 1986, approved compacts may prohibit the importation of low-level waste from other regions, thereby providing a strong incentive for states to enter into compacts. Michigan, the state where the Cook Plant is located, was a member of the Midwest Compact, but its membership was revoked in 1991. As a result, Michigan is responsible for developing a disposal site for the low-level waste generated in Michigan. 25 33 Although Michigan amended its law regarding low-level waste site development in 1994 to allow a volunteer to host a facility, little progress has been made to date. A bill was introduced in 1996 to further address the issue but no action was taken. Development of required legislation and progress with the site selection process has been inhibited by many factors, and management is unable to predict when a new disposal site for Michigan low-level waste will be available. Texas is a member of the Texas Compact, which includes the states of Maine and Vermont. Texas had identified a disposal site in Hudspeth County for construction of a low-level waste disposal facility. During the licensing process for the Hudspeth site, that site was found to be unsuitable. No additional site has been considered. Several bills have been submitted in the Texas legislature in 2001 to address this issue. Management is unable to predict when a disposal site for Texas low-level waste will be available. On July 1, 1995, the disposal site in South Carolina reopened to accept waste from most areas of the U.S., including Michigan and Texas. This was the first opportunity for the Cook Plant to dispose of low-level waste since 1990. To the extent practicable, the waste formerly placed in storage and the waste presently generated by the Cook Plant and STP are now being sent to the disposal site. Under state law, the amounts of low-level radioactive waste being disposed of at the South Carolina facility from non-regional generators, such as the Cook Plant and STP, are limited and being reduced. Non-regional access to the South Carolina facility is currently allowed through the end of fiscal year 2008. ENVIRONMENTAL AND OTHER MATTERS AEP's subsidiaries are subject to regulation by federal, state and local authorities with regard to air and water-quality control and other environmental matters, and are subject to zoning and other regulation by local authorities. In addition to imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. It is expected that: - Costs related to environmental requirements will eventually be reflected in the rates of AEP's electric utility subsidiaries, or where states are deregulating generation, unbundled transition period generation rates, stranded cost wires charges and future market prices for electricity. - AEP's electric utility subsidiaries will be able to provide for required environmental controls. However, some customers may curtail or cease operations as a consequence of higher energy costs. There can be no assurance that all such costs will be recovered. Moreover, legislation recently adopted by certain states and proposed at the state and federal level governing restructuring of the electric utility industry may also affect the recovery of certain costs. See Competition and Business Change. Except as noted herein, AEP's subsidiaries that own or operate generating, transmission and distribution facilities are in substantial compliance with pollution control laws and regulations. Reference is made to Management's Discussion and Analysis of Results of Operations and Management's Discussion and Analysis of Financial Condition, Contingencies and Other Matters and the footnote to the financial statements entitled Commitments and Contingencies incorporated by reference in Items 7 and 8, respectively, for further information with respect to environmental matters. Air Pollution Control For the AEP System operating companies, compliance with the CAA is requiring substantial expenditures that generally are being recovered through the rates of AEP's operating subsidiaries. Certain matters discussed below may require significant additional operating and capital expenditures. However, there can be no assurance that all such costs will be recovered. See Construction Program -- Construction Expenditures. 26 34 Title I National Ambient Air Quality Standards Attainment: In July 1997, Federal EPA revised the ozone and particulate matter National Ambient Air Quality Standards (NAAQS), creating a new eight-hour ozone standard and establishing a new standard for particulate matter less than 2.5 microns in diameter (PM2.5). Both of these new standards have the potential to affect adversely the operation of AEP System generating units. In May 1999, the U.S. Court of Appeals for the District of Columbia Circuit remanded the ozone and PM2.5 NAAQS to Federal EPA. In February 2001, the U.S. Supreme Court issued an opinion reversing in part and affirming in part the Court of Appeals decision. The Supreme Court remanded the case to the Court of Appeals for further proceedings, including a review of whether adoption of the standards was arbitrary and capricious and directed Federal EPA to develop a policy for implementing the revised ozone standard in conformity with the CAA. NOx SIP Call: In October 1998, Federal EPA issued a final rule (NOx transport SIP call or NOx SIP Call) establishing state-by-state NOx emission budgets for the five-month ozone season to be met beginning May 1, 2003. The NOx budgets originally applied to 22 eastern states and the District of Columbia and are premised mainly on the assumption of controlling power plant NOx emissions projected for the year 2007 to 0.15 lb. per million Btu (approximately 85% below 1990 levels), although the reductions could be substantially greater for certain State Implementation Plans. The SIP call was accompanied by a proposed Federal Implementation Plan, which could be implemented in any state that fails to submit an approvable SIP. The NOx reductions called for by Federal EPA are targeted at coal-fired electric utilities and may adversely impact the ability of electric utilities to obtain new and modified source permits or to operate affected facilities without making significant capital expenditures. In October 1998, the AEP System operating companies joined with certain other parties seeking a review of the final NOx SIP Call rule in the U.S. Court of Appeals for the District of Columbia Circuit. In March 2000, the court issued a decision upholding the major provisions of the rule. The court subsequently extended the date for submission of SIP revisions until October 30, 2000, and the compliance deadline until May 31, 2004. On March 5, 2001, the U.S. Supreme Court denied petitions filed by industry petitioners, including AEP System operating companies, seeking review of the Court of Appeals decision. In December 2000, Federal EPA issued a determination that eleven states, including certain states in which AEP System operating companies have sources covered by the NOx SIP Call rule, had failed to submit complying SIP revisions. This determination has been appealed by AEP System operating companies and unaffiliated utilities to the U.S. Court of Appeals for the District of Columbia Circuit. In April 2000, the Texas Natural Resource Conservation Commission adopted rules requiring significant reductions in NOx emissions from utility sources, including those of CPL and SWEPCo. The rule compliance date is May 2003 for CPL and May 2005 for SWEPCo. Preliminary estimates indicate that compliance with the revised NOx SIP Call rule, and SIP revisions already adopted, could result in required capital expenditures for the AEP System of approximately $1.6 billion. AEP operating company estimates are as follows:
(IN MILLIONS) AEGCo...................................................$125 APCo.....................................................365 CPL.......................................................57 CSPCo....................................................106 I&M......................................................202 KEPCo....................................................140 OPCo.....................................................606 SWEPCo....................................................28
In June 2000 OPCo announced that it was beginning a $175 million installation of selective catalytic reduction technology (expected to be operational in 2001) to reduce NOx emissions on its two-unit 2,600 MW Gavin Plant. Construction of selective catalytic reduction technology on Amos Plant Unit 3, which is jointly owned by OPCo and APCo, and APCo's Mountaineer Plant is scheduled to begin in 2001. The Amos and Mountaineer projects (expected to be completed in 2002) are estimated to cost a total of $230 million. Management has undertaken the Gavin, Amos and Mountaineer projects to meet applicable NOx emission reduction requirements. 27 35 Since compliance costs cannot be estimated with certainty, the actual costs to comply could be significantly different from this preliminary estimate 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 through regulated rates and/or future market prices for electricity where generation is deregulated, they will have a material adverse effect on future results of operations, cash flows and possibly financial condition of AEP and its affected subsidiaries. Section 126 Petitions: In January 2000, Federal EPA adopted a revised rule granting petitions filed by certain northeastern states under Section 126 of the CAA. The petitions sought significant reductions in nitrogen oxide emissions from utility and industrial sources. The rule imposes emission reduction requirements comparable to the NOx SIP Call rule beginning May 1, 2003, for most of AEP's coal-fired generating units. Certain AEP System operating companies and other utilities filed petitions for review in the U.S. Court of Appeals for the District of Columbia Circuit. Briefing has been completed and oral argument was held in December 2000. Cost estimates for compliance with Section 126 are projected to be somewhat less than those set forth above for the NOx SIP Call rule reflecting the fact that Section 126 does not apply to I&M's Rockport Plant. West Virginia SO2 Limits: West Virginia promulgated SO2 limitations, which Federal EPA approved in February 1978. The emission limitations for OPCo's Mitchell Plant have been approved by Federal EPA for primary ambient air quality (health-related) standards only. West Virginia is obligated to reanalyze SO2 emission limits for the Mitchell Plant with respect to secondary ambient air quality (welfare-related) standards. Because the CAA provides no specific deadline for approval of emission limits to achieve secondary ambient air quality standards, it is not certain when Federal EPA will take dispositive action regarding the Mitchell Plant. In August 1994, Federal EPA issued a Notice of Violation to OPCo alleging that Kammer Plant was operating in violation of the applicable federally enforceable SO2 emission limit. In May 1996, the Notice of Violation and an enforcement action subsequently filed by Federal EPA were resolved through the entry of a consent decree in the U.S. District Court for the Northern District of West Virginia. Kammer Plant has achieved and maintained compliance with the applicable SO2 emission limit for a period in excess of one year, pursuant to the provisions of the consent decree. OPCo is currently seeking the termination of the consent decree. Short Term SO2 Limits: In January 1997, Federal EPA proposed a new intervention level program under the authority of Section 303 of the CAA to address five-minute peak SO2 concentrations believed to pose a health risk to certain segments of the population. The proposal establishes a "concern" level and an "endangerment" level. States must investigate exceedances of the concern level and decide whether to take corrective action. If the endangerment level is exceeded, the state must take action to reduce SO2 levels. In January 2001, Federal EPA published a Federal Register notice inviting comment with respect to its decision not to promulgate a five-minute SO2 NAAQS and intent to take final action on the intervention level program by the summer of 2001. The effect of this proposed intervention program on AEP operations cannot be predicted at this time. Hazardous Air Pollutants: Hazardous air pollutant (HAP) emissions from utility boilers are potentially subject to control requirements under Title III of the CAAA which specifically directed Federal EPA to study potential public health impacts of HAPs emitted from electric utility steam generating units. In December 2000, Federal EPA announced its intent to regulate emissions of mercury from coal and oil-fired power plants, concluding that these emissions pose significant hazards to public health. A decision on whether to regulate other HAPs emissions from these sources was deferred. Federal EPA added coal and oil-fired electric utility steam generating units to the list of "major sources" of HAPs under Section 112 (c) of the CAA, which compels the development of "Maximum Achievable Control Technology" (MACT) standards for these units. Listing under Section 112 (c) also compels a preconstruction permitting obligation to establish case-by-case MACT standards for each new, modified, or 28 36 reconstructed source in the category. MACT standards for utility mercury emissions are scheduled to be proposed by December 2003 and finalized by December 2004. On February 16 and 20, 2001, utility industry groups filed petitions for review of Federal EPA's action in the U.S. Court of Appeals for the District of Columbia Circuit. On February 23, 2001, the Utility Air Regulatory Group (which includes AEP System operating companies as members) filed a petition with Federal EPA seeking reconsideration of the decision to regulate mercury emissions from power plants under Section 112(c) of the CAA. In addition, Federal EPA is required to study the deposition of hazardous pollutants in the Great Lakes, the Chesapeake Bay, Lake Champlain, and other coastal waters. As part of this assessment, Federal EPA is authorized to adopt regulations to prevent serious adverse effects to public health and serious or widespread environmental effects. In 1998, Federal EPA determined that the CAA is adequate to address any adverse public health or environmental effects associated with the atmospheric deposition of hazardous air pollutants in the Great Lakes. Title IV Acid Rain Program: The Acid Rain Program (Title IV) of the CAAA created an emission allowance program pursuant to which utilities are authorized to emit a designated quantity of SO2, measured in tons per year. Phase II of the Acid Rain Program, which affects all fossil fuel-fired steam generating units with capacity greater than 25 megawatts imposed more stringent SO2 emission control requirements beginning January 1, 2000. If a unit emitted SO2 in 1985 at a rate in excess of 1.2 pounds per million Btu heat input, the Phase II allowance allocation is premised upon an emission rate of 1.2 pounds at 1985 utilization levels. Future SO2 allowance requirements will be met through accumulation, acquisition, the use of controls or fuels, or a combination thereof. Title IV of the CAAA also regulates emissions of NOx. Federal EPA has promulgated NOx emission limitations for all boiler types in the AEP System at levels significantly below original design, which were to be achieved by January 1, 2000 on a unit-by-unit or System-wide average basis. AEP sources subject to Title IV of the CAAA are in compliance with the provisions thereof. Regional Haze: In July 1999, Federal EPA finalized rules to regulate regional haze attributable to anthropogenic emissions. The primary goal of the new regional haze program is to address visibility impairment in and around "Class I" protected areas, such as national parks and wilderness areas. Because regional haze precursor emissions are believed by Federal EPA to travel long distances, Federal EPA proposes to regulate such precursor emissions in every state. Under the proposal, each state must develop a regional haze control program that imposes controls necessary to steadily reduce visibility impairment in Class I areas on the worst days and that ensures that visibility remains good on the best days. The AEP System is a significant emitter of fine particulate matter and other precursors of regional haze. Federal EPA's regional haze rule may have an adverse financial impact on AEP as it may trigger the requirement to install costly new pollution control devices to control emissions of fine particulate matter and its precursors (including SO2 and NOx). The actual impact of the regional haze regulations cannot be determined at this time. AEP System operating companies and other utilities filed a petition seeking a review of the regional haze rule in the U.S. Court of Appeals for the District of Columbia Circuit in August 1999. In January 2001, Federal EPA announced that it is considering the issuance of proposed guidelines for states to use in setting Best Available Retrofit Technology (BART) emission limits for power plants and other large emission sources. The proposal would call for technologies to reduce visibility-impairing emissions by 90 to 95 percent. Emission trading programs could be used in lieu of unit-by-unit BART requirements under the proposal, provided they yield greater visibility improvement and emission reductions. Permitting and Enforcement: The CAAA expanded the enforcement authority of the federal government by: - .Increasing the range of civil and criminal penalties for violations of the CAA and enhancing administrative civil provisions. 29 37 - Imposing a national operating permit system, emission fee program and enhanced monitoring, recordkeeping and reporting requirements. Section 103 of CERCLA and Section 304 of the Emergency Planning and Community Right-to-Know Act require notification to state and federal authorities of releases of reportable quantities (RQs) of hazardous and extremely hazardous substances. A number of these substances are emitted by AEP's power plants and other sources. Until recently, emissions of these substances, whether expressly limited in a permit or otherwise subject to federal review or waiver (e.g., mercury), were deemed "federally permitted releases" which did not require emergency notification. In December 1999, Federal EPA published interim guidance in the Federal Register, which provided that any hazardous substance or extremely hazardous substance not expressly and individually limited in a permit must be reported if they are emitted at levels above an RQ. Specifically, constituents of regulated pollutants (e.g., metals contained in particulate matter) were not deemed to be federally permitted. AEP System operating companies provided supplemental information regarding air releases from their facilities in the spring of 2000. Annual follow-up reports will be submitted in April 2001. Global Climate Change: In December 1997, delegates from 167 nations, including the U.S., agreed to a treaty, known as the "Kyoto Protocol," establishing legally-binding emission reductions for gases suspected of causing climate change. If the U.S. becomes a party to the treaty, it will be bound to reduce emissions of CO2, methane and nitrous oxides by 7% below 1990 levels and emissions of hydrofluorcarbons, perfluorocarbons and sulfur hexafluoride 7% below 1995 levels in the years 2008-2012. The Protocol requires ratification by at least 55 nations that account for at least 55% of developed countries' 1990 emissions of CO2 to enter into force. Although the U.S. agreed to the treaty and President Clinton signed it on November 12, 1998, the treaty has not been sent to the Senate for its advice and consent to ratification. In a letter dated March 13, 2001 from President Bush to four U. S. senators, he indicated his opposition to the Kyoto Protocol and said he does not believe that the government should impose mandatory emissions reductions for CO2 on the electric utility sector. The treaty is currently incomplete and international negotiations that were to resolve the outstanding issues were suspended in November 2000. The major issues requiring resolution include: - Participation by developing countries in the control requirements. - Rules, procedures, methodologies and guidelines of the treaty's emission trading and joint implementation provisions. - Crediting for terrestrial carbon sequestration activities. - Compliance enforcement provisions. Negotiations are scheduled to resume in July 2001. Since the AEP System is a significant emitter of carbon dioxide, its results of operations, cash flows and financial condition could be materially adversely affected by the imposition of limitations on CO2 emissions if compliance costs cannot be fully recovered from customers. In addition, any such severe program to reduce CO2 emissions could impose substantial costs on industry and society and erode the economic base that AEP's operations serve. However, it is management's belief that the Kyoto Protocol is highly unlikely to be ratified or implemented in the U. S. in its current form. New Source Review: In July 1992, Federal EPA published final regulations governing application of new source rules to generating plant repairs and pollution control projects undertaken to comply with the CAA. Generally, the rule provides that plants undertaking pollution control projects will not trigger New Source Review (NSR) requirements. The Natural Resources Defense Council and a group of utilities, including five AEP System operating companies, filed petitions in the U.S. Court of Appeals for the District of Columbia Circuit seeking a review of the regulations. In July 1998, Federal EPA requested comment on proposed revisions to 30 38 the New Source Review rules, which would change New Source Review applicability criteria by eliminating exclusions contained in the current regulation. New Source Review Litigation: On November 3, 1999, following issuance by Federal EPA of substantial information requests to AEP System operating companies, the Department of Justice (DOJ), on Federal EPA's behalf, filed a complaint in the U.S. District Court for the Southern District of Ohio that alleges AEP made modifications to generating units at certain of its coal-fired generating plants over the course of the past 25 years that extend unit operating lives or restore or increase unit generating capacity without a preconstruction permit in violation of the CAA. The complaint named OPCo's Cardinal Unit 1, Mitchell, Muskingum River, and Sporn plants and I&M's Tanners Creek plant. Federal EPA also issued Notices of Violation to AEP alleging similar violations at certain other AEP plants. In March 2000, DOJ filed an amended complaint that added allegations for certain of the AEP plants previously named in the complaint as well as counts for APCo's Amos, Clinch River, and Kanawha River plants, CSPCo's Conesville Plant, and OPCo's Kammer Plant. In addition to the allegations regarding New Source Review and New Source Performance Standard violations, DOJ included allegations regarding visible particulate emission violations for Cardinal and Muskingum River plants. A number of northeastern and eastern states have been allowed to intervene in the litigation, and a number of special interest groups filed a separate complaint based on substantially similar allegations, which has been consolidated with the DOJ complaint. In addition to the plants named by the government and special interest groups, the intervenor states have included allegations concerning OPCo's Gavin Plant. On May 10, 2000, AEP filed a motion to dismiss with the District Court, which, if granted, would dispose of most of the claims of the government and intervenors. This motion is currently pending before the Court. On February 23, 2001, the plaintiffs filed a motion for partial summary judgment seeking a determination that four projects undertaken on units at Sporn, Cardinal, and Clinch River Plants do not constitute "routine maintenance, repair and replacement" as used in the NSR programs. Management believes its maintenance, repair and replacement activities were in conformity with the Clean Air Act and intends to vigorously pursue its defense. A number of unaffiliated utilities have also received notices of violation, complaints, or administrative orders relating to NSR. A notice of violation was issued in June 2000 to DP&L with respect to its ownership interest in Stuart Station, in which CSPCo also owns a 26 percent interest. W.C. Beckjord Unit 6, operated by CG&E, in which CSPCo owns a 12.5 percent interest, is also the subject of an enforcement action. CG&E and VEPCo have each entered into an agreement in principle with the DOJ in an attempt to resolve the litigation, but no final agreements have been announced. One of the unaffiliated utilities, Tampa Electric Company, has reached a settlement in its litigation with the Federal government. The CAA authorizes civil penalties of up to $27,500 per day per violation at each generating unit ($25,000 per day prior to January 30, 1997). Civil penalties, if ultimately imposed by the court, and the cost of any required new pollution control equipment, if the court accepts Federal EPA's contentions, could be substantial. In November 2000, several environmental groups filed a petition with Ohio EPA seeking to have the draft Title V operating permits for OPCo's Cardinal and Muskingum River plants as well as the Beckjord Plant and a plant owned by an unaffiliated utility, modified to incorporate requirements and timetables for compliance with New Source Review requirements. In December 2000, a petition was filed by these groups with the Administrator of Federal EPA seeking a similar modification of the final Title V permit for CSPCo's Conesville Plant. Ohio EPA has refused to consider these petitions outside the regular Title V permit processing procedures or to interfere with the resolution of these issues by the District Court. 31 39 In the event AEP does not prevail, any capital and operating costs of additional pollution control equipment that may be required as well as any penalties imposed could materially adversely affect future results of operations, cash flows and possibly financial condition unless such costs can be recovered through regulated rates, and where states are deregulating generation, unbundled transition period generation rates, wires charges and future market prices for energy. Water Pollution Control The Clean Water Act prohibits the discharge of pollutants to waters of the United States from point sources except pursuant to an NPDES permit issued by Federal EPA or a state under a federally authorized state program. Under the Clean Water Act, effluent limitations requiring application of the best available technology economically achievable are to be applied, and those limitations require that no pollutants be discharged if Federal EPA finds elimination of such discharges is technologically and economically achievable. The Clean Water Act provides citizens with a cause of action to enforce compliance with its pollution control requirements. Since 1982, many such actions against NPDES permit holders have been filed. To date, no AEP System plants have been named in such actions. All AEP System generating plants are required to have NPDES permits and have received them. Under Federal EPA's regulations, operation under an expired NPDES permit is authorized provided an application is filed at least 180 days prior to expiration. Renewal applications are being prepared or have been filed for renewal of NPDES permits that expire in 2001. The NPDES permits generally require that certain thermal impact study programs be undertaken. These studies have been completed for all System plants. Thermal variances are in effect for all plants with once-through cooling water. The thermal variances for CSPCo's Conesville and OPCo's Muskingum River plants impose thermal management conditions that could result in load curtailment under certain conditions, but the cost impacts are not expected to be significant. Based on favorable results of in-stream biological studies, the thermal limits for both Conesville and Muskingum River plants were raised in the renewed permits issued in 1996. Consequently, the potential for load curtailment and adverse cost impacts was further reduced. Section 316(b) of the Clean Water Act requires that cooling water intake structures reflect the best technology available (BTA) for minimizing adverse environmental impact. Under a revised court established schedule, Federal EPA is required to develop regulations defining adverse impacts and BTA for new sources by November 2001. Regulations applicable to existing power plants are not required to be issued by Federal EPA until August 2003. As part of the rulemaking, Federal EPA has issued questionnaires to power plants, including AEP System plants, requesting information on impingement and entrainment of aquatic organisms from existing plant cooling water intakes. Federal EPA's rulemaking could result in a definition of BTA that would affect any new plant construction and could ultimately require retrofitting of certain existing plant intake structures. Such changes would involve costs for AEP System operating companies, but the significance of these costs cannot be determined at this time. Certain mining operations conducted by System companies as discussed under Fuel Supply are also subject to federal and state water pollution control requirements, which may entail substantial expenditures for control facilities, not included at present in the System's construction cost estimates set forth herein. Section 303 of the Federal Clean Water Act requires states to adopt stringent water quality standards for a large category of toxic pollutants and to identify specialized control measures for dischargers to waters where it is shown that water quality standards are not being met. In order to bring these waters back into compliance, total maximum daily load (TMDL) allocations of these pollutants will be made, and subsequently translated into discharge limits in NPDES permits. Federal EPA has also directed that states take action to adopt enhanced anti-degradation of water quality requirements. Implementation of these provisions 32 40 could result in significant costs to the AEP System if biological monitoring requirements and water quality-based effluent limits and requirements are placed in NPDES permits. In March 1995, Federal EPA finalized a set of rules that establish minimum water quality standards, anti-degradation policies and implementation procedures for more stringently controlling releases of toxic pollutants into the Great Lakes system. This regulatory package is called the Great Lakes Water Quality Initiative (GLWQI). The most direct compliance cost impact could be related to I&M's Cook Plant. Based on Federal EPA's current policy on intake credits and site specific variables and Michigan's implementation strategy, management does not presently expect the GLWQI will have a significant adverse impact on Cook Plant operations. If Indiana and Ohio eventually adopt the GLWQI criteria for statewide application, AEP System plants located in those states could be adversely affected, although the significance depends on the implementation strategy of those states. Oil Pollution Act: The Oil Pollution Act of 1990 (OPA) defines certain facilities that, due to oil storage volume, and location, could reasonably be expected to cause significant and substantial harm to the environment by discharging oil. Such facilities must operate under approved spill response plans and implement spill response training and drill programs. OPA imposes substantial penalties for failure to comply. AEP System operating companies with oil handling and storage facilities meeting the OPA criteria have in place required response plans, training and drill programs. Solid and Hazardous Waste Section 311 of the Clean Water Act imposes substantial penalties for spills of Federal EPA-listed hazardous substances into water and for failure to report such spills. CERCLA expanded the reporting requirement to cover the release of hazardous substances generally into the environment, including water, land and air. AEP's subsidiaries store and use some of these hazardous substances, including PCBs contained in certain capacitors and transformers, but the occurrence and ramifications of a spill or release of such substances cannot be predicted. CERCLA, RCRA and similar state laws provide governmental agencies with the authority to require cleanup of hazardous waste sites and releases of hazardous substances into the environment and to seek compensation for damages to natural resources. Since liability under CERCLA is strict, joint and several, and can be applied retroactively, AEP System operating companies which previously disposed of PCB-containing electrical equipment and other hazardous substances may be required to participate in remedial activities at such disposal sites should environmental problems result. AEP System operating companies are identified as Potentially Responsible Parties (PRPs) for five federal sites where remediation has not been completed, including APCo at one site, CSPCo at one site, I&M at two sites, and OPCo at one site. Management's present estimates do not anticipate material clean-up costs for identified sites for which AEP subsidiaries have been declared PRPs. However, if significant costs are incurred for cleanup, future results of operations and possibly financial condition could be adversely affected unless the costs can be recovered through rates and/or future market prices for electricity where generation is deregulated. Regulations issued by Federal EPA under the Toxic Substances Control Act govern the use, distribution and disposal of PCBs, including PCBs in electrical equipment. Deadlines for removing certain PCB-containing electrical equipment from service have been met. In addition to handling hazardous substances, the System companies generate solid waste associated with the combustion of coal, the vast majority of which is fly ash, bottom ash and flue gas desulfurization wastes. These wastes presently are considered to be non-hazardous under RCRA and applicable state law and the wastes are treated and disposed of in surface impoundments or landfills in accordance with state permits or authorization or are beneficially utilized. As required by RCRA, Federal EPA evaluated whether high volume coal combustion wastes (such as fly ash, bottom ash and flue gas desulfurization wastes) should be regulated as hazardous waste. In August 1993, Federal EPA issued a regulatory determination that such high 33 41 volume coal combustion wastes should not be regulated as hazardous waste. Federal EPA chose to address separately the issue of low volume wastes (such as metal and boiler cleaning wastes) associated with burning coal and other fossil fuels. In May 2000, Federal EPA issued a regulatory determination that such low volume wastes are also excluded from regulation under the RCRA hazardous waste provisions when mixed and co-managed with high volume fossil fuel combustion wastes. All presently generated hazardous waste is being disposed of at permitted off-site facilities in compliance with applicable federal and state laws and regulations. For System facilities that generate such wastes, System companies have filed the requisite notices and are complying with RCRA and applicable state regulations for generators. Nuclear waste produced at the Cook Plant and STP and regulated under the Atomic Energy Act is excluded from regulation under RCRA. Underground Storage Tanks: Federal EPA's technical requirements for underground storage tanks containing petroleum required retrofitting or replacement of an appreciable number of tanks. Compliance costs for tank replacement were not significant. Some limited site remediation associated with tank removal is ongoing, but these costs are not expected to be significant. Electric and Magnetic Fields (EMF) EMF is found everywhere there is electricity. Electric fields are created by the presence of electric charges. Magnetic fields are produced by the flow of those charges. This means that EMF is created by electricity flowing in transmission and distribution lines, electrical equipment, household wiring, and appliances. A number of studies in the past several years have examined the possibility of adverse health effects from EMF. While some of the epidemiological studies have indicated some association between exposure to EMF and health effects, the majority of studies have indicated no such association. The Energy Policy Act of 1992 established a coordinated Federal EMF research program which ended in 1998. In 1999, the National Institute of Environmental Health Sciences (NIEHS), as required by the Act, provided a report to Congress summarizing the results of this program. The report concluded that "the probability that ...EMF is truly a health hazard is currently small" and that the evidence that exists for health effects is "insufficient to warrant aggressive regulatory actions." Nevertheless, the NIEHS identified several areas where further research might be warranted. AEP has supported EMF research through the years and continues to fund the Electric Power Research Institute's EMF research program, contributing over $400,000 to this program in 2000 and intending to contribute a similar amount in 2001. See Research and Development. AEP's participation in these programs is a continuation of its efforts to monitor and support further research and to communicate with its customers and employees about this issue. Residential customers of AEP are provided information and field measurements on request, although there is no scientific basis for interpreting such measurements. A number of lawsuits based on EMF-related grounds have been filed against electric utilities. A suit was filed on May 23, 1990 against I&M involving claims that EMF from a 345 KV transmission line caused adverse health effects. On March 23, 1998 the court ruled that the plaintiffs failed to prove that I&M caused any of the injuries claimed by the plaintiffs. This part of the trial court's decision was upheld on appeal. Certain issues unrelated to health effects are pending at the trial court. No specific amount has been requested for damages in this case. Mediation is scheduled for June, 2001. Some states have enacted regulations to limit the strength of magnetic fields at the edge of transmission line rights-of-way. No state which the AEP System serves has done so. Management cannot predict the ultimate impact of the question of EMF exposure and adverse health effects. If further research shows that EMF exposure contributes to increased risk of cancer or other health problems, or if the courts conclude that EMF exposure harms individuals and that utilities are liable for damages, or if states limit the strength of magnetic fields to such a level that the current 34 42 electricity delivery system must be significantly changed, then the results of operations and financial condition of AEP and its operating subsidiaries could be materially adversely affected unless these costs can be recovered from ratepayers. RESEARCH AND DEVELOPMENT AEP and its subsidiaries are involved in over 150 research projects that are directed to: - Exploring new methods of generating electricity, such as through renewable sources (e.g., wind, solar). - Developing more efficient methods of operating generating plants. - Reducing emissions resulting from the burning of fossil fuels (coal and natural gas). - Improving the efficiency, utilization and reliability of the transmission and distribution systems. - Exploring the application of new electrotechnologies. - Exploring the use and application of distributed generation. AEP System operating companies are members of the Electric Power Research Institute (EPRI), an organization founded in 1973 that manages research and development initiatives on behalf of its members. EPRI's members include investor owned and public utilities, independent power producers, international organizations and others. AEP participates in EPRI programs that meet its research and development objectives. Total AEP dues to EPRI were $17,000,000 for 2000, $22,000,000 for 1999 and $23,000,000 for 1998. Of these amounts, the former CSW System paid approximately $7,000,000 in 2000, $8,000,00 in 1999 and $8,000,000 in 1998 for EPRI programs. Total research and development expenditures by AEP and its subsidiaries, including EPRI dues, were approximately $20,000,000 for the year ended December 31, 2000, $25,000,000 for the year ended December 31, 1999 and $32,000,000 for the year ended December 31, 1998. Item 2. PROPERTIES At December 31, 2000, the subsidiaries of AEP owned (or leased where indicated) generating plants with the net power capabilities (winter rating) shown in the following table:
COAL NATURAL GAS HYDRO NUCLEAR LIGNITE OTHER TOTAL COMPANY STATIONS MW MW MW MW MW MW MW ================================================================================================================================ AEGCo 1(a) 1,300 1,300 APCo 17(b) 5,081 777 5,858 CPL 12(c)(d) 686 3,175 6 630 4,497 CSPCo 6(e) 2,595 2,595 I&M 10(a) 2,295 11 2,110 4,416 KEPCo 1 1,060 1,060 OPCo 8(b)(f) 8,464 48 8,512 PSO 8(c) 1,018 2,873 25(g) 3,916 SWEPCo 9 1,848 1,797 842 4,487 WTU 12(c) 377 999 16(g) 1,392 ================================================================================================================================ Totals: 79 24,724 8,862 842 2,740 842 41 38,033 ================================================================================================================================
- ---------------------------------- (a) Unit 1 of the Rockport Plant is owned one-half by AEGCo and one-half by I&M. Unit 2 of the Rockport Plant is leased one-half by AEGCo and one-half by I&M. The leases terminate in 2022 unless extended. (b) Unit 3 of the John E. Amos Plant is owned one-third by APCo and two-thirds by OPCo. (c) CPL, PSO, and WTU jointly own the Oklaunion power station. Their respective ownership interests are reflected in this table. (d) Reflects CPL's interest in STP. (e) CSPCo owns generating units in common with CG&E and DP&L. Its ownership interest of 1,330 MW is reflected in this table. (f) The scrubber facilities at OPCo's General James M. Gavin Plant are leased. The lease terminates in 2010 unless extended. (g) PSO and WTU have 25 MW and 10 MW respectively of facilities designed primarily to burn oil. WTU has one 6 MW wind farm facility. 35 43 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, 2000 is listed below.
CAPACITY OWNERSHIP FACILITY COMPANY LOCATION TOTAL MW INTEREST STATUS =================================================================================================================================== Brush II CSWEnergy Colorado 68 47% QF Fort Lupton CSWEnergy Colorado 272 50% QF Mulberry CSWEnergy Florida 120 50% QF Orange Cogen CSWEnergy Florida 103 50% QF Newgulf CSWEnergy Texas 85 100% EWG Sweeny (a) CSWEnergy Texas 360 50% QF - ----------------------------------------------------------------------------------------------------------------------------------- Total U.S. 1,008 - ----------------------------------------------------------------------------------------------------------------------------------- Medway CSWInternational UnitedKingdom 675 37.5% n/a Altamira CSWInternational Mexico 118 50% FUCO - ----------------------------------------------------------------------------------------------------------------------------------- Total International 793 - -----------------------------------------------------------------------------------------------------------------------------------
- ----------------------------- (a) During 2001, additional development at the Sweeny facility is expected to add approximately 120 MW to current capacity. See Item 1 under Fuel Supply, for information concerning coal reserves owned or controlled by subsidiaries of AEP. The following table sets forth the total 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)................... 208,809(b) 2,023 APCo.......................... 50,187 642 CPL........................... 31,125 --- CSPCo (a)..................... 13,864 --- I&M........................... 20,602 614 KEPCo......................... 10,385 258 OPCo ......................... 29,620 509 PSO........................... 18,565 --- SWEPCo........................ 18,851 --- WTU........................... 12,439 ---
- ---------------------- (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 physical properties of the AEP System operating companies 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. 36 44 PEAK DEMAND The east zone system is interconnected through 121 high-voltage transmission interconnections with 25 neighboring electric utility systems. The all-time and 2000 one-hour peak system demands were 25,940,000 and 23,223,000 kilowatts, respectively (which included 7,314,000 and 5,341,000 kilowatts, respectively, of scheduled deliveries to unaffiliated systems which the system might, on appropriate notice, have elected not to schedule for delivery) and occurred on June 17, 1994 and August 7, 2000, respectively. The net dependable capacity to serve the system load on such date, including power available under contractual obligations, was 23,457,000 and 23,790,000 kilowatts, respectively. The all-time and 2000 one-hour internal peak demands were 19,952,000 and 19,167,000 kilowatts, respectively, and occurred on July 30, 1999 and January 28, 2000, respectively. The net dependable capacity to serve the system load on such date, including power dedicated under contractual arrangements, was 23,829,000 and 24,036,000 kilowatts, respectively. The all-time one-hour integrated and internal net system peak demands and 2000 peak demands for the east zone generating subsidiaries are shown in the following tabulation:
ALL-TIME ONE-HOUR INTEGRATED 2000 ONE-HOUR INTEGRATED NET NET SYSTEM PEAK DEMAND SYSTEM PEAK DEMAND - ----------------------------------- ------------------------------ (IN THOUSANDS) NUMBER OF NUMBER OF KILOWATTS DATE KILOWATTS DATE -------------- -------- ------------- -------- APCo........ 8,303 January 17, 1997 7,509 December 20, 2000 CSPCo....... 4,239 August 2, 2000 4,240 August 2, 2000 I&M......... 5,040 August 15, 2000 5,048 August 15, 2000 KEPCo....... 1,860 January 10, 2001 1,761 December 20, 2000 OPCo........ 7,291 June 17, 1994 6,199 August 2, 2000
ALL-TIME ONE-HOUR INTEGRATED 2000 ONE-HOUR INTEGRATED NET NET INTERNAL PEAK DEMAND INTERNAL PEAK DEMAND - ----------------------------------- ------------------------------ (IN THOUSANDS) NUMBER OF NUMBER OF KILOWATTS DATE KILOWATTS DATE ------------- -------- ------------- -------- APCo......... 6,908 February 5, 1996 6,558 January 28, 2000 CSPCo........ 3,804 July 30, 1999 3,499 August 31, 2000 I&M.......... 4,127 July 30, 1999 3,949 August 30, 2000 KEPCo....... 1,579 January 3, 2001 1,558 January 27, 2000 OPCo......... 5,705 June 11, 1999 5,029 June 14, 2000
The all-time and 2000 one-hour internal peak demand for the west zone system was 14,234,000 kilowatts on August 31, 2000. The all-time one-hour internal net system peak demands and 2000 peak demands for the west zone generating subsidiaries are shown in the following tabulation:
ALL-TIME ONE-HOUR INTEGRATED 2000 ONE-HOUR INTEGRATED NET NET INTERNAL PEAK DEMAND INTERNAL PEAK DEMAND - ------------------------------------ ------------------------------ (IN THOUSANDS) NUMBER OF NUMBER OF KILOWATTS DATE KILOWATTS DATE ------------- ------ ------------- -------- CPL ......... 4,623 September 5, 2000 4,623 September 5, 2000 PSO.......... 3,823 August 30, 2000 3,823 August 30, 2000 SWEPCo....... 4,625 August 31, 2000 4,625 August 31, 2000 WTU......... 1,537 September 5, 2000 1,537 September 5, 2000
HYDROELECTRIC PLANTS AEP has 18 facilities, of which 16 are licensed through FERC. The new license for the Elkhart hydroelectric plant in Indiana was issued January 11, 2001 and extends for a period of thirty years. The license for the Mottville hydroelectric plant in Michigan expires in 2003. A notice of intent to relicense was filed in 1998. The application for new license will be filed in 2001. COOK NUCLEAR PLANT AND STP The following table provides operating information relating to the Cook Plant and STP.
COOK PLANT STP(a) ---------------------- ---------------------- UNIT 1 UNIT 2 UNIT 1 UNIT 2 ------ ------ ------ ------ YEAR PLACED IN OPERATION 1975 1978 1988 1989 YEAR OF EXPIRATION OF NRC LICENSE (b) 2014 2017 2027 2028 NOMINAL NET ELECTRICAL RATING IN KILOWATTS 1,020,000 1,090,000 1,250,600 1,250,600 NET CAPACITY FACTORS 2000 (c) 1.4% 50.0% 78.2% 96.1% 1999 (c) 0% 0% 88.0% 89.4%
- --------------------- (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 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 37 45 experience gained in the construction and operation of nuclear facilities. I&M and CPL may also incur costs and experience reduced output at Cook Plant and STP, respectively, because of the design criteria prevailing at the time of construction and the age of the plant's systems and equipment. Nuclear industry-wide and Cook Plant and STP initiatives have contributed to slowing the growth of operating and maintenance costs at these plants. However, the ability of I&M and CPL to obtain adequate and timely recovery of costs associated with the Cook Plant and STP, respectively, including replacement power, any unamortized investment at the end of the useful life of the Cook Plant and STP (whether scheduled or premature), the carrying costs of that investment and retirement costs, is not assured. See Competition and Business Change. POTENTIAL UNINSURED LOSSES Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including liabilities relating to damage to the Cook Plant or STP and costs of replacement power in the event of a nuclear incident at the Cook Plant or STP. Future losses or liabilities which are not completely insured, unless allowed to be recovered through rates, could have a material adverse effect on results of operations and the financial condition of AEP, CPL, I&M and other AEP System companies. Reference is made to the footnote to the financial statements entitled Commitments and Contingencies that is incorporated by reference in Item 8 for information with respect to nuclear incident liability insurance. Item 3. LEGAL PROCEEDINGS Federal EPA Notice of Violation to OPCo: On August 31, 2000, Region V, Federal EPA, issued a Notice of Violation (NOV) to OPCo's Gavin Plant in connection with stack emissions. Among other alleged violations, the NOV alleges violation of the Federal EPA-approved Ohio air pollution nuisance rule. AEP has submitted a request for a conference to discuss the NOV with Region V representatives. Municipal Franchise Fee Litigation: CPL has been involved in litigation regarding municipal franchise fees in Texas as a result of a class action suit filed by the City of San Juan, Texas in 1996. The City of San Juan claims CPL underpaid municipal franchise fees and seeks damages of up to $300 million plus attorney's fees. CPL filed a counterclaim for overpayment of franchise fees. During 1997, 1998 and 1999 the litigation moved procedurally through the Texas Court System and was sent to mediation without resolution. In 1999 a class notice was mailed to each of the cities served by CPL. Over 90 of the 128 cities declined to participate in the lawsuit. However, CPL has pledged that if any final, non-appealable court decision awards a judgment against CPL for a franchise underpayment, CPL will extend the principles of that decision, with regard to any franchise underpayment, to the cities that declined to participate in the litigation. In December 1999, the court ruled that the class of plaintiffs would consist of approximately 30 cities. A trial date for June 2001 has been set. Although management believes that it has substantial defenses to the cities' claims and intends to defend itself against the cities' claims and pursue its counterclaim vigorously, management cannot predict the outcome of this litigation or its impact on results of operations, cash flows or financial condition. COLI Litigation: On February 20, 2001, the U.S. District Court for the Southern District of Ohio ruled against AEP in its suit against the United States over deductibility of interest claimed by AEP in its consolidated federal income tax return related to its COLI program. AEP had filed suit to resolve the IRS' assertion that interest deductions for AEP's COLI program should not be allowed. In 1998 and 1999 AEP paid the disputed taxes and interest attributable to COLI interest deductions for taxable years 1991-98 to avoid the potential assessment by the IRS of additional interest on the contested tax. The payments were included in other assets pending 38 46 the resolution of this matter. As a result of the U.S. District Court's decision to deny the COLI interest deductions, net income was reduced in 2000 as follows:
(IN MILLIONS) AEP System operating companies......................... $319 APCo................................................ 82 CSPCo............................................... 41 I&M................................................. 66 KEPCo............................................... 8 OPCo................................................ 118
The Company plans to appeal the decision. See Item 1 for a discussion of certain environmental matters. Reference is made to the footnote to the financial statements entitled Commitments and Contingencies incorporated by reference in Item 8 for further information with respect to other legal proceedings. Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS AEP, APCO, CPL, I&M, OPCO AND SWEPCO. None. AEGCO, CSPCO, KEPCO, PSO AND WTU. Omitted pursuant to Instruction I(2)(c). EXECUTIVE OFFICERS OF THE REGISTRANTS AEP. The following persons are, or may be deemed, executive officers of AEP. Their ages are given as of March 1, 2001.
NAME AGE OFFICE (a) - ---- --- ---------- E. Linn Draper, Jr................... 59 Chairman of the Board, President and Chief Executive Officer of AEP and of the Service Corporation Thomas V. Shockley, III.............. 55 Vice Chairman of the Service Corporation Paul D. Addis........................ 47 Executive Vice President-Wholesale/Energy Services of the Service Corporation Donald M. Clements, Jr............... 51 Executive Vice President-Corporate Development of the Service Corporation Henry W. Fayne....................... 54 Executive Vice President-Finance and Analysis of the Service Corporation William J. Lhota..................... 61 Executive Vice President- Energy Delivery of the Service Corporation Susan Tomasky........................ 47 Executive Vice President-Legal, Policy and Corporate Communications of the Service Corporation J. H. Vipperman...................... 60 Executive Vice President-Shared Services of the Service Corporation
- ------------------------- (a) All of the executive officers listed above have been employed by the Service Corporation or System companies in various capacities (AEP, as such, has no employees) during the past five years, except for Messrs. Addis and Shockley and Ms. Tomasky. Prior to joining the Service Corporation in February 1997 in his present position, Mr. Addis was Executive Vice President (1992-1993) and President (1993-January 1997) of Louis Dreyfus Electric Power, Inc. and President of Duke/Louis Dreyfus LLC (1995-January 1997). Mr. Addis became an executive officer of AEP effective January 1, 2000. 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). Ms. Tomasky became an executive officer of AEP effective with her promotion to Executive Vice President on January 26, 2000. 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 Senior Vice President of CSW (1980-1997). 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. 39 47 APCO, CPL, I&M, OPCO AND SWEPCO. The names of the executive officers of APCo, CPL, I&M, OPCo and SWEPCo, the positions they hold with these companies, their ages as of March 1, 2001, and a brief account of their business experience during the past five years appear below. The directors and executive officers of APCo, CPL, I&M, OPCo and SWEPCo are elected annually to serve a one-year term.
NAME AGE POSITION (a)(b) PERIOD - ---- --- --------------- ------ E. Linn Draper, Jr........ 59 Director of CPL and SWEPCo 2000-Present Chairman of the Board and Chief Executive Officer of CPL and SWEPCo 2000-Present Director of APCo, I&M and OPCo 1992-Present Chairman of the Board and Chief Executive Officer of APCo, I&M and OPCo 1993-Present Chairman of the Board, President and Chief Executive Officer of AEP and the Service Corporation 1993-Present Thomas V. Shockley, III... 55 Director and Vice President of APCo, CPL, I&M, OPCo and SWEPCo 2000-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............ 54 Director of CPL and SWEPCO 2000-Present Director of APCo 1995-Present Director of OPCo 1993-Present Director of I&M 1998-Present Vice President of CPL and SWEPCo 2000-Present Vice President of APCo, I&M and OPCo 1998-Present Vice President and Chief Financial Officer of AEP 1998-Present Executive Vice President-Finance and Analysis of the Service Corporation 2000-Present Executive Vice President-Financial Services of the Service Corporation 1998-2000 Senior Vice President-Corporate Planning & Budgeting of the Service Corporation 1995-1998 William J. Lhota.......... 61 Director of CPL and SWEPCo 2000-Present Director of APCo 1990-Present Director of I&M and OPCo 1989-Present President and Chief Operating Officer of CPL and SWEPCo 2000-Present President and Chief Operating Officer of APCo, I&M and OPCo 1996-Present Executive Vice President-Energy Delivery of the Service Corporation 2000-Present Executive Vice President of the Service Corporation 1993-2000 Susan Tomasky............. 47 Director and Vice President of APCo, CPL, I&M, OPCo and SWEPCo 2000-Present Executive Vice President-Legal, Policy and Corporate Communications and General Counsel of the Service Corporation 2000-Present 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
40 48
NAME AGE POSITION (a)(b) PERIOD - ---- --- --------------- ------ J. H. Vipperman........... 60 Director of CPL and SWEPCo 2000-Present Director of APCo 1985-Present Director of I&M and OPCo 1996-Present Vice President of CPL and SWEPCo 2000-Present Vice President of APCo, I&M and OPCo 1996-Present Executive Vice President-Shared Services of the Service Corporation 2000-Present Executive Vice President-Corporate Services of the Service Corporation 1998-2000 Executive Vice President-Energy Delivery of the Service Corporation 1996-1997
- ----------------- (a) Dr. Draper is a director of BCP Management, Inc., which is the general partner of Borden Chemicals and Plastics L.P., and Mr. Lhota is a director of Huntington Bancshares Incorporated and State Auto Financial Corporation. (b) Dr. Draper, Messrs. Fayne, Lhota, Shockley and Vipperman and Ms. Tomasky are directors of AEGCo, CSPCo, KEPCo, PSO and WTU. Dr. Draper and Mr. Shockley are also directors of AEP. PART II Item 5. MARKET FOR REGISTRANTS' COMMON EQUITY AND RELATED STOCKHOLDER MATTERS AEP. AEP Common Stock is traded principally on the New York Stock Exchange. The following table sets forth for the calendar periods indicated the high and low sales prices for the Common Stock as reported on the New York Stock Exchange Composite Tape and the amount of cash dividends paid per share of Common Stock.
PER SHARE MARKET PRICE ------------------------------- QUARTER ENDED HIGH LOW DIVIDEND - ------------- ---- --- -------- March 1999................................................... 48-3/16 39-5/16 .60 June 1999.................................................... 44-1/16 37-7/16 .60 September 1999............................................... 37-7/8 33-1/2 .60 December 1999................................................ 35-13/16 30-9/16 .60 March 2000................................................... 34-15/16 25-15/16 .60 June 2000.................................................... 38-1/2 29-7/16 .60 September 2000............................................... 40 29-15/16 .60 December 2000................................................ 48-15/16 36-3/16 .60
At December 31, 2000, AEP had approximately 160,000 shareholders of record. AEGCO, APCO, CPL, CSPCO, I&M, KEPCO, OPCO, PSO, SWEPCO AND WTU. The common stock of these companies is held solely by AEP. The amounts of cash dividends on common stock paid by these companies to AEP during 2000 and 1999 are incorporated by reference to the material under Statement of Retained Earnings in the 2000 Annual Reports. 41 49 Item 6. SELECTED FINANCIAL DATA AEGCo, CSPCo, KEPCo, PSO AND WTU. Omitted pursuant to Instruction I(2)(a). AEP, APCo, CPL, I&M, OPCo AND SWEPCo. The information required by this item is incorporated herein by reference to the material under Selected Consolidated Financial Data in the 2000 Annual Reports. Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION AEGCo, CSPCo, KEPCo, PSO AND WTU. Omitted pursuant to Instruction I(2)(a). Management's narrative analysis of the results of operations and other information required by Instruction I(2)(a) is incorporated herein by reference to the material under Management's Narrative Analysis of Results of Operations in the 2000 Annual Reports. AEP, APCo, CPL, I&M, OPCo AND SWEPCo. The information required by this item is incorporated herein by reference to the material under Management's Discussion and Analysis of Results of Operations and Management's Discussion and Analysis of Financial Condition, Contingencies and Other Matters in the 2000 Annual Reports. Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK AEGCo, AEP, APCo, CPL, CSPCo, I&M, KEPCo, OPCo, PSO, SWEPCo AND WTU. The information required by this item is incorporated herein by reference to the material under Management's Discussion and Analysis of Financial Condition, Contingencies and Other Matters in the 2000 Annual Reports. Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA AEGCo, AEP, APCo, CPL, CSPCo, I&M, KEPCo, OPCo, PSO, SWEPCo AND WTU. The information required by this item is incorporated herein by reference to the financial statements and supplementary data described under Item 14 herein. Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE AEGCo, AEP, APCo, CSPCo, I&M, KEPCo AND OPCo. None. CPL, PSO, SWEPCo AND WTU. The information required by this item is incorporated herein by reference to each company's Current Report on Form 8-K dated July 5, 2000. 42 50 PART III Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS AEGCo, CSPCo, KEPCo, PSO AND WTU. Omitted pursuant to Instruction I(2)(c). AEP. The information required by this item is incorporated herein by reference to the material under Nominees for Director of the definitive proxy statement of AEP for the 2001 annual meeting of shareholders, to be filed within 120 days after December 31, 2000. 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 2001 annual meeting of stockholders, to be filed within 120 days after December 31, 2000. Reference also is made to the information under the caption Executive Officers of the Registrants in Part I of this report. CPL AND SWEPCo. The information required by this item is incorporated herein by reference to the material under Election of Directors of the definitive information statement of APCo for the 2001 annual meeting of stockholders, to be filed within 120 days after December 31, 2000. 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, 2001, and a brief account of their business experience during the past five years appear below and under the caption Executive Officers of the Registrants in Part I of this report.
NAME AGE POSITION (a) PERIOD - ---- --- ------------ ------ K. G. Boyd.............. 49 Director 1997-Present Vice President - Fort Wayne Distribution Operations 2000-Present Indiana Region Manager 1997-2000 Fort Wayne District Manager 1994-1997 Marc E. Lewis........... 46 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..... 51 Director 2000-Present General Manager, Community Services 2000-Present Manager, Customer Services Operations 1997-2000 Director, Customer Services 1994-1997 John R. Sampson......... 48 Director and Vice President 1999-Present Indiana & Michigan State President 1999-Present Site Vice President, Cook Nuclear Plant 1998-1999 Plant Manager, Cook Nuclear Plant 1996-1998 Jackie S. Siefker....... 47 Director 2000-Present Manager, Distribution Systems 2000-Present District Manager 1995-2000 D. B. Synowiec.......... 57 Director 1995-Present Plant Manager, Rockport Plant 1990-Present W. E. Walters........... 53 Director 1991-Present Michiana Region Manager 1994-2000 Director of Projects 2000-Present
- ----------------- (a) Positions are with I&M unless otherwise indicated. 43 51 Item 11. EXECUTIVE COMPENSATION AEGCo, CSPCo, KEPCo, PSO AND WTU. Omitted pursuant to Instruction I(2)(c). AEP. The information required by this item is incorporated herein by reference to the material under Directors Compensation and Stock Ownership Guidelines, Executive Compensation and the performance graph of the definitive proxy statement of AEP for the 2001 annual meeting of shareholders to be filed within 120 days after December 31, 2000. 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 2001 annual meeting of stockholders, to be filed within 120 days after December 31, 2000. CPL, I&M AND SWEPCo. The information required by this item is incorporated herein by reference to the material under Executive Compensation of the definitive information statement of APCo for the 2001 annual meeting of stockholders, to be filed within 120 days after December 31, 2000. The following table sets forth the aggregate cash and other compensation for services rendered for the fiscal years of 2000, 1999 and 1998 paid or awarded to the presidents of CPL and SWEPCo. Summary Compensation Table
ANNUAL COMPENSATION --------------------------------------------- OTHER SALARY BONUS ANNUAL NAME AND PRINCIPAL POSITION YEAR ($) ($) COMPENSATION - --------------------------------------------------------------------------------------------------- J. GONZALO SANDOVAL - General 2000 143,323 38,153 0 manager/president of CPL (3) 1999 138,863 31,268 0 1998 138,115 34,955 0 MICHAEL H. MADISON - President of 2000 179,922 78,937 0 SWEPCo (3) 1999 186,944 91,065 5,544 1998 178,953 87,380 28,914 LONG-TERM COMPENSATION ---------------------- AWARDS PAYOUTS ------ ------- SECURITIES LTIP ALL OTHER UNDERLYING PAYOUTS COMPENSATION NAME AND PRINCIPAL POSITION OPTIONS (#) ($)(1) ($)(2) - ------------------------------------------------------------------------------------- J. GONZALO SANDOVAL - General 6,250 14,656 7,068 manager/president of CPL (3) 0 19,661 7,200 0 9,961 6,580 MICHAEL H. MADISON - President of 15,000 192,444 198,211 SWEPCo (3) 0 19,661 8,103 0 9,961 7,900
- ------------------------ (1) The awards reflected in this column are the value of restricted shares paid out under CSW's Long-Term Incentive Plan and, in the case of Mr. Madison, performance share units. Upon vesting, shares of AEP Common Stock were reissued without restrictions. The amounts reported in the Summary Compensation Table represent the market value of the shares at the date of grant. (2) Detail of the 2000 amounts in the All Other Compensation column is shown below.
Item Mr. Sandoval Mr. Madison ---- ------------ ----------- Savings Plan Matching Contributions.................. $7,068 $7,650 Personal Liability Insurance......................... 0 761 Change-in Control Payment............................ 0 179,000 Vehicle Allowance.................................... 0 10,800 - ------ Total All Other Compensation...................... $7,068 $198,211 ====== ========
(3) Messrs. Sandoval and Madison resigned their positions on June 28, 2000, but remained employees of the AEP System. 44 52 Option Grants in 2000
INDIVIDUAL GRANTS ------------------------------------------------------------------------------------ NUMBER OF PERCENT OF SECURITIES TOTAL OPTIONS UNDERLYING GRANTED TO GRANT DATE OPTIONS GRANTED EMPLOYEES IN EXERCISE OR BASE PRESENT VALUE NAME (#) (1) 2000 (2) PRICE ($/SH) EXPIRATION DATE ($) (3) - ---------------------- ----------------- --------------- ------------------- ------------------- -------------- J. Gonzalo Sandoval 6,250 0.1% 35.625 09-20-2010 36,783 Michael H. Madison 15,000 0.2% 35.625 09-20-2010 88,280
- --------------------- (1) Options were granted on September 20, 2000, pursuant to the AEP 2000 Long-Term Incentive Plan. All options granted on this date have an exercise price equal to the closing price of AEP Common Stock on the New York Stock Exchange Composite Transactions Tape on September 20, 2000. These options will vest in equal increments, annually, over a three-year period beginning on January 1, 2002. Options also fully vest upon termination due to retirement after one year from the grant date or due to disability or death and expire five years thereafter, or on their scheduled expiration date if earlier. Options expire upon termination of employment for reasons other than retirement, disability or death, unless the Human Resources Committee determines that circumstances warrant continuation of the options for up to five years. Options are nontransferable. (2) A total of 6,046,000 options were granted in 2000. (3) Value was calculated using the Black-Scholes option valuation model. The actual value, if any, ultimately realized depends on the market value of AEP's Common Stock at a future date. Significant assumptions are shown below: Stock Price Volatility 24.75% Dividend Yield 6.02% Risk-Free Rate of Return 6.50% Option Term 10 years
Aggregated Option Exercises in 2000 and Year-End Option Values
SHARE NUMBER OF SECURITIES UNDERLYING ACQUIRED ON VALUE UNEXERCISED OPTIONS AT 12-31-00 (#) EXERCISE REALIZED ------------------------------------ NAME (#) (1) ($) (1) EXERCISABLE UNEXERCISABLE - ---------------------------- ------------- ----------- -------------- ----------------- J. Gonzalo Sandoval -- -- 1,750 6,250 Michael H. Madison -- -- 6,281 15,000 VALUE OF UNEXERCISED IN-THE-MONEY OPTIONS AT 12-31-00 ($) (2) ------------------------------------ NAME EXERCISABLE UNEXERCISABLE - ---------------------------- ---------------- ---------------- J. Gonzalo Sandoval 0 67,969 Michael H. Madison 52,448 163,125
- --------------------- (1) Neither of these officers exercised options during 2000. (2) Based on the difference between the closing price of AEP Common Stock on the New York Stock Exchange Composite Transactions Tape on December 29, 2000 ($46.50) and the option exercise price. "In-the-money" means the market price of the stock is greater than the exercise price of the option on the date indicated. Cash Balance Retirement Plan CPL and SWEPCo maintain the Cash Balance Plan for eligible employees. In addition, these companies maintain the Special Executive Retirement Plan (SERP), a non-qualified plan that provides benefits that cannot be payable under the Cash Balance Plan because of maximum limitations imposed on such plans by the Internal Revenue Code. Under the cash balance formula, each participant has an account for recordkeeping purposes only, to which dollar amount credits are allocated annually based on a percentage of the participant's pay. Pay for the Cash Balance Plan includes base pay, bonuses, overtime, and commissions. The applicable percentage is determined by the age and years of vesting service the participant has as of December 31 of each year. 45 53 The following table shows the percentage used to determine dollar amount credits at the age and years of service indicated:
SUM OF AGE PLUS YEARS OF SERVICE APPLICABLE PERCENTAGE ---------------- --------------------- <30 3.0% 30-39 3.5% 40-49 4.5% 50-59 5.5% 60-69 7.0% 70 or more 8.5%
As of December 31, 2000, the sum of age plus years of service of Messrs. Sandoval and Madison were 78 and 81, respectively. At retirement or other termination of employment, an amount equal to the vested balance (including qualified and SERP benefit) then credited to the account is payable to the participant in the form of an immediate or deferred lump sum or annuity. Benefits (both from the Cash Balance Plan and the SERP) under the cash balance formula are not subject to reduction for Social Security benefits or other offset amounts. The estimated annual benefits payable to Messrs. Sandoval and Madison as a single life annuity at age 65 under the Cash Balance Plan and the SERP are $93,508 for Mr. Sandoval and $122,555 for Mr. Madision. These amounts are based on the following assumptions: - Salary used is base pay paid for calendar year 2000 assuming no future increases plus bonus at 2000 target level. - Conversion of the lump-sum cash balance to a single life annuity at age 65, based on an interest rate of 5.78% and the 1983 Group Annuity Mortality Table. Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AEGCo, CSPCo, KEPCo, PSO AND WTU. Omitted pursuant to Instruction I(2)(c). AEP. The information required by this item is incorporated herein by reference to the material under Share Ownership of Directors and Executive Officers of the definitive proxy statement of AEP for the 2001 annual meeting of shareholders to be filed within 120 days after December 31, 2000. APCo AND OPCo. The information required by this item is incorporated herein by reference to the material under Share Ownership of Directors and Executive Officers in the definitive information statement of each company for the 2001 annual meeting of stockholders, to be filed within 120 days after December 31, 2000. CPL AND SWEPCo. The information required by this item is incorporated herein by reference to the material under Share Ownership of Directors and Executive Officers in the definitive information statement of APCo for the 2001 annual meeting of stockholders, to be filed within 120 days after December 31, 2000. I&M. All 1,400,000 outstanding shares of Common Stock, no par value, of I&M are directly and beneficially held by AEP. Holders of the Cumulative Preferred Stock of I&M generally have no voting rights, except with respect to certain corporate actions and in the event of certain defaults in the payment of dividends on such shares. The table below shows the number of shares of AEP Common Stock and stock-based units that were beneficially owned, directly or indirectly, as of January 1, 2001, by each director and nominee of I&M as of March 12, 2001 and each of the executive officers of I&M named in the summary compensation table, and by all directors and executive officers of I&M as a group. It is based on information provided to I&M by such persons. No such person owns any shares of any series of the Cumulative Preferred Stock of I&M. Unless otherwise noted, each person has sole voting power and investment power over the number of shares of AEP Common Stock and stock-based units set forth opposite his name. Fractions of shares and units have been rounded to the nearest whole number. 46 54
STOCK ----- NAME SHARES(a) UNITS(b) TOTAL - ---- --------- -------- ----- Karl G. Boyd................................................. 2,137 308 2,445 E. Linn Draper, Jr........................................... 9,535(c) 106,181 115,716 Henry W. Fayne............................................... 5,590(d) 11,163 16,753 Marc E. Lewis................................................ 898 -- 898 William J. Lhota............................................. 18,854(c)(d) 16,249 35,103 Susanne M. Moorman........................................... 685 -- 685 John R. Sampson.............................................. 430 338 768 Thomas V. Shockley, III...................................... 93,965(e)(f) -- 93,965 Jackie S. Siefker............................................ 3,093 -- 3,093 David B. Synowiec............................................ 2,505 423 2,928 Susan Tomasky................................................ 1,744 98 1,842 Joseph H. Vipperman.......................................... 12,460(c)(d) 4,871 17,331 William E. Walters........................................... 7,441 334 7,775 All Directors and Executive Officers......................... 244,568(d)(g) 139,965 384,533
- ------------------------- (a) Includes share equivalents held in the AEP Retirement Savings Plan (and for Mr. Shockley, the CSW Retirement Savings Plan) in the amounts listed below:
AEP RETIREMENT SAVINGS NAME PLAN (SHARE EQUIVALENTS) ---- ------------------------ Mr. Boyd.................................... 2,137 Dr. Draper.................................. 3,947 Mr. Fayne................................... 5,014 Mr. Lewis................................... 898 Mr. Lhota................................... 16,674 Ms. Moorman................................. 685 Mr. Sampson................................ 430
AEP RETIREMENT SAVINGS NAME PLAN (SHARE EQUIVALENTS) ---- ------------------------ Mr. Shockley...................................... 6,234 Ms. Siefker....................................... 3,093 Mr. Synowiec...................................... 2,505 Ms. Tomasky....................................... 1,744 Mr. Vipperman..................................... 11,626 Mr. Walters....................................... 7,441 All Directors and Executive Officers.................... 62,428
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. (b) This column includes amounts deferred in stock units and held under AEP's officer benefit plans. (c) Includes the following numbers of shares held in joint tenancy with a family member: Dr. Draper, 5,588; Mr. Lhota, 2,180; and Mr. Vipperman, 76. (d) Does not include, for Messrs. Fayne, Lhota and Vipperman, 85,231 shares in the American Electric Power System Educational Trust Fund over which Messrs. Fayne, Lhota and Vipperman share voting and investment power as trustees (they disclaim beneficial ownership). The amount of shares shown for all directors and executive officers as a group includes these shares (e) Includes the following numbers of shares held by family members over which beneficial ownership is disclaimed: Mr. Shockley, 496. (f) Includes 49, 938 shares for Mr. Shockley attributable to options exercisable within 60 days. (g) Represents less than 1% of the total number of shares outstanding Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AEP, APCo, CPL, I&M, OPCo AND SWEPCo. None. AEGCo, CSPCo, KEPCo, PSO AND WTU. Omitted pursuant to Instruction I(2)(c). 47 55 PART IV Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (a) The following documents are filed as a part of this report: 1. FINANCIAL STATEMENTS: The following financial statements have been incorporated herein by reference pursuant to Item 8.
PAGE ---- AEGCo: Independent Auditors' Report; Statements of Income for the years ended December 31, 2000, 1999 and 1998; Statements of Retained Earnings for the years ended December 31, 2000, 1999 and 1998; Statements of Cash Flows for the years ended December 31, 2000, 1999 and 1998; Balance Sheets as of December 31, 2000 and 1999; Statements of Capitalization as of December 31, 2000 and 1999; Combined Notes to Financial Statements. AEP and its subsidiaries consolidated: Consolidated Statements of Income for the years ended December 31, 2000, 1999 and 1998; Consolidated Balance Sheets as of December 31, 2000 and 1999; Consolidated Statements of Cash Flows for the years ended December 31, 2000, 1999 and 1998; Consolidated Statements of Common Shareholders' Equity for the years ended December 31, 2000, 1999 and 1998; Combined Notes to Financial Statements; Schedule of Consolidated Cumulative Preferred Stocks of Subsidiaries at December 31, 2000 and 1999; Schedule of Consolidated Long-term Debt of Subsidiaries at December 31, 2000 and 1999; Independent Auditors' Reports. APCo, CPL, CSPCo, I&M, OPCo, PSO and SWEPCo: Independent Auditors' Report(s); Consolidated Statements of Income for the years ended December 31, 2000, 1999 and 1998; Consolidated Balance Sheets as of December 31, 2000 and 1999; Consolidated Statements of Cash Flows for the years ended December 31, 2000, 1999 and 1998; Consolidated Statements of Retained Earnings for the years ended December 31, 2000, 1999 and 1998; Consolidated Statements of Capitalization as of December 31, 2000 and 1999; Schedule of Consolidated Long-term Debt as of December 31, 2000 and 1999; Combined Notes to Financial Statements. KEPCo and WTU: Independent Auditors' Report(s); Statements of Income for the years ended December 31, 2000, 1999 and 1998; Statements of Retained Earnings for the years ended December 31, 2000, 1999 and 1998; Statements of Cash Flows for the years ended December 31, 2000, 1999 and 1998; Balance Sheets as of December 31, 2000 and 1999; Statements of Capitalization as of December 31, 2000 and 1999; Schedule of Long-term Debt as of December 31, 2000 and 1999; Combined Notes to Financial Statements. 2. FINANCIAL STATEMENT SCHEDULES: Financial Statement Schedules are listed in the Index to Financial Statement Schedules (Certain schedules have been omitted because the required information is contained in the notes to financial statements or because such schedules are not required or are not applicable). S-1 Independent Auditors' Report S-2 3. EXHIBITS: Exhibits for AEGCo, AEP, APCo, CPL, CSPCo, I&M, KEPCo, OPCo, PSO, SWEPCo and WTU are listed in the Exhibit Index and are incorporated herein by reference E-1
(b) No Reports on Form 8-K were filed during the quarter ended December 31, 2000. 48 56 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/ H. W. FAYNE --------------------------------------- (H. W. FAYNE, VICE PRESIDENT AND CHIEF FINANCIAL OFFICER) Date: March 20, 2001 PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED.
SIGNATURE TITLE DATE --------- ----- ---- (I) PRINCIPAL EXECUTIVE OFFICER: *E. LINN DRAPER, JR. Chairman of the Board, President, Chief Executive Officer And Director (II) PRINCIPAL FINANCIAL OFFICER: /S/ H. W. FAYNE Vice President and March 20, 2001 - ----------------------------------------- Chief Financial Officer (H. W. FAYNE) (III) PRINCIPAL ACCOUNTING OFFICER: /S/ L. V. ASSANTE Deputy Controller March 20, 2001 - ----------------------------------------- (L. V. ASSANTE) (IV) A MAJORITY OF THE DIRECTORS: *E. R. BROOKS *DONALD M. CARLTON *JOHN P. DESBARRES *ROBERT W. FRI *WILLIAM R. HOWELL *LESTER A. HUDSON, JR. *LEONARD J. KUJAWA *JAMES L. POWELL *RICHARD L. SANDOR *THOMAS V. SHOCKLEY, III *DONALD G. SMITH *LINDA GILLESPIE STUNTZ *KATHRYN D. SULLIVAN *MORRIS TANENBAUM March 20, 2001 *By: /S/ H. W. FAYNE ------------------------------------- (H. W. FAYNE, ATTORNEY-IN-FACT)
49 57 SIGNATURES PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED. THE SIGNATURE OF THE UNDERSIGNED COMPANY SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING REFERENCE TO SUCH COMPANY AND ANY SUBSIDIARIES THEREOF. AEP GENERATING COMPANY APPALACHIAN POWER COMPANY CENTRAL POWER AND LIGHT COMPANY COLUMBUS SOUTHERN POWER COMPANY KENTUCKY POWER COMPANY OHIO POWER COMPANY PUBLIC SERVICE COMPANY OF OKLAHOMA SOUTHWESTERN ELECTRIC POWER COMPANY WEST TEXAS UTILITIES COMPANY BY: /S/ A. A. PENA ------------------------------------------- (A. A. PENA, VICE PRESIDENT AND TREASURER) Date: March 20, 2001 PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED. THE SIGNATURE OF EACH OF THE UNDERSIGNED SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING REFERENCE TO THE ABOVE-NAMED COMPANY AND ANY SUBSIDIARIES THEREOF.
SIGNATURE TITLE DATE --------- ----- ---- (i) PRINCIPAL EXECUTIVE OFFICER: *E. LINN DRAPER, JR. Chairman of the Board, Chief Executive Officer And Director (ii) PRINCIPAL FINANCIAL OFFICER: /S/ A. A. PENA Vice President, Treasurer, March 20, 2001 - ------------------------------------------- And Director (A. A. PENA) (iii) PRINCIPAL ACCOUNTING OFFICER: /S/ L. V. ASSANTE Deputy Controller March 20, 2001 - ------------------------------------------- (L. V. ASSANTE) (iv) A MAJORITY OF THE DIRECTORS: *HENRY W. FAYNE *WM. J. LHOTA *THOMAS V. SHOCKLEY, III *SUSAN TOMASKY *J. H. VIPPERMAN March 20, 2001 *By: /S/ A. A. PENA ------------------------------------------ (A. A. PENA, ATTORNEY-IN-FACT)
50 58 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/ A. A. PENA --------------------------------------------- (A. A. PENA, VICE PRESIDENT AND TREASURER) Date: March 20, 2001 PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED. THE SIGNATURE OF EACH OF THE UNDERSIGNED SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING REFERENCE TO THE ABOVE-NAMED COMPANY AND ANY SUBSIDIARIES THEREOF.
SIGNATURE TITLE DATE --------- ----- ---- (i) PRINCIPAL EXECUTIVE OFFICER: *E. LINN DRAPER, JR. Chairman of the Board, Chief Executive Officer And Director (ii) PRINCIPAL FINANCIAL OFFICER: /S/ A. A. PENA Vice President and Treasurer March 20, 2001 - ------------------------------------------------ (A. A. PENA) (iii) PRINCIPAL ACCOUNTING OFFICER: /S/ L. V. ASSANTE Deputy Controller March 20, 2001 - ------------------------------------------------ (L. V. ASSANTE) (iv) A MAJORITY OF THE DIRECTORS: *K. G. BOYD * HENRY W. FAYNE *MARC E. LEWIS *WM. J. LHOTA *SUSANNE M. MOORMAN *JOHN R. SAMPSON *THOMAS V. SHOCKLEY, III *JACKIE S. SIEFKER *D. B. SYNOWIEC *SUSAN TOMASKY *J. H. VIPPERMAN *W. E. WALTERS *By: /s/ A. A. Pena March 20, 2001 ------------------------------------------------ (A. A. PENA, ATTORNEY-IN-FACT)
51 59 [THIS PAGE INTENTIONALLY LEFT BLANK] 60 INDEX TO FINANCIAL STATEMENT SCHEDULES
Page INDEPENDENT AUDITORS' REPORT ........................................................................ S-2 The following financial statement schedules are included in this report on the pages indicated. AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Schedule II -- Valuation and Qualifying Accounts and Reserves .............................. S-3 APPALACHIAN POWER COMPANY AND SUBSIDIARIES Schedule II -- Valuation and Qualifying Accounts and Reserves .............................. S-3 CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARY Schedule II -- Valuation and Qualifying Accounts and Reserves .............................. S-3 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Schedule II -- Valuation and Qualifying Accounts and Reserves .............................. S-4 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Schedule II -- Valuation and Qualifying Accounts and Reserves............................... S-4 KENTUCKY POWER COMPANY Schedule II -- Valuation and Qualifying Accounts and Reserves .............................. S-4 OHIO POWER COMPANY AND SUBSIDIARIES Schedule II -- Valuation and Qualifying Accounts and Reserves.............................. S-5 PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES Schedule II -- Valuation and Qualifying Accounts and Reserves.............................. S-5 SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Schedule II -- Valuation and Qualifying Accounts and Reserves.............................. S-5 WEST TEXAS UTILITIES COMPANY Schedule II -- Valuation and Qualifying Accounts and Reserves.............................. S-6
S-1 61 INDEPENDENT AUDITORS' REPORT AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARIES: We have audited the consolidated financial statements of American Electric Power Company, Inc. and its subsidiaries and the financial statements of certain of its subsidiaries, listed in Item 14 herein, as of December 31, 2000 and 1999, and for each of the three years in the period ended December 31, 2000, and have issued our reports thereon dated February 26, 2001; such financial statements and reports are included in the 2000 Annual Reports and are incorporated herein by reference. Our audits also included the financial statement schedules of American Electric Power Company, Inc. and its subsidiaries and of certain of its subsidiaries, listed in Item 14, except for the financial statement schedules of Central Power and Light Company and subsidiary, Public Service Company of Oklahoma and its subsidiaries, Southwestern Electric Power Company and subsidiaries, and West Texas Utilities Company for the years ended December 31, 1999 and 1998 and the financial information of Central and South West Corporation and its subsidiaries that is included in the financial statement schedule for American Electric Power Company, Inc. and its subsidiaries for the years ended December 31, 1999 and 1998. 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 26, 2001 S-2 62
========================================================================================================== AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES ========================================================================================================== COLUMN A COLUMN B COLUMN C ========================================================================================================== ADDITIONS ---------------------------- BALANCE AT CHARGED TO CHARGED TO BEGINNING COSTS AND OTHER DESCRIPTION OF PERIOD EXPENSES ACCOUNTS - ---------------------------------------------------------------------------------------------------------- (IN THOUSANDS) DEDUCTED FROM ASSETS: Accumulated Provision for Uncollectible Accounts: Year Ended December 31, 2000.............. $17,066 $14,878 $ 423(a) ======= ======= ========= Year Ended December 31, 1999.............. $14,841 $24,165 $15,788(a) ======= ======= ======= Year Ended December 31, 1998.............. $ 9,049 $28,809 $ 8,330(a) ======= ======= ========
============================================================================================ AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES ============================================================================================ COLUMN A COLUMN D COLUMN E ============================================================================================ BALANCE AT END OF DESCRIPTION DEDUCTIONS PERIOD - -------------------------------------------------------------------------------------------- (IN THOUSANDS) DEDUCTED FROM ASSETS: Accumulated Provision for Uncollectible Accounts: Year Ended December 31, 2000.............. $21,323(b) $11,044 ======= ======= Year Ended December 31, 1999.............. $37,728(b) $17,066 ======= ======= Year Ended December 31, 1998.............. $31,347(b) $14,841 ======= =======
- ---------------- (a) Recoveries on accounts previously written off. (b) Uncollectible accounts written off.
========================================================================================================== APPALACHIAN POWER COMPANY AND SUBSIDIARIES SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES ========================================================================================================== COLUMN A COLUMN B COLUMN C ========================================================================================================== ADDITIONS ---------------------------- BALANCE AT CHARGED TO CHARGED TO BEGINNING COSTS AND OTHER DESCRIPTION OF PERIOD EXPENSES ACCOUNTS - ---------------------------------------------------------------------------------------------------------- (IN THOUSANDS) DEDUCTED FROM ASSETS: Accumulated Provision for Uncollectible Accounts: Year Ended December 31, 2000.............. $2,609 $6,592 $1,526(a) ====== ====== ====== Year Ended December 31, 1999.............. $2,234 $5,492 $1,995(a) ====== ====== ====== Year Ended December 31, 1998.............. $1,333 $5,093 $1,306(a) ====== ====== ======
========================================================================================== APPALACHIAN POWER COMPANY AND SUBSIDIARIES SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES ========================================================================================== COLUMN A COLUMN D COLUMN E ========================================================================================== BALANCE AT END OF DESCRIPTION DEDUCTIONS PERIOD - ------------------------------------------------------------------------------------------ (IN THOUSANDS) DEDUCTED FROM ASSETS: Accumulated Provision for Uncollectible Accounts: Year Ended December 31, 2000.............. $8,139(b) $2,588 ====== ====== Year Ended December 31, 1999.............. $7,112(b) $2,609 ====== ====== Year Ended December 31, 1998.............. $5,498(b) $2,234 ====== ======
- ----------------- (a) Recoveries on accounts previously written off. (b) Uncollectible accounts written off.
======================================================================================================== CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARY SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES ======================================================================================================== COLUMN A COLUMN B COLUMN C ======================================================================================================== ADDITIONS ---------------------------- BALANCE AT CHARGED TO CHARGED TO BEGINNING COSTS AND OTHER DESCRIPTION OF PERIOD EXPENSES ACCOUNTS - -------------------------------------------------------------------------------------------------------- (IN THOUSANDS) DEDUCTED FROM ASSETS: Accumulated Provision for Uncollectible Accounts: Year Ended December 31, 2000.............. $ -- $1,675 $ -- (a) ======== ====== ======== Year Ended December 31, 1999.............. $ -- $ -- $ -- (a) ======== ====== ======== Year Ended December 31, 1998.............. $ -- $ -- $ -- (a) ======== ====== ========
=========================================================================================== CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARY SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES =========================================================================================== COLUMN A COLUMN D COLUMN E =========================================================================================== BALANCE AT END OF DESCRIPTION DEDUCTIONS PERIOD - ------------------------------------------------------------------------------------------- (IN THOUSANDS) DEDUCTED FROM ASSETS: Accumulated Provision for Uncollectible Accounts: Year Ended December 31, 2000.............. $ -- (b) $1,675 ======== ====== Year Ended December 31, 1999.............. $ -- (b) $ -- ======== ====== Year Ended December 31, 1998.............. $ -- (b) $ -- ======== ======
- --------------------- (a) Recoveries on accounts previously written off. (b) Uncollectible accounts written off. S-3 63
=========================================================================================================== COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES =========================================================================================================== COLUMN A COLUMN B COLUMN C =========================================================================================================== ADDITIONS ------------------------------------ BALANCE AT CHARGED TO CHARGED TO BEGINNING COSTS AND OTHER DESCRIPTION OF PERIOD EXPENSES ACCOUNTS - ---------------------------------------------------- ------------------------------------------------------ (IN THOUSANDS) DEDUCTED FROM ASSETS: Accumulated Provision for Uncollectible Accounts: Year Ended December 31, 2000.............. $3,045 $2,082 $ 1,405(a) ====== ====== ======== Year Ended December 31, 1999.............. $2,598 $3,334 $10,782(a) ====== ====== ======= Year Ended December 31, 1998.............. $1,058 $7,551 $ 5,278(a) ====== ====== ========
======================================================================================== COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES ======================================================================================== COLUMN A COLUMN D COLUMN E ======================================================================================== BALANCE AT END OF DESCRIPTION DEDUCTIONS PERIOD - ---------------------------------------------------------------------------------------- (IN THOUSANDS) DEDUCTED FROM ASSETS: Accumulated Provision for Uncollectible Accounts: Year Ended December 31, 2000.............. $ 5,873(b) $ 659 ======== ======= Year Ended December 31, 1999.............. $13,669(b) $3,045 ======= ====== Year Ended December 31, 1998.............. $11,289(b) $2,598 ======= ======
- -------------------- (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 =========================================================================================================== ADDITIONS ------------------------------------ BALANCE AT CHARGED TO CHARGED TO BEGINNING COSTS AND OTHER DESCRIPTION OF PERIOD EXPENSES ACCOUNTS - ---------------------------------------------------- ------------------------------------------------------ (IN THOUSANDS) DEDUCTED FROM ASSETS: Accumulated Provision for Uncollectible Accounts: Year Ended December 31, 2000.............. $1,848 $ (235) $ 907(a) ====== ====== ====== Year Ended December 31, 1999.............. $2,027 $3,966 $1,367(a) ====== ====== ====== Year Ended December 31, 1998.............. $1,188 $4,630 $ 221(a) ====== ====== ======
======================================================================================= INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES ======================================================================================= COLUMN A COLUMN D COLUMN E ======================================================================================= BALANCE AT END OF DESCRIPTION DEDUCTIONS PERIOD - --------------------------------------------------------------------------------------- (IN THOUSANDS) DEDUCTED FROM ASSETS: Accumulated Provision for Uncollectible Accounts: Year Ended December 31, 2000.............. $1,761(b) $ 759 ====== ====== Year Ended December 31, 1999.............. $5,512(b) $1,848 ====== ====== Year Ended December 31, 1998.............. $4,012(b) $2,027 ====== ======
- --------------------- (a) Recoveries on accounts previously written off. (b) Uncollectible accounts written off.
=========================================================================================================== KENTUCKY POWER COMPANY SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES =========================================================================================================== COLUMN A COLUMN B COLUMN C =========================================================================================================== ADDITIONS ------------------------------------ BALANCE AT CHARGED TO CHARGED TO BEGINNING COSTS AND OTHER DESCRIPTION OF PERIOD EXPENSES ACCOUNTS - ---------------------------------------------------- ------------------------------------------------------ (IN THOUSANDS) DEDUCTED FROM ASSETS: Accumulated Provision for Uncollectible Accounts: Year Ended December 31, 2000.............. $637 $ 187 $ 9(a) ==== ====== ==== Year Ended December 31, 1999.............. $848 $1,032 $467(a) ==== ====== ==== Year Ended December 31, 1998.............. $525 $1,280 $392(a) ==== ====== ====
========================================================================================= KENTUCKY POWER COMPANY SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES ========================================================================================= COLUMN A COLUMN D COLUMN E ========================================================================================= BALANCE AT END OF DESCRIPTION DEDUCTIONS PERIOD - ---------------------------------------------------- ------------------------------------ (IN THOUSANDS) DEDUCTED FROM ASSETS: Accumulated Provision for Uncollectible Accounts: Year Ended December 31, 2000.............. $ 551(b) $282 ======= ==== Year Ended December 31, 1999.............. $1,710(b) $637 ====== ==== Year Ended December 31, 1998.............. $1,349(b) $848 ====== ====
- --------------------- (a) Recoveries on accounts previously written off. (b) Uncollectible accounts written off. S-4 64
=========================================================================================================== OHIO POWER COMPANY AND SUBSIDIARIES SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES =========================================================================================================== COLUMN A COLUMN B COLUMN C =========================================================================================================== ADDITIONS ------------------------------------ BALANCE AT CHARGED TO CHARGED TO BEGINNING COSTS AND OTHER DESCRIPTION OF PERIOD EXPENSES ACCOUNTS - ---------------------------------------------------- ------------------------------------------------------ (IN THOUSANDS) DEDUCTED FROM ASSETS: Accumulated Provision for Uncollectible Accounts: Year Ended December 31, 2000.............. $2,223 $ 472 $ 778(a) ====== ====== ====== Year Ended December 31, 1999.............. $1,678 $4,730 $1,273(a) ====== ====== ====== Year Ended December 31, 1998.............. $2,501 $3,255 $ 941(a) ====== ====== ======
============================================================================================ OHIO POWER COMPANY AND SUBSIDIARIES SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES ============================================================================================ COLUMN A COLUMN D COLUMN E ============================================================================================ BALANCE AT END OF DESCRIPTION DEDUCTIONS PERIOD - -------------------------------------------------------------------------------------------- (IN THOUSANDS) DEDUCTED FROM ASSETS: Accumulated Provision for Uncollectible Accounts: Year Ended December 31, 2000.............. $2,419(b) $1,054 ====== ====== Year Ended December 31, 1999.............. $5,458(b) $2,223 ====== ====== Year Ended December 31, 1998.............. $5,019(b) $1,678 ====== ======
- --------------------- (a) Recoveries on accounts previously written off. (b) Uncollectible accounts written off.
============================================================================================================= PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES ============================================================================================================= COLUMN A COLUMN B COLUMN C ============================================================================================================= ADDITIONS ------------------------------------ BALANCE AT CHARGED TO CHARGED TO BEGINNING COSTS AND OTHER DESCRIPTION OF PERIOD EXPENSES ACCOUNTS - ------------------------------------------------------------------------------------------------------------- (IN THOUSANDS) DEDUCTED FROM ASSETS: Accumulated Provision for Uncollectible Accounts: Year Ended December 31, 2000.............. $ -- $ 467 $ -- (a) ======== ======= ======== Year Ended December 31, 1999.............. $ -- $ -- $ -- (a) ======== ======== ======== Year Ended December 31, 1998.............. $ -- $ -- $ -- (a) ======== ======== ========
======================================================================================== PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES ======================================================================================== COLUMN A COLUMN D COLUMN E ======================================================================================== BALANCE AT END OF DESCRIPTION DEDUCTIONS PERIOD - ---------------------------------------------------- ----------------------------------- (IN THOUSANDS) DEDUCTED FROM ASSETS: Accumulated Provision for Uncollectible Accounts: Year Ended December 31, 2000.............. $ -- (b) $ 467 ======== ====== Year Ended December 31, 1999.............. $ -- (b) $ -- ======== ====== Year Ended December 31, 1998.............. $ -- (b) $ -- ======== ======
- --------------------- (a) Recoveries on accounts previously written off. (b) Uncollectible accounts written off.
============================================================================================================ SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES ============================================================================================================ COLUMN A COLUMN B COLUMN C ============================================================================================================ ADDITIONS ------------------------------------ BALANCE AT CHARGED TO CHARGED TO BEGINNING COSTS AND OTHER DESCRIPTION OF PERIOD EXPENSES ACCOUNTS - ---------------------------------------------------- ------------------------------------------------------- (IN THOUSANDS) DEDUCTED FROM ASSETS: Accumulated Provision for Uncollectible Accounts: Year Ended December 31, 2000.............. $4,428 $ 911 $(4,428)(a) ====== ======= =========== Year Ended December 31, 1999.............. $3,269 $5,415 $ -- (a) ====== ====== ========== Year Ended December 31, 1998.............. $2,216 $4,547 $ -- (a) ====== ====== ==========
========================================================================================== SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES ========================================================================================== COLUMN A COLUMN D COLUMN E ========================================================================================== BALANCE AT END OF DESCRIPTION DEDUCTIONS PERIOD - ------------------------------------------------------------------------------------------ (IN THOUSANDS) DEDUCTED FROM ASSETS: Accumulated Provision for Uncollectible Accounts: Year Ended December 31, 2000.............. $ -- (b) $ 911 ======= ====== Year Ended December 31, 1999.............. $ 4,256(b) $4,428 ======= ====== Year Ended December 31, 1998.............. $ 3,494(b) $3,269 ======= ======
- --------------------- (a) Recoveries on accounts previously written off. (b) Uncollectible accounts written off. S-5 65
=========================================================================================================== WEST TEXAS UTILITIES COMPANY SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES =========================================================================================================== COLUMN A COLUMN B COLUMN C =========================================================================================================== ADDITIONS ------------------------------------ BALANCE AT CHARGED TO CHARGED TO BEGINNING COSTS AND OTHER DESCRIPTION OF PERIOD EXPENSES ACCOUNTS - ---------------------------------------------------- ------------------------------------------------------ (IN THOUSANDS) DEDUCTED FROM ASSETS: Accumulated Provision for Uncollectible Accounts: Year Ended December 31, 2000.............. $186 $1,499 $46(a) ==== ====== === Year Ended December 31, 1999.............. $497 $ (66) $43(a) ==== ======= === Year Ended December 31, 1998.............. $ 73 $ 616 $40(a) ===== ======= ===
======================================================================================= WEST TEXAS UTILITIES COMPANY SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES ======================================================================================= COLUMN A COLUMN D COLUMN E ======================================================================================= BALANCE AT END OF DESCRIPTION DEDUCTIONS PERIOD - --------------------------------------------------------------------------------------- (IN THOUSANDS) DEDUCTED FROM ASSETS: Accumulated Provision for Uncollectible Accounts: Year Ended December 31, 2000.............. $1,443(b) $288 ====== ==== Year Ended December 31, 1999.............. $ 288(b) $186 ====== ==== Year Ended December 31, 1998.............. $ 232(b) $497 ======= ====
- --------------------- (a) Recoveries on accounts previously written off. (b) Uncollectible accounts written off. S-6 66 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). 10(a) -- Copy of Capital Funds Agreement dated as of December 30, 1988 between AEGCo and AEP [Registration Statement No. 33-32752, Exhibit 28(a)]. 10(b)(1) -- Copy of Unit Power Agreement dated as of March 31, 1982 between AEGCo and I&M, as amended [Registration Statement No. 33-32752, Exhibits 28(b)(1)(A) and 28(b)(1)(B)]. 10(b)(2) -- Copy of Unit Power Agreement, dated as of August 1, 1984, among AEGCo, I&M and KEPCo [Registration Statement No. 33-32752, Exhibit 28(b)(2)]. 10(b)(3) -- Copy of Agreement, dated as of October 1, 1984, among AEGCo, I&M, APCo and Virginia Electric and Power Company [Registration Statement No. 33-32752, Exhibit 28(b)(3)]. 10(c) -- Copy of Lease Agreements, dated as of December 1, 1989, between AEGCo and Wilmington Trust Company, as amended [Registration Statement No. 33-32752, Exhibits 28(c)(1)(C), 28(c)(2)(C), 28(c)(3)(C), 28(c)(4)(C), 28(c)(5)(C) and 28(c)(6)(C); Annual Report on Form 10-K of AEGCo for the fiscal year ended December 31, 1993, File No. 0-18135, Exhibits 10(c)(1)(B), 10(c)(2)(B), 10(c)(3)(B), 10(c)(4)(B), 10(c)(5)(B) and 10(c)(6)(B)]. *13 -- Copy of those portions of the AEGCo 2000 Annual Report (for the fiscal year ended December 31, 2000) which are incorporated by reference in this filing. *24 -- Power of Attorney. AEP++ 3(a) -- Copy of Restated Certificate of Incorporation of AEP, dated October 29, 1997 [Quarterly Report on Form 10-Q of AEP for the quarter ended September 30, 1997, File No. 1-3525, Exhibit 3(a)]. 3(b) -- Copy of Certificate of Amendment of the Restated Certificate of Incorporation of AEP, dated January 13, 1999 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1998, File No. 1-3525, Exhibit 3(b)]. 3(c) -- Composite copy of the Restated Certificate of Incorporation of AEP, as amended [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1998, File No. 1-3525, Exhibit 3(c)]. 3(d) -- Copy of By-Laws of AEP, as amended through January 28, 1998 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1997, File No. 1-3525, Exhibit 3(b)]. 10(a) -- Interconnection Agreement, dated July 6, 1951, among APCo, CSPCo, KEPCo, OPCo and I&M and with the Service Corporation, as amended [Registration Statement No. 2-52910, Exhibit 5(a); Registration Statement No. 2-61009, Exhibit 5(b); and Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1990, File No. 1-3525, Exhibit 10(a)(3)]. 10(b) -- Copy of Transmission Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KEPCo, OPCo and with the Service Corporation as agent, as amended [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1985, File No. 1-3525,
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EXHIBIT NUMBER DESCRIPTION - -------------- ----------- AEP++ (continued) Exhibit 10(b); and Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1988, File No. 1-3525, Exhibit 10(b)(2)]. 10(c) -- Copy of Lease Agreements, dated as of December 1, 1989, between AEGCo or I&M and Wilmington Trust Company, as amended [Registration Statement No. 33-32752, Exhibits 28(c)(1)(C), 28(c)(2)(C), 28(c)(3)(C), 28(c)(4)(C), 28(c)(5)(C) and 28(c)(6)(C); Registration Statement No. 33-32753, Exhibits 28(a)(1)(C), 28(a)(2)(C), 28(a)(3)(C), 28(a)(4)(C), 28(a)(5)(C) and 28(a)(6)(C); and Annual Report on Form 10-K of AEGCo for the fiscal year ended December 31, 1993, File No. 0-18135, Exhibits 10(c)(1)(B), 10(c)(2)(B), 10(c)(3)(B), 10(c)(4)(B), 10(c)(5)(B) and 10(c)(6)(B); Annual Report on Form 10-K of I&M for the fiscal year ended December 31, 1993, File No. 1-3570, Exhibits 10(e)(1)(B), 10(e)(2)(B), 10(e)(3)(B), 10(e)(4)(B), 10(e)(5)(B) and 10(e)(6)(B)]. 10(d) -- Lease Agreement dated January 20, 1995 between OPCo and JMG Funding, Limited Partnership, and amendment thereto (confidential treatment requested) [Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1994, File No. 1-6543, Exhibit 10(l)(2)]. 10(e) -- Modification No. 1 to the AEP System Interim Allowance Agreement, dated July 28, 1994, among APCo, CSPCo, I&M, KEPCo, OPCo and the Service Corporation [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(l)]. 10(f)(1) -- Agreement and Plan of Merger, dated as of December 21, 1997, By and Among American Electric Power Company, Inc., Augusta Acquisition Corporation and Central and South West Corporation [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1997, File No. 1-3525, Exhibit 10(f)]. 10(f)(2) -- Amendment No. 1, dated as of December 31, 1999, to the Agreement and Plan of Merger [Current Report on Form 8-K of AEP dated December 15, 1999, File No. 1-3525, Exhibit 10]. +10(g)(1) -- AEP Deferred Compensation Agreement for certain executive officers [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(e)]. +10(g)(2) -- Amendment to AEP Deferred Compensation Agreement for certain executive officers [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1986, File No. 1-3525, Exhibit 10(d)(2)]. +10(h) -- AEP Accident Coverage Insurance Plan for directors [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(g)]. *+10(i)(1) -- AEP Deferred Compensation and Stock Plan for Non-Employee Directors, as amended June 1, 2000. *+10(i)(2) -- AEP Stock Unit Accumulation Plan for Non-Employee Directors, as amended June 1, 2000. *+10(j)(1)(A) -- AEP System Excess Benefit Plan, Amended and Restated as of January 1, 2001. +10(j)(1)(B) -- Guaranty by AEP of the Service Corporation Excess Benefits Plan [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1990, File No. 1-3525, Exhibit 10(h)(1)(B)]. *+10(j)(2) -- AEP System Supplemental Retirement Savings Plan, Amended and Restated as of January 1, 2001 (Non-Qualified). +10(j)(3) -- Service Corporation Umbrella Trust for Executives [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1993, File No. 1-3525, Exhibit 10(g)(3)]. +10(k) -- Employment Agreement between E. Linn Draper, Jr. and AEP and the Service Corporation [Annual Report on Form 10-K of AEGCo for the fiscal year ended December 31, 1991, File No. 0-18135, Exhibit 10(g)(3)]. +10(l) -- AEP System Senior Officer Annual Incentive Compensation Plan[Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(i)(1)].
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EXHIBIT NUMBER DESCRIPTION - -------------- ----------- AEP++ (continued) +10(m) -- AEP System Survivor Benefit Plan, effective January 27, 1998 [Quarterly Report on Form 10-Q of AEP for the quarter ended September 30, 1998, File No. 1-3525, Exhibit 10]. +10(n) -- Letter agreement between AEP and Donald M. Clements, Jr. dated August 19, 1994 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1998, File No. 1-3525, Exhibit 10(n)]. +10(o) -- 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(p) -- AEP Change In Control Agreement [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1999, File No. 1-3525, Exhibit 10(p)]. +10(q) -- AEP System 2000 Long-Term Incentive Plan [Proxy Statement of AEP, March 10, 2000]. *+10(r)(1) -- Employment Agreement between Paul Addis and the Service Corporation dated January 17, 1996. *+10(r)(2) -- Amending Agreement dated July 30, 1998 to Employment Agreement of Paul Addis. *+10(r)(3) -- AEP Energy Services Incentive Compensation Plan. *+10(r)(4) -- AEP Energy Services Phantom Equity Plan. *+10(s) -- Memorandum of agreement between Susan Tomasky and the Service Corporation dated January 3, 2001. *13 -- Copy of those portions of the AEP 2000 Annual Report (for the fiscal year ended December 31, 2000) which are incorporated by reference in this filing. *21 -- List of subsidiaries of AEP. *23(a) -- Consent of Deloitte & Touche LLP. *23(b) -- Consent of Arthur Andersen LLP. *23(c) -- Consent of KPMG Audit plc. *24 -- Power of Attorney. 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 June 15, 2000). 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, Exhibit2(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
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EXHIBIT NUMBER DESCRIPTION - -------------- ----------- APCO++ (continued) 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) and4(c); Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1996, File No. 1-3457, Exhibit 4(b); Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1998, File No. 1-3457, Exhibit 4(b)]. 4(b) -- Indenture (for unsecured debt securities), dated as of January 1, 1998, between APCo and The Bank of New York, As Trustee [Registration Statement No. 333-45927, Exhibit 4(a); Registration Statement No. 333-49071, Exhibit 4(b); Registration Statement No. 333-84061, Exhibits 4(b) and 4(c); Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1999, File No. 1-3457, Exhibit 4(c)]. *4(c) -- Company Order and Officers' Certificate, dated June 27, 2000, establishing certain terms of the Floating Rate Notes, Series A, due 2001. 10(a)(1) -- Copy of Power Agreement, dated October 15, 1952, between OVEC and United States of America, acting by and through the United States Atomic Energy Commission, and, subsequent to January 18, 1975, the Administrator of the Energy Research and Development Administration, as amended [Registration Statement No. 2-60015, Exhibit 5(a); Registration Statement No. 2-63234, Exhibit 5(a)(1)(B); Registration Statement No 2-66301, Exhibit 5(a)(1)(C); Registration Statement No. 2-67728, Exhibit 5(a)(1)(D); Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1989, File No. 1-3457, Exhibit 10(a)(1)(F); and Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1992, File No. 1-3457, Exhibit 10(a)(1)(B)]. 10(a)(2) -- Copy of Inter-Company Power Agreement, dated as of July 10, 1953, among OVEC and the Sponsoring Companies, as amended [Registration Statement No. 2-60015, Exhibit 5(c); Registration Statement No. 2-67728, Exhibit 5(a)(3)(B); and Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1992, File No. 1-3457, Exhibit 10(a)(2)(B)]. 10(a)(3) -- Copy of Power Agreement, dated July 10, 1953, between OVEC and Indiana-Kentucky Electric Corporation, as amended [Registration Statement No. 2-60015, Exhibit 5(e)]. 10(b) -- Copy of Interconnection Agreement, dated July 6, 1951, among APCo, CSPCo, KEPCo, OPCo and I&M and with the Service Corporation, as amended [Registration Statement No. 2-52910, Exhibit 5(a); Registration Statement No. 2-61009, Exhibit 5(b); Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1990, File No. 1-3525, Exhibit 10(a)(3)]. 10(c) -- Copy of Transmission Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KEPCo, OPCo and with the Service Corporation as agent, as amended [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(b); Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1988, File No. 1-3525, Exhibit 10(b)(2)]. 10(d) -- Copy of Modification No. 1 to the AEP System Interim Allowance Agreement, dated July 28, 1994, among APCo, CSPCo, I&M, KEPCo, OPCo and the Service Corporation [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(l)]. 10(e)(1) -- Agreement and Plan of Merger, dated as of December 21, 1997, By and Among American Electric Power Company, Inc., Augusta Acquisition Corporation and Central and South West Corporation [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1997, File No. 1-3525, Exhibit 10(f)].
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EXHIBIT NUMBER DESCRIPTION - -------------- ----------- APCO++ (continued) 10(e)(2) -- Amendment No. 1, dated as of December 31, 1999, to the Agreement and Plan of Merger [Current Report on Form 8-K of APCo dated December 15, 1999, File No. 1-3457, Exhibit 10]. +10(f)(1) -- AEP Deferred Compensation Agreement for certain executive officers [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(e)]. +10(f)(2) -- Amendment to AEP Deferred Compensation Agreement for certain executive officers [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1986, File No. 1-3525, Exhibit 10(d)(2)]. +10(g) -- AEP System Senior Officer Annual Incentive Compensation Plan [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(i)(1)]. +10(h)(1) -- AEP System Excess Benefit Plan, Amended and Restated as of January 1, 2001 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2000, File No. 1-3525, Exhibit 10(j)(1)(A)]. +10(h)(2) -- AEP System Supplemental Retirement Savings Plan, Amended and Restated as of January 1, 2001 (Non-Qualified) [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2000, File No. 1-3525, Exhibit 10(j)(2)]. +10(h)(3) -- Umbrella Trust for Executives [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1993, File No. 1-3525, Exhibit 10(g)(3)]. +10(i) -- Employment Agreement between E. Linn Draper, Jr. and AEP and the Service Corporation [Annual Report on Form 10-K of AEGCo for the fiscal year ended December 31, 1991, File No. 0-18135, Exhibit 10(g)(3)]. +10(j) -- AEP System Survivor Benefit Plan, effective January 27, 1998 [Quarterly Report on Form 10-Q of AEP for the quarter ended September 30, 1998, File No. 1-3525, Exhibit 10]. +10(k) -- AEP Senior Executive Severance Plan for Merger with Central and South West Corporation, effective March 1, 1999[Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1998, File No. 1-3525, Exhibit 10(o)]. +10(l) -- AEP Change In Control Agreement [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1999, File No. 1-3525, Exhibit 10(p)]. +10(m) -- AEP System 2000 Long-Term Incentive Plan [Proxy Statement of AEP, March 10, 2000]. +10(n) -- Memorandum of agreement between Susan Tomasky and the Service Corporation dated January 3, 2001 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2000, File No. 1-3525, Exhibit 10(s)]. *12 -- Statement re: Computation of Ratios. *13 -- Copy of those portions of the APCo 2000 Annual Report (for the fiscal year ended December 31, 2000) 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, 2000, File No. 1-3525, Exhibit 21]. *23 -- Consent of Deloitte & Touche LLP. *24 -- Power of Attorney. CPL++ 3(a) -- Restated Articles of Incorporation Without Amendment, Articles of Correction to Restated Articles of Incorporation Without Amendment, Articles of Amendment to Restated Articles of Incorporation, Statements of Registered Office and/or Agent, and Articles of Amendment to the Articles of Incorporation [Quarterly Report on Form 10-Q of CPL for the quarter ended March 31, 1997, File No. 0-346, Exhibit 3.1]. *3(b) -- By-Laws of CPL (amended as of April 19, 2000). 4(a) -- Indenture of Mortgage or Deed of Trust, dated November 1, 1943, between CPL and The First National Bank of Chicago and R. D. Manella, as Trustees, as amended and supplemented [Registration Statement No. 2-60712, Exhibit 5.01; Registration
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EXHIBIT NUMBER DESCRIPTION - -------------- ----------- CPL++ (continued) Statement No. 2-62271, Exhibit 2.02; Form U-1 No. 70-7003, Exhibit 17; Registration Statement No. 2-98944, Exhibit 4 (b); Form U-1 No. 70-7236, Exhibit 4; Form U-1 No. 70-7249, Exhibit 4; Form U-1 No. 70-7520, Exhibit 2; Form U-1 No. 70-7721, Exhibit 3; Form U-1 No. 70-7725, Exhibit 10; Form U-1 No. 70-8053, Exhibit 10 (a); Form U-1 No. 70-8053, Exhibit 10 (b); Form U-1 No. 70-8053, Exhibit 10 (c); Form U-1 No. 70-8053, Exhibit 10 (d); Form U-1 No. 70-8053, Exhibit 10 (e); Form U-1 No. 70-8053, Exhibit 10 (f)]. 4(b) -- CPL-obligated, mandatorily redeemable preferred securities of subsidiary trust holding solely Junior Subordinated Debentures of CPL: (1) Indenture, dated as of May 1, 1997, between CPL and the Bank of New York, as Trustee [Quarterly Report on Form 10-Q of CPL dated March 31, 1997, File No. 0-346, Exhibits 4.1 and 4.2]. (2) Amended and Restated Trust Agreement of CPL Capital I, dated as of May 1, 1997, among CPL, as Depositor, the Bank of New York, as Property Trustee, The Bank of New York (Delaware), as Delaware Trustee, and the Administrative Trustee [Quarterly Report on Form 10-Q of CPL dated March 31, 1997, File No. 0-346, Exhibit 4.3]. (3) Guarantee Agreement, dated as of May 1, 1997, delivered by CPL for the benefit of the holders of CPL Capital I's Preferred Securities [Quarterly Report on Form 10-Q of CPL dated March 31, 1997, File No. 0-346, Exhibit 4.4]. (4) Agreement as to Expenses and Liabilities dated as of May 1, 1997, between CPL and CPL Capital I [Quarterly Report on Form 10-Q of CPL dated March 31, 1997, File No. 0-346, Exhibit 4.5]. *4(c) -- Indenture (for unsecured debt securities), dated as of November 15, 1999, between CPL and The Bank of New York, as Trustee. *4(d) -- First Supplemental Indenture, dated as of November 15, 1999, between CPL and The Bank of New York, as Trustee, for Floating Rate Notes due November 23, 2001. *4(e) -- Second Supplemental Indenture, dated as of February 16, 2000, between CPL and The Bank of New York, as Trustee, for Floating Rate Notes due February 22, 2002. *12 -- Statement re: Computation of Ratios. *13 -- Copy of those portions of the CPL 2000 Annual Report (for the fiscal year ended December 31, 2000) which are incorporated by reference in this filing. *23(a) -- Consent of Deloitte & Touche LLP. *23(b) -- Consent of Arthur Andersen LLP. *24 -- Power of Attorney. CSPCO++ 3(a) -- Copy of Amended Articles of Incorporation of CSPCo, as amended to March 6, 1992 [Registration Statement No. 33-53377, Exhibit 4(a)]. 3(b) -- Copy of Certificate of Amendment to Amended Articles of Incorporation of CSPCo, dated May 19, 1994 [Annual Report on Form 10-K of CSPCo for the fiscal year ended December 31, 1994, File No. 1-2680, Exhibit 3(b)]. 3(c) -- Composite copy of Amended Articles of Incorporation of CSPCo, as amended [Annual Report on Form 10-K of CSPCo for the fiscal year ended December 31, 1994, File No. 1-2680, Exhibit 3(c)]. 3(d) -- Copy of Code of Regulations and By-Laws of CSPCo [Annual Report on Form 10-K of CSPCo for the fiscal year ended December 31, 1987, File No. 1-2680, Exhibit 3(d)]. 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.
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EXHIBIT NUMBER DESCRIPTION - -------------- ----------- CSPCO++ (continued) 33-19227, Exhibits 4(b), 4(e), 4(f), 4(g) and 4(h); Registration Statement No. 33-35651, Exhibit 4(b); Registration Statement No. 33-46859, Exhibits 4(b) and 4(c); Registration Statement No. 33-50316, Exhibits 4(b) and 4(c); Registration Statement No. 33-60336, Exhibits 4(b), 4(c) and 4(d); Registration Statement No. 33-50447, Exhibits 4(b) and 4(c); Annual Report on Form 10-K of CSPCo for the fiscal year ended December 31, 1993, File No. 1-2680, Exhibit 4(b)]. 4(b) -- Copy of Indenture (for unsecured debt securities), dated as of September 1, 1997, between CSPCo and Bankers Trust Company, as Trustee [Registration Statement No. 333-54025, Exhibits 4(a), 4(b), 4(c) and 4(d); Annual Report on Form 10-K of CSPCo for the fiscal year ended December 31, 1998, File No. 1-2680, Exhibits 4(c) and 4(d)]. 10(a)(1) -- Copy of Power Agreement, dated October 15, 1952, between OVEC and United States of America, acting by and through the United States Atomic Energy Commission, and, subsequent to January 18, 1975, the Administrator of the Energy Research and Development Administration, as amended [Registration Statement No. 2-60015, Exhibit 5(a); Registration Statement No. 2-63234, Exhibit 5(a)(1)(B); Registration Statement No. 2-66301, Exhibit 5(a)(1)(C); Registration Statement No. 2-67728, Exhibit 5(a)(1)(B); Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1989, File No. 1-3457, Exhibit 10(a)(1)(F); and Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1992, File No. 1-3457, Exhibit 10(a)(1)(B)]. 10(a)(2) -- Copy of Inter-Company Power Agreement, dated July 10, 1953, among OVEC and the Sponsoring Companies, as amended [Registration Statement No. 2-60015, Exhibit 5(c); Registration Statement No. 2-67728, Exhibit 5(a)(3)(B); and Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1992, File No. 1-3457, Exhibit 10(a)(2)(B)]. 10(a)(3) -- Copy of Power Agreement, dated July 10, 1953, between OVEC and Indiana-Kentucky Electric Corporation, as amended [Registration Statement No. 2-60015, Exhibit 5(e)]. 10(b) -- Copy of Interconnection Agreement, dated July 6, 1951, among APCo, CSPCo, KEPCo, OPCo and I&M and the Service Corporation, as amended [Registration Statement No. 2-52910, Exhibit 5(a); Registration Statement No. 2-61009, Exhibit 5(b); and Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1990, File No. 1-3525, Exhibit 10(a)(3)]. 10(c) -- Copy of Transmission Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KEPCo, OPCo, and with the Service Corporation as agent, as amended [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(b); and Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1988, File No. 1-3525, Exhibit 10(b)(2)]. 10(d) -- Copy of Modification No. 1 to the AEP System Interim Allowance Agreement, dated July 28, 1994, among APCo, CSPCo, I&M, KEPCo, OPCo and the Service Corporation [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(l)]. 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 2000 Annual Report (for the fiscal year ended December 31, 2000) which are incorporated by reference in this filing. *23 -- Consent of Deloitte & Touche LLP. *24 -- Power of Attorney.
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EXHIBIT NUMBER DESCRIPTION - -------------- ----------- 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 January 1, 1996) [Annual Report on Form 10-K of I&M for the fiscal year ended December 31, 1995, File No. 1-3570, Exhibit 3(c)]. 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); Annual Report on Form 10-K of I&M for the fiscal year ended December 31, 1999, File No. 1-3570, Exhibit 4(c)]. * 4(c) -- Copy of Company Order and Officers' Certificate, dated August 31, 2000, establishing certain terms of the Floating Rate Notes, Series B, due 2002. 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)].
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EXHIBIT NUMBER DESCRIPTION - -------------- ----------- I&M++ (CONTINUED) 10(a)(3) -- Copy of Power Agreement, dated July 10, 1953, between OVEC and Indiana-Kentucky Electric Corporation, as amended [Registration Statement No. 2-60015, Exhibit 5(e)]. 10(a)(4) -- Copy of Inter-Company Power Agreement, dated as of July 10, 1953, among OVEC and the Sponsoring Companies, as amended [Registration Statement No. 2-60015, Exhibit 5(c); Registration Statement No. 2-67728, Exhibit 5(a)(3)(B); Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1992, File No. 1-3457, Exhibit 10(a)(2)(B)]. 10(a)(5) -- Copy of Power Agreement, dated July 10, 1953, between OVEC and Indiana-Kentucky Electric Corporation, as amended [Registration Statement No. 2-60015, Exhibit 5(e)]. 10(b) -- Copy of Interconnection Agreement, dated July 6, 1951, among APCo, CSPCo, KEPCo, I&M, and OPCo and with the Service Corporation, as amended [Registration Statement No. 2-52910, Exhibit 5(a); Registration Statement No. 2-61009, Exhibit 5(b); and Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1990, File No. 1-3525, Exhibit 10(a)(3)]. 10(c) -- Copy of Transmission Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KEPCo, OPCo and with the Service Corporation as agent, as amended [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(b); and Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1988, File No. 1-3525, Exhibit 10(b)(2)]. 10(d) -- Copy of Modification No. 1 to the AEP System Interim Allowance Agreement, dated July 28, 1994, among APCo, CSPCo, I&M, KEPCo, OPCo and the Service Corporation [Annual Report on Form 10-K of AEP for the fiscal year ended December 1, 1996, File No. 1-3525, Exhibit 10(l)]. 10(e) -- Copy of Nuclear Material Lease Agreement, dated as of December 1, 1990, between I&M and DCC Fuel Corporation [Annual Report on Form 10-K of I&M for the fiscal year ended December 31, 1993, File No. 1-3570, Exhibit 10(d)]. 10(f) -- Copy of Lease Agreements, dated as of December 1, 1989, between I&M and Wilmington Trust Company, as amended [Registration Statement No. 33-32753, Exhibits 28(a)(1)(C), 28(a)(2)(C), 28(a)(3)(C), 28(a)(4)(C), 28(a)(5)(C) and 28(a)(6)(C); Annual Report on Form 10-K of I&M for the fiscal year ended December 31, 1993, File No. 1-3570, Exhibits 10(e)(1)(B), 10(e)(2)(B), 10(e)(3)(B), 10(e)(4)(B), 10(e)(5)(B) and 10(e)(6)(B)]. 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 2000 Annual Report (for the fiscal year ended December 31, 2000) 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, 2000, File No. 1-3525, Exhibit 21]. *24 -- Power of Attorney. KEPCO++ 3(a) -- Copy of Restated Articles of Incorporation of KEPCo [Annual Report on Form 10-K of KEPCo for the fiscal year ended December 31, 1991, File No. 1-6858, Exhibit 3(a)]. *3(b) -- Copy of By-Laws of KEPCo (amended as of June 15, 2000).
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EXHIBIT NUMBER DESCRIPTION - -------------- ----------- KEPCO++ (CONTINUED) 4(a) -- Copy of Mortgage and Deed of Trust, dated May 1, 1949, between KEPCo and Bankers Trust Company, as supplemented and amended [Registration Statement No. 2-65820, Exhibits 2(b)(1), 2(b)(2), 2(b)(3), 2(b)(4), 2(b)(5), and 2(b)(6); Registration Statement No. 33-39394, Exhibits 4(b) and 4(c); Registration Statement No. 33-53226, Exhibits 4(b) and 4(c); Registration Statement No. 33-61808, Exhibits 4(b) and 4(c), Registration Statement No. 33-53007, Exhibits 4(b), 4(c) and 4(d)]. 4(b) -- Copy of Indenture (for unsecured debt securities), dated as of September 1, 1997, between KEPCo and Bankers Trust Company, as Trustee [Registration Statement No. 333-75785, Exhibits 4(a), 4(b), 4(c) and 4(d); Annual Report on Form 10-K of KEPCo for the fiscal year ended December 31, 1999, File No. 1-6858, Exhibit 4(c)]. *4(c) -- Copy of Company Order and Officers' Certificate, dated November 17, 2000, establishing certain terms of the Floating Rate Notes, Series B, due 2002. 10(a) -- Copy of Interconnection Agreement, dated July 6, 1951, among APCo, CSPCo, KEPCo, I&M and OPCo and with the Service Corporation, as amended [Registration Statement No. 2-52910, Exhibit 5(a);Registration Statement No. 2-61009, Exhibit 5(b); and Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1990, File No. 1-3525, Exhibit 10(a)(3)]. 10(b) -- Copy of Transmission Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KEPCo, OPCo and with the Service Corporation as agent, as amended [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(b); and Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1988, File No. 1-3525, Exhibit 10(b)(2)]. 10(c) -- Copy of Modification No. 1 to the AEP System Interim Allowance Agreement, dated July 28, 1994, among APCo, CSPCo, I&M, KEPCo, OPCo and the Service Corporation [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(l)]. 10(d)(1) -- Agreement and Plan of Merger, dated as of December 21, 1997, By and Among American Electric Power Company, Inc., Augusta Acquisition Corporation and Central and South West Corporation [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1997, File No. 1-3525, Exhibit 10(f)]. 10(d)(2) -- Amendment No. 1, dated as of December 31, 1999, to the Agreement and Plan of Merger [Current Report on Form 8-K of KEPCo dated December 15, 1999, File No. 1-6858, Exhibit 10]. *12 -- Statement re: Computation of Ratios. *13 -- Copy of those portions of the KEPCo 2000 Annual Report (for the fiscal year ended December 31, 2000) which are incorporated by reference in this filing. *24 -- Power of Attorney. OPCO++ 3(a) -- Copy of Amended Articles of Incorporation of OPCo, and amendments thereto to December 31, 1993 [Registration Statement No. 33-50139, Exhibit 4(a); Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1993, File No. 1-6543, Exhibit 3(b)]. 3(b) -- Certificate of Amendment to Amended Articles of Incorporation of OPCo, dated May 3, 1994 [Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1994, File No. 1-6543, Exhibit 3(b)]. 3(c) -- Copy of Certificate of Amendment to Amended Articles of Incorporation of OPCo, dated March 6, 1997 [Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1996, File No. 1-6543, Exhibit 3(c)]. 3(d) -- Composite copy of the Amended Articles of Incorporation of OPCo (amended as of March 7, 1997) [Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1996, File No. 1-6543, Exhibit 3(d)]. 3(e) -- Copy of Code of Regulations of OPCo [Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1990, File No. 1-6543, Exhibit 3(d)].
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EXHIBIT NUMBER DESCRIPTION - -------------- ----------- OPCO++ (CONTINUED) 4(a) -- Copy of Mortgage and Deed of Trust, dated as of October 1, 1938, between OPCo and Manufacturers Hanover Trust Company (now Chemical Bank), as Trustee, as amended and supplemented [Registration Statement No. 2-3828, Exhibit B-4; Registration Statement No. 2-60721, Exhibits 2(c)(2), 2(c)(3), 2(c)(4), 2(c)(5), 2(c)(6), 2(c)(7), 2(c)(8), 2(c)(9), 2(c)(10), 2(c)(11), 2(c)(12), 2(c)(13), 2(c)(14), 2(c)(15), 2(c)(16), 2(c)(17), 2(c)(18), 2(c)(19), 2(c)(20), 2(c)(21), 2(c)(22), 2(c)(23), 2(c)(24), 2(c)(25), 2(c)(26), 2(c)(27), 2(c)(28), 2(c)(29), 2(c)(30), and 2(c)(31); Registration Statement No. 2-83591, Exhibit 4(b); Registration Statement No. 33-21208, Exhibits 4(a)(ii), 4(a)(iii) and 4(a)(iv); Registration Statement No. 33-31069, Exhibit 4(a)(ii); Registration Statement No. 33-44995, Exhibit 4(a)(ii); Registration Statement No. 33-59006, Exhibits 4(a)(ii), 4(a)(iii) and 4(a)(iv); Registration Statement No. 33-50373, Exhibits 4(a)(ii), 4(a)(iii) and 4(a)(iv); Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1993, File No. 1-6543, Exhibit 4(b)]. 4(b) -- Copy of Indenture (for unsecured debt securities), dated as of September 1, 1997, between OPCo and Bankers Trust Company, as Trustee [Registration Statement No. 333-49595, Exhibits 4(a), 4(b) and 4(c); Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1998, File No. 1-6543, Exhibits 4(c) and 4(d); Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1999, File No. 1-6543, Exhibits 4(c) and 4(d)]. *4(c) -- Copy of Company Order and Officers' Certificate, dated May 22, 2000, establishing certain terms of the Floating Rate Notes, Series A, due 2001. 10(a)(1) -- Copy of Power Agreement, dated October 15, 1952, between OVEC and United States of America, acting by and through the United States Atomic Energy Commission, and, subsequent to January 18, 1975, the Administrator of the Energy Research and Development Administration, as amended [Registration Statement No. 2-60015, Exhibit 5(a); Registration Statement No. 2-63234, Exhibit 5(a)(1)(B); Registration Statement No. 2-66301, Exhibit 5(a)(1)(C); Registration Statement No. 2-67728, Exhibit 5(a)(1)(D); Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1989, File No. 1-3457, Exhibit 10(a)(1)(F); Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1992, File No. 1-3457, Exhibit 10(a)(1)(B)]. 10(a)(2) -- Copy of Inter-Company Power Agreement, dated July 10, 1953, among OVEC and the Sponsoring Companies, as amended [Registration Statement No. 2-60015, Exhibit 5(c); Registration Statement No. 2-67728, Exhibit 5(a)(3)(B); Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1992, File No. 1-3457, Exhibit 10(a)(2)(B)]. 10(a)(3) -- Copy of Power Agreement, dated July 10, 1953, between OVEC and Indiana-Kentucky Electric Corporation, as amended [Registration Statement No. 2-60015, Exhibit 5(e)]. 10(b) -- Copy of Interconnection Agreement, dated July 6, 1951, among APCo, CSPCo, KEPCo, I&M and OPCo and with the Service Corporation, as amended [Registration Statement No. 2-52910, Exhibit 5(a); Registration Statement No. 2-61009, Exhibit 5(b); Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1990, File 1-3525, Exhibit 10(a)(3)]. 10(c) -- Copy of Transmission Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KEPCo, OPCo and with the Service Corporation as agent [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(b); Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1988, File No. 1-3525, Exhibit 10(b)(2)]. 10(d) -- Copy of Modification No. 1 to the AEP System Interim Allowance Agreement, dated July 28, 1994, among APCo, CSPCo, I&M, KEPCo, OPCo and the Service Corporation [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(l)].
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EXHIBIT NUMBER DESCRIPTION - -------------- ----------- OPCO++ (CONTINUED) 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)(1) -- AEP Deferred Compensation Agreement for certain executive officers [Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(e)]. +10(h)(2) -- Amendment to AEP Deferred Compensation Agreement for certain executive officers [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1986, File No. 1-3525, Exhibit 10(d)(2)]. +10(i) -- AEP System Senior Officer Annual Incentive Compensation Plan [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(i)(1)]. +10(j)(1) -- AEP System Excess Benefit Plan, Amended and Restated as of January 1, 2001 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2000, File No. 1-3525, Exhibit 10(j)(1)(A)]. +10(j)(2) -- AEP System Supplemental Retirement Savings Plan, Amended and Restated as of January 1, 2001 (Non-Qualified) [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2000, File No. 1-3525, Exhibit 10(j)(2)]. +10(j)(3) -- Umbrella Trust for Executives [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1993, File No. 1-3525, Exhibit 10(g)(3)]. +10(k) -- Employment Agreement between E. Linn Draper, Jr. and AEP and the Service Corporation [Annual Report on Form 10-K of AEGCo for the fiscal year ended December 31, 1991, File No. 0-18135, Exhibit 10(g)(3)]. +10(l) -- AEP System Survivor Benefit Plan, effective January 27, 1998 [Quarterly Report on Form 10-Q of AEP for the quarter ended September 30, 1998, File No. 1-3525, Exhibit 10]. +10(m) -- AEP Senior Executive Severance Plan for Merger with Central and South West Corporation, effective March 1, 1999[Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1998, File No. 1-3525, Exhibit 10(o)]. +10(n) -- AEP Change In Control Agreement [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1999, File No. 1-3525, Exhibit 10(p)]. +10(o) -- AEP System 2000 Long-Term Incentive Plan [Proxy Statement of AEP, March 10, 2000]. +10(p) -- Memorandum of agreement between Susan Tomasky and the Service Corporation dated January 3, 2001 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2000, File No. 1-3525, Exhibit 10(s)]. *12 -- Statement re: Computation of Ratios. *13 -- Copy of those portions of the OPCo 2000 Annual Report (for the fiscal year ended December 31, 2000) 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, 2000, File No. 1-3525, Exhibit 21]. *23 -- Consent of Deloitte & Touche LLP.
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EXHIBIT NUMBER DESCRIPTION - -------------- ----------- OPCO++ (CONTINUED) *24 -- Power of Attorney. 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). 4(a) -- Indenture, dated July 1, 1945, between PSO and Liberty Bank and Trust Company of Tulsa, National Association, as Trustee, as amended and supplemented [Registration Statement No. 2-60712, Exhibit 5.03; Registration Statement No. 2-64432, Exhibit 2.02; Registration Statement No. 2-65871, Exhibit 2.02; Form U-1 No. 70-6822, Exhibit 2; Form U-1 No. 70-7234, Exhibit 3; Registration Statement No. 33-48650, Exhibit 4(b); Registration Statement No. 33-49143, Exhibit 4(c); Registration Statement No. 33-49575, Exhibit 4(b); Annual Report on Form 10-K of PSO for the fiscal year ended December 31, 1993, File No. 0-343, Exhibit 4(b); Current Report on Form 8-K of PSO dated March 4, 1996, No. 0-343, Exhibit 4.01; Current Report on Form 8-K of PSO dated March 4, 1996, No. 0-343, Exhibit 4.02; Current Report on Form 8-K of PSO dated March 4, 1996, No. 0-343, Exhibit 4.03]. 4(b) -- PSO-obligated, mandatorily redeemable preferred securities of subsidiary trust holding solely Junior Subordinated Debentures of PSO: (1) Indenture, dated as of May 1, 1997, between PSO and The Bank of New York, as Trustee [Quarterly Report on Form 10-Q of PSO dated March 31, 1997, File No. 0-343, Exhibits 4.6 and 4.7]. (2) Amended and Restated Trust Agreement of PSO Capital I, dated as of May 1, 1997, among PSO, as Depositor, The Bank of New York, as Property Trustee, The Bank of New York (Delaware), as Delaware Trustee, and the Administrative Trustee [Quarterly Report on Form 10-Q of PSO dated March 31, 1997, File No. 0-343, Exhibit 4.8]. (3) Guarantee Agreement, dated as of May 1, 1997, delivered by PSO for the benefit of the holders of PSO Capital I's Preferred Securities [Quarterly Report on Form 10-Q of PSO dated March 31, 1997, File No. 0-343, Exhibits 4.9]. (4) Agreement as to Expenses and Liabilities, dated as of May 1, 1997, between PSO and PSO Capital I [Quarterly Report on Form 10-Q of PSO dated March 31, 1997, File No. 0-343, Exhibits 4.10]. *4(c) -- Indenture (for unsecured debt securities), dated as of November 1, 2000, between PSO and The Bank of New York, as Trustee. *4(d) -- First Supplemental Indenture, dated as of November 1, 2000, between PSO and The Bank of New York, as Trustee, for Floating Rate Notes, Series A, due November 21, 2002. *12 -- Statement re: Computation of Ratios. *13 -- Copy of those portions of the PSO 2000 Annual Report (for the fiscal year ended December 31, 2000) which are incorporated by reference in this filing. *23(a) -- Consent of Deloitte & Touche LLP. *23(b) -- Consent of Arthur Andersen LLP. *24 -- Power of Attorney. SWEPCO++ 3(a) -- Restated Certificate of Incorporation, as amended through May 6, 1997, including Certificate of Amendment of Restated Certificate of Incorporation [Quarterly Report on Form 10-Q of SWEPCo for the quarter ended March 31, 1997, File No. 1-3146, Exhibit 3.4]. 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].
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EXHIBIT NUMBER DESCRIPTION - -------------- ----------- SWEPCO++ (CONTINUED) 4(a) -- Indenture, dated February 1, 1940, between SWEPCO and Continental Bank, National Association and M. J. Kruger, as Trustees, as amended and supplemented [Registration Statement No. 2-60712, Exhibit 5.04; Registration Statement No. 2-61943, Exhibit 2.02; Registration Statement No. 2-66033, Exhibit 2.02; Registration Statement No. 2-71126, Exhibit 2.02; Registration Statement No. 2-77165, Exhibit 2.02; Form U-1 No. 70-7121, Exhibit 4; Form U-1 No. 70-7233, Exhibit 3; Form U-1 No. 70-7676, Exhibit 3; Form U-1 No. 70-7934, Exhibit 10; Form U-1 No. 72-8041, Exhibit 10(b); Form U-1 No. 70-8041, Exhibit 10(c); Form U-1 No. 70-8239, Exhibit 10(a)]. 4(b) -- SWEPCO-obligated, mandatorily redeemable preferred securities of subsidiary trust holding solely Junior Subordinated Debentures of SWEPCO: (1) Indenture, dated as of May 1, 1997, between SWEPCO and the Bank of New York, as Trustee [Quarterly Report on Form 10-Q of SWEPCO dated March 31, 1997, File No. 1-3146, Exhibits 4.11 and 4.12]. (2) Amended and Restated Trust Agreement of SWEPCO Capital I, dated as of May 1, 1997, among SWEPCO, as Depositor, the Bank of New York, as Property Trustee, The Bank of New York (Delaware), as Delaware Trustee, and the Administrative Trustee [Quarterly Report on Form 10-Q of SWEPCO dated March 31, 1997, File No. 1-3146, Exhibit 4.13]. (3) Guarantee Agreement, dated as of May 1, 1997, delivered by SWEPCO for the benefit of the holders of SWEPCO Capital I's Preferred Securities [Quarterly Report on Form 10-Q of SWEPCO dated March 31, 1997, File No. 1-3146, Exhibit 4.14]. (4) Agreement as to Expenses and Liabilities, dated as of May 1, 1997 between SWEPCO and SWEPCO Capital I [Quarterly Report on Form 10-Q of SWEPCO dated March 31, 1997, File No. 1-3146, Exhibits 4.15]. *4(c) -- Indenture (for unsecured debt securities), dated as of February 4, 2000, between SWEPCO and The Bank of New York, as Trustee. *4(d) -- First Supplemental Indenture, dated as of February 25, 2000, between SWEPCO and The Bank of New York, as Trustee, for Floating Rate Notes due March 1, 2001. *12 -- Statement re: Computation of Ratios. *13 -- Copy of those portions of the SWEPCo 2000 Annual Report (for the fiscal year ended December 31, 2000) which are incorporated by reference in this filing. *23(a) -- Consent of Deloitte & Touche LLP. *23(b) -- Consent of Arthur Andersen LLP. *24 -- Power of Attorney. WTU++ 3(a) -- Restated Articles of Incorporation, as amended, and Articles of Amendment to the Articles of Incorporation [Annual Report on Form 10-K of WTU for the fiscal year ended December 31, 1996, File No. 0-340, Exhibit 3.5]. 3(b) -- By-Laws of WTU (amended as of May 1, 2000) [Quarterly Report on Form 10-Q of WTU for the quarter ended March 31, 2000, File No. 0-340, Exhibit 3.4]. 4(a) -- Indenture, dated August 1, 1943, between WTU and Harris Trust and Savings Bank and J. Bartolini, as Trustees, as amended and supplemented [Registration Statement No. 2-60712, Exhibit 5.05; Registration Statement No. 2-63931, Exhibit 2.02; Registration Statement No. 2-74408, Exhibit 4.02; Form U-1 No. 70-6820, Exhibit 12; Form U-1 No. 70-6925, Exhibit 13; Registration Statement No. 2-98843, Exhibit 4(b); Form U-1 No. 70-7237, Exhibit 4; Form U-1 No. 70-7719, Exhibit 3; Form U-1 No. 70-7936, Exhibit 10; Form U-1 No. 70-8057, Exhibit 10; Form U-1 No. 70-8265, Exhibit 10; Form U-1 No. 70-8057, Exhibit 10(b); Form U-1 No. 70-8057, Exhibit 10(c)]. *12 -- Statement re: Computation of Ratios. *13 -- Copy of those portions of the WTU 2000 Annual Report (for the fiscal year ended December 31, 2000) which are incorporated by reference in this filing.
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EXHIBIT NUMBER DESCRIPTION - -------------- ----------- WTU++ (CONTINUED) *24 -- Power of Attorney. -----------------------
++Certain instruments defining the rights of holders of long-term debt of the registrants included in the financial statements of registrants filed herewith have been omitted because the total amount of securities authorized thereunder does not exceed 10% of the total assets of registrants. The registrants hereby agree to furnish a copy of any such omitted instrument to the SEC upon request. EX-10.(I)(1) 2 0002.txt AMENDED DEFERRED COMP/NON-EMPLOYEE DIRECTOR Exhibit 10(i)(1) American Electric Power Company, Inc. Deferred Compensation and Stock Plan For Non-Employee Directors (As Amended June 1, 2000) Article 1 Purpose The purposes of this American Electric Power Company, Inc. Deferred Compensation and Stock Plan For Non-Employee Directors (the "Plan") are to enable the Company to attract and retain qualified persons to serve as Non-Employee Directors, to provide Non-Employee Directors with an opportunity to defer some or all of their Retainer as a means of saving for retirement or other purposes, to solidify the common interests of its Non-Employee Directors and shareholders by enhancing the equity interest of Non-Employee Directors in the Company, and to encourage the highest level of Non-Employee Director performance by providing such Non-Employee Directors with a proprietary interest in the Company's performance and progress by permitting Non-Employee Directors to receive all or a portion of their Retainer in Common Stock and/or to defer all or a portion of their Retainer in Stock Units. Article 2 Effective Date The Plan is subject to the approval of a majority of the holders of the Company's Common Stock entitled to vote thereon at the Annual Meeting of Shareholders to be held on April 23, 1997, or such other date fixed for the next meeting of shareholders or any adjournment or postponement thereof. Subject to the receipt of such approval, the Plan shall be effective as of January 1, 1997. Article 3 Definitions Whenever used in the Plan, the following terms shall have the respective meanings set forth below: 3.1 "Account" means, with respect to each Participant, the Participant's separate individual account established and maintained for the exclusive purpose of accounting for the Participant's deferred Retainer which is accrued in terms of Stock Units. 3.2 "Beneficiary" means, with respect to each Participant, the recipient or recipients designated by the Participant who are, upon the Participant's death, entitled in accordance with the Plan's terms to receive the benefits to be paid with respect to the Participant. 3.3 "Board" means the Board of Directors of the Company. 3.4 "Committee" means the Committee on Directors of the Board. 3.5 "Common Stock" means the common stock, $6.50 par value, of the Company. 3.6 "Company" means American Electric Power Company, Inc., a New York corporation, and any successor thereto. 3.7 "Director" means an individual who is a member of the Board. 3.8 "Market Value" means the closing price of the Common Stock, as published in The Wall Street Journal report of the New York Stock Exchange - Composite Transactions on the date in question or, if the Common Stock shall not have been traded on such date or if the New York Stock Exchange is closed on such date, then the first day prior thereto on which the Common Stock was so traded. 3.9 "Non-Employee Director" means any person who serves on the Board and who is not an officer of the Company or employee of its Subsidiaries. 3.10 "Participant" means any Non-Employee Director who has made an election to receive all or a portion of such person's Retainer in shares of Common Stock and/or to defer payment of all or a portion of such Retainer in Stock Units. 3.11 "Retainer" means the designated annual cash retainer, currently paid quarterly, for Non-Employee Directors established from time to time by the Board as annual compensation for services rendered, exclusive of compensation for service as a member of any committee designated by the Board or in connection with any meeting of the Board or special assignment, and exclusive of reimbursements for expenses incurred in performance of service as a Director. 3.12 "Stock Unit" means a measure of value, expressed as a share of Common Stock, credited to a Participant under this Plan. No certificates shall be issued with respect to such Stock Units, but the Company shall maintain a bookkeeping Account in the name of the Participant to which the Stock Units shall relate. 3.13 "Subsidiary" means any corporation in which the Company owns directly or indirectly through its Subsidiaries, at least 50 percent of the total combined voting power of all classes of stock, or any other entity (including, but not limited to, partnerships and joint ventures) in which the Company owns at least 50 percent of the combined equity thereof. 3.14 "Termination" means retirement from the Board or termination of services as a Director for any other reason. Article 4 Election to Receive Common Stock for Retainer and/or to Defer Retainer in Stock Units 4.1 Election On or before December 31 of any year, for calendar years subsequent to 1997, a Non-Employee Director may elect, by filing with the Company an election, (a) to receive all or a specified portion of the Director's Retainer in shares of Common Stock and/or (b) to defer receipt of all or a specified portion of the Director's Retainer in Stock Units until the Director's Termination or for a period that results in payment commencing not later than five years thereafter as elected by the Participant. The election to defer payment beyond the Participant's Termination must be made at least one year prior to such Termination. Notwithstanding the foregoing, a Non-Employee Director may choose to participate in the Plan beginning with the Retainer payable on June 30, 1997, by filing an election to so participate on or before March 31, 1997. A Non-Employee Director elected to fill a vacancy on the Company's Board and who was not a Director on the preceding December 31, or whose term of office did not begin until after that date, may file an election to receive Common Stock and/or to defer, for all or a specified portion of the Director's Retainer, commencing not less than three months after the date of the election. 4.2 Revocation of Election An effective election pursuant to Section 4.1 may not be revoked or modified (except as otherwise stated herein) with respect to the Retainer payable for a calendar year or portion of a calendar year for which such election is effective. An effective election may be terminated or modified for any subsequent calendar year by the filing of an election, on or before December 31 of the preceding calendar year for which such modification or termination is to be effective. 4.3 Common Stock Election When a Participant elects pursuant to Section 4.1 to receive all or a portion of the Participant's Retainer in shares of Common Stock, the number of whole shares to be distributed to the Participant, with any fractional shares to be paid in cash, as of the date the Retainer would otherwise have been payable to the Participant, shall be equal to the dollar amount of the Retainer which otherwise would have been payable to the Participant divided by the Market Value on such date. 4.4 Deferred Retainer Election When a Participant elects pursuant to Section 4.1 to defer all or a portion of the Participant's Retainer in Stock Units, the number of whole and fractional Stock Units, computed to three decimal places, to be credited to the Participant's Account, on the date the deferred Retainer would otherwise have been payable to the Participant, shall be equal to the dollar amount of the deferred Retainer which otherwise would have been payable to the Participant divided by the Market Value on such date. Article 5 Dividends and Adjustments 5.1 Reinvestment of Dividends On each dividend payment date with respect to the Common Stock, the Account of a Participant, with Stock Units held pursuant to Article 4, shall be credited with an additional number of whole and fractional Stock Units, computed to three decimal places, equal to the product of the dividend per share then payable, multiplied by the number of Stock Units then credited to such Account, divided by the Market Value on the dividend payment date. 5.2 Adjustments The number of Stock Units credited to a Participant's Account pursuant to Article 4 shall be appropriately adjusted for any change in the Common Stock by reason of any merger, reclassification, consolidation, recapitalization, stock dividend, stock split or any similar change affecting the Common Stock. Article 6 Payment of Stock Units 6.1 Manner of Payment Upon Termination In accordance with the Participant's election, filed with the Company, all Stock Units held in a Participant's Account shall be paid to the Participant either as (a) a lump sum distribution within 10 days after the Participant's deferred distribution date, or (b) up to 10 annual installments commencing within 10 days after the Participant's deferred distribution date. This election shall be made at the same time the Participant makes a deferral election as provided in Section 4.1. Payment may be made in cash, shares of Common Stock, or a combination of both as elected by the Participant. The election to be paid in cash or Common Stock must be filed with the Company at least 30 days prior to the payment date and, in the event an election is not made, payment will be made in cash. 6.2 Manner of Payment Upon Death Notwithstanding the Participant's election, if a Participant dies while Stock Units are held in the Participant's Account, such Stock Units will be paid in a lump sum in cash within 90 days from the date of the Participant's death to the Beneficiary or the Participant's estate, as the case may be. Upon application by the Beneficiary or the legal representative for the Participant's estate, the lump sum payment may be deferred beyond 90 days for good cause if the Committee consents to such deferral. 6.3 Determination Any cash payments of Stock Units shall be calculated on the basis of the average of the Market Value of the Common Stock for the last 20 trading days prior to the Participant's deferred distribution date, respective installment payment dates or the date of the Participant's death, as the case may be. Payment in Common Stock shall be at the rate of one share of Common Stock for each Stock Unit, with any fractional shares to be paid in cash. Article 7 Beneficiary Designation Each Participant shall be entitled to designate a Beneficiary or Beneficiaries (which may be an entity other than a natural person) who, following the Participant's death, will be entitled to receive any payments to be made under Section 6.2. At any time, and from time to time, any designation may be changed or cancelled by the Participant without the consent of any Beneficiary. Any designation, change, or cancellation must be by written notice filed with the Company and shall not be effective until received by the Company. Payment shall be made in accordance with the last unrevoked written designation of Beneficiary that has been signed by the Participant and delivered by the Participant to the Company prior to the Participant's death. If the Participant designates more than one Beneficiary, any payments under Section 6.2 to the Beneficiaries shall be made in equal shares unless the Participant has designated otherwise, in which case the payments shall be made in the proportions designated by the Participant. If no Beneficiary has been named by the Participant or if all Beneficiaries predecease the Participant, payment shall be made to the Participant's estate. Article 8 Transferability Restrictions The Plan shall not in any manner be liable for, or subject to, the debts and liabilities of any Participant or Beneficiary. No payee may assign any payment due such party under the Plan. No benefits at any time payable under the Plan shall be subject in any manner to anticipation, alienation, sale, transfer, assignment, pledge, attachment, garnishment, levy, execution, or other legal or equitable process, or encumbrance of any kind. Article 9 Funding Policy The Company's obligations under the Plan shall be totally unfunded so that the Company or any Subsidiary is under merely a contractual duty to make payments when due under the Plan. The promise to pay shall not be represented by notes and shall not be secured in any way. Article 10 Change in Control Notwithstanding any provision of this Plan to the contrary, if a "Change in Control" (as defined below) of the Company occurs, Stock Units held in a Participant's Account will be paid in a lump sum in cash, shares of Common Stock, or a combination of both, to the Participant, as elected by the Participant, not later than 15 days after the date of the Change in Control. For this purpose, the balance in the Account shall be determined by the higher of (a) the average of the Market Value of the Common Stock for the last 20 trading days prior to such Change in Control or (b) if the Change in Control of the Company occurs as a result of a tender or exchange offer or consummation of a corporate transaction, then the highest price paid per share of Common Stock pursuant thereto. Any consideration other than cash forming a part or all of the consideration for the Common Stock to be paid pursuant to the applicable transaction shall be valued at the valuation price thereon determined by the Board. In addition, the Company shall reimburse a Participant for the legal fees and expenses incurred if the Participant is required to seek to obtain or enforce any right to distribution. In the event that it is determined that such Participant is properly entitled to a cash distribution hereunder, such Participant shall also be entitled to interest thereon at the prime rate of interest as published in The Wall Street Journal plus two percent from the date such distribution should have been made to and including the date it is made. Notwithstanding any provisions of this Plan to the contrary, the provisions of this Article may not be amended by an amendment effected within three years following a Change in Control. A "Change in Control" of the Company shall be deemed to have occurred if (a) any "person" or "group" (as such terms are used in Sections 13(d) and 14(d) of the Securities Exchange Act of 1934, as amended ("Exchange Act")), other than a trustee or other fiduciary holding securities under an employee benefit plan of the Company, becomes the "beneficial owner" (as defined in Rule 13d-3 under the Exchange Act), directly or indirectly, of more than 25 percent of the then outstanding voting stock of the Company; (b) during any period of two consecutive years, individuals who at the beginning of such period constitute the Board, together with any new Directors whose election or nomination for election was approved by a vote of at least two-thirds of the Directors then still in office who were either Directors at the beginning of the period or whose election or nomination for election was previously so approved, cease for any reason to constitute at least a majority of the Board; or (c) the Company's shareholders approve a merger or consolidation of the Company with any other corporation, other than a merger or consolidation which would result in the voting securities of the Company outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity) at least 75 percent of the total voting power represented by the voting securities of the Company or such surviving entity outstanding immediately after such merger or consolidation; or (d) the shareholders of the Company approve a plan of complete liquidation of the Company, or an agreement for the sale or disposition by the Company (in one transaction or a series of transactions) of all or substantially all of the Company's assets. Notwithstanding the foregoing, a Change in Control shall not be deemed to occur as a result of any event described in (a) or (c) above, if Directors who were a majority of the members of the Board prior to such event and who continue to serve as Directors after such event determine that the event shall not constitute a Change in Control. Article 11 Administration The Plan shall be administered by the Committee. The Committee shall have authority to interpret the Plan, and to prescribe, amend and rescind rules and regulations relating to the administration of the Plan, and all such interpretations, rules and regulations shall be conclusive and binding on all Participants. The Committee may employ agents, attorneys, accountants, or other persons (who also may be employees of a Subsidiary) and allocate or delegate to them powers, rights,, and duties, all as the Committee may consider necessary or advisable to properly carry out the administration of the Plan. Article 12 Amendment and Termination The Company, by resolution duly adopted by the Board, shall have the right, authority and power to alter, amend, modify, revoke, or terminate the Plan; except as provided in Article 10; and provided further, that no amendment or termination of the Plan shall adversely affect the rights of any Participant with respect to any Stock Units held in such Participant's Account, unless the Participant shall consent thereto in writing. Article 13 Miscellaneous 13.1 No Right to Continue as a Director Nothing in this Plan shall be construed as conferring upon a Participant any right to continue as a member of the Board. 13.2 No Interest as a Shareholder Stock Units do not give a Participant any rights whatsoever with respect to shares of Common Stock until such time and to such extent that payment of Stock Units is made in shares of Common Stock as requested by the Participant. 13.3 No Right to Corporate Assets Nothing in this Plan shall be construed as giving the Participant, the Participant's designated Beneficiaries or any other person any equity or interest of any kind in the assets of the Company or any Subsidiary or creating a trust of any kind or a fiduciary relationship of any kind between the Company or any Subsidiary and any person. As to any claim for payments due under the provisions of the Plan, a Participant, Beneficiary and any other persons having a claim for payments shall be unsecured creditors of the Company or any Subsidiary. 13.4 Payment to Legal Representative for Participant In the event the Committee shall find that a Participant is unable to care for his or her affairs because of illness or accident, the Committee may direct that any payment due the Participant be paid to the Participant's duly appointed legal representative, and any such payment so made shall be a complete discharge of the liabilities of the Plan. 13.5 No Limit on Further Corporate Action Nothing contained in the Plan shall be construed so as to prevent the Company or any Subsidiary from taking any corporate action which is deemed by the Company or any Subsidiary to be appropriate or in its best interest. 13.6 Governing Law The Plan shall be construed and administered according to the laws of the State of New York to the extent that those laws are not preempted by the laws of the United States of America. 13.7 Headings The headings of articles, sections, subsections, paragraphs or other parts of the Plan are for convenience of reference only and do not define, limit, construe, or otherwise affect its contents. EX-10.(I)(2) 3 0003.txt AMENDED STOCK UNIT ACCUMULATION PLAN Exhibit 10(i)(2) American Electric Power Company, Inc. Stock Unit Accumulation Plan For Non-Employee Directors (As Amended June 1, 2000) Article 1 Purpose The purposes of this American Electric Power Company, Inc. Stock Unit Accumulation Plan For Non-Employee Directors (the "Plan") are to enable the Company to attract and retain qualified persons to serve as Non-Employee Directors, to solidify the common interests of its Non-Employee Directors and shareholders by enhancing the equity interest of Non-Employee Directors in the Company, and to encourage the highest level of Non-Employee Director performance by providing such Non-Employee Directors with a proprietary interest in the Company's performance and progress by paying a portion of the compensation of the Non-Employee Directors in deferred Stock Units. Article 2 Effective Date The Plan shall be effective as of January 1, 1997. Article 3 Definitions Whenever used in the Plan, the following terms shall have the respective meanings set forth below: 3.1 "Account" means, with respect to each Participant, the Participant's separate individual account established and maintained for the exclusive purpose of accounting for the Participant's award of Stock Units. 3.2 "Beneficiary" means, with respect to each Participant, the recipient or recipients designated by the Participant who are, upon the Participant's death, entitled in accordance with the Plan's terms to receive the benefits to be paid with respect to the Participant. 3.3 "Board" means the Board of Directors of the Company. 3.4 "Committee" means the Committee on Directors of the Board. 3.5 "Common Stock" means the common stock, $6.50 par value, of the Company. 3.6 "Company" means American Electric Power Company, Inc., a New York corporation, and any successor thereto. 3.7 "Director" means an individual who is a member of the Board. 3.8 "Market Value" means the closing price of the Common Stock, as published in The Wall Street Journal report of the New York Stock Exchange - Composite Transactions on the date in question or, if the Common Stock shall not have been traded on such date or if the New York Stock Exchange is closed on such date, then the first day prior thereto on which the Common Stock was so traded. 3.9 "Non-Employee Director" means any person who serves on the Board and who is not an officer of the Company or employee of its Subsidiaries. 3.10 "Participant" means any Non-Employee Director who has received an award of Stock Units. 3.11 "Retainer" means the designated annual cash retainer, currently paid quarterly, for Non-Employee Directors established from time to time by the Board as annual compensation for services rendered, exclusive of compensation for service as a member of any committee designated by the Board or in connection with any meeting of the Board or special assignment, and exclusive of reimbursements for expenses incurred in performance of service as a Director. 3.12 "Stock Unit" means a measure of value, expressed as a share of Common Stock, credited to a Participant under this Plan. No certificates shall be issued with respect to such Stock Units, but the Company shall maintain a bookkeeping Account in the name of the Participant to which the Stock Units shall relate. 3.13 "Subsidiary" means any corporation in which the Company owns directly or indirectly through its Subsidiaries, at least 50 percent of the total combined voting power of all classes of stock, or any other entity (including, but not limited to, partnerships and joint ventures) in which the Company owns at least 50 percent of the combined equity thereof. 3.14 "Termination" means retirement from the Board or termination of service as a Director for any other reason. Article 4 Stock Unit Awards 4.1 Annual Awards Each Non-Employee Director's Account shall be credited with 750 Stock Units as of the first day of the month in which the Director becomes a member of the Board, and on the first day of such month for each year thereafter. In the event of a change in the Retainer, the Committee may reconsider the amount of the annual awards and may recommend to the Board changes in the number of Stock Units to be awarded. 4.2 Retirement Program Termination Awards On and as of December 31, 1996, each Non-Employee Director serving as such on such date who makes or has made an irrevocable election by January 31, 1997 to waive participation in, and any and all benefits under, the Company's Retirement Plan for Directors, shall have credited to the Account of such Participant, as of January 1, 1997, the number of vested and nonforfeitable Stock Units as follows: R. M. Duncan 3,000; R. W. Fri 600; A. G. Hansen 3,000; L. A. Hudson, Jr. 3,000; A. E. Peyton 3,000; D. G. Smith 900; L. G. Stuntz 1,200; M. Tanenbaum 2,400; and A. H. Zwinger 3,000. Article 5 Dividends and Adjustments 5.1 Reinvestment of Dividends On each dividend payment date with respect to the Common Stock, the Account of a Participant, with Stock Units held pursuant to Article 4, shall be credited with an additional number of whole and fractional Stock Units, computed to three decimal places, equal to the product of the dividend per share then payable, multiplied by the number of Stock Units then credited to such Account, divided by the Market Value on the dividend payment date. 5.2 Adjustments The number of Stock Units credited to a Participant's Account pursuant to Article 4 shall be appropriately adjusted for any change in the Common Stock by reason of any merger, reclassification, consolidation, recapitalization, stock dividend, stock split or any similar change affecting the Common Stock. Article 6 Payment of Stock Units 6.1 Manner of Payment Upon Termination Stock Units held in a Participant's Account shall be paid to the Participant in a lump sum in cash within 10 days after the Participant's Termination unless the Participant has filed an election with the Company to defer such payment as provided in the following sentence. The Participant may elect (a) to defer the lump sum payment for one or more years up to a maximum of five years following Termination or (b) to receive payment of the Stock Units in up to 10 annual installments commencing within 10 days after Termination or the deferred payment date elected by the Participant pursuant to part (a) of this sentence. The election to defer payment beyond the Participant's Termination must be made at least one year prior to such Termination. 6.2 Manner of Payment Upon Death Notwithstanding the Participant's election, if a Participant dies while Stock Units are held in the Participant's Account, such Stock Units, whether vested or unvested and forfeitable, will be paid in a lump sum in cash within 90 days from the date of the Participant's death to the Beneficiary or the Participant's estate, as the case may be. Upon application of the Beneficiary or the legal representative of the Participant's estate, the lump sum payment may be deferred beyond 90 days for good cause if the Committee consents to such deferral. 6.3 Determination Any cash payments of Stock Units shall be calculated on the basis of the average of the Market Value of the Common Stock for the last 20 trading days prior to the Participant's Termination, deferred distribution date, respective installment payment dates or the date of the Participant's death, as the case may be. Article 7 Beneficiary Designation Each Participant shall be entitled to designate a Beneficiary or Beneficiaries (which may be an entity other than a natural person) who, following the Participant's death, will be entitled to receive any payments to be made under Section 6.2. At any time, and from time to time, any designation may be changed or cancelled by the Participant without the consent of any Beneficiary. Any designation, change, or cancellation must be by written notice filed with the Company and shall not be effective until received by the Company. Payment shall be made in accordance with the last unrevoked written designation of Beneficiary that has been signed by the Participant and delivered by the Participant to the Company prior to the Participant's death. If the Participant designates more than one Beneficiary, any payments under Section 6.2 to the Beneficiaries shall be made in equal shares unless the Participant has designated otherwise, in which case the payments shall be made in the proportions designated by the Participant. If no Beneficiary has been named by the Participant or if all Beneficiaries predecease the Participant, payment shall be made to the Participant's estate. Article 8 Transferability Restrictions The Plan shall not in any manner be liable for, or subject to, the debts and liabilities of any Participant or Beneficiary. No payee may assign any payment due such party under the Plan. No benefits at any time payable under the Plan shall be subject in any manner to anticipation, alienation, sale, transfer, assignment, pledge, attachment, garnishment, levy, execution, or other legal or equitable process, or encumbrance of any kind. Article 9 Funding Policy The Company's obligations under the Plan shall be totally unfunded so that the Company or any Subsidiary is under merely a contractual duty to make payments when due under the Plan. The promise to pay shall not be represented by notes and shall not be secured in any way. Article 10 Change in Control Notwithstanding any provision of this Plan to the contrary, if a "Change in Control" (as defined below) of the Company occurs, Stock Units held in a Participant's Account, whether vested or unvested and forfeitable, will be paid in a lump sum in cash to the Participant not later than 15 days after the date of the Change in Control. For this purpose, the balance in the Account shall be determined by the higher of (a) the average of the Market Value of the Common Stock for the last 20 trading days prior to such Change in Control or (b) if the Change in Control of the Company occurs as a result of a tender or exchange offer or consummation of a corporate transaction, then the highest price paid per share of Common Stock pursuant thereto. Any consideration other than cash forming a part or all of the consideration for the Common Stock to be paid pursuant to the applicable transaction shall be valued at the valuation price thereon determined by the Board. In addition, the Company shall reimburse a Participant for the legal fees and expenses incurred if the Participant is required to seek to obtain or enforce any right to distribution. In the event that it is determined that such Participant is properly entitled to a cash distribution hereunder, such Participant shall also be entitled to interest thereon at the prime rate of interest as published in The Wall Street Journal plus two percent from the date such distribution should have been made to and including the date it is made. Notwithstanding any provisions of this Plan to the contrary, the provisions of this Article may not be amended by an amendment effected within three years following a Change in Control. A "Change in Control" of the Company shall be deemed to have occurred if (a) any "person" or "group" (as such terms are used in Sections 13(d) and 14(d) of the Securities Exchange Act of 1934, as amended ("Exchange Act")), other than a trustee or other fiduciary holding securities under an employee benefit plan of the Company, becomes the "beneficial owner" (as defined in Rule 13d-3 under the Exchange Act), directly or indirectly, of more than 25 percent of the then outstanding voting stock of the Company; (b) during any period of two consecutive years, individuals who at the beginning of such period constitute the Board, together with any new Directors whose election or nomination for election was approved by a vote of at least two-thirds of the Directors then still in office who were either Directors at the beginning of the period or whose election or nomination for election was previously so approved, cease for any reason to constitute at least a majority of the Board; or (c) the Company's shareholders approve a merger or consolidation of the Company with any other corporation, other than a merger or consolidation which would result in the voting securities of the Company outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity) at least 75 percent of the total voting power represented by the voting securities of the Company or such surviving entity outstanding immediately after such merger or consolidation; or (d) the shareholders of the Company approve a plan of complete liquidation of the Company, or an agreement for the sale or disposition by the Company (in one transaction or a series of transactions) of all or substantially all of the Company's assets. Notwithstanding the foregoing, a Change in Control shall not be deemed to occur as a result of any event described in (a) or (c) above, if Directors who were a majority of the members of the Board prior to such event and who continue to serve as Directors after such event determine that the event shall not constitute a Change in Control. Article 11 Administration The Plan shall be administered by the Committee. The Committee shall have authority to interpret the Plan, and to prescribe, amend and rescind rules and regulations relating to the administration of the Plan, and all such interpretations, rules and regulations shall be conclusive and binding on all Participants. The Committee may employ agents, attorneys, accountants, or other persons (who also may be employees of a Subsidiary) and allocate or delegate to them powers, rights, and duties, all as the Committee may consider necessary or advisable to properly carry out the administration of the Plan. Article 12 Amendment and Termination The Company, by resolution duly adopted by the Board, shall have the right, authority and power to alter, amend, modify, revoke, or terminate the Plan; except as provided in Article 10; and provided further, that no amendment or termination of the Plan shall adversely affect the rights of any Participant with respect to any Stock Units held in such Participant's Account, unless the Participant shall consent thereto in writing. Article 13 Miscellaneous 13.1 No Right to Continue as a Director Nothing in this Plan shall be construed as conferring upon a Participant any right to continue as a member of the Board. 13.2 No Interest as a Shareholder Stock Units do not give a Participant any rights whatsoever with respect to shares of Common Stock. 13.3 No Right to Corporate Assets Nothing in this Plan shall be construed as giving the Participant, the Participant's designated Beneficiaries or any other person any equity or interest of any kind in the assets of the Company or any Subsidiary or creating a trust of any kind or a fiduciary relationship of any kind between the Company or any Subsidiary and any person. As to any claim for payments due under the provisions of the Plan, a Participant, Beneficiary and any other persons having a claim for payments shall be unsecured creditors of the Company or any Subsidiary. 13.4 Payment to Legal Representative for Participant In the event the Committee shall find that a Participant is unable to care for his or her affairs because of illness or accident, the Committee may direct that any payment due the Participant be paid to the Participant's duly appointed legal representative, and any such payment so made shall be a complete discharge of the liabilities of the Plan. 13.5 No Limit on Further Corporate Action Nothing contained in the Plan shall be construed so as to prevent the Company or any Subsidiary from taking any corporate action which is deemed by the Company or any Subsidiary to be appropriate or in its best interest. 13.6 Governing Law The Plan shall be construed and administered according to the laws of the State of New York to the extent that those laws are not preempted by the laws of the United States of America. 13.7 Headings The headings of articles, sections, subsections, paragraphs or other parts of the Plan are for convenience of reference only and do not define, limit, construe, or otherwise affect its contents. EX-10.(J)(1)(A) 4 0004.txt AMENDED EXCESS BENEFIT PLAN EXHIBIT 10(j)(1)(A) AMERICAN ELECTRIC POWER SYSTEM EXCESS BENEFIT PLAN AMENDED AND RESTATED AS OF JANUARY 1, 2001 ARTICLE I Purposes and Effective Date 1.1 The American Electric Power System Excess Benefit Plan is established to provide Supplemental Retirement Benefits for eligible employees whose retirement benefits from the American Electric Power System Retirement Plan are restricted due to limitations imposed by provisions of the Internal Revenue Code or who are entitled to Supplemental Retirement Benefits under the terms of an employment agreement between the eligible employee and an employer. 1.2 The effective date of the Excess Benefit Plan is January 1, 1990 and the effective date of this amended and restated Plan is January 1, 2001. ARTICLE II Definitions 2.1 "Accredited Service" means the period of time taken into account under the terms of the Retirement Plan for the purpose of computing a Retirement Plan benefit under either the Cash Balance Formula or the Final Average Pay Formula. 2.2 "Base Compensation" means a Participant's regular base salary or wage including any salary or wage reductions made pursuant to sections 125 and 402(e)(3) of the Code and contributions to the American Electric Power System Supplemental Retirement Savings Plan; and excluding bonuses (such as but not limited to project bonuses and sign-on bonuses), compensation paid pursuant to the terms of an annual compensation plan, performance pay awards, severance pay, relocation payments, or any other form of additional compensation that is not considered to be part of base salary or base wage. 2.3 "Cash Balance Formula" means the cash balance benefit formula used to calculate benefits under the Retirement Plan effective for Plan Years commencing after December 31, 2000. 2.4 "Code" means the Internal Revenue Code of 1986, as amended from time to time. 2.5 "Committee" means the Employee Benefit Trusts Committee. 2.6 "Company" means the American Electric Power Service Corporation and its subsidiaries and affiliates who adopt the Excess Benefit Plan. 2.7 "Corporation" means the American Electric Power Company, Inc., a New York corporation, and its affiliates and subsidiaries. 2.8 "Employment Contract" means a contract between the Company and a Participant that provides the Participant with a non-qualified retirement benefit. 2.9 "ERISA" means the Employee Retirement Income Security Act of 1974 as amended from time to time. 2.10 "Excess Benefit Plan" means the American Electric Power System Excess Benefit Plan, as amended or restated from time to time. 2.11 "Final Average Pay Formula" means the final average pay benefit formula used to calculate benefits under the Retirement Plan. 2.12 "Incentive Compensation" means incentive compensation paid pursuant to the terms of an annual incentive compensation plan, provided that compensation shall not include non-annual bonuses (such as but not limited to project bonuses and sign-on bonuses), severance pay, relocation payments, or any other form of additional compensation that is not considered to be part of Base Compensation. An Incentive Compensation award, the payment of which is deferred according to the terms of the plan or by the election of the Participant, shall be deemed earned at the end of the Plan Year for the Incentive Compensation Plan. 2.13 "Lump Sum Benefit" means under the Final Average Pay Formula the present value of the difference between the Participant's Supplemental Retirement Benefit calculated using the Retirement Plan early retirement reduction factors from age 65 to age 55 and, if necessary, actuarially reduced from age 55 to the date the Supplemental Retirement Benefit is paid and the Participant"s Supplemental Retirement Benefit actuarially reduced from age 65 to the date the Supplemental Retirement Benefit is paid; or, when applicable for computing the pre-retirement surviving spouse annuity, the present value of the difference between 50% of the Participant's Supplemental Retirement Benefit calculated using the Retirement Plan early retirement reduction factors from age 65 to age 55 and, if necessary, actuarially reduced from age 55 to the Participant's date of death and (b) 50% of the Participant's Supplemental Retirement Benefit actuarially reduced from age 65 to the date the Participant's date of death. 2.14 "Maximum Benefit" means the maximum early, normal, disability or deferred vested retirement benefit permitted by the Code to be paid to a Participant from the Retirement Plan under either the Final Average Pay Formula or the Cash Balance Formula upon the Participant's early, normal, disability or deferred retirement or the pre-retirement surviving spouse annuity permitted by the Code to be paid to the Surviving Spouse upon the death of the Participant. 2.15 "Participant" means any exempt salaried employee of the Company who is a participant in the Retirement Plan, and for purposes of earning a Supplemental Retirement Benefit under: (a) the Final Average Pay Formula, whose Base Compensation for the Plan Year exceeds the limitation of section 401(a)(17) of the Code, or who is entitled to a Supplemental Retirement Benefit under the terms of an Employment Contract, or (b) the Cash Balance Formula, whose Base Compensation plus Incentive Compensation for the Plan Year exceeds the limitation of section 401(a)(17) of the Code. If in any Plan Year after a salaried employee becomes a Participant, the Participant's Base Compensation or Base Compensation plus Incentive Compensation is lower than the compensation limits imposed by section 401(a)(17) of the Code due to an increase in the 401(a)(17) limits, the Participant shall nevertheless continue as a Participant in the Excess Benefit Plan until the Participant terminates employment or the Excess Benefit Plan is terminated. 2.16 "Plan Year" means the calendar year commencing each January 1 and ending each December 31. 2.17 "Retirement Plan" means the American Electric Power System Retirement Plan, as amended from time to time. 2.18 "Supplemental Retirement Benefit" means the difference between the Participant's Unrestricted Benefit and the Participant's Maximum Benefit under either the Cash Balance Formula or Final Average Pay Formula. 2.19 "Surviving Spouse" means the spouse of a Participant who is legally married to the Participant and whose marriage to the Participant occurred at least one year prior to the earlier of the Participant's termination of employment or death. 2.20 "Unrestricted Benefit" means the early, normal, disability or deferred vested retirement benefit payable to a Participant upon a Participant's early, normal, disability or deferred vested retirement or the pre-retirement surviving annuity payable to the Surviving Spouse upon the death of the Participant under the terms of the Retirement Plan Cash Balance Formula or Final Average Pay Formula assuming (i) the Code restrictions on benefits that can be provided by the Retirement Plan under either benefit formula are not applicable and (ii) the maximum compensation upon which the benefit is based is the Participant's Base Compensation and Incentive Compensation up to one million dollars or the non-qualified retirement benefit provided for in an Employment Agreement. ARTICLE III Benefits 3.1 An employee who was a Participant in the Excess Benefit Plan as of December 31, 2000 shall accrue a benefit under both the Cash Balance Formula and the Final Average Pay Formula as of January 1, 2001 and shall be entitled to an account balance adjustment for the Participant"s cash balance account in the Excess Benefit Plan as described in the Retirement Plan An employee who was not a Participant in the Excess Benefit Plan as of December 31, 2000 and who becomes a Participant after December 31, 2000 shall accrue a benefit under the Excess Benefit Plan as follows: (a) If the Participant's Base Compensation exceeds the compensation limitation of section 401(a)(17) of the Code prior to December 31, 2010, the Participant shall accrue a benefit under the Final Average Pay Formula, or (b) If the Participant's Base Compensation plus Incentive Compensation exceeds the compensation limit of 401(a)(17) of the Code, the Participant shall accrue a benefit under the Cash Balance Formula. No Participant shall accrue a benefit under the Final Average Pay Formula after December 31, 2010. 3.2 Upon a Participant's normal retirement, in accordance with the terms of the Retirement Plan, the Participant shall be entitled to a Supplemental Retirement Benefit under either the Cash Balance Formula or the Final Average Pay Formula, as elected by the Participant, reduced by any qualified or non-qualified retirement benefits the Participant is entitled to receive from any prior employer as identified in an Employment Contract. 3.3 Upon a Participant's early retirement, in accordance with the terms of the Retirement Plan, the Participant shall be entitled to a Supplemental Retirement Benefit under either the Cash Balance Formula or the Final Average Pay Formula, as elected by the Participant, adjusted by the early retirement factors contained in the Retirement Plan, if applicable, reduced by any qualified or non-qualified retirement benefits the Participant is entitled to receive from any prior employer as identified in an Employment Contract. 3.4 Upon a Participant's termination of employment prior to qualifying for early retirement under the terms of the Retirement Plan, the Participant shall be entitled to a Supplemental Retirement Benefit under either the Cash Balance Formula or the Final Average Pay Formula, as elected by the Participant, that is adjusted in accordance with the reductions specified in the Retirement Plan for deferred vested Retirement Plan participants, if applicable, reduced by any qualified or non-qualified retirement benefits the Participant is entitled to receive from any prior employer as identified in an Employment Contract. 3.5 A Participant whose employment is terminated prior to age 55 due to a restructuring, consolidation or downsizing of the Company and who, at the time of termination, has (i) completed 25 or more years of Accredited Service under the terms of the Retirement Plan or (ii) has attained age 50 and has completed 10 or more years of Accredited Service under the terms of the Retirement Plan and (iii) who elects to receive his or her benefit under the Final Average Pay Formula shall be entitled to an early retirement Supplemental Retirement Benefit as described in section 3.3 above and a Lump Sum Benefit, the sum of which shall be reduced by any qualified or non-qualified retirement benefits the Participant is entitled to receive from any prior employer as identified in an Employment Contract. ARTICLE IV Death Benefits 4.1 Upon the death of a Participant prior to the Participant's termination of employment or commencement of benefits, the Surviving Spouse shall be entitled to a Supplemental Retirement Benefit paid as either an annuity or lump sum, as elected by the Surviving Spouse, reduced by any qualified or non-qualified retirement benefits the Surviving Spouse is entitled to receive from the Participant's prior employer or employers as identified in an Employment Contract. 4.2 Upon the death of the Participant after commencement of the Participant's Supplemental Retirement Benefit, the Surviving Spouse shall be entitled to a Supplemental Retirement Benefit elected by the Participant at the time of the Participant's retirement or termination of employment, reduced by any qualified or non-qualified retirement benefits the Surviving Spouse is entitled to receive from the Participant's prior employer or employers as identified in an Employment Contract 4.3 Upon the death of a Participant described in section 3.5 prior to the Participant's election to commence benefits, the Surviving Spouse shall be entitled to a Supplemental Retirement Benefit that would be paid to the Surviving Spouse of a Participant described in section 3.4 and shall be entitled to a Lump Sum Benefit the sum of which is to be reduced by any qualified or non-qualified retirement benefits the Surviving Spouse is entitled to receive from the Participant's prior employer or employers as identified in an Employment Contract; provided that, the Surviving Spouse elects to receive his or her benefit under the Final Average Pay Formula. 4.4 The Participant, with the consent of the spouse, may name an individual or trust as the beneficiary of any death benefit that may be payable under the Final Average Pay Formula or the Cash Balance Formula. The beneficiary shall be designated on a form provided by the Committee. If the Participant does not designate a beneficiary, the default beneficiary shall be the Participant's Spouse, or if the Participant is not married at the time of death, the Participant's estate. ARTICLE V Payment of Supplemental Retirement Benefits 5.1 Except as provided in section 5.2, a Participant's election under the Retirement Plan of a single life annuity, a 50% joint and survivor annuity, or an optional form of payment (with the valid consent of the Participant's spouse where required under the terms of the Retirement Plan) shall be deemed to be the election made by the Participant for the Supplemental Retirement Benefit payable under the Excess Benefit Plan. The payment of a Supplemental Retirement Benefit as an annuity shall commence at the same time annuity benefit payments from the Retirement Plan commence. 5.2 A Participant may elect to receive his or her Supplemental Retirement Benefit as a partial lump sum with the balance of the Supplemental Retirement Benefit paid as an annuity as provided in section 5.1, a total lump sum distribution or as installment payments over a period of at least two and not more than ten years. The Participant may elect to defer the payment of a partial or lump sum distribution or the start date of installment payments to a date no later than the date the Participant attains age 70-1/2. During any deferral period and during an installment period, the unpaid balance of the Supplemental Retirement Benefit shall receive interest credits at the interest rate then being credited for the Cash Balance Formula. Supplemental Retirement Benefit payments for Participants who terminate employment during the 2001 Plan Year and elect a lump sum or installment payment option shall commence no earlier than January 1, 2002. 5.3 A Participant described in section 3.5, may elect to commence payments of the Participant's Supplemental Retirement Benefit as of the first day of any month following the Participant's termination of employment, provided that the Participant also elects to receive retirement benefits from the Retirement Plan as of the same date. Supplemental Retirement Benefits that commence prior to age 55 shall be reduced actuarially from age 55 to the Participant's age at the time the Supplemental Retirement Benefit payments commence. The Lump Sum Benefit payable to the Participant shall be calculated and paid as of the date the Participant elects to receive payment of the Supplemental Retirement Benefits. ARTICLE VI Administration 6.1 The Committee shall administer the Excess Benefit Plan. The Committee shall have the authority to interpret the Excess Benefit Plan and to prescribe, amend and rescind rules and regulations relating to the administration of the Excess Benefit plan, and all such interpretations, rules and regulations shall be conclusive and binding on all Participants. 6.2 The Committee may employ agents, attorneys, accountants, or other persons and allocate or delegate to them powers, rights, and duties all as the Committee may consider necessary or advisable to properly carry out the administration of the Excess Benefit Plan. ARTICLE VII Amendment or Termination 7.1 The Company intends the Excess Benefit Plan to be permanent but reserves the right to amend or terminate the Excess Benefit Plan when, in the sole opinion of the Company, such amendment or termination is advisable. Any such amendment or termination shall be made pursuant to a resolution of the Board of Directors of the Company. 7.2 No amendment or termination of the Excess Benefit Plan shall directly or indirectly deprive any current or former Participant or Surviving Spouse of all or any portion of any Supplemental Retirement Benefit which commenced prior to the effective date of such amendment or termination or which would be payable if the Participant terminated employment for any reason, including death, on such effective date. ARTICLE VIII Miscellaneous 8.1 Nothing in this Excess Benefit Plan shall interfere with or limit in any way the right of the Company to terminate any Participant's employment at any time, nor confer upon a Participant any right to continue in the employ of the Company. 8.2 In the event the Committee shall find that a Participant or Surviving Spouse is unable to care for his or her affairs because of illness or accident, the Committee may direct that any payment due the Participant or the Surviving Spouse be paid to the duly appointed legal representative of the Participant or Surviving Spouse, and any such payment so made shall be a complete discharge of the liabilities of the Excess Benefit Plan. 8.3 Except as otherwise expressly provided herein, all terms, conditions and actuarial assumptions of the Retirement Plan applicable to benefits payable under the terms of the Retirement Plan shall also be applicable to the Supplemental Retirement Benefits paid under the terms of the Excess Benefit Plan. 8.4 The Supplemental Retirement Benefits paid under the Excess Benefit Plan shall not be funded, but shall constitute liabilities of the Company to be paid out of general corporate assets. Nothing contained in the Excess Benefit Plan shall constitute a guaranty by the Company or any other entity or person that the assets of the Company will be sufficient to pay any benefit hereunder. 8.5 The Excess Benefit Plan shall be construed and administered according to the laws of the State of Ohio. ARTICLE IX Change In Control 9.1 Notwithstanding any provisions of the Excess Benefit Plan to the contrary, if a Change in Control, as defined in Section 9.2, of the Corporation occurs, all Supplemental Retirement Benefits accrued as of the date of the Change in Control shall be fully vested and non-forfeitable. 9.2 A "Change in Control" of the Corporation shall be deemed to have occurred if (i) any "person" or "group" (as such terms are used in Sections 13(d) and 14(d) of the Securities Exchange Act of 1934 ("Exchange Act")), other than any company owned, directly or indirectly, by the shareholders of the Corporation in substantially the same proportions as their ownership of stock of the Corporation or a trustee or other fiduciary holding securities under an employee benefit plan of the Corporation, becomes the "beneficial owner" (as defined in Rule 13d-3 under the Exchange Act), directly or indirectly, of more than 25 percent of the then outstanding voting stock of the Corporation, (ii) during any period of two consecutive years, individuals who at the beginning of such period constitute the Board, together with any new Directors (other than a director nominated by a person (x) who has entered into an agreement with the Corporation to effect a transaction described in Section 9.2(i), (iii) or (iv) who publicly announces an intention to take or to consider taking actions (including, but not limited to, an actual or threatened proxy contest) which if consummated would constitute a Change In Control) whose election or nomination for election was approved by a vote of at least two-thirds of the Directors then still in office who were either Directors at the beginning of the period or whose election or nomination for election was previously so approved, cease for any reason to constitute at least a majority of the Board; or (iii) the consummation of a merger or consolidation of the Corporation with any other entity, other than a merger or consolidation which would result in the voting securities of the Corporation outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity) at least 50 percent of the total voting power represented by the voting securities of the Corporation or such surviving entity outstanding immediately after such merger or consolidation; or (iv) the shareholders of the Corporation approve a plan of complete liquidation of the Corporation, or an agreement for the sale or disposition by the Corporation (in one transaction or a series of transactions) of all or substantially all of the Corporation's assets. Notwithstanding the foregoing, a Change in Control shall not be deemed to occur as a result of the consummation of the transactions contemplated in the Agreement and Plan of Merger by and among the Corporation, Augusta Acquisition Corporation and Central and South West Corporation dated as of December 21, 1997, nor thereafter as a result of any event in (i) or (iii) above, if Directors who were members of the Board prior to such event continue to constitute majority of the Board after such event. For purposes of this Section 9.2, "Board" shall mean the Board of Directors of the Corporation, and "Director" shall mean an individual who is a member of the Board. ARTICLE X Claims Procedure 10.1 If a Participant makes a written request alleging a right to receive benefits under the Excess Benefit Plan or alleging a right to receive an adjustment in benefits being paid under the Excess Benefit Plan, the Committee shall treat it as a claim for benefits. All claims for benefits under the Excess Benefit Plan shall be sent to the Committee and must be received within 75 days after the Participant's termination of employment. If the Committee determines that any Participant who has claimed a right to receive benefits, or different benefits, under the Excess Benefit Plan is not entitled to receive all or any part of the benefits claimed, it will inform the claimant in writing of its determination and the reasons therefor in terms calculated to be understood by the claimant. The notice will be sent within 90 days of the claim unless the Committee determines additional time, not exceeding 90 days, is needed. The notice shall make specific reference to the pertinent Excess Benefit Plan provisions on which the denial is based, and describe any additional material or information, if any, necessary for the claimant to perfect the claim and the reason any such addition material or information is necessary. Such notice shall, in addition, inform the claimant what procedure the claimant should follow to take advantage of the review procedures set forth below in the event the claimant desires to contest the denial of the claim. The claimant may within 90 days thereafter submit in writing to the Committee a notice that the claimant contests the denial of the claim by the Committee and desires a further review. The Committee shall within 60 days thereafter review the claim and authorize the claimant to appear personally and review pertinent documents and submit issues and comments relating to the claim to the persons responsible for making the determination on behalf of the Committee. The Committee will render its final decision with specific reasons therefore in writing and will transmit it to the claimant within 60 days of the written request for review, unless the Committee determines additional time, not exceeding 60 days, is needed, and so notifies the claimant. If the Committee fails to respond to a claim filed in accordance with the foregoing within 90 days or any such extended period, the Committee shall be deemed to have denied the claim. EX-10.(J)(2) 5 0005.txt AMENDED SUPPLEMENTAL SAVINGS PLAN EXHIBIT 10(j)(2) AMERICAN ELECTRIC POWER SYSTEM SUPPLEMENTAL RETIREMENT SAVINGS PLAN AMENDED AND RESTATED AS OF JANUARY 1, 2001 ARTICLE I Purposes and Effective Date 1.1 The American Electric Power System Supplemental Retirement Savings Plan is established to provide to eligible employees a tax-deferred savings opportunity otherwise not available to them under the terms of the American Electric Power System Retirement Savings Plan because of contribution restrictions imposed by the Internal Revenue Code. 1.2 The effective date of the American Electric Power System Supplemental Retirement Savings Plan is January 1, 1994 and the effective date of the Amended and Restated American Electric Power System Supplemental Retirement Savings Plan is January 1, 2001. ARTICLE II DEFINITIONS 2.1 "Account" means the separate memo account established and maintained by the Company or the recordkeeper employed by the Company to record Contributions allocated to a Participant's Account and to record any related Investment Income on the Fund or Funds selected by the Participant. 2.2 "Applicable Federal Rate" means 120% of the applicable federal long-term rate, with monthly compounding (as prescribed under Section 1274(d) of the Code), published for the December immediately prior to the Plan year. 2.3 "Code" means the Internal Revenue Code of 1986, as amended from time to time. 2.4 "Committee" means the Employee Benefit Trusts Committee as established by the Board of Directors of American Electric Power Service Corporation. 2.5 "Compensation" means the sum of a Participant's regular base salary or wage including any salary or wage reductions made pursuant to sections 125 and 402(e)(3) of the Code and contributions to this Plan and incentive compensation paid pursuant to the terms of an annual incentive compensation plan up to a maximum of one million dollars, provided that compensation shall not include non-annual bonuses (such as but not limited to project bonuses and sign-on bonuses), severance pay, relocation payments, or any other form of additional compensation that is not considered to be part of base salary, base wage or incentive compensations. 2.6 "Company" means the American Electric Power Service Corporation and its subsidiaries and affiliates. 2.7 "Company Contributions" means the matching contributions made by the Company pursuant to section 3.2. 2.8 "Contributions" means, as the context may require, Participant Contributions and Company contributions. 2.9 "Corporation" means the American Electric Power Company, Inc., a New York corporation. 2.10 "Eligible Employee" means an employee of the Company whose base salary or base wage, including salary or wage reductions made pursuant to section 125 and 402(e)(3) of the Code, equals or exceeds $100,000 2.11 "ERISA" means the Employee Retirement Income Security Act of 1974, as amended from time to time. 2.12 "Fund" means the investment options made available to participants in the Savings Plan and includes the Interest Bearing Account. 2.13 "Investment Income" means with respect to Participant Contributions and Company Contributions the earnings, gains and losses derived from the investment of such Contributions in a Fund or Funds. 2.14 "Interest Bearing Account" means an investment option to be made available to Participants in this Plan in which the Contributions invested in this option are credited with interest at the Applicable Federal Rate. 2.16 "Pay Reduction Agreement" means an agreement between the Company and the Participant in which the Participant elects to reduce his or her Compensation for the Plan Year and the Company agrees to treat the amount of the salary reduction as a Participant Contribution to this Plan. 2.17 "Participant Contributions" means contributions made by the Participant pursuant to an executed Pay Reduction Agreement subject to the Participant Contribution limits contained in section 3.1. 2.18 "Plan" means the American Electric Power System Supplemental Retirement Savings Plan. 2.19 "Plan year" means the calendar year commencing each January 1 and ending each December 31. 2.20 "Savings Plan" means the American Electric Power System Retirement Savings Plan, a plan qualified under section 401(a) of the Code, as in effect from time to time. ARTICLE III CONTRIBUTIONS 3.1 A Participant may elect to make Participant Contributions by executing a Pay Reduction Agreement. All Participant Contributions (i) shall be made by payroll deductions at the end of each payroll period, (ii) shall be based upon the Compensation the Participant received during such payroll period, and (iii) shall commence as soon as practicable after the Participant completes and delivers to the Committee a Pay Reduction Agreement. Participant Contributions are to be made in multiples of one (1) whole percentage of Compensation, not to exceed 20 percent of Compensation for any payroll period or Plan Year. The maximum Participant Contribution for any Plan Year shall not exceed the difference between (a) the Participant's Compensation for the Plan Year times 20 percent and (b) the aggregate amount of the Participant's Before-Tax and After-Tax contributions to the Savings Plan. 3.2 Subject to the limitation contained in section 3.3, the Company shall be deemed to contribute to the Plan on behalf of each Participant an amount equal to 75% of the amount, not in excess of 6% of a Participant's Compensation, contributed to the Plan by the Participant. 3.3 The amount of Company Contributions deemed to be contributed to the Plan on behalf of a Participant in combination with contributions made by the Company to the Savings Plan on behalf of the Participant, shall, in the aggregate be equal to the lesser of (a) 75% of the Participant Contributions made by the Participant to this Plan and the Savings Plan, or (b) 4.5% of the Participant's Compensation. If the aggregate contributions exceed the lesser limitation, Company Contributions credited to the Participant's Account shall be reduced until the aggregate Company Contributions made under both the Savings Plan and this Plan do not exceed the limitation. 3.4 Employees who become eligible for the Plan during the Plan Year shall become Participants on the first day of the Plan Year following the next annual enrollment period, provided they enter into a Pay Reduction Agreement during the enrollment period. ARTICLE IV INVESTMENT OF CONTRIBUTIONS 4.1 Participant Contributions and Company Contributions shall be invested in the Funds selected by the Participant. The Participant may change the selected Funds by notifying the recordkeeper retained by the Company. Any change in the Funds selected by the Participant shall be implemented as soon as practicable. 4.2 A Participant may elect to transfer all or a portion of the Contributions from any Fund or Funds to any other Fund or Funds by giving notice to the recordkeeper retained by the Company. Transfers between Funds may be made in any whole percentage or dollar amounts and shall be implemented as soon as possible. 4.3 The Funds shall be valued daily at their fair market value and each Participant's Account shall be valued daily at its fair market value. The fair market value calculation for a Participant's Account shall be made after all Contributions, withdrawals, distributions, Investment Income and transfers for the day are recorded. 4.4 The Plan is an unfunded non-qualified deferred compensation plan and therefore the Contributions credited to a Participant's Account and the investment of those Contributions in the Fund or Funds selected by the Participant are memo accounts that represent general, unsecured liabilities of the Company payable exclusively out of the general assets of the Company. ARTICLE V ELECTION, DISTRIBUTIONS AND BENEFICIARIES 5.1 In order for an election to make Participant Contributions to be effective for any given Plan Year, the Participant must enter into an irrevocable Pay Reduction Agreement during the annual enrollment period preceding the Plan Year as to which the election is to take effect. The Pay Reduction Agreement shall remain in force as to the Plan Year for which it is delivered and shall carry forward for each subsequent Plan Year until it is revoked or superseded by a new Pay Reduction Agreement entered into during an annual enrollment period. No election shall be effective to defer under the Plan any Compensation which is earned by the Participant on or before the first day of the Plan year for which the Pay Reduction Agreement is entered into. The Pay Reduction Agreement and any revocation thereof shall contain such information as may be reasonably required by the Committee and shall be executed at the time and in the manner prescribed by the Committee. 5.2 Upon a Participant's termination of employment for any reason other than death, all amounts which are credited to the Participant's Account shall be distributed to the Participant in the form of: (1) a single lump-sum payment when the Participant's employment is terminated or at the end of the post-termination deferral period selected by the Participant, or (2) in approximately equal annual or semi-annual installment payments over not less than two or more than ten years commencing when the Participant's employment is terminated or at the end of the post-termination deferral period selected by the Participant. A post-termination deferral shall be for a period of at least one year but not more then five years from the date the Participant's employment is terminate. The Participant's distribution election shall be made when the Participant first elects to participate in the Plan. The Participant may amend or revoke the distribution election at any time prior to the Participant's termination of employment, but any such amendment or revocation must be made at least twelve months prior to the initial distribution. If the Participant does not elect a post-termination deferral, the distribution of a lump-sum payment or the first installment payment shall be made within 120 days after the Participant's termination of employment. If the Participant elected a post-termination deferral, the lump-sum payment or the first installment payment shall be made within 120 days after the end of the deferral period. If the Participant elects a post-termination deferral or elects installment payments, the Participant shall be eligible to invest the remaining balance in the Participant's Account as provided in section 4.2. A lump sum distribution with no post-termination deferral will be made for participants who do not make a distribution election. 5.3 Upon a Participant's death prior to termination of employment or prior to the complete distribution of the Participant's Account, all amounts credited to the Participant's Account shall be distributed to (a) the Participant's named beneficiary, or (b) if the named beneficiary predeceases the Participant or if the Participant did not name a beneficiary, to the Participant's estate. Distributions to the named beneficiary shall be in the form of (1) a single lump-sum payment or (2) in approximately equal annual or semi-annual installment payments over not less than two nor more then ten years as elected by the beneficiary. The beneficiary's distribution election must be made within 90 days of the Participant's date of death. If an election is not made, the beneficiary shall receive a lump-sum payment. The distribution of a lump-sum payment or the first installment payment to a beneficiary shall be made within 90 days after the beneficiary makes or fails to make a distribution election. In the event the beneficiary elects installment payments, the beneficiary shall be eligible to invest the remaining balance in the Account as provided in section 4.2 as if the beneficiary is a Participant. In the event a beneficiary receiving installment payments shall die prior to a complete distribution of the Account, the remaining balance in the Account shall be paid to the beneficiary's estate within 120 days after the Committee is notified of beneficiary's death. The distribution of a lump-sum payment to the Participant's estate shall be made within 120 days after the Participant's date of death. 5.4 Each Participant shall have the right to designate a beneficiary or beneficiaries who shall receive the balance of the Participant's Account if the Participant dies prior to the complete distribution of the Participant's Account. Any designation, or change or rescission thereof, shall be made by completing and furnishing to the Committee the appropriate beneficiary form prescribed by the Committee. The last designation of beneficiary received by the Committee prior to the death of the Participant shall control. ARTICLE VI TAXES AND TAX TREATMENT 6.1 Each Participant agrees that as a condition of participation in the Plan, the Company may withhold federal, state and local income taxes, Social Security taxes and Medicare Taxes from any distribution hereunder to the extent that such taxes are then payable. 6.2 The adoption and maintenance of the Plan is conditioned upon (1) the applicability of section 451(a) of the Code to the Participant's recognition of gross income as a result of participation herein, (2) the fact that the Participants will not recognize gross income as a result of participation in the Plan unless and until and then only to the extent that distributions are received, (3) the applicability of section 404(a)(5) of the Code to the deductibility of the amounts distributed to the Participants hereunder, (4) the fact that the Company will not receive a deduction for amount credited to any Account unless and until and then only to the extent that amounts are actually distributed and (5) the inapplicability of the provisions of Titles 2, 3, and 4 of ERISA. If the Internal Revenue Service, Department of Labor or any court of competent jurisdiction determines or finds as a fact or legal conclusion that any of the above conditions is untrue and issues an assessment, determination, opinion or report to such effect, or if in the opinion of counsel to the Company any one of the above assumptions is incorrect, then the Company shall have the option to terminate this Plan as provided in section 8.1. ARTICLE VII Administration 7.1 The Committee shall (i) administer and interpret the terms and conditions of the Plan, (ii) establish reasonable procedures with which Participants must comply to exercise any right established hereunder, and (iii) be permitted to delegate its responsibilities or duties hereunder to any person or entity. The rights and duties of the Participants and all other persons and entities claiming an interest under the Plan are subject to, and governed by, such acts of administration, interpretation, procedure and delegation. 7.2 The Committee may employ agents, attorneys, accountants, or other persons and allocate or delegate to them powers, rights, and duties all as the Committee may consider necessary or advisable to properly carry out the administration of the Plan. 7.3 The Company shall maintain, or cause to be maintained, records showing the individual credit balances of each Participant's Account. Each Participant shall be furnished with quarterly statements setting forth the value of the total credits to the Participant's Account. ARTICLE VIII Amendment or Termination 8.1 The Company intends to continue the Plan indefinitely but reserves the right to modify the Plan from time to time, or to terminate the Plan entirely or to direct the permanent discontinuance or temporary suspension of Contributions under the Plan; provided that no such modification, termination, discontinuance or suspension shall affect or otherwise deprive a Participant or beneficiary of any distributions to which they may be entitled under the Plan. ARTICLE IX Miscellaneous 9.1 Nothing in the Plan shall interfere with or limit in any way the right of the Company to terminate any Participant's employment at any time, nor confer upon a Participant any right to continue in the employ of the Company. 9.2 In the event the Committee shall find that a Participant or beneficiary is unable to care for his or her affairs because of illness or accident, the Committee may direct that any payment due the Participant or the beneficiary be paid to the duly appointed legal representative of the Participant or beneficiary, and any such payment so made shall be a complete discharge of the liabilities of the Plan and the Company. 9.3 The Plan shall be construed and administered according to the laws of the State of Ohio. ARTICLE X Change In Control 10.1 Notwithstanding any provisions of the Plan to the contrary, if a Change in Control, as defined in Section 10.2, of the Corporation occurs, all benefits accrued as of the date of the Change in Control shall be fully vested and non-forfeitable. 10.2 A "Change in Control" of the Corporation shall be deemed to have occurred if (i) any "person" or "group" (as such terms are used in Sections 13(d) and 14(d) of the Securities Exchange Act of 1934 ("Exchange Act")), other than any company owned, directly or indirectly, by the shareholders of the Corporation in substantially the same proportions as their ownership of stock of the Corporation or a trustee or other fiduciary holding securities under an employee benefit plan of the Corporation, becomes the "beneficial owner" (as defined in Rule 13d-3 under the Exchange Act), directly or indirectly, of more than 25 percent of the then outstanding voting stock of the Corporation, (ii) during any period of two consecutive years, individuals who at the beginning of such period constitute the Board, together with any new Directors (other than a director nominated by a person (x) who has entered into an agreement with the Corporation to effect a transaction described in Section 10.2(i), (iii) or (iv) who publicly announces an intention to take or to consider taking actions (including, but not limited to, an actual or threatened proxy contest) which if consummated would constitute a Change In Control) whose election or nomination for election was approved by a vote of at least two-thirds of the Directors then still in office who were either Directors at the beginning of the period or whose election or nomination for election was previously so approved, cease for any reason to constitute at least a majority of the Board; or (iii) the consummation of a merger or consolidation of the Corporation with any other entity, other than a merger or consolidation which would result in the voting securities of the Corporation outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity) at least 50 percent of the total voting power represented by the voting securities of the Corporation or such surviving entity outstanding immediately after such merger or consolidation; or (iv) the shareholders of the Corporation approve a plan of complete liquidation of the Corporation, or an agreement for the sale or disposition by the Corporation (in one transaction or a series of transactions) of all or substantially all of the Corporation's assets. Notwithstanding the foregoing, a Change in Control shall not be deemed to occur as a result of the consummation of the transactions contemplated in the Agreement and Plan of Merger by and among the Corporation, Augusta Acquisition Corporation and Central and South West Corporation dated as of December 21, 1997, nor thereafter as a result of any event in (i) or (iii) above, if Directors who were members of the Board prior to such event continue to constitute a majority of the Board after such event. For purposes of this Section 10.2, "Board" shall mean the Board of Directors of the Corporation, and "Director" shall mean an individual who is a member of the Board. ARTICLE XI Claims Procedure 11.1 If a Participant makes a written request alleging a right to receive benefits under the Plan or alleging a right to receive an adjustment in benefits being paid under the Plan, the Committee shall treat it as a claim for benefits. All claims for benefits under the Plan shall be sent to the Committee and must be received within 75 days after the Participant's termination of employment. If the Committee determines that any Participant who has claimed a right to receive benefits, or different benefits, under the Plan is not entitled to receive all or any part of the benefits claimed, it will inform the claimant in writing of its determination and the reasons therefor in terms calculated to be understood by the claimant. The notice will be sent within 90 days of the claim unless the Committee determines additional time, not exceeding 90 days, is needed. The notice shall make specific reference to the pertinent Plan provisions on which the denial is based, and describe any additional material or information, if any, necessary for the claimant to perfect the claim and the reason any such addition material or information is necessary. Such notice shall, in addition, inform the claimant what procedure the claimant should follow to take advantage of the review procedures set forth below in the event the claimant desires to contest the denial of the claim. The claimant may within 90 days thereafter submit in writing to the Committee a notice that the claimant contests the denial of the claim by the Committee and desires a further review. The Committee shall within 60 days thereafter review the claim and authorize the claimant to appear personally and review pertinent documents and submit issues and comments relating to the claim to the persons responsible for making the determination on behalf of the Committee. The Committee will render its final decision with specific reasons therefore in writing and will transmit it to the claimant within 60 days of the written request for review, unless the Committee determines additional time, not exceeding 60 days, is needed, and so notifies the claimant. If the Committee fails to respond to a claim filed in accordance with the foregoing within 90 days or any such extended period, the Committee shall be deemed to have denied the claim. EX-10.(R)(1) 6 0006.txt EMPLOYMENT AGREEMENT - P. ADDIS Exhibit 10(r)(1) Employment Agreement This Employment Agreement, entered into between American Electric Power Service Corporation (hereinafter referred to as the "Company") and Paul D. Addis (hereinafter referred to as the "Employee"). WITNESS: that in consideration of the mutual reciprocal promises herein contained, the parties hereby covenant as follows: WHEREAS, the Company is desirous of hiring the Employee because of his business experience and expertise; and WHEREAS, the Employee is desirous of being employed by the Company in the below-described executive capacity: NOW, THEREFORE, it is hereby agreed as follows: Section I Term of Employment 1.01 The Company employs the Employee and the Employee accepts employment with the Company beginning during February, 1997 and ending three years later, subject however, to prior termination of this Employment Agreement as provided in Section VI and paragraph 2.02 of Section II. The actual date the Employee's employment with the Company commences shall be referred to as the "Date of Hire." Section II Duties of Employee 2.01 On the Date of Hire, the Employee shall assume the office and duties of Executive Vice President. The Employee's duties after he assumes the position of Executive Vice President shall include: helping to define and lead the Company's unregulated business activities; assisting in the development of strategies for the Company's generation; energy delivery, marketing and new business development; and other similar duties as may be reasonably prescribed from time to time by the Board of Directors of the Company (the "Company Board") or the Chairman of the Board of the Company. The Employee also agrees to perform reasonable services for, and consult with and advise, corporations affiliated with the Company as the Company Board, or the Chairman of the Board of the Company may from time to time specify. Services performed for affiliated companies shall not entitle the Employee to additional compensation. 2.02 If the Employee at any time during the term of this Employment Agreement shall be unable because of personal injury, illness, or any other cause to perform his duties under this Employment Agreement, the Company may assign the Employee to other duties and the compensation to be paid to the Employee for performing those duties shall be determined by the Company in the Company's sole discretion. If the Employee is unwilling to accept the modification in duties and compensation offered by the Company, this Employment Agreement shall terminate immediately and the Employee shall be entitled to the severance benefit provided in Section 6.02 of this Employment Agreement. 2.03 The Employee shall devote his entire productive time, ability and attention to the business of the Company during the term of this Employment Agreement. The Employee shall not directly or indirectly render any services of a business, commercial, or professional nature to any other person or organization, whether for compensation or otherwise, without the prior written consent of the Company. Section III Compensation 3.01 As compensation for services rendered under this Employment Agreement, the Employee shall be entitled to receive from the Company a salary of $ 350,000 per year, payable in equal semi-monthly installments; provided, however, that the amount of the annual salary shall be subject to annual adjustments, commencing January 1, 1998, at the Company's discretion pursuant to its Exempt Salary Administration Program. 3.02 In addition to the annual salary provided for in paragraph 3.01, the Employee shall be eligible to participate in the Management Incentive Compensation Plan and in the Performance Share Incentive Plan commencing on the first day of the month following the Employee's Date of Hire. Section IV Benefits 4.01 The Employee shall be eligible to participate in the American Electric Power System Retirement Plan on the first day of the month following his completion of one year of employment as measured from the Date of Hire, in the American Electric Power System Employees Savings Plan on the first day of the month following his completion of six months of employment as measured from the Date of Hire, and in the American Electric Power System Supplemental Savings Plan on January 1, 1998. The Employee shall be eligible to participate in the American Electric Power System medical plan, long-term disability plan, and life insurance plans on the first day of the month following his Date of Hire. 4.02 The Employee shall be immediately eligible to participate in the dental plan. If necessary, the Company shall provide such dental plan benefits out of its general assets. 4.03 According to Company policy, the Employee shall be provided with a Company automobile and membership in a luncheon club. 4.04 The Company shall reimburse the Employee for temporary housing and weekend trips back to Connecticut between February 1, 1997 and the end of the 1996/1997 school year. The Employee shall be eligible to participate in the Company's Employee Relocation Program any time during the Employee's first two years of employment. Section V Supplemental Retirement Benefit 5.01 Upon the Employee's termination of employment for any reason, except for good cause as defined in paragraph 6.03, the Employee shall be entitled to a Supplemental Retirement Benefit equal to: (a) The retirement benefit the Employee would be entitled to receive as of the date of the Employee's termination of employment, under the terms of the American Electric Power System Retirement Plan, as amended from time to time or any successor thereto ("AEPS Retirement Plan"), based upon the compensation the Employee received from the Company prior to the Employee's termination of employment, including earned Management Incentive Compensation awards and excluding earned Performance Share Incentive Plan awards; assuming that as of the date of the Employee's termination of employment the Employee's period of accredited service shall be equal to the sum of the Employee's actual period of service with the Company and an additional 18.5 years of accredited service; and if the Employee retires prior to age 62 and elects to receive retirement benefits prior to age 62, the retirement benefit that the employee would receive at age 62 shall be reduced by one-quarter of a percent for each month prior to age 62 that retirement benefits commence as shown in the table below: The employee will receive this percentage of the retirement benefit that would normally be If retirement benefits are paid at age 62: paid starting at: -------------------------------- ------------------------------- Age 61 97% 60 94% 59 91% 58 88% 57 85% 56 82% 55 79% (b) Less any retirement benefit the Employee is entitled to receive from all qualified and non qualified plans sponsored by any prior employer of the Employee. The Employee shall provide the Company with a list of such other plans within a reasonable time after the Employee's Date of Hire. (c) Less any retirement benefit the Employee is entitled to received from the AEPS Retirement Plan. 5.02 The Employee's election under the terms of the AEPS Retirement Plan of a 50% Joint and Survivor Annuity or any other optional form of payment, with the valid consent of the Employee's Spouse where required, shall be deemed to be the payment election the Employee makes for purposes of the Supplemental Retirement Benefit. 5.03 If the Employee's employment with the Company is terminated due to the death of the Employee, the Employee's spouse shall be entitled to a Supplemental Pre-Retirement Surviving Spouse Annuity provided the Employee and the Employee's spouse were married for at least one year prior to the Employee's death. The amount of the Supplemental Pre-Retirement Surviving Spouse Annuity shall be equal to the following: (a) The pre-retirement surviving spouse annuity the Employee's spouse would be entitled to receive under the terms of the AEPS Retirement Plan, based upon the compensation the Employee received from the Company prior to his death, including the Employee's earned Management Incentive Compensation awards and excluding the Employee's earned Performance Share Incentive Plan awards; assuming that as of the Employee's date of death the Employee's accredited service is equal to the sum of the Employee's actual period of service with the Company and an additional 18.5 years of accredited service; and applying the benefit reduction factors in paragraph 5.01(a) if the employee was eligible for early retirement at the time of death. (b) Less any surviving spouse annuity the Employee's surviving spouse is entitled to receive from any qualified or non qualified plan sponsored by any prior employer of the Employee. (c) Less any surviving spouse annuity the Employee's surviving spouse is entitled to receive from the AEPS Retirement Plan. 5.04 The Supplemental Retirement Benefit or the Supplemental Pre-Retirement Surviving Spouse Annuity shall be paid out of the general assets of the Company and shall be covered by the American Electric Power Service Corporation Umbrella Trust for Executives. 5.05 In the event the Employee's employment is terminated by the Company for other than "good cause" or in the event the Employee voluntarily terminates employment with the written consent of the Company, the supplemental benefits provided in this Section V shall become fully vested and non-forfeitable. Section VI Termination 6.01 The Company or the Employee may terminate this Employment Agreement and the employment relationship at any time. Termination of this Employment Agreement shall be by delivery of a written notice to Employee at his place of employment and to Company by delivery of a written notice to the Chairman of the Board. 6.02 In the event the Employee's employment is terminated by the Company for other than "good cause" within three years of the Employee's Date of Hire, or in the event the Employee voluntarily terminates employment with the written consent of the Company within three years of the Employee's Date of Hire, the Employee shall be entitled to the following severance benefits. (a) If the Employee's employment is terminated within the first 18 months of the Employee's employment as measured from the Date of Hire, the Employee shall be entitled to a continuation of the Employee's then base salary for 36 months from the date the Employee's employment is terminated. (b) If the Employee's employment is terminated after the Employee has completed 18 months of employment and prior to the completion of 30 months of employment as measured from the Employee's Date of Hire, the Employee shall be entitled to a continuation of the Employee's then base salary. The number of months of salary continuation is to be computed as follows: 36 minus 2 months for each additional month of employment beyond the completion of 18 months of employment. (c) If the Employee's employment is terminated after the Employee has completed 30 months of employment and prior to the completion of 48 months of employment as measured from the Employee's Date of Hire, the Employee shall be entitled to a continuation of the Employee's then base salary for a period of 12 months. Severance payments made under the provisions of this section 6.02 shall be in lieu of any other severance plan then offered by the Company. If the Employee's employment is terminated after the Employee has completed four years of employment, the Employee shall be entitled to the normal severance benefits in place at that time. 6.03 In the event the Employee is involuntarily terminated for "good cause" prior to the Employee's completion of three years of employment as measured from the Date of Hire, or in the event the Employee voluntarily terminates employment without the written consent of the Company prior to the completion of three years of employment as measured from the Date of Hire, all rights of the Employee under this Employment Agreement shall be terminated and the Company shall have no liability or obligation to make any payments to or for the benefit of the Employee or the Employee's spouse hereunder, including without limitation, the Supplemental Retirement Benefits provided in Section V hereof. The Company agrees that it will not unreasonably withhold its consent in the event the Employee voluntarily terminates employment prior to the completion of three years of employment as measured from the Date of Hire. For purposes of this Employment Agreement, "good cause" shall include: the Employee's theft or destruction of Company property; the Employee's willful breach or habitual neglect of the duties that he is required to perform under this Employment Agreement; and the Employee's behavior or actions which are illegal and or unethical such as sexual harassment or violation of equal employment laws. Section VII Miscellaneous 7.01 This Employment Agreement contains the entire agreement of the Company and the Employee relating to the subject matter hereof, and the Company and the Employee each acknowledge that they have made no agreements, representations or warranties relating to the subject matter of this Employment Agreement which are not set forth herein and that this Employment Agreement supersedes and revokes any prior agreements. 7.02 This Employment Agreement may not on behalf of or in respect to the Company or the Employee be changed, modified, released, discharged or otherwise terminated in whole or in part except by an instrument in writing signed by a duly authorized officer of the Company and the Employee or as otherwise provided herein. 7.03 This Employment Agreement shall extend to and be binding upon the Employee, his legal representatives and heirs, and upon the Company, its successors and assigns; provided, however, that the Company may not assign this Employment Agreement except to another corporation within the group of companies known as the AEP System Companies. 7.04 Nothing herein shall be construed as amending the terms and conditions of the AEPS Retirement Plan or the American Electric Power System Employees Savings Plan. This Employment Agreement, consisting of seven pages including the signature page, signed this 17th day of January, 1996. /s/ Paul D. Addis /s/ E. Linn Draper, Jr. - ------------------------------ -------------------------------- Paul D. Addis E. Linn Draper, Jr. Chairman of the Board, President and Chief Executive Officer, American Electric Power Service Corporation EX-10.(R)(2) 7 0007.txt AMENDED AGREEMENT - P. ADDIS Exhibit 10(r)(2) Amending Agreement Paul Addis (hereinafter referred to as "Employee") and American Electric Power Service Corporation (hereinafter referred to as the "Company") hereby voluntarily agree to amend the Employment Agreement executed by the parties in December 1997 as set forth in this Amending Agreement. The Amending Agreement is entered into this 30 day of July, 1998. Whereas, the Company and the Employee previously entered into an Employment Agreement; and Whereas, the Employment Agreement provided that the Employee would participate in certain incentive compensation plans then offered by the Company, and further provided that the Employee would be entitled to a supplemental non-qualified retirement benefit; and Whereas, the Company has adopted a new compensation package that includes new incentive compensation plans and a revised supplemental non- qualified retirement benefit that the Company would like to offer to the Employee in lieu of the Employees current compensation package; and Whereas, the Employee would like to participate in the new compensation package offered by the Company, and the Employee does not have the right under the Employment Agreement, or otherwise, to participate in the new compensation package offered by the Company: Now Therefore, in consideration for being provided with the right to participate in the new compensation package offered by the Company, is hereby agreed by the Company and the Employee that Sections 3.02, 5.01(a) and 5.03(a) of the Employment Agreement shall be amended as set forth below. (l) Section 3.02 of the Employment Agreement shall be amended to read as follows: 3.02. In addition to the annual salary provided for in paragraph 3.01, the Employee shall be eligible to participate in the AEP Energy Services, Inc. Annual Incentive Compensation Plan, the Performance Share Incentive Plan and the Employee shall receive a 2.7% interest in the AEP Energy Services, Inc. Phantom Equity Plan. In return for the Employee's interest in the AEP Energy Services Phantom Equity Plan, the Employee's participation in the Performance Share Incentive Plan shall be at a twenty (20) percent level. The Employee's date of participation in each plan shall be as of the first day of the month following the Employee's Date of Hire. If the Company adopts a new or amends a current incentive compensation plan for employees who hold the position of Executive Vice President, the Employee shall participate in the new or amended plan subject to the approval of the Chairman. The Chairman shall also determine the Employee's level of participation in said new or amended plan. (ll) Section 5.01(a) of the Employment Agreement shall be amended to read as follows: Section 5.01(a): (a) The retirement benefit the Employee would be entitled to receive as of the date of the Employee's termination of employment, under the terms of the American Electric Power System Retirement Plan, as amended from time to time or any successor thereto ("AEPS Retirement Plan"), based upon the base compensation the Employee received from the Company prior to the Employee's termination of employment, including earned AEP Energy Services, Inc. Annual Incentive Compensation Plan awards up to a maximum of 30% of annual base compensation; assuming that as of the date of the Employee's termination of employment the Employee's period of accredited service shall be equal to the sum of the Employee's actual period of service with Company and an additional 18.5 years of accredited service; and if the Employee retires prior to age 62 and elects to receive retirement benefits prior to age 62, the retirement benefit that the Employee would receive at age 62 shall be reduced by one-quarter of a percent for each month prior to age 62 that retirement benefits commence as shown in the table below: The Employee will receive this If retirement benefits are percentage of the retirement paid starting at: benefit That would normally be paid at age 62: - ------------------------------- -------------------------------------- Age 61 97% 60 94% 59 91% 58 88% 57 85% 56 82% 55 79% (lll) Section 5.03(a) of the Employment Agreement shall be amended to read as follows: Section 5.03(a) (a) The pre-retirement surviving spouse annuity the Employee's spouse would be entitled to receive under the terms of the AEPS Retirement Plan, based upon the base compensation the Employee received from the Company prior to his death, including the Employee's earned AEP Energy Services, Inc. Annual Incentive Compensation Plan awards up to a maximum of 30% of annual base compensation; assuming that as of the Employee's date of death the Employee's accredited service is equal to the sum of the Employee's actual period of service with the Company and an additional 18.5 years of accredited service; and applying the benefit reduction factors in Section 5.01(a) if the Employee was eligible for early retirement at the time of death. /s/Paul D. Addis /s/ E. Linn Draper, Jr. --------------------------- -------------------------------- Paul D. Addis E. Linn Draper, Jr. Executive Vice President Chairman of the Board, American Electric Power President and Chief Service Corporation Service Executive Officer American Electric Power Corporation EX-10.(R)(3) 8 0008.txt AEP ENERGY SERVICES INCENTIVE COMP PLAN Exhibit 10(r)(3) AEP ENERGY SERVICES, INC. INCENTIVE COMPENSATION PLAN Article 1 Establishment, Purpose and Effective Date 1.1 The Company hereby establishes the "AEP Energy Services, Inc. Incentive Compensation Plan" (the "Plan"). 1.2 The purposes of the Plan are to improve corporate performance and enhance shareholder value by providing Plan Participants incentives to earn annual incentive compensation and to assist the Company in retaining and recruiting key employees. 1.3 The Plan is effective as of January 1, 1997. Article 2 Definitions 2.1 "Administrative Expense Multiple" means the multiple of Total Salaries necessary to include employee fringes and benefits and the administrative and general expenses associated with those salaries. The Compensation Committee initially establishes the multiple as 1.75, subject to revision. 2.2 "Administrative Expenses" means the result of the Administrative Expense Multiple as applied to Total Salaries for the Plan Year. 2.3 "Annual Bonus Pool" means 15% of the Pretax Operating Income for the Plan Year. 2.4 "Company" means American Electric Power Service Corporation, Inc. 2.5 "Compensation Committee" means the individuals holding the following offices within the Company; Chairman of the Board, President and Chief Executive Officer; Executive Vice President-Corporate Services; Executive Vice President-Financial Services; Senior Vice President-Human Resources; and the President of AEP Energy Services, Inc., and any other senior officer of the Company or its Subsidiaries selected by the Compensation Committee. 2.6 "Direct Expenses" means non-reoccurring expenses for the Plan Year that are not part of the Administrative Expenses such as, but not limited to, moving costs, signing bonuses and cost of working capital. 2.7 "Employee" means either employees of AEP Energy Services, Inc. or employees of the Company, who are involved in energy trading and other approved activities for AEP Energy Services, Inc. as traders, managers, support personnel or marketers as well as all other employees identified by the Compensation Committee whose efforts are dedicated to energy trading activities. 2.8 "Gross Margin" for the Plan Year means (I) the net gain or loss associated with all sales and purchases of electricity and gas recorded for the Plan Year on a mark-to-market basis calculated as of December 31 of the Plan Year, and (ii) the net revenue received or cost incurred associated with the sale and purchase of options. For purposes of this Plan, net gains or losses shall be limited to sales and purchases intended to be realized within two years of the close of the Plan Year. 2.9 "Incentive Award" means the amount of incentive compensation, as determined by the Compensation Committee, payable to a Participant for the Plan Year. 2.10 "Pretax Operating Income" means Gross Margin for the Plan Year less Administrative and Direct Expenses for the Plan Year. 2.11 "Plan Year" means the calendar year commencing January 1, and ending December 31. 2.12 "Total Salaries" means the salaries of all Employees as well as all other employees identified by the Compensation Committee whose efforts are dedicated to energy trading activities, including but not limited to risk control, credit analysis, and legal support. Article 3 Plan Participant 3.1 Employees will be selected for participation in the Plan by the President of AEP Energy Services, Inc. on or before the commencement of the Plan Year. Individuals who become Employees after the start of the Plan Year may become eligible to participate in the Plan at the discretion of the President of AEP Energy Services, Inc. The Compensation Committee may approve or adjust the selections made by the President and any action taken by the Compensation Committee shall be final. The President of AEP Energy Services, Inc. will provide written notification to those employees who are selected as participants. 3.2 Employees selected to participate in the Plan shall not be eligible to participate in the American Electric Power System Management Incentive Compensation Plan, the American Electric Power System Senior Officer Annual Incentive Compensation Plan or the Company Wide Incentive Plan. 3.3 Participation in the Plan for a Plan Year is not a guarantee for Participation in future incentive compensation plans that may be adopted by the Company. Participation in this Plan does not and is not meant to provide for a guarantee of continued employment. Article 4 Determination of Awards 4.1 If the Annual Bonus Pool for the Plan Year is less than or equal to the amount of the guaranteed bonuses for the Plan Year, Participants in the Plan shall receive an Incentive Award only to the extent of their guaranteed bonuses. If the Annual Bonus Pool is less than or equal to the amount of guaranteed bonuses for the Plan Year, Participants in the Plan who do not have guaranteed bonuses shall not receive an Incentive Award for the Plan Year. 4.2 After the end of the Plan Year, the Committee, with the President recusing himself, shall determine the President's award. The President of AEP Energy Services, Inc. shall thereafter make a recommendation to the Compensation Committee as to the amount of each of the other Participant's Incentive Award for the Plan Year. The Compensation Committee may approve or adjust any recommendation made by the President and any action taken by the Compensation Committee shall be final. A Participant shall have no right to appeal the final Incentive Award approved by the Compensation Committee. Article 5 Payment of Incentive Awards 5.1 Earned Incentive Awards shall be paid as soon as possible after the end of the Plan Year, but in no event shall an earned Incentive Award be paid later than four months after the end of the Plan Year. 5.2 Except for a Participant who retires, becomes permanently and totally disabled or dies, a Participant must be an employee of the Company or of AEP Energy Services, Inc. on the last day of the Plan Year to earn an Incentive Award. A Participant who transfers during the Plan Year to another employer affiliated with the Company may earn an Incentive Award. 5.3 All payments shall be subject to the applicable federal, state and local income tax withholdings and shall also be subject to the applicable payroll tax withholdings such as withholding for Social Security and Medicare taxes. Article 6 Administration 6.1 The Plan shall be administered by the Compensation Committee. The Compensation Committee shall have the authority to interpret the Plan and to prescribe, amend and rescind rules and regulations relating to the administration of the Plan, and all such interpretations, rules and regulations shall be conclusive and binding on all Participants. 6.2 The Compensation Committee may employ agents, attorneys, accountants, or other persons and allocate or delegate to them powers, rights, and duties all as the Compensation Committee may consider necessary or advisable to properly carry out the administration of the Plan. Article 7 Miscellaneous 7.1 The Compensation Committee shall have the right, authority and power to alter, amend, modify, revoke or terminate the Plan; provided that no amendment or termination of the Plan shall adversely affect the rights of any Participant with respect to earned but unpaid Incentive Compensation awards. 7.2 The Compensation Committee shall periodically review the terms and conditions of this Plan with the Human Resource Committee of the Board of Directors of the American Electric Power Company, Inc. 7.3 No benefits at any time payable under this Plan to a Participant or a Participant's estate shall be subject in any manner to anticipation, alienation, sale, transfer, assignment, pledge, attachment, garnishment, levy, execution, or other legal or equitable process, or encumbrance of any kind. 7.4 Nothing in this Plan shall interfere with or limit in any way the right of the Company to terminate any Participant's employment at any time, nor confer upon a Participant any right to continue in the employ of the Company. 7.5 The Plan shall be construed and administered according to the laws of the State of Ohio. 7.6 In the event the Compensation Committee shall find that a Participant is unable to care for his or her affairs because of illness or accident, the Compensation Committee may direct that any payment due the Participant be paid to the Participant's duly appointed legal representative, and any such payment so made shall be a complete discharge of the liabilities of the Plan Article 8 Change in Control 8.1 Notwithstanding any provisions of this Plan to the contrary, if a Change in Control, as defined in Section 8.2, of the Company occurs, all Incentive Awards shall be deemed to be fully earned as of the date of the Change in Control. The determination of the amount of Incentive Awards earned shall be made as of the last day before the Change in Control. Cash payments of the Incentive Awards shall be made within three months after the Change in Control. 8.2 A "Change in Control" of the Company shall be deemed to have occurred if (i) any "person" or "group" (as such terms are used in Sections 13(d) and 14(d) of the Securities Exchange Act of 1934 ("Exchange Act")), other than any company owned, directly or indirectly, by the shareholders of the Company in substantially the same proportions as their ownership of stock of the Company or a trustee or other fiduciary holding securities under an employee benefit plan of the Company, becomes the "beneficial owner" (as defined in Rule 13d-3 under the Exchange Act), directly or indirectly, of more than 25 percent of the then outstanding voting stock of the Company, (ii) during any period of two consecutive years, individuals who at the beginning of such period constitute the Board, together with any new Directors (other than a director nominated by a person (x) who has entered into an agreement with the Company to effect a transaction described in Section 8.2(i), (iii) or (iv) or (y) who publicly announces an intention to take or to consider taking actions (including, but not limited to, an actual or threatened proxy contest) which if consummated would constitute a Change In Control) whose election or nomination for election was approved by a vote of at least two-thirds of the Directors then still in office who were either Directors at the beginning of the period or whose election or nomination for election was previously so approved, cease for any reason to constitute at least a majority of the Board; or (iii) the consummation of a merger or consolidation of the Company with any other entity, other than a merger or consolidation which would result in the voting securities of the Company outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity) at least 50 percent of the total voting power represented by the voting securities of the Company or such surviving entity outstanding immediately after such merger or consolidation; or (iv) the shareholders of the Company approve a plan of complete liquidation of the Company, or an agreement for the sale or disposition by the Company (in one transaction or a series of transactions) of all or substantially all of the Company's assets. Notwithstanding the foregoing, a Change in Control shall not be deemed to occur as a result of the consummation of the transactions contemplated in the Agreement and Plan of Merger by and among the Company, Augusta Acquisition Corporation and Central and South West Corporation dated as of December 21, 1997, nor thereafter as a result of any event in (i) or (iii) above, if Directors who were members of the Board prior to such event continue to constitute majority of the Board after such event. For purposes of this Section 8.2, "Board" shall mean the Board of Directors of the Company, and "Director" shall mean an individual who is a member of the Board. ADDENDUM AEP ENERGY SERVICES, INC. INCENTIVE COMPENSATION PLAN DEFERRAL OF AWARDS Introduction: This addendum is applicable for just those Participants who are either in a designated salary grade or who have been selected by the Compensation Committee as being eligible to elect deferrals of all or part of an Incentive Award. Definitions: "Account" means, with respect to each Participant, a separate account established and maintained for the exclusive purpose of accounting for the incentive compensation deferred by the Participant. "Common Stock" means the common stock, $6.50 par value, of the American Electric Power Company, Inc., a New York corporation, and any successor thereto. "Deferred Distribution Date" means the date the Participant terminates employment or the date specified in the Participant's deferral election agreement if a distribution is to be made prior to a Participant's termination of employment. "Interest Bearing Account" means memo account which is credited with annual interest equal to 120% of the applicable federal long-term rate with monthly compounding as published by the Internal Revenue Service in the December preceding the Plan Year. "Market Value" means the closing price of the Common Stock, as published in The Wall Street Journal report of the New York Stock Exchange - Composite Transaction on the date in question or, if the Common Stock shall not have been traded on such date of if the New York Stock Exchange is closed on such date, then the first day prior thereto on which the Common Stock was so traded. "Participant" means, for purposes of being eligible to make a deferral election, an exempt Employee in exempt salary grade 27 or higher, and such other Employees as designated by the Compensation Committee. "Stock Unit" means a measure of value, expressed as a share of Common Stock. No certificates shall be issued with respect to such Stock Units, but the Company shall maintain bookkeeping Account in the name of the Participant to which the Stock Units shall relate. Deferral Election: A Participant may elect to defer payment of all or part of the Incentive Award for one or more years with a maximum deferral period that results in payment commencing no later than five years after the Participant's termination of employment. The deferral election must be filed with the Company on or before April 15 of the Plan Year for which the deferral is elected. Deferral Account: If a Participant elects to defer all or a portion of the Participant's Incentive Award, the Participant may elect to have the deferred amounts invested in Stock Units or in the Interest Bearing Account. If the Participant elects to invest in Stock Units, Stock Units shall be credited to the Participant's Account effective the January 1 immediately following the completion of the Plan Year. The number of whole and fractional Stock Units, computed to three decimal places, to be credited to the Participant's Account shall be equal to the dollar amount of the Incentive Award which otherwise would have been payable to the Participant divided by the average of the Market Value for the last 20 trading days of the Plan Year. On each dividend payment date with respect to the Common Stock, the Account of a Participant shall be credited with an additional number of whole and fractional Stock Units equal to the product of the dividend per share then payable, multiplied by the number of Stock Units then credited to such Account, divided by the Market Value on the dividend payment date. The number of a Participant's Stock Units shall be appropriately adjusted for any change in the Common Stock by reason of any merger, reclassification, consolidation, recapitalization, stock dividend, stock split or any similar change affecting the Common Stock. If the Participant elects to invest in the Interest Bearing Account, the deferred portion of the Incentive Award shall be deemed to be invested in the Interest Bearing Account on the date the Incentive Awards would have been paid were it not for the deferral election. The amounts invested in the Interest Bearing Account shall receive interest credits equal to the interest rate determined the December before each Plan Year. Payment of Deferred Awards: All deferred Incentive Awards shall be paid as a lump sum within 30 days of the Deferred Distribution Date. The lump sum amount for Stock Units shall be the average of the Market Value of the Common Stock for the 20 consecutive trading days through to the Participant's Deferred Distribution Date. The lump sum amount for the Interest Bearing Account shall be the sum of the amounts deferred plus interest credited through the Deferred Distribution Date. Upon the death of an active or terminated Participant, all deferred awards shall be paid to the Participant's surviving spouse as a lump sum within 30 days after the Participant's date of death. If the Participant does not have a surviving spouse, the deferred awards shall be paid to the Participant's estate as a lump sum within 30 days after the Participant's date of death. The amount of the lump sum cash distribution shall be calculated as provided in the immediate preceding paragraph. EX-10.(R)(4) 9 0009.txt AEP ENERGY SERVICES PHANTOM EQUITY PLAN Exhibit 10(r)(4) AEP ENERGY SERVICES, INC. PHANTOM EQUITY PLAN Article 1 Establishment, Purpose, Effective Date and Termination Date 1.1 The Company hereby establishes the "AEP Energy Services, Inc. Phantom Equity Plan" (the "Plan") effective as of July 1, 1997. The Plan shall terminate as of June 30, 2002. 1.2 The purposes of the Plan are to focus Participants on the profitability of AEP Energy Services, Inc. that enhances shareholder value and provides Participants with an equity participation sufficient to attract, motivate and retain qualified executives. Article 2 Definitions 2.1 "Adjusted Net Income" means the Pretax Net Income for a Plan Year less Taxes and less the Capital Charge for the Plan Year as illustrated in Exhibit A. 2.2 "Annual Bonus Awards" means the bonuses paid within a Plan Year under the terms of the AEP Energy Services, Inc. Incentive Compensation Plan. 2.3 "Average Adjusted Net Income" means the sum of the Adjusted Net Income for each Plan Year divided by the number of Plan Years included in the sum. 2.4 "Capital" means the net equity investment, if any, in AEP Energy Services, Inc. made by the Company and/or its affiliates and subsidiaries. For these purposes, net equity investment shall exclude any net equity investment for which a transfer payment requirement has been established and reflected in Pretax Operating Income as defined in the AEP Energy Services, Inc. Incentive Compensation Plan. 2.5 "Capital Charge" means the product of multiplying the average Capital (calculated as the average of month end values) by the average cost of equity for each Plan Year. 2.6 "Company" means American Electric Power Service Corporation, Inc. 2.7 "Compensation Committee" means the individuals holding the following offices within the Company; Chairman of the Board, President and Chief Executive Officer; Executive Vice President (President of AEP Energy Services, Inc.); Executive Vice President-Financial Services; Executive Vice President-Corporate Services; and Senior Vice President-Human Resources. 2.8 "Employee means either employees of AEP Energy Services, Inc. or employees of the Company, who are involved in energy trading for AEP Energy Services, Inc. as traders, managers, support personnel or marketers as well as all other employees identified by the Compensation Committee whose efforts are dedicated to energy trading activities. 2.9 "Equity Multiple" means the factor ten (10.0). 2.10 "Interest Expense" means the interest charged to AEP Energy Services, Inc. for the use of borrowed funds. 2.11 "Interest Income" means interest earned by AEP Energy Services, Inc. 2.12 "Interim Participation Interest" means a percentage of the Phantom Equity interest granted to a Participant after July 1, 1997. 2.13 "Participant" means an Employee who meets the requirements set forth in Section 3.1. 2.14 "Participation Interest" means a percentage of the Phantom Equity interest granted to a Participant as of July 1, 1997. 2.15 "Phantom Equity" means the value of AEP Energy Services, Inc. as of any Valuation Date determined by multiplying the Average Adjusted Net Income by the Equity Multiple and subtracting from the resulting product the Capital, as illustrated in Exhibit B. 2.16 "Plan Year" means a fiscal year commencing on July 1 and ending on June 30. The first Plan Year shall commence on July 1, 1997 and end on June 30, 1998. 2.17 "Pretax Net Income" means Pretax Operating Income for a Plan Year less Annual Bonus Awards less Interest Expense as illustrated in Exhibit A. 2.18 "Pretax Operating Income" means pretax operating income as defined in the AEP Energy Services, Inc. Incentive Compensation Plan. 2.19 "Taxes" means an allowance for federal, state and local income taxes equal to thirty-five percent (35%) of Pretax Net Income. The Compensation Committee may adjust the rate annually to reflect changes in tax laws or to credit AEP Energy Services, Inc. for any tax benefits generated by AEP Energy Services, Inc. 2.20 "Valuation Date" means September 30, December 31, March 31 or June 30 of each Plan Year as specified in the Plan. Article 3 Participation 3.1 Employees who are recommended for participation in the Plan by the President of AEP Energy Services and whose participation in the Plan is approved by the Compensation Committee shall become Plan Participants. At the discretion of the Compensation Committee, participation may commence either (a) on the start of the first Plan Year or (b) any date after the start of the first Plan Year but not later than the first day of the last Plan Year. 3.2 The President of AEP Energy Services, Inc. shall provide a written notice to each Employee who is selected to Participate in the Plan. The written notice shall provide a brief explanation of the Participation Interest or Interim Participation Interest granted to the Participant and shall contain a copy of the Plan. Article 4 Phantom Equity 4.1 For any Plan Year the Adjusted Net Income for AEP Energy Services, Inc. shall be determined by deducting from Pretax Net Income for such year the following items: Taxes and the Capital Charge, as illustrated in Exhibit A. 4.2 Phantom Equity for the full term of this Plan (July 1, 1997 through June 30, 2002) shall equal Average Adjusted Net Income, as calculated for five Plan Years, times the Equity Multiple less Capital, as illustrated in Exhibit B. If Average Adjusted Net Income for the period is zero (0) or less, then the Phantom Equity shall be zero (0). 4.3 Phantom Equity for a period of less than five Plan Years shall equal Average Adjusted Net Income, as calculated for the number of Plan Years considered, times the Equity Multiple less Capital. If Average Adjusted Net Income for the calculation period is zero (0) or less, then the Phantom Equity for the interim period shall equal zero (0). Article 5 Participation Interest And Interim Participation Interest 5.1 The maximum aggregate percentage of Participation Interest and Interim Participation Interest that may be awarded and outstanding at any time shall be fifteen percent (15%) of the Phantom Equity for the term of this Plan. If a Participation Interest or Interim Participation Interest is forfeited by a Participant pursuant to Sections 5.4 or 5.6, the portion of the forfeited Participation Interest or Interim Participation Interest shall be deducted from the percentages awarded and outstanding at the time of forfeiture. 5.2 There is no requirement that the maximum aggregate percentage of Participation Interest and Interim Participation Interest must be awarded. It is within the discretion of the President of AEP Energy Services, Inc. and the Compensation Committee as to the aggregate amount of awards to be granted. If a Participation Interest or Interim Participation Interest is forfeited by a Participant, the President of AEP Energy Services, Inc. and the Compensation Committee may award the forfeited portion of the Participation Interest or Interim Participation Interest to a new or current Participant. 5.3 The President of AEP Energy Services, Inc. shall, subject to the approval of the Compensation Committee, determine the individual Participation Interest or Interim Participation Interest granted to a Participant. 5.4 A Participation Interest or Interim Participation Interest granted to a Participant shall be forfeited if before June 30, 2002: a) a Participant with less than two years of service voluntarily terminates employment; b) a Participant with two or more years of service voluntarily terminates employment and engages in business in competition with AEP Energy Services, Inc.; or c) if AEP Energy Services, Inc. terminates the Participant for cause. 5.5 A Participation Interest or Interim Participation Interest granted to a Participant shall not be forfeited if before June 30, 2002: (a) AEP Energy Services, Inc. does not renew the Participant's contract, or (b) if during the term of an employment contract between the Participant and AEP Energy Services, Inc. both parties mutually agree to terminate the employment contract and the employment relationship between the Participant and AEP Energy Services, Inc. (c) a Participant with two or more years of service voluntarily terminates employment and does not engage in business in competition with AEP Energy Services, Inc. 5.6 If a Participant's employment is terminated due to the Participant's death, disability or retirement prior to June 30, 2002, a portion of the Participation Interest or Interim Participation Interest granted to the Participant shall be forfeited. If the Participant was granted a Participation Interest, the portion of the Participation Interest forfeited shall be determined by multiplying the Participation Interest percentage by a fraction, the numerator of which is the number of full months from the date of termination to June 30, 2002 and the denominator of which is sixty (60). If the Participant was granted an Interim Participation Interest, the portion of the Interim Participation Interest forfeited shall be determined by multiplying the Interim Participation Interest percentage by a fraction, the numerator of which is the number of full months from the date of termination to June 30, 2002 and the denominator of which is the number of months from the Valuation Date the Interim Participation Interest was granted to June 30, 2002. 5.7 In the event of a conflict between the terms described in Article 5 herein and the terms of the employment contract agreed to by the Participant and the Company, the terms of the employment contract shall take precedent. Article 6 Calculation and Payment of Awards 6.1 Participants who were awarded Participation Interest and who continued as Plan Participants through June 30, 2002, will have the value of their individual awards determined by multiplying the Phantom Equity as of the June 30, 2002 Valuation Date by the percent of their Participant Interest award. If the Phantom Equity at the end of the June 30, 2002 Valuation Date is zero or less, the Participants will not be entitled to any form of supplemental payment. 6.2 Unless otherwise defined in the terms of an employment contract agreed to by the Participant and the Company, Participants who were awarded Interim Participation Interest and who are Plan Participants as of June 30, 2002, will have the value of their individual awards determined as follows: The difference between the Phantom Equity as of the June 30, 2002 Valuation Date less the Phantom Equity determined as of the Valuation Date immediately proceeding the date the Interim Participation Interest was granted times the Participant's Interim Participation Interest shall equal the value of the Participant's award. 6.3 Unless otherwise defined in the terms of an employment contract agreed to by the Participant and the Company, Participants who terminate employment before June 30, 2002 and who do not forfeit their Participation Interest pursuant to Section 5.5 will have the value of their individual awards determined by multiplying their Participant Interest by the lower of (a) the Phantom Equity as of the Valuation Date immediately preceding their date of termination or (b) the Phantom Equity as of June 30, 2002. 6.4 Unless otherwise defined in the terms of an employment contract agreed to by the Participant and the Company, Participants who terminate employment before June 30, 2002 and who do not forfeit all of their Participation Interest pursuant to Section 5.6 will have the value of their individual awards determined by multiplying the Phantom Equity as of the Valuation Date immediately preceding the date of termination of employment by their Participation Interest. 6.5 Unless otherwise defined in the terms of an employment contract agreed to by the Participant and the Company, Participants who terminate employment before June 30, 2002 and who do not forfeit their Interim Participation Interest pursuant to Section 5.5 will have the value of their individual awards determined by multiplying their Interim Participation Interest by the lower of (a) the difference between the Phantom Equity as of the Valuation Date immediately preceding the date of termination less the Phantom Equity determined as of the Valuation Date immediately preceding the date the Interim Participation Interest was granted, or (b) the difference between the Phantom Equity as of June 30, 2002 less the Phantom Equity determined as of the Valuation date immediately preceding date the Interim Participation Interest was granted. 6.6 Unless otherwise define in the terms of an employment contract agreed to by the Participant and the Company, Participants who terminate employment before June 30, 2002 and who do not forfeit all of their Interim Participation Interest pursuant to Section 5.6 will have the value of their individual awards determined as follows: The difference between the Phantom Equity as of the Valuation Date immediately preceding the date of termination of employment less the Phantom Equity determined as of the Valuation Date immediately preceding the date the Interim Participation Interest was granted times the Participant's Interim Participation Interest shall equal the value of the Participant's award. 6.7 Notwithstanding any provision of this Plan to the contrary, if pursuant to Section 8.1 this Plan is terminated or if a Plan amendment adversely affects the rights of a Participant's Participation Interest or Interim Participation Interest or adversely affects the calculation of Phantom Equity, all Participation Interest and all Interim Participation Interest shall be deemed to be fully vested as of the date of termination or amendment. The determination of Phantom Equity shall be made as of the last Valuation Date immediately prior to the date of the termination or the amendment. Payment of Participation Interest or Interim Participation Interest shall be made within four months after the date of termination or the date of the amendment. 6.8 In the event American Electric Power Company, Inc. or the Company sells or otherwise disposes of AEP Energy Services, Inc. during the term of this Plan and the acquirer of AEP Energy Services, Inc. does not continue this Plan, the Plan shall be deemed to have terminated as of the date of the sale or disposition and the value of each Participant's Participation Interest and/or Interim Participation Interest shall be determined as of the date of the sale and/or disposition with the Phantom Equity equal to the sale price or disposition price less Capital. 6.9 All earned Participation Interest and Interim Participation Interest awards shall be paid to the Participant no later than October 31, 2002. Article 7 Administration 7.1 The Compensation Committee shall administer the Plan. The Compensation Committee shall have the authority to interpret the Plan and to prescribe, amend and rescind rules and regulations relating to the administration of the Plan, and all such interpretations, rules and regulations shall be conclusive and binding on all Participants. 7.2 The Compensation Committee may employ agents, attorneys, accountants, or other persons and allocate or delegate to them powers, rights, and duties all as the Compensation Committee may consider necessary or advisable to properly carry out the administration of the Plan. Article 8 Miscellaneous 8.1 The Compensation Committee shall have the right, authority and power to alter, amend, modify, revoke or terminate the Plan; provided, however, that no amendment of the Plan shall adversely affect the rights of any Participant with respect to Participation Interest and Interim Participation Interest that have been awarded prior to the amendment of the Plan and that no amendment of the Plan shall adversely affect the calculation of Phantom Equity. 8.2 No benefits at any time payable under this Plan to a Participant or a Participant's estate shall be subject in any manner to anticipation, alienation, sale, transfer, assignment, pledge, attachment, garnishment, levy, execution, or other legal or equitable process, or encumbrance of any kind. 8.3 Nothing in this Plan shall interfere with or limit in any way the right of the Company to terminate any Participant's employment at any time, nor confer upon a Participant any right to continue in the employ of the Company. 8.4 The Plan shall be construed and administered according to the laws of the State of Ohio. 8.5 In the event the Compensation Committee shall find that a Participant is unable to care for his or her affairs because of illness or accident, the Compensation Committee may direct that any payment due the Participant be paid to the Participant's duly appointed legal representative, and any such payment so made shall be a complete discharge of the liabilities of the Plan. 8.6 In the event a Participant dies prior to the complete payment of the Participant's award, the amount owing to the Participant shall be paid to the Participant's designated beneficiary or beneficiaries. A Participant at any time may, on a form provided by the Compensation Committee, (i) designate one or more persons as the Participant's beneficiary and (ii) change the beneficiary designation. In the event there is no record of a beneficiary designation, all amounts owed to the Participant shall be paid to the Participant's surviving spouse. If the Participant is not married, all amounts owed to the Participant shall be paid to the Participant's estate. Article 9 Change In Control 9.1 Notwithstanding any provision of this Plan to the contrary, if a Change In Control of American Electric Power Company, Inc. (hereinafter referred to as the "Corporation") occurs, all Participation Interests and all Interim Participation Interest shall be deemed to be fully accrued as of the date of the Change In Control. The determination of Phantom Equity shall be made as of the last date before the Change In Control even if the valuation date is not the last day of a Plan Year. Payments of Participation Interests or Interim Participant Interest shall be made within four months after the date of the Change In Control. 9.2 A "Change in Control" of the Corporation shall be deemed to have occurred if (i) any "person" or "group" (as such terms are used in Sections 13(d) and 14(d) of the Securities Exchange Ace of 1934 ("Exchange Act")), other than any company owned, directly or indirectly, by the shareholders of the Corporation in substantially the same proportions as their ownership of stock of the Corporation or a trustee or other fiduciary holding securities under an employee benefit plan of the Corporation, becomes the "beneficial owner" (as defined in Rule 13d-3 under the Exchange Act), directly or indirectly, of more than 25 percent of the then outstanding voting stock of the Corporation, (ii) during any period of two consecutive years, individuals who at the beginning of such period constitute the Board, together with any new Directors (other than a director nominated by a person (x) who has entered into an agreement with the Corporation to effect a transaction described in Section 9.2 (i), (iii) or (iv) hereof or (y) who publicly announces an intention to take or to consider taking actions (including, but not limited to, an actual or threatened proxy contest) which if consummated would constitute a Change In Control) whose election or nomination for election was approved by a vote of at least two-thirds of the Directors then still in office who were either Directors at the beginning of the period or whose election or nomination for election was previously so approved, cease for any reason to constitute at least a majority of the Board; or (iii) the Corporation's shareholders consummation of a merger or consolidation of the Corporation with any other entity, other than a merger or consolidation which would result in the voting securities of the Corporation outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity) at least 50 percent of the total voting power represented by the voting securities of the Corporation or such surviving entity outstanding immediately after such merger or consolidation; or (iv) the shareholders of the Corporation approve a plan of complete liquidation of the Corporation, or an agreement for the date or disposition of the Corporation (in one transaction or a series of transactions) of all or substantially all the Corporation's assets. Notwithstanding the foregoing, a Change in Control shall not be deemed to occur as a result of the consummation of the transaction contemplated in the Agreement and Plan of Merger by and among the Corporation, Augusta Acquisition Corporation and Central and South West Corporation dated as of December 21, 1997, nor thereafter as a result of any event in (i) or (iii) above, if Directors who were members of the Board prior to such event continue to constitute a majority of the Board after such event. For purposes of this Section 9.2, "Board" shall mean the Board of Directors of the Corporation, and "Director" shall mean an individual who is a member of the Board. EXHIBIT A AEP ENERGY SERVICES, INC. PHANTOM EQUITY PLAN Computation of Pretax Net Income and Adjusted Net Income Pretax Operating Income Plus Interest Income Less Annual Bonus Awards Less Interest Expense Equals Pretax Net Income Less Taxes Less Capital Charge Equals Adjusted Net Income EXHIBIT B AEP ENERGY SERVICES, INC. PHANTOM EQUITY PLAN COMPUTATION OF PHANTOM EQUITY Average Adjusted Net Income Times Equity Multiple Less Capital Equals Phantom Equity EX-10.(S) 10 0010.txt TOMASKY AGREEMENT Exhibit 10(s) Date: January 3, 2001 Subject: From: J. H. Vipperman To: S. Tomasky In consideration of the prior experience you brought to AEP, you are being provided 20 years' additional retirement plan service. The additional years of service, along with your actual years of service, will be used in computing your benefit under the final average pay formula and the cash balance formula. Under the cash balance formula with the additional service, you will receive the maximum company credit (8.5%) on compensation beginning in 2001. You will be vested in the retirement benefits earned under both the qualified Retirement Plan and the AEP Excess Benefit Plan after the completion of five years of service. c: M. S. Ackerman EX-13 11 0011.txt AEP & SUB COMBINED FINANCIAL STATEMENTS 2000 Annual Reports American Electric Power Company, Inc. AEP Generating Company Appalachian Power Company Central Power and Light Company Columbus Southern Power Company Indiana Michigan Power Company Kentucky Power Company Ohio Power Company Public Service Company of Oklahoma Southwestern Electric Power Company West Texas Utilities Company Audited Financial Statements and Management's Discussion and Analysis
Contents Page Glossary of Terms i Forward Looking Information iv American Electric Power Company, Inc. and Subsidiary Companies Selected Consolidated Financial Data A-1 Management's Discussion and Analysis of Results of Operations A-2 Consolidated Statements of Income A-8 Consolidated Balance Sheets A-9 Consolidated Statements of Cash Flows A-11 Consolidated Statements of Common Shareholders' Equity A-12 Schedule of Consolidated Cumulative Preferred Stocks of Subsidiaries A-13 Schedule of Consolidated Long-term Debt of Subsidiaries A-14 Index to Notes to Consolidated Financial Statements A-15 Management's Responsibility A-16 Independent Auditors' Report A-17 AEP Generating Company Selected Financial Data B-1 Management's Narrative Analysis of Results of Operations B-2 Statements of Income and Statements of Retained Earnings B-3 Balance Sheets B-4 Statements of Cash Flows B-6 Statements of Capitalization B-7 Index to Notes to Financial Statements B-8 Independent Auditors' Report B-9 Appalachian Power Company and Subsidiaries Selected Consolidated Financial Data C-1 Management's Discussion and Analysis of Results of Operations C-2 Consolidated Statements of Income C-5 Consolidated Balance Sheets C-6 Consolidated Statements of Cash Flows C-8 Consolidated Statements of Retained Earnings C-9 Consolidated Statements of Capitalization C-10 Schedule of Long-term Debt C-11 Index to Notes to Consolidated Financial Statements C-12 Independent Auditors' Report C-13 Central Power & Light Company and Subsidiaries Selected Consolidated Financial Data D-1 Management's Discussion and Analysis of Results of Operations D-2 Consolidated Statements of Income D-5 Consolidated Balance Sheets D-6 Consolidated Statements of Cash Flows D-8 Consolidated Statements of Retained Earnings D-9 Consolidated Statements of Capitalization D-10 Schedule of Long-term Debt D-11 Index to Notes to Consolidated Financial Statements D-12 Independent Auditors' Report D-13 Columbus Southern Power Company and Subsidiaries Selected Consolidated Financial Data E-1 Management's Narrative Analysis of Results of Operations E-2 Consolidated Statements of Income and Consolidated Statements of Retained Earnings E-5 Consolidated Balance Sheets E-6 Consolidated Statements of Cash Flows E-8 Consolidated Statements of Capitalization E-9 Schedule of Long-term Debt E-10 Index to Notes to Consolidated Financial Statements E-11 Independent Auditors' Report E-12 Indiana Michigan Power Company and Subsidiaries Selected Consolidated Financial Data F-1 Management's Discussion and Analysis of Results of Operations F-2 Consolidated Statements of Income F-5 Consolidated Balance Sheets F-6 Consolidated Statements of Cash Flows F-8 Consolidated Statements of Retained Earnings F-9 Consolidated Statements of Capitalization F-10 Schedule of Long-term Debt F-11 Index to Notes to Consolidated Financial Statements F-13 Independent Auditors' Report F-14 Kentucky Power Company Selected Financial Data G-1 Management's Narrative Analysis of Results of Operations G-2 Statements of Income and Statements of Retained Earnings G-4 Balance Sheets G-5 Statements of Cash Flows G-7 Statements of Capitalization G-8 Schedule of Long-term Debt G-9 Index to Notes to Financial Statements G-10 Independent Auditors' Report G-11 Ohio Power Company and Subsidiaries Selected Consolidated Financial Data H-1 Management's Discussion and Analysis of Results of Operations H-2 Consolidated Statements of Income H-5 Consolidated Balance Sheets H-6 Consolidated Statements of Cash Flows H-8 Consolidated Statements of Retained Earnings H-9 Consolidated Statements of Capitalization H-10 Schedule of Long-term Debt H-11 Index to Notes to Consolidated Financial Statements H-13 Independent Auditors' Report H-14 Public Service Company of Oklahoma and Subsidiaries Selected Consolidated Financial Data I-1 Management's Narrative Analysis of Results of Operations I-2 Consolidated Statements of Income and Consolidated Statements of Retained Earnings I-4 Consolidated Balance Sheets I-5 Consolidated Statements of Cash Flows I-7 Consolidated Statements of Capitalization I-8 Schedule of Long-term Debt I-9 Index to Notes to Consolidated Financial Statements I-10 Independent Auditors' Report I-11 Southwestern Electric Power Company and Subsidiaries Selected Consolidated Financial Data J-1 Management's Discussion and Analysis of Results of Operations J-2 Consolidated Statements of Income and Consolidated Statements of Retained Earnings J-5 Consolidated Balance Sheets J-6 Consolidated Statements of Cash Flows J-8 Consolidated Statements of Capitalization J-9 Schedule of Long-term Debt J-10 Index to Notes to Consolidated Financial Statements J-11 Independent Auditors' Report J-12 West Texas Utilities Company Selected Financial Data K-1 Management's Narrative Analysis of Results of Operations K-2 Statements of Income and Statements of Retained Earnings K-4 Balance Sheets K-5 Statements of Cash Flows K-7 Statements of Capitalization K-8 Schedule of Long-term Debt K-9 Index to Notes to Financial Statements K-10 Independent Auditors' Report K-11 Combined Notes to Financial Statements L-1 Management's Discussion and Analysis of Financial Condition, Contingencies and Other Matters M-1
iv GLOSSARY OF TERMS When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below. Term Meaning 2004 True-up Proceeding............ A filing to be made after January 10, 2004 under the Texas Legislation to finalize the amount of stranded costs and the recovery of such costs. AEGCo.............................. AEP Generating Company, an electric utility subsidiary of AEP. AEP................................ American Electric Power Company, Inc. AEP Consolidated................... AEP and its majority owned subsidiaries consolidated. AEP Credit....................,Inc. AEP Credit, Inc., a subsidiary of AEP which factors accounts receivable and accrued utility revenues for affiliated and unaffiliated domestic electric utility companies. AEP East electric operating companies..........................APCo, CSPCo, I&M, KPCo and OPCo. AEPR............................... AEP Resources, Inc. AEP System or the System........... The American Electric Power System, an integrated electric utility system, owned and operated by AEP's electric utility subsidiaries. AEPSC.............................. American Electric Power Service Corporation, a service subsidiary providing management and professional services to AEP and its subsidiaries. AEP Power Pool..................... AEP System Power Pool. Members are APCo, CSPCo, I&M, KPCo and OPCo. The Pool shares the generation, cost of generation and resultant wholesale system sales of the member companies. AEP West electric operating companies.......................... CPL, PSO, SWEPCo and WTU. AFUDC.............................. Allowance for funds used during construction, a noncash nonoperating income item that is capitalized and recovered through depreciation over the service life of domestic regulated electric utility plant. Alliance RTO....................... Alliance Regional Transmission Organization, an ISO formed by AEP and four unaffiliated utilities. Amos Plant......................... John E. Amos Plant, a 2,900 MW generation station jointly owned and operated by APCo and OPCo. APCo............................... Appalachian Power Company, an AEP electric utility subsidiary. Arkansas Commission................ Arkansas Public Service Commission. Buckeye............................ Buckeye Power, Inc., an unaffiliated corporation. CLECO.............................. Central Louisiana Electric Company, Inc., an unaffiliated corporation. COLI............................... Corporate owned life insurance program. Cook Plant......................... The Donald C. Cook Nuclear Plant, a two-unit, 2,110 MW nuclear plant owned by I&M. CPL................................ Central Power and Light Company, an AEP electric utility subsidiary. CSPCo.............................. Columbus Southern Power Company, an AEP electric utility subsidiary. CSW............................... Central and South West Corporation, a subsidiary of AEP. CSW Energy......................... CSW Energy, Inc., an AEP subsidiary which invests in energy projects and builds power plants. CSW International.................. CSW International, Inc., an AEP subsidiary which invests in energy projects and entities outside the United States. D.C. Circuit Court................. The United States Court of Appeals for the District of Columbia Circuit. DHMV............................... Dolet Hills Mining Venture. DOE................................ United States Department of Energy. ECOM............................... Excess Cost Over Market. ENEC............................... Expanded Net Energy Costs. EITF............................... The Financial Accounting Standards Board's Emerging Issues Task Force. ERCOT.............................. The Electric Reliability Council of Texas. EWGs............................... Exempt Wholesale Generators. FASB............................... Financial Accounting Standards Board. Federal EPA........................ United States Environmental Protection Agency. FERC............................... Federal Energy Regulatory Commission. FMB ............................... First Mortgage Bond. FUCOs.............................. Foreign Utility Companies. GAAP............................... Generally Accepted Accounting Principles. I&M................................ Indiana Michigan Power Company, an AEP electric utility subsidiary. IPC................................ Installment Purchase Contract. IRS................................ Internal Revenue Service. IURC............................... Indiana Utility Regulatory Commission. ISO................................ Independent system operator. Joint Stipulation.................. Joint Stipulation and Agreement for Settlement of APCo's WV rate proceeding. KPCo............................... Kentucky Power Company, an AEP electric utility subsidiary. KPSC............................... Kentucky Public Service Commission. KWH................................ Kilowatthour. LIG................................ Louisiana Intrastate Gas. Michigan Legislation............... The Customer Choice and Electricity Reliability Act, a Michigan law which provides for customer choice of electricity supplier. Midwest ISO........................ An independent operator of transmission assets in the Midwest. MLR................................ Member load ratio, the method used to allocate AEP Power Pool transactions to its members. Money Pool......................... AEP System's Money Pool. MPSC............................... Michigan Public Service Commission. MTN................................ Medium Term Notes. MW................................. Megawatt. MWH................................ Megawatthour. NEIL............................... Nuclear Electric Insurance Limited. Nox................................ Nitrogen oxide. Nox Rule........................... A final rules issued by Federal EPA which requires NOx reductions in 22 eastern states including seven of the states in which AEP companies operates. NP................................. Notes Payable. NRC................................ Nuclear Regulatory Commission. Ohio Act........................... The Ohio Electric Restructuring Act of 1999. Ohio EPA........................... Ohio Environmental Protection Agency. OPCo.............................. Ohio Power Company, an AEP electric utility subsidiary. OVEC............................... Ohio Valley Electric Corporation, an electric utility company in which AEP and CSPCo own a 44.2% equity interest. PCBs............................... Polychlorinated Biphenyls. PJM................................ Pennsylvania - New Jersey - Maryland regional transmission organization. PRP.............................. Potentially Responsible Party. PSO................................ Public Service Company of Oklahoma, an AEP electric utility subsidiary. PUCO............................... The Public Utilities Commission of Ohio. PUCT............................... The Public Utility Commission of Texas. PUHCA.............................. Public Utility Holding Company Act of 1935, as amended. PURPA.............................. The Public Utility Regulatory Policies Act of 1978. RCRA............................... Resource Conservation and Recovery Act of 1976, as amended. Registrant Subsidiaries............ AEP subsidiaries who are SEC registrants; AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU. Rockport Plant..................... A generating plant, consisting of two 1,300 MW coal-fired generating units near Rockport, Indiana owned by AEGCo and I&M. RTO................................ Regional Transmission Organization. SEC................................ Securities and Exchange Commission. SFAS............................... Statement of Financial Accounting Standards issued by the Financial Accounting Standards Board. SFAS 71............................ Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain ------------------------------------- Types of Regulation. ------------------- SFAS 101........................... Statement of Financial Accounting Standards No. 101, Accounting for the Discontinuance of ------------------------------------ Application of Statement 71. SFAS 121........................... Statement of Financial Accounting Standards No. 121, Accounting for the Impairment of -------------------------------- Long-Lived Assets and for Long-Lived Assets to be Disposed of. -------------------------------------------------------------- SFAS 133........................... Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments ------------------------------------- and Hedging Activities. SNF................................ Spent Nuclear Fuel. SPP................................ Southwest Power Pool. STP................................ South Texas Project Nuclear Generating Plant, owned 25.2% by Central Power and Light Company, an AEP electric utility subsidiary . STPNOC............................. STP Nuclear Operating Company, a non-profit Texas corporation which operates STP on behalf of its joint owners including CPL. Superfund......................... The Comprehensive Environmental, Response, Compensation and Liability Act. SWEPCo............................. Southwestern Electric Power Company, an AEP electric utility subsidiary. Texas Appeals Court................ The Third District of Texas Court of Appeals. Texas Legislation.................. Legislation enacted in 1999 to restructure the electric utility industry in Texas. Travis District Court.............. State District Court of Travis County, Texas. TVA ............................... Tennessee Valley Authority. U.K................................ The United Kingdom. UN................................. Unsecured Note. VaR................................ Value at Risk, a method to quantify risk exposure. Virginia SCC....................... Virginia State Corporation Commission. WV................................. West Virginia. WVPSC.............................. Public Service Commission of West Virginia. WPCo............................... Wheeling Power Company, an AEP electric distribution subsidiary. WTU................................ West Texas Utilities Company, an AEP electric utility subsidiary. Yorkshire.......................... Yorkshire Electricity Group plc, a U.K. regional electricity company owned jointly by AEP and New Century Energies. Zimmer Plant....................... William H. Zimmer Generating Station, a 1,300 MW coal-fired unit owned 25.4% by Columbus Southern Power Company, an AEP subsidiary.
FORWARD LOOKING INFORMATION - ----------------------------------------------------------------------------- This discussion includes forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. These forward-looking statements reflect assumptions, and involve a number of risks and uncertainties. Among the factors both foreign and domestic that could cause actual results to differ materially from forward looking statements are: electric load and customer growth; abnormal weather conditions; available sources of and prices for coal and gas; availability of generating capacity; the impact of the merger with CSW including actual merger savings being less than the related rate reductions; risks related to energy trading and construction under contract; the speed and degree to which competition is introduced to our power generation business; the structure and timing of a competitive market for electricity and its impact on prices; the ability to recover net regulatory assets, other stranded costs and implementation costs in connection with deregulation of generation in certain states; new legislation and government regulations; the ability to successfully control costs; the success of new business ventures; international developments affecting our foreign investments; the economic climate and growth in our service and trading territories both domestic and foreign; the ability of the Company to successfully challenge new environmental regulations and to successfully litigate claims that the Company violated the Clean Air Act; successful resolution of litigation regarding municipal franchise fees in Texas; inflationary trends; changes in electricity and gas market prices; interest rates; foreign exchange rates, and other risks and unforeseen events. AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
A-17 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Selected Consolidated Financial Data Year Ended December 31, 2000 1999 1998 1997 1996 - ----------------------------------------------------------------------------------------- INCOME STATEMENTS DATA (in millions): Total Revenues $13,694 $12,407 $11,840 $11,163 $11,017 Operating Income 2,026 2,325 2,280 2,198 2,368 Income From Continuing Operations 302 986 975 949 871 Discontinued Operations - - - - 132 Extraordinary Loss (35) (14) - (285) - Net Income 267 972 975 664 1,003 December 31, 2000 1999 1998 1997 1996 - ----------------------------------------------------------------------------------------- BALANCE SHEETS DATA (in millions): Property, Plant and Equipment $38,088 $36,938 $35,655 $33,496 $32,443 Accumulated Depreciation and Amortization 15,695 15,073 14,136 13,229 12,494 ------- ------- ------- ------- ------- Net Property, Plant and Equipment $22,393 $21,865 $21,519 $20,267 $19,949 ======= ======= ======= ======= ======= Total Assets $54,548 $35,719 $33,418 $30,092 $29,228 Common Shareholders' Equity 8,054 8,673 8,452 8,220 8,334 Cumulative Preferred Stocks of Subsidiaries: Not Subject to Mandatory Redemption 61 63 222 223 382 Subject to Mandatory Redemption* 100 119 128 154 543 Trust Preferred Securities 334 335 335 335 - Long-term Debt* 10,754 11,524 11,113 9,354 9,112 Obligations Under Capital Leases* 614 610 539 549 422 *Including portion due within one year Year Ended December 31, 2000 1999 1998 1997 1996 - ----------------------------------------------------------------------------------------- COMMON STOCK DATA: Earnings per Common Share: Continuing Operations $0.94 $3.07 $3.06 $2.99 $2.79 Discontinued Operations - - - - 0.42 Extraordinary Loss (.11) (.04) - (0.90) - ----- ----- ----- ----- ------ Net Income $0.83 $3.03 $3.06 $2.09 $3.21 ===== ===== ===== ===== ===== Average Number of Shares Outstanding (in millions) 322 321 318 316 312 Market Price Range: High $48-15/16 $48-3/16 $53-5/16 $ 52 $44-3/4 Low 25-15/16 30-9/16 42-1/16 39-1/8 38-5/8 Year-end Market Price 46-1/2 32-1/8 47-1/16 51-5/8 41-1/8 Cash Dividends on Common* $2.40 $2.40 $2.40 $2.40 $2.40 Dividend Payout Ratio* 289.2% 79.2% 78.4% 114.8% 74.5% Book Value per Share $25.01 $26.96 $26.46 $25.91 $26.45 The consolidated financial statements give retroactive effect to AEP's merger with CSW, which was accounted for as a pooling of interests, as if AEP and CSW had always been combined. *Based on AEP historical dividend rate.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Management's Discussion and Analysis of Results of Operations American Electric Power Company, Inc. (AEP) is one of the largest investor owned electric public utility holding companies in the U.S. serving over 4.8 million retail customers in eleven states (Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia) and selling bulk power at wholesale both within and beyond its domestic retail service area. AEP has 38,000 megawatts of generation and over 38,000 miles of transmission lines and 186,000 miles of distribution lines in the U.S. Subsidiaries own 1,250 megawatts as independent power producers in Colorado, Florida and Texas. In recent years AEP has expanded its domestic operations to include gas marketing, processing, storage and transportation operations, electric, gas and coal trading operations and telecommunication services and invested in and acquired foreign distribution operations in the U.K., Australia and Brazil and electricity generating facilities in China and Mexico. Subsidiaries also provide power engineering, generation and transmission plant maintenance and construction, and energy management services worldwide. AEP is one of the largest traders of electricity and gas in the U.S. In 2000 we established an energy trading operation in Europe. Presently AEP is in the process of restructuring its assets and operations to separate the regulated operations from the non-regulated operations and to functionally and, where permitted by law, structurally unbundle its domestic vertically integrated electric utility business into separate generation, transmission and distribution businesses. The purpose of this restructuring is to focus our management and technical expertise to maximize the potential for growth of both non-regulated and regulated operations, to evaluate the performance of these separate and different businesses and to meet the separation requirements of federal and state restructuring legislation and codes of conduct. Five of AEP's 11 states (Arkansas, Ohio, Texas, Virginia, and West Virginia) are in various stages of transitioning to deregulation of generation and to customer choice and market-based pricing from monopoly and regulator set rates for the retail sale of electricity. When the transition is implemented in those states, transmission will be regulated by the Federal Energy Regulatory Commission and distribution services will continue to be cost-based rate regulated by the states. Although we are actively supporting the transition to competition, there is little progress in the remaining six states. Therefore, in the near term, our retail electric business in Indiana, Kentucky, Louisiana, Michigan, Oklahoma and Tennessee will continue to be operated as an integrated public utility subject to state regulation. The foreign energy delivery investments and operations are not cost-based rate regulated but they are generally subject to different forms of price controls, such as capped prices. As such these foreign investments and operations will be included in our unbundled regulated business. On November 1, 2000, AEP filed a restructuring plan under PUHCA with the SEC seeking approval to form two wholly owned holding company subsidiaries of AEP to separately own AEP's regulated and non-regulated subsidiaries and to structurally separate into separate legal entities along functional lines (i.e. generation, transmission and distribution) six of the electric utility operating companies (APCo, CPL, CSPCo, OPCo, SWEPCo and WTU). These six operating companies do business in the states that are implementing restructuring (Arkansas, Ohio, Texas, Virginia and West Virginia). The remaining domestic electric operating companies will be functionally unbundled for internal management and internal reporting purposes and for financial segment reporting but will not be structurally unbundled into separate companies since state law and/or regulation prohibits such action. One holding company will hold the unbundled non-regulated electric generation subsidiaries and the non-regulated domestic and foreign subsidiaries including the European trading company and the foreign generating companies, while the other holding company will hold the bundled domestic regulated electric utility companies and the foreign distribution companies. The restructuring will facilitate management's strategy to grow the deregulated wholesale electricity supply and electric and gas trading business and to evaluate the other business operations to explore ways to improve their results of operations and to continuously evaluate and where necessary reshape our business to grow earnings and improve shareholder value. The legal transfer of assets and structural separation plans will also require FERC, certain state and other regulatory approvals. 2000 was a year of accomplishment that positions AEP for earnings growth. In 2000 we completed the merger of AEP and CSW, greatly increasing the scope and size of AEP; achieved the targeted merger savings; returned the two unit 2,110 MW Cook Plant to service after an extended outage; reached a settlement on a restructuring plan in Ohio that will allow our electric generating and supply business in Ohio to transition over five years to market pricing and recover its stranded cost, including generation-related regulatory assets; continued to grow our domestic electricity and gas trading businesses to become one of the largest electricity and gas traders; established and grew an energy trading operation in Europe; added to our gas assets and operations with the announcement in the first quarter of 2001 of the planned acquisition of Houston Pipe Line Company; restructured our incentive compensation plans to more closely align them with the creation of shareholder value; reduced our power plant operation and maintenance costs while increasing plant availability; established AEP Pro Serv, Inc. to market AEP's expertise in power engineering, environmental engineering and generating plant maintenance services worldwide; closed contracts to design, build, operate and market the output of new power plants for Dow Chemical, Buckeye Power and Columbia Energy; and initiated a re-design of our existing PeopleSoft financial software as part of an enterprise-wide application to fully integrate our financial, work management and supply chain software and to provide data on a business unit basis consistent with our corporate separation initiative. Although 2000 was a year marked by significant accomplishments that position AEP for future earnings growth, it resulted in a reduction in earnings and earnings per share due mainly to non-recurring items, such as: a loss incurred from a court decision disallowing tax deductions for interest related to AEP's COLI program; the write-off of non-recoverable merger costs; the expensing of Cook nuclear restart costs in contrast to 1999 when a significant portion of the restart costs were deferred with regulatory approval; the write-off of certain extraordinary costs that were stranded and liabilities incurred in connection with the restructuring of the regulation of the electric utility business in Ohio, Virginia, and West Virginia to transition that portion of AEP's domestic electricity supply business from cost-based rate regulation to customer choice and market pricing; the recognition of losses associated with a CSW investment in Chile which was sold in the fourth quarter; an impairment writedown of AEP's investment in Yorkshire to reflect a pending sale of the investment in 2001; and write-offs of unrecoverable contract costs and goodwill on certain of CSW's non-regulated businesses acquired in the merger. Earnings in 2001 are expected to improve significantly with the return of Cook Plant's 2,110 MW of generating capacity due to the completion of restart efforts and the cessation of significant restart costs at Cook and the growth of our wholesale marketing and trading business. Our focus for 2001 will be on completing our corporate separation plan to separate our regulated and non-regulated businesses. We believe that a successful implementation of this plan will support our business objective of unlocking shareholder value by providing managers with a simpler structure through which business unit performance can be more easily anticipated and monitored thereby focusing management attention; permitting more efficient financing; and meeting the regulatory codes of conduct required as part of industry restructuring. Although management expects that the future outlook for results of operations is excellent there are contingencies, challenges and obstacles to overcome and manage, such as new more stringent Federal EPA environmental requirements and recent complaints and related litigation, further delays in transition to competition supported in part by concerns that California's energy crisis could happen in our service territory, the recovery of generation-related regulatory assets and other stranded costs in Texas and any additional state jurisdictions that we can successfully promote the adoption of customer choice and a transition to market pricing from regulated rate setting, franchise fee litigation in Texas, litigation concerning AEP's financial disclosures regarding the extended Cook Plant safety outage and timing of the successful completion of restart efforts, the amortization of transition regulatory assets from the introduction of competition to our previously regulated domestic generation business and the amortization of deferred costs from the successful effort to restart Cook Plant and to merge AEP and CSW and the outcome of litigation to recover $90 million of duplicate tax expense from May 2001 to April 2002 resulting from restructuring in Ohio. These challenges, contingencies and obstacles, which are discussed in detail in the Notes to Consolidated Financial Statements and in Management's Discussion and Analysis of Financial Condition, Contingencies and Other Matters, are receiving management's full attention and we intend to work diligently to resolve these matters by finding workable solutions that balance the interests of our customers, our employees and our shareholders. Results of Operations Net Income Although revenues increased by $1.3 billion net income declined to $267 million or $0.83 per share in 2000 from $972 million or $3.03 per share in 1999. The decrease was primarily due to Cook Nuclear Plant restart costs, a disallowance of tax deductions for corporate owned life insurance (COLI), expensing of costs related to AEP's recently completed merger with CSW, write offs related to non-regulated subsidiaries and an extraordinary loss from the discontinuance of regulatory accounting for generation in certain states. In 1999 net income was virtually un-changed as increased expenses to prepare the Cook Nuclear Plant for restart, net of related deferrals, were offset by a gain from a sale of a 50% interest in a cogeneration project. Revenues Increase AEP's revenues include a significant number of transactions from the trading of electricity and gas. Revenues from trading of electricity are recorded net of purchases as domestic electric utility wholesale sales for transactions in AEP's traditional marketing area (up to two transmission systems from the AEP service territory) and as revenues from worldwide electric and gas operations for transactions beyond two transmission systems from AEP. Revenues from gas trading are recorded net of purchases and reported in revenues from worldwide electric and gas operations. Trading transactions involve the purchase and sale of substantial amounts of electricity and gas. The level of electricity trading trans-actions tends to fluctuate due to the highly competitive nature of the short-term (spot) energy market and other factors, such as af-filiated and unaffiliated generating plant avail-ability, weather conditions and the economy. The FERC rules, which introduced a greater degree of competition into the wholesale energy market, have had a major effect on the volume of electricity trading as most electricity is traded in the short-term market. AEP's total revenues increased 10% in 2000 and 5% in 1999. The table below shows the changes in the components of revenues from domestic electric utility operations and worldwide electric and gas operations. While worldwide electric and gas operations revenues increased 12% in 2000, most of the increase in total revenues was caused by the increased revenues from domestic electric utility operations. Increase (Decrease) From Previous Year (Dollars in Millions) 2000 1999 Amount % Amount % Domestic Electric Utility Operations: Retail: Residential $ 230 $ 18 Commercial 163 56 Industrial (71) 11 Other 25 7 ------ ----- 347 4.2 92 1.1 Wholesale 672 59.9 (145)(11.5) Other (30)(6.8) 57 15.3 ------ ----- Total Domestic Electric Utility Operations 989 10.1 4 - Worldwide Electric and Gas Operations 298 11.6 563 28.1 ------ ----- Total $1,287 10.4 $ 567 4.8 ====== ===== The increase in total revenues from domestic electric utility operations in 2000 was primarily due to a 38% increase in wholesale sales volume and increased retail fuel revenues as a result of higher gas prices used to generate electricity. The reduction in industrial revenues in 2000 is attributable to the expiration of a long-term contract on December 31, 1999. The significant increase in wholesale sales volume, which accounted for a 60% increase in wholesale revenues, resulted from efforts to grow AEP's energy marketing and trading operations, favorable market conditions, and the availability of additional generation due to the return to service of one of the Cook Plant nuclear units in June 2000 and improved generating unit availability due mainly to improved outage management. The second Cook Plant unit which returned to service in December 2000 did not have a significant impact on revenues. In 1999 revenues from domestic electric utility operations were unchanged. A 1% gain in retail revenues was more than offset by a 12% decline in wholesale revenues. The 12% decline in wholesale revenues in 1999 was predominantly due to a decrease in wholesale energy sales and a reduction in net revenues from power trading due to a decline in margins. The decrease in wholesale sales reflects the expiration in July 1998 of a power contract which supplied power to several municipal customers and the decision by another wholesale customer who buys energy under a unit power agreement not to take energy from AEP during an outage of that unit. The decline in wholesale margins in 1999 reflects the moderation of weather and the effected capacity shortages experienced in the summer of 1998. Revenues from worldwide electric and gas operations increased 12% in 2000 due to increased natural gas and gas liquid product prices. Volumes of natural gas remained consistent with the prior year, however, prices increased significantly. In 1999 revenues derived from worldwide electric and gas operations increased 28%. This increase is primarily due to the acquisitions in December 1998, of CitiPower in Australia and of LIG, and the commercial operation of a two-unit 250 MW coal-fired generating plant in China. Operating Expenses Increase Changes in the components of operating expenses were as follows: Increase (Decrease) From Previous Year (Dollars in Millions) 2000 1999 Amount % Amount % Fuel and Purchased Power $ 679 19.7 $ (6) (0.2) Maintenance and Other Operation 342 12.8 79 3.0 Merger Costs 203 - - - Depreciation and Amortization 51 5.0 22 2.2 Taxes Other Than Income Taxes 7 1.1 5 0.8 Worldwide Electric and Gas Operations 304 13.3 422 22.7 ------ ---- Total $1,586 15.7 $522 5.5 ====== ==== Fuel and purchased power expense increased 20% in 2000 due to a significant increase in the cost of natural gas used for generation. Natural gas usage for generation declined 5% while the cost of natural gas consumed rose 60%. Net income was not impacted by this significant cost increase due to the operation of fuel recovery mechanisms. These fuel recovery mechanisms generally provide for the deferral of fuel costs above the amounts included in rates or the accrual of revenues for fuel costs not yet recovered. Upon regulatory commission review and approval of the unrecovered fuel costs, the accrued or deferred amounts are billed to customers. The increase in maintenance and other operation expense in 2000 was mainly due to increased expenditures to prepare the Cook Plant nuclear units for restart following an extended NRC monitored outage and increased usage of and prices for emissions allowances. The increase in Cook Plant restart costs resulted from the effect of deferring restart costs in 1999 and an increase in the restart expenditure level. The Cook Plant began an extended outage in September 1997 when both nuclear generating units were shut down because of questions regarding the operability of certain safety systems. In 1999 a portion of incremental restart expenses were deferred in accordance with IURC and MPSC settlement agreements which resolved all jurisdictional rate-related issues related to the Cook Plant's extended outage. Unit 2 returned to service in June and achieved full power operation on July 5, 2000 and Unit 1 returned to service in December and achieved full power operation on January 3, 2001. The increase in emission allowance usage and prices resulted from the stricter air quality standards of Phase II of the 1990 Clean Air Act Amendments, which became effective on January 1, 2000. The increase in maintenance and other operation expense in 1999 was primarily due to a NRC required 10-year inspection of STP Units 1 and 2 and increased expenditures to prepare the Cook Plant nuclear units for restart. Although a portion of Cook Plant restart costs were deferred in 1999 pursuant to regulatory orders, net expenditures charged to expense increased over 1998. With the consummation of the merger with CSW, certain deferred merger costs were expensed. 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. Worldwide electric and gas operations expense in 2000 increased 13% to $2.6 billion from $2.3 billion. The increase was due to the increase in natural gas prices, the write down to market value of a CSW available-for-sale investment in a Chilean-based electric company sold in December 2000 and the effect of a gain in 1999 on the planned sale of a 50% interest in a cogeneration project. Federal law limits ownership in qualifying cogeneration facilities to 50%. CSW Energy constructed the project and completed the sale of a 50% interest in the project to an unaffiliated entity in 1999. Expenses of the worldwide electric and gas operations increased in 1999 due to the addition of expenses of businesses acquired in December 1998 and the start of commercial operation of the two-unit 250 MW coal-fired generating plant in China. Interest and Preferred Dividends In 2000 interest and preferred stock dividends increased by 16% to $1,160 million from $996 million in 1999 due to additional interest expense from the ruling on the litigation with the government disallowing COLI tax deductions and AEP's intention to maintain flexibility for corporate separation by issuing short-term debt at flexible rates. The use of fixed interest rate swaps has been employed to mitigate the risk from floating interest rates. The 11% increase in interest and preferred stock dividends in 1999 was due primarily to increased interest expense on long-term debt. Long-term debt outstanding increased $564 million in 1999. Other Income Other income decreased from $139 million in 1999 to $33 million in 2000 primarily due to a write-down of AEP's Yorkshire investment to reflect a proposed sale in 2001, losses of non-regulated subsidiaries accounted for on an equity basis, and a charge for the discontinuance of an electric storage water heater demand side management program. Other income increased 46% in 1999 primarily due to gains from the sale of investments at SEEBOARD and from interest income related to a cogeneration power plant. Income Taxes Income taxes increased in 2000 primarily due to an unfavorable ruling in AEP's suit against the government over interest deductions claimed relating to AEP's COLI program and nondeductible merger related costs.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Consolidated Statements of Income - ------------------------------------------------------------------------------ (in millions - except per share amounts) Year Ended December 31, ------------------------------------- 2000 1999 1998 ---- ---- ---- REVENUES: Domestic Electric Utility Operations $10,827 $ 9,838 $ 9,834 Worldwide Electric and Gas Operations 2,867 2,569 2,006 ------- ------- ------- TOTAL REVENUES 13,694 12,407 11,840 ------- ------- ------- EXPENSES: Fuel and Purchased Power 4,128 3,449 3,455 Maintenance and Other Operation 3,017 2,675 2,596 Non-recoverable Merger Costs 203 - - Depreciation and Amortization 1,062 1,011 989 Taxes Other Than Income Taxes 671 664 659 Worldwide Electric and Gas Operations 2,587 2,283 1,861 ------- ------- ------- TOTAL EXPENSES 11,668 10,082 9,560 ------- ------- ------- OPERATING INCOME 2,026 2,325 2,280 OTHER INCOME (net) 33 139 95 ------- ------- -------- INCOME BEFORE INTEREST, PREFERRED DIVIDENDS AND INCOME TAXES 2,059 2,464 2,375 INTEREST AND PREFERRED DIVIDENDS 1,160 996 898 ------- ------- ------- INCOME BEFORE INCOME TAXES 899 1,468 1,477 INCOME TAXES 597 482 502 ------- ------- ------- INCOME BEFORE EXTRAORDINARY ITEM 302 986 975 EXTRAORDINARY LOSSES: DISCONTINUANCE OF REGULATORY ACCOUNTING FOR GENERATION (35) (8) - LOSS ON REACQUIRED DEBT - (6) - ------- ------- -------- NET INCOME $ 267 $ 972 $ 975 ======= ======= ======= AVERAGE NUMBER OF SHARES OUTSTANDING 322 321 318 === === === EARNINGS PER SHARE: Income Before Extraordinary Item $ 0.94 $3.07 $3.06 Extraordinary Losses (0.11) (.04) - ------ ----- ------ Net Income $ 0.83 $3.03 $3.06 ====== ===== ===== 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, 2000 1999 ---- ---- ASSETS CURRENT ASSETS: Cash and Cash Equivalents $ 437 $ 609 Special Deposits - 50 Accounts Receivable: Customers 827 553 Miscellaneous 2,883 1,486 Allowance for Uncollectible Accounts (11) (12) Energy Trading Contracts 16,627 1,001 Other 1,268 1,311 ------- ------- TOTAL CURRENT ASSETS 22,031 4,998 ------- ------- PROPERTY PLANT AND EQUIPMENT: Electric: Production 16,328 15,869 Transmission 5,609 5,495 Distribution 10,843 10,432 Other (including gas and coal mining assets and nuclear fuel) 4,077 4,081 Construction Work in Progress 1,231 1,061 ------- ------- Total Property, Plant and Equipment 38,088 36,938 Accumulated Depreciation and Amortization 15,695 15,073 ------- ------- NET PROPERTY, PLANT AND EQUIPMENT 22,393 21,865 ------- ------- REGULATORY ASSETS 3,698 3,464 ------- ------- INVESTMENTS IN POWER AND COMMUNICATIONS PROJECTS 782 862 ------- ------- GOODWILL (NET OF AMORTIZATION) 1,382 1,531 ------- ------- LONG-TERM ENERGY TRADING CONTRACTS 1,620 136 ------- ------- OTHER ASSETS 2,642 2,863 ------- ------- TOTAL $54,548 $35,719 ======= ======= See Notes to Consolidated Financial Statements beginning on page L-1.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Consolidated Balance Sheets - ------------------------------------------------------------------------------------ December 31, 2000 1999 ---- ---- LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES: Accounts Payable $ 2,627 $ 1,280 Short-term Debt 4,333 3,012 Long-term Debt Due Within One Year* 1,152 1,367 Energy Trading Contracts 16,801 964 Other 2,154 1,443 ------- ------- TOTAL CURRENT LIABILITIES 27,067 8,066 ------- ------- LONG-TERM DEBT* 9,602 10,157 ------- ------- CERTAIN SUBSIDIARY OBLIGATED, MANDATORILY REDEEMABLE, PREFERRED SECURITIES OF SUBSIDIARY TRUSTS HOLDING SOLELY JUNIOR SUBORDINATED DEBENTURES OF SUCH SUBSIDIARIES 334 335 ------- ------- DEFERRED INCOME TAXES 4,875 5,150 ------- ------- DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2 203 213 ------- ------- DEFERRED INVESTMENT TAX CREDITS 528 580 ------- ------- LONG-TERM ENERGY TRADING CONTRACTS 1,381 108 ------- ------- DEFERRED CREDITS AND REGULATORY LIABILITIES 637 607 ------- ------- OTHER NONCURRENT LIABILITIES 1,706 1,648 ------- ------- CUMULATIVE PREFERRED STOCK OF SUBSIDIARIES* 161 182 ------- ------- COMMITMENTS AND CONTINGENCIES (Note 8) COMMON SHAREHOLDERS' EQUITY: Common Stock-Par Value $6.50: 2000 1999 ---- ---- Shares Authorized. .600,000,000 600,000,000 Shares Issued. . . .331,019,146 330,692,317 (8,999,992 shares were held in treasury at December 31, 2000 and 1999) 2,152 2,149 Paid-in Capital 2,915 2,898 Accumulated Other Comprehensive Income (Loss) (103) (4) Retained Earnings 3,090 3,630 ------- ------- TOTAL COMMON SHAREHOLDERS' EQUITY 8,054 8,673 ------- ------- TOTAL $54,548 $35,719 ======= ======= *See Accompanying Schedules.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Consolidated Statements of Cash Flows - -------------------------------------------------------------------------------------------------------------------------------- (in millions) Year Ended December 31, 2000 1999 1998 ---- ---- ---- OPERATING ACTIVITIES: Net Income $ 267 $ 972 $ 975 Adjustments for Noncash Items: Depreciation and Amortization 1,299 1,294 1,171 Deferred Federal Income Taxes (170) 180 (2) Deferred Investment Tax Credits (36) (38) (37) Amortization (Deferral) of Operating Expenses and Carrying Charges (net) 48 (151) 15 Equity in Earnings of Yorkshire Electricity Group plc (44) (45) (38) Extraordinary Item 35 14 - Deferred Costs Under Fuel Clause Mechanisms (449) (191) 36 Changes in Certain Current Assets and Liabilities: Accounts Receivable (net) (1,632) (80) (329) Fuel, Materials and Supplies 147 (162) (23) Accrued Utility Revenues (79) (35) 5 Accounts Payable 1,322 74 270 Taxes Accrued 172 29 20 Payment of Disputed Tax and Interest Related to COLI 319 (16) (303) Other (net) 304 (231) 195 ------- ------- ------- Net Cash Flows From Operating Activities 1,503 1,614 1,955 ------- ------- ------- INVESTING ACTIVITIES: Construction Expenditures (1,773) (1,680) (1,396) Investment in CitiPower - - (1,054) Investment in Gas Assets - - (340) Other 19 7 (54) ------- ------- ------- Net Cash Flows Used For Investing Activities (1,754) (1,673) (2,844) ------- ------- ------- FINANCING ACTIVITIES: Issuance of Common Stock 14 93 96 Issuance of Long-term Debt 1,124 1,391 2,645 Retirement of Cumulative Preferred Stock (20) (170) (28) Retirement of Long-term Debt (1,565) (915) (1,101) Change in Short-term Debt (net) 1,308 812 264 Dividends Paid on Common Stock (805) (833) (827) Other Financing Activities - (43) - ------- ------- ------- Net Cash Flows From Financing Activities 56 335 1,049 ------- ------- ------- Effect of Exchange Rate Change on Cash 23 (2) - ------- ------- ------- Net Increase (Decrease) in Cash and Cash Equivalents (172) 274 160 Cash and Cash Equivalents January 1 609 335 175 ------- ------- ------- Cash and Cash Equivalents December 31 $ 437 $ 609 $ 335 ======= ======= ======= 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 - ------------------------------------------------------------------------------------------------------------ (in millions) Accumulated Other Common Stock Paid-In Retained Comprehensive Shares Amount Capital Earnings Income (Loss) Total JANUARY 1, 1998 326 $2,036 $2,818 $3,356 $ 23 $8,233 Conforming Change in Accounting Policy - - - (13) - (13) Reclassification Adjustment - 85 (85) - - - --- ------ ------ ------ ----- ------ Adjusted Balance at Beginning of Period 326 2,121 2,733 3,343 23 8,220 Issuances 2 13 83 - - 96 Retirements and Other - - 2 3 - 5 Cash Dividends Declared - - - (827) - (827) ------ 7,494 Comprehensive Income: Other Comprehensive Income, Net of Taxes Foreign Currency Translation Adjustment - - - - 6 6 Unrealized Loss on Securities - - - - (14) (14) Adjustments for Gain Included in Net Income - - - - (7) (7) Minimum Pension Liability - - - - (1) (1) Net Income - - - 975 - 975 ------ Total Comprehensive Income 959 --- ------ ------ ------- ----- ------ DECEMBER 31, 1998 328 2,134 2,818 3,494 7 8,453 Conforming Change in Accounting Policy - - - (1) - (1) --- ------ ------ ------- ----- ------ Adjusted Balance at Beginning of Period 328 2,134 2,818 3,493 7 8,452 Issuances 3 15 77 - - 92 Retirements and Other - - 3 - - 3 Cash Dividends Declared - - - (833) - (833) ------ 7,714 Comprehensive Income: Other Comprehensive Income, Net of Taxes Foreign Currency Translation Adjustment - - - - (13) (13) Minimum Pension Liability - - - - 2 2 Net Income - - - 972 - 972 ------ Total Comprehensive Income 961 --- ------ ------ ------- ----- ------- DECEMBER 31, 1999 331 2,149 2,898 3,632 (4) 8,675 Conforming Change in Accounting Policy - - - (2) - (2) --- ----- ----- ----- ----- ------ Adjusted Balance at Beginning of Period 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 === ====== ====== ====== ===== ====== 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, 2000 ----------------------------------------------------------------- Call Price per Shares Shares Amount (In Share (a) Authorized(b) Outstanding(g) 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) (e) 1,650,000 513,450 52 7% (f) (f) 250,000 150,000 15 ---- Total Subject to Mandatory Redemption (c) $100 ==== December 31, 1999 ----------------------------------------------------------------- Call Price per Shares Shares Amount (In Share (a) Authorized(b) Outstanding(g) Millions) - -------------------------------------------------------------------------------------------------------- Not Subject to Mandatory Redemption: 4.00% - 5.00% $102-$110 1,525,903 629,671 $ 63 ==== Subject to Mandatory Redemption: 5.90% - 5.92% (c) (d) 1,950,000 343,100 $ 34 6.02% - 6-7/8% (c) (e) 1,950,000 597,950 60 7% (f) (f) 250,000 250,000 25 ---- Total Subject to Mandatory Redemption (c) $119 ==== NOTES TO SCHEDULE OF CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES (a) At the option of the subsidiary the shares may be redeemed at the call price plus accrued dividends. The involuntary liquidation preference is $100 per share for all outstanding shares. (b) As of December 31, 2000 the subsidiaries had 13,592,750, 22,200,000 and 7,713,495 shares of $100, $25 and no par value preferred stock, respectively, that were authorized but unissued. (c) Shares outstanding and related amounts are stated net of applicable retirements through sinking funds(generally at par) and reacquisitions of shares in anticipation of future requirements. The subsidiaries reacquired enough shares in 1997 to meet all sinking fund requirements on certain series until 2008 and on certain series until 2009 when all remaining outstanding shares must be redeemed. The sinking fund provisions of the series subject to mandatory redemption aggregate (after deducting sinking fund requirements) of $5 million in 2002, $12 million in 2003, $12 million in 2004 and $2 million in 2005. (d) Not callable prior to 2003; after that the call price is $100 per share. (e) Not callable prior to 2000; after that the call price is $100 per share. (f) With sinking fund. (g) The number of shares of preferred stock redeemed is 209,563 shares in 2000, 1,698,276 shares in 1999 and 281,250 shares in 1998.
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, 2000 2000 1999 2000 1999 ----------------- ---- ---- ---- ---- (in millions) ------------- FIRST MORTGAGE BONDS 2000-2003 6.96% 5.91%-8.95% 5.25%-8.95% $ 1,247 $ 1,621 2004-2008 6.97% 6-1/8%-8% 6-1/8%-8% 1,140 1,148 2020-2025 7.74% 6-7/8%-8.80% 6-7/8%-8.80% 1,104 1,172 INSTALLMENT PURCHASE CONTRACTS (a) 2000-2009 5.53% 4.90%-7.70% 4.80%-7.70% 234 235 2011-2030 6.02% 4.875%-8.20% 3.332%-8.20% 1,447 1,477 NOTES PAYABLE (b) 2000-2021 7.14% 6.20%-9.60% 5.8675%-9.60% 1,181 2,030 SENIOR UNSECURED NOTES 2000-2004 6.99% 6.50%-7.45% 6.07%-7.45% 2,049 1,403 2005-2009 6.59% 6.24%-6.91% 6.24%-6.91% 475 488 2038 7.30% 7.20%-7-3/8% 7.20%-7-3/8% 340 340 JUNIOR DEBENTURES 2025-2038 8.05% 7.60%-8.72% 7.60%-8.72% 620 620 YANKEE BONDS AND EURO BONDS 2001-2006 8.51% 7.98%-8.875% 7.98%-8.875% 684 742 OTHER LONG-TERM DEBT (c) 280 300 Unamortized Discount (net) (47) (52) ------- ------- Total Long-term Debt Outstanding (d) 10,754 11,524 Less Portion Due Within One Year 1,152 1,367 ------- ------- Long-term Portion $ 9,602 $10,157 ======= ======= NOTES TO SCHEDULE OF CONSOLIDATED LONG-TERM DEBT OF SUBSIDIARIES (a) For certain series of installment purchase contracts interest rates are subject to periodic adjustment. Certain series will be purchased on demand at periodic interest-adjustment dates. Letters of credit from banks and standby bond purchase agreements support certain series. (b) Notes payable represent outstanding promissory notes issued under term loan agreements 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. (c) Other long-term debt consists of a liability along with accrued interest for disposal of spent nuclear fuel (see Note 8 of the Notes to Consolidated Financial Statements) and financing obligation under sale lease back agreements. (d) Long-term debt outstanding at December 31, 2000 is payable as follows: Principal Amount (in millions) 2001 $ 1,152 2002 1,167 2003 1,628 2004 884 2005 616 Later Years 5,354 ------- Total Principal Amount 10,801 Unamortized Discount (47) ------- Total $10,754 =======
AMERICAN ELECTRIC POWER COMPANY INC. AND SUBSIDIARY COMPANIES Index to Notes to Consolidated Financial Statements - ----------------------------------------------------------------------------- The notes listed below are combined with the notes to financial statements for AEP and its other subsidiary registrants. The combined footnotes begin on page L-1. Combined Footnote Reference Significant Accounting Policies Note 1 Extraordinary Items Note 2 Merger Note 3 Nuclear Plant Restart Note 4 Rate Matters Note 5 Effects of Regulation Note 6 Industry Restructuring Note 7 Commitments and Contingencies Note 8 Acquisitions Note 9 International Investments Note 10 Staff Reductions Note 11 Benefit Plans Note 12 Stock-Based Compensation Note 13 Business Segments Note 14 Financial Instruments, Credit and Risk Management Note 15 Income Taxes Note 16 Supplementary Information Note 17 Leases Note 18 Lines of Credit and Factoring of Receivables Note 19 Unaudited Quarterly Financial Information Note 20 Trust Preferred Securities Note 21 MANAGEMENT'S RESPONSIBILITY - ------------------------------------------------------------------ The management of American Electric Power Company, Inc. is responsible for the integrity and objectivity of the information and representations in this annual report, including the consolidated financial statements. These statements have been prepared in conformity with generally accepted accounting principles, using informed estimates where appropriate, to reflect the Company's financial condition and results of operations. The information in other sections of the annual report is consistent with these statements. The Company's Board of Directors has oversight responsibilities for determining that management has fulfilled its obligation in the preparation of the financial statements and in the ongoing examination of the Company's established internal control structure over financial reporting. The Audit Committee, which consists solely of outside directors and which reports directly to the Board of Directors, meets regularly with management, Deloitte & Touche LLP - independent auditors and the Company's internal audit staff to discuss accounting, auditing and reporting matters. To ensure auditor independence, both Deloitte & Touche LLP and the internal audit staff have unrestricted access to the Audit Committee. The financial statements have been audited by Deloitte & Touche LLP, whose report appears on the next page. The auditors provide an objective, independent review as to management's discharge of its responsibilities insofar as they relate to the fairness of the Company's reported financial condition and results of operations. Their audit includes procedures believed by them to provide reasonable assurance that the financial statements are free of material misstatement and includes an evaluation of the Company's internal control structure over financial reporting. INDEPENDENT AUDITORS' REPORT - ------------------------------------------------------------------------------ To the Shareholders and Board of Directors of American Electric Power Company, Inc.: We have audited the consolidated balance sheets of American Electric Power Company, Inc. and its subsidiaries as of December 31, 2000 and 1999, and the related consolidated statements of income, comprehensive income, common shareholders' equity, and cash flows for each of the three years in the period ended December 31, 2000. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements based on our audits. The consolidated financial statements give retroactive effect to the merger of American Electric Power Company, Inc. and its subsidiaries and Central and South West Corporation and its subsidiaries, which has been accounted for as a pooling of interests as described in Note 3 to the consolidated financial statements. We did not audit the consolidated balance sheet of Central and South West Corporation and its subsidiaries as of December 31, 1999, or the related consolidated statements of income, comprehensive income, common shareholders' equity, and cash flows for the years ended December 31, 1999 and 1998, which statements reflect total assets of $14,162,000,000 as of December 31, 1999, and total revenues of $5,537,000,000 and $5,482,000,000 for the years ended December 31, 1999 and 1998, respectively. Those consolidated statements, before the restatement described in Note 3, were audited by other auditors whose report, dated February 25, 2000, has been furnished to us, and our opinion, insofar as it relates to those amounts included for Central and South West Corporation and its subsidiaries for 1999 and 1998, is based solely on the report of such other auditors. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits and the report of the other auditors provide a reasonable basis for our opinion. In our opinion, based on our audits and the report of the other auditors, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of American Electric Power Company, Inc. and its subsidiaries as of December 31, 2000 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2000 in conformity with accounting principles generally accepted in the United States of America. We also audited the adjustments described in Note 3 that were applied to restate the 1999 and 1998 financial statements to give retroactive effect to the change in the method of accounting for vacation pay accruals. In our opinion, such adjustments are appropriate and have been properly applied. Deloitte & Touche LLP Columbus, Ohio February 26, 2001 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Stockholders and Board of Directors of Central and South West Corporation: We have audited the consolidated balance sheets of Central and South West Corporation (a Delaware corporation) and subsidiary companies as of December 31, 1999, and the related consolidated statements of income, stockholders' equity and cash flows, for each of the two years in the period ended December 31, 1999 prior to the restatement (and, therefore, are not presented herein) for the retroactive effect of the conforming change in the method of accounting for vacation pay accruals and certain conforming reclassifications to the historical financial statements as described in Note 3 to the restated consolidated financial statements. These financial statements are the responsibility of the Corporation's management. Our responsibility is to express an opinion on these financial statements based on our audits. We did not audit the financial statements of CSW UK Holdings (1999) and CSW UK Finance Company (1998) which statements reflect total assets and total revenues of 20 percent and 31 percent in 1999, and total revenues of 32 percent in 1998, respectively, of the related consolidated totals. Those statements were audited by other auditors whose reports have been furnished to us, and our opinion, insofar as it relates to the amounts included for those entities, is based solely on the reports of the other auditors. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits and the reports of other auditors provide a reasonable basis for our opinion. In our opinion, based on our audits and the reports of other auditors, the financial statements prior to the restatement referred to above present fairly, in all material respects, the financial position of Central and South West Corporation and subsidiary companies as of December 31, 1999, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 1999, in conformity with accounting principles generally accepted in the United States. Arthur Andersen LLP Dallas, Texas February 25, 2000 AUDITOR's REPORT TO THE MEMBERS OF CSW UK HOLDINGS We have audited the consolidated balance sheets of CSW UK Holdings and subsidiaries as of 31 December 1999 and the related consolidated statement of earnings and statement of cash flows for the years then ended. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit. We conducted our audit in accordance with generally accepted auditing standards in the United States. 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, or 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 audit provides a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above and not included herein present fairly, in all material respects, the financial position of CSW UK Holdings and subsidiaries at 31 December 1999 and the result of their operations and cash flows for the year then ended in conformity with generally accepted accounting principles in the United Kingdom. Generally accepted accounting principles in the United Kingdom vary in certain significant respects from generally accepted accounting principles in the United States. Application of generally accepted accounting principles in the United States would have affected results of operations and shareholders' equity as of and for the year ended 31 December 1999 to the extent summarized in the notes to the consolidated financial statements. KPMG Audit Plc Chartered Accountants London, England 17 January 2000 AUDITOR'S REPORT TO THE MEMBERS OF CSW UK FINANCE COMPANY We have audited the consolidated balance sheet of CSW UK Finance Company and subsidiaries as of 31 December 1998 and the related consolidated statement of earnings and statements of cash flows for the year then ended. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit. We conducted our audit in accordance with generally accepted auditing standards in the United States. 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 audit provides a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above and not included herein present fairly, in all material respects, the financial position of CSW UK Finance Company and subsidiaries at 31 December 1998 and the results of their operations and cash flows for the year then ended in conformity with generally accepted accounting principles in the United Kingdom. Generally accepted accounting principles in the United Kingdom vary in certain significant respects from generally accepted accounting principles in the United States. Application of generally accepted accounting principles in the United States would have affected results of operations and shareholders' equity as of and for the year ended 31 December 1998 to the extent summarized in the notes to the consolidated financial statements. KPMG Audit Plc Chartered Accountants London, England 18 January 1999 AEP GENERATING COMPANY
B-9 AEP GENERATING COMPANY Selected Financial Data - --------------------------------------------------------------------------------------------------------------- Year Ended December 31, ----------------------------------------------------- 2000 1999 1998 1997 1996 ---- ---- ---- ---- ---- (in thousands) INCOME STATEMENTS DATA: Operating Revenues $228,516 $217,189 $224,146 $227,868 $225,892 Operating Expenses 220,092 211,849 215,415 218,828 215,997 -------- -------- -------- -------- -------- Operating Income 8,424 5,340 8,731 9,040 9,895 Nonoperating Income 3,429 3,659 3,364 3,603 3,695 -------- -------- -------- -------- -------- Income Before Interest Charges 11,853 8,999 12,095 12,643 13,590 Interest Charges 3,869 2,804 3,149 3,857 4,159 -------- -------- -------- -------- -------- Net Income $ 7,984 $ 6,195 $ 8,946 $ 8,786 $ 9,431 ======== ======== ======== ======== ======== December 31, ------------------------------------------------------ 2000 1999 1998 1997 1996 ---- ---- ---- ---- ---- (in thousands) BALANCE SHEETS DATA: Electric Utility Plant $642,302 $640,093 $636,460 $633,450 $632,257 Accumulated Depreciation 315,566 295,065 277,855 257,191 238,532 -------- -------- -------- -------- -------- Net Electric Utility Plant $326,736 $345,028 $358,605 $376,259 $393,725 ======== ======== ======== ======== ======== Total Assets $374,602 $398,640 $403,892 $419,058 $442,911 ======== ======== ======== ======== ======== Common Stock and Paid-in Capital $ 24,434 $ 30,235 $ 36,235 $ 40,235 $ 45,235 Retained Earnings 9,722 3,673 2,770 2,528 1,886 -------- -------- -------- -------- -------- Total Common Shareholder's Equity $ 34,156 $ 33,908 $ 39,005 $ 42,763 $ 47,121 ======== ======== ======== ======== ======== Long-term Debt (a) $ 44,808 $ 44,800 $ 44,792 $ 69,570 $ 89,554 ======== ======== ======== ======== ======== Total Capitalization and Liabilities $374,602 $398,640 $403,892 $419,058 $442,911 ======== ======== ======== ======== ======== (a) Including portion due within one year.
AEP GENERATING COMPANY Management's Narrative Analysis of Results of Operations AEP Generating Company is engaged in the generation and wholesale sale of electric power to two affiliates under long-term agreements. Operating revenues are derived from the sale of Rockport Plant energy and capacity to two affiliated companies, I&M and KPCo pursuant to FERC approved long-term unit power agreements. Under the terms of its unit power agreement, I&M is required to buy all of AEGCo's Rockport capacity when the unit power agreement with KPCo expires in 2004. The unit power agreements provide for recovery of costs including a FERC approved rate of return on common equity and a return on other capital net of temporary cash investments. Net income increased $1.8 million or 29% as a result of the recordation of income tax accrual adjustments and an increase in return on other capital. Comparative net income was increased by the income tax accrual adjustments since an unfavorable income tax accrual adjustment was recorded in 1999 and income tax accrual adjustments are not included in billings under the terms of the unit power agreements. Return on other capital increased as a result of higher interest charges without an offset for earnings on temporary cash investments in 2000. Income statement items which changed significantly were: Increase (Decrease) (dollars in millions) From Previous Year Amount % Operating Revenues. . . . . $11.3 5 Fuel Expense. . . . . . . . 8.5 9 Maintenance Expense . . . . (0.9) (8) Taxes Other Than Federal Income Taxes . . . . . . . 0.5 10 Interest Charges. . . . . . 1.1 38 The increase in operating revenues reflects recovery under the unit power agreements of higher fuel expense and an increase in the return on other capital. Fuel expense increased due to an increase in generation reflecting greater availability of the Rockport Plant generating units in 2000 and an increase in the cost of fuel. The decrease in maintenance expense can be attributed to cost containment efforts and the shorter duration in 2000 of maintenance outages for boiler inspection and repair than in 1999. Taxes other than federal income taxes increased due to an increase in state income taxes which resulted from an increase in taxable income in 2000 and adjustments to estimated prior year taxes following the filing of the 1999 and 1998 returns. The increase in interest charges was primarily due to an increase in interest rates in 2000. AEGCo's long-term debt interest rates are variable on a daily basis which results in interest charges adjusting quickly to market rate changes.
AEP GENERATING COMPANY Statements of Income - ------------------------------------------------------------------------------------------ Year Ended December 31, ----------------------------------- 2000 1999 1998 ---- ---- ---- (in thousands) OPERATING REVENUES $228,516 $217,189 $224,146 -------- -------- -------- OPERATING EXPENSES: Fuel 102,978 94,481 96,791 Rent - Rockport Plant Unit 2 68,283 68,283 68,283 Other Operation 10,295 10,451 10,001 Maintenance 9,616 10,492 11,894 Depreciation 22,162 21,845 21,652 Taxes Other Than Federal Income Taxes 5,060 4,585 3,495 Federal Income Taxes 1,698 1,712 3,299 -------- -------- -------- TOTAL OPERATING EXPENSES 220,092 211,849 215,415 -------- -------- -------- OPERATING INCOME 8,424 5,340 8,731 NONOPERATING INCOME 3,429 3,659 3,364 -------- -------- -------- INCOME BEFORE INTEREST CHARGES 11,853 8,999 12,095 INTEREST CHARGES 3,869 2,804 3,149 -------- -------- -------- NET INCOME $ 7,984 $ 6,195 $ 8,946 ======== ======== ======== Statements of Retained Earnings - -------------------------------------------------------------------------------------------------------------------- Year Ended December 31, ----------------------------------- 2000 1999 1998 ---- ---- ---- (in thousands) RETAINED EARNINGS JANUARY 1 $3,673 $2,770 $2,528 NET INCOME 7,984 6,195 8,946 CASH DIVIDENDS DECLARED 1,935 5,292 8,704 ------ ------ ------ RETAINED EARNINGS DECEMBER 31 $9,722 $3,673 $2,770 ====== ====== ====== See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY Balance Sheets - ----------------------------------------------------------------------------------------- December 31, 2000 1999 ---- ---- (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production $635,215 $629,286 General 2,795 2,400 Construction Work in Progress 4,292 8,407 -------- -------- Total Electric Utility Plant 642,302 640,093 Accumulated Depreciation 315,566 295,065 -------- -------- NET ELECTRIC UTILITY PLANT 326,736 345,028 -------- -------- CURRENT ASSETS: Cash and Cash Equivalents 2,757 317 Accounts Receivable: Affiliated Companies 21,374 22,464 Miscellaneous 2,341 2,643 Fuel - at average cost 11,006 17,505 Materials and Supplies - at average cost 3,979 3,966 Prepayments 145 150 -------- -------- TOTAL CURRENT ASSETS 41,602 47,045 -------- -------- REGULATORY ASSETS 5,504 5,744 -------- -------- DEFERRED CHARGES 760 823 -------- -------- TOTAL $374,602 $398,640 ======== ======== See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY - ---------------------------------------------------------------------------------------------------------------------------------- December 31, 2000 1999 ---- ---- (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 29,235 Retained Earnings 9,722 3,673 -------- -------- TOTAL CAPITALIZATION AND COMMON SHAREHOLDER'S EQUITY 34,156 33,908 -------- -------- OTHER NONCURRENT LIABILITIES 358 592 -------- -------- CURRENT LIABILITIES: Long-term Debt Due Within One Year 44,808 44,800 Short-term Debt - Notes Payable - 24,700 Advances from Affiliates 28,068 - Accounts Payable: General 6,109 7,539 Affiliated Companies 7,724 19,451 Taxes Accrued 4,993 4,285 Rent Accrued - Rockport Plant Unit 2 4,963 4,963 Other 4,443 4,763 -------- -------- TOTAL CURRENT LIABILITIES 101,108 110,501 -------- -------- DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2 122,188 127,759 -------- -------- REGULATORY LIABILITIES: Deferred Investment Tax Credits 59,718 63,114 Amounts Due to Customers for Income Taxes 23,996 26,266 -------- -------- TOTAL REGULATORY LIABILITIES 83,714 89,380 -------- -------- DEFERRED INCOME TAXES 32,928 36,500 -------- -------- DEFERRED CREDITS 150 - -------- --------- CONTINGENCIES (Note 8) TOTAL $374,602 $398,640 ======== ======== See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY Statements of Cash Flows - ------------------------------------------------------------------------------------------ Year Ended December 31, ----------------------------------- 2000 1999 1998 ---- ---- ---- (in thousands) OPERATING ACTIVITIES: Net Income $ 7,984 $ 6,195 $ 8,946 Adjustments for Noncash Items: Depreciation 22,162 21,845 21,652 Deferred Federal Income Taxes (5,842) (5,282) 5,544 Deferred Investment Tax Credits (3,396) (3,448) (3,454) Amortization of Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2 (5,571) (5,571) (5,571) Changes in Certain Current Assets and Liabilities: Accounts Receivable 1,392 (2,213) (2,184) Fuel, Materials and Supplies 6,486 (6,263) (855) Accounts Payable (13,157) 14,394 2,892 Taxes Accrued 708 1,058 (193) Other (net) 1,232 (1,570) 2,542 -------- -------- -------- Net Cash Flows From Operating Activities 11,998 19,145 29,319 -------- -------- -------- INVESTING ACTIVITIES: Construction Expenditures (5,190) (8,349) (6,574) Proceeds From Sales of Property - 331 2,254 -------- -------- --------- Net Cash Flows Used For Investing Activities (5,190) (8,018) (4,320) -------- -------- -------- FINANCING ACTIVITIES: Return of Capital to Parent Company (5,801) (6,000) (4,000) Retirement of Long-term Debt - - (25,000) Change in Short-term Debt (net) (24,700) 250 12,700 Change in Advances From Affiliates (net) 28,068 - - Dividends Paid (1,935) (5,292) (8,704) -------- -------- -------- Net Cash Flows Used For Financing Activities (4,368) (11,042) (25,004) -------- -------- -------- Net Increase (Decrease) in Cash and Cash Equivalents 2,440 85 (5) Cash and Cash Equivalents January 1 317 232 237 -------- -------- -------- Cash and Cash Equivalents December 31 $ 2,757 $ 317 $ 232 ======== ======== ========= Supplemental Disclosure: Cash paid (received) for interest net of capitalized amounts was $3,531,000, $2,468,000 and $3,060,000 and for income taxes was $6,820,000, $6,565,000 and $(2,131,000) in 2000, 1999 and 1998, respectively. See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY Statements of Capitalization - --------------------------------------------------------------------------------------------- December 31, -------------------------- 2000 1999 ---- ---- (in thousands) COMMON STOCK EQUITY (a) $ 34,156 $ 33,908 -------- -------- 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 (192) (200) Amount Due Within One Year (44,808) (44,800) -------- -------- - - -------- -------- TOTAL CAPITALIZATION $ 34,156 $ 33,908 ======== ======== (a) In 2000, 1999 and 1998, AEGCo returned capital to AEP in the amounts of $5.8 million, $6 million and $4 million, respectively. There were no other material transactions affecting common stock and paid-in capital in 2000, 1999 and 1998. (b) Installment purchase contracts were entered into in connection with the issuance of pollution control revenue bonds by the City of Rockport, Indiana. Under the terms of the installment purchase contracts, AEGCo is required 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. On the Series 1995 A and B bonds the principal is payable at maturity or on the demand of bondholders. AEGCo has agreements that provide for brokers to remarket bonds tendered. In the event the bonds cannot be remarketed, AEGCo has a standby bond purchase agreement with a bank that provides for the bank to purchase any bonds not remarketed. The purchase agreement expires in 2001. Therefore, the installment purchase contracts have been reclassified as due within one year. (c) These series have an adjustable interest rate that can be a daily, weekly, commercial paper or term rate as designated by AEGCo. AEGCo selected a daily rate which ranged from 1.65% to 6.1% during 2000 and 1.4% to 5.2% during 1999 and averaged 4.1% in 2000 and 3.2% in 1999. The interest rates were 5% and 4.9% at December 31, 2000 and 4.95% and 4.8% at December 31, 1999 for Series A and Series B, respectively. See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY Index to Notes to 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 Effects of Regulation Note 6 Commitments and Contingencies Note 8 Business Segments Note 14 Financial Instruments, Credit and Risk Management Note 15 Income Taxes Note 16 Leases Note 18 Lines of Credit and Factoring of Receivables Note 19 Unaudited Quarterly Financial Information Note 20 Related Party Transactions Note 23 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, 2000 and 1999, and the related statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2000. 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, 2000 and 1999, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2000 in conformity with accounting principles generally accepted in the United States of America. Deloitte & Touche LLP Columbus, Ohio February 26, 2001 APPALACHIAN POWER COMPANY AND SUBSIDIARIES
C-13 APPALACHIAN POWER COMPANY AND SUBSIDIARIES Selected Consolidated Financial Data Year Ended December 31, ----------------------------------------------------------- 2000 1999 1998 1997 1996 ---- ---- ---- ---- ---- (in thousands) INCOME STATEMENTS DATA: Operating Revenues $1,860,165 $1,650,937 $1,672,244 $1,628,515 $1,624,869 Operating Expenses 1,659,011 1,409,701 1,443,701 1,388,521 1,381,993 ---------- ---------- ---------- ---------- ---------- Operating Income 201,154 241,236 228,543 239,994 242,876 Nonoperating Income (Loss) 11,752 8,096 (8,301) (222) 128 ---------- ---------- ---------- ---------- ---------- Income Before Interest Charges 212,906 249,332 220,242 239,772 243,004 Interest Charges 148,000 128,840 126,912 119,258 109,315 ---------- ---------- ---------- ---------- ---------- Income Before Extraordinary Item 64,906 120,492 93,330 120,514 133,689 Extraordinary Gain 8,938 - - - - ---------- ---------- ---------- ---------- ---------- Net Income 73,844 120,492 93,330 120,514 133,689 Preferred Stock Dividend Requirements 2,504 2,706 2,497 7,006 15,938 ---------- ---------- ---------- ---------- ---------- Earnings Applicable to Common Stock $ 71,340 $ 117,786 $ 90,833 $ 113,508 $ 117,751 ========== ========== ========== ========== ========== Year Ended December 31, ---------------------------------------------------------- 2000 1999 1998 1997 1996 ---- ---- ---- ---- ---- (in thousands) BALANCE SHEETS DATA: Electric Utility Plant $5,418,278 $5,262,951 $5,087,359 $4,901,046 $4,717,132 Accumulated Depreciation and Amortization 2,188,796 2,079,490 1,984,856 1,869,057 1,782,017 ---------- ---------- ---------- ---------- ---------- Net Electric Utility Plant $3,229,482 $3,183,461 $3,102,503 $3,031,989 $2,935,115 ========== ========== ========== ========== ========== Total Assets $6,646,153 $4,354,400 $4,047,038 $3,883,430 $3,800,737 ========== ========== ========== ========== ========== Common Stock and Paid-in Capital $ 975,676 $ 974,717 $ 924,091 $ 873,506 $ 835,838 Retained Earnings 120,584 175,854 179,461 207,544 208,472 ---------- ---------- ---------- ---------- ---------- Total Common Shareholder's Equity $1,096,260 $1,150,571 $1,103,552 $1,081,050 $1,044,310 ========== ========== ========== ========== ========== Cumulative Preferred Stock: Not Subject to Mandatory Redemption $ 17,790 $ 18,491 $ 19,359 $ 19,747 $ 29,815 Subject to Mandatory Redemption 10,860 20,310 22,310 22,310 190,000 ---------- ---------- ---------- ---------- ---------- Total Cumulative Preferred Stock $ 28,650 $ 38,801 $ 41,669 $ 42,057 $ 219,815 ========== ========== ========== ========== ========== Long-term Debt (a) $1,605,818 $1,665,307 $1,552,455 $1,494,535 $1,365,842 ========== ========== ========== ========== ========== Obligations Under Capital Leases (a) $ 63,160 $ 64,645 $ 65,175 $ 60,110 $ 51,969 ========== ========== ========== ========== ========== Total Capitalization and Liabilities $6,646,153 $4,354,400 $4,047,038 $3,883,430 $3,800,737 ========== ========== ========== ========== ========== (a) Including portion due within one year
APPALACHIAN POWER COMPANY AND SUBSIDIARIES Management's Discussion and Analysis of Results of Operations - ------------------------------------------------------------------------------ APCo is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to 909,000 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. APCo also sells wholesale power to municipalities. The cost of the AEP System's generating capacity is allocated among the AEP Power Pool members based on their relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity credits. AEP Power Pool members are also compensated for their out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received or purchased 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 per-centage share of revenues or costs. APCo as a member of the AEP Power Pool shares in the revenues and costs of the AEP Power Pool's wholesale sales to and net forward trades with other utility systems and power marketers. Revenues from forward electricity trades are recorded net of purchases as operating revenues for transactions in AEP's traditional marketing area (up to two trans-mission systems from the AEP service territory) and as nonoperating income for transactions beyond two transmission systems from AEP. The AEP Power Pool also enters into power trading transactions for options, futures and swaps. APCo's share of these transactions is recorded in nonoperating income. 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 a corporate owned life insurance (COLI) program. In 1998 and 1999 APCo paid the disputed taxes and interest attributable to the COLI interest deductions for taxable years 1991-98. The payments were included in Other Property and Investments pending the resolution of this matter. As a result of the Court's decision, net income was reduced by $82 million in 2000. Results of Operations Net Income Income before extraordinary items decreased $55.6 million or 46% in 2000 primarily due to the COLI decision. An extraordinary gain from the discontinuance of SFAS 71 regulatory accounting of $9 million after tax was recorded in June 2000. (See Note 7 of the Notes to Consolidated Financial Statements). Net income increased $27.2 million or 29% in 1999 primarily due to a nonoperating gain in 1999 on the sale of real estate and mining assets by APCo's inactive mining subsidiaries and a decline in operating expenses. Operating Revenues The 13% increase in operating revenues in 2000 resulted from APCo's share of increased wholesale electricity transactions by the AEP Power Pool. Operating revenues decreased 1% in 1999 primarily due to a de-crease in wholesale sales and a decline in net revenues reflecting lower margins on whole-sale trading transactions. The changes in the components of revenues were as follows: Increase (Decrease) From Previous Year (dollars in millions) - --------------------- 2000 1999 --------------------------- Amount % Amount % Retail: Residential $ 15.5 $ 19.4 Commercial 9.2 17.1 Industrial (15.1) (4.4) Other 1.7 0.9 ------ ------ 11.3 1 33.0 3 Wholesale 237.0 88 (80.6) (23) Transmission and Other (39.1)(44) 26.3 42 ------ ------ Total $209.2 13 $(21.3) (1) ====== ====== Retail revenues increased in 1999 primarily due to a 2% increase in retail sales reflecting higher residential and commercial sales. The increase in retail sales was primarily due to colder winter weather and customer growth. The increase in wholesale revenues in 2000 is due to a significant increase in AEP Power Pool transactions. As a result of an affiliated company's major industrial customer's decision not to continue its purchased power agreement, additional power was available to the AEP Power Pool for wholesale sales contributing to the increase in APCo's wholesale revenues. The decline in wholesale revenues in 1999 reflects the termination of a contract with several municipal customers in July 1998 and a decline in margins on regulated power trading transactions. The decline in margins reflects the moderation in 1999 of extreme weather in 1998 and capacity shortages experienced in the summer of 1998. In 2000 transmission and other revenues decreased substantially due to the combined effect of an unfavorable mark-to-market adjustment in 2000 on outstanding forward trading contracts, a favorable adjustment to a provision for revenue refunds recorded in 1999 in connection with the execution of a final rate refund and a favorable adjustment to rental income in 1999 for agreed to retroactive billings to telecommunications companies for pole attachments. Operating Expenses Operating expenses increased 18% in 2000 primarily due to an increase in purchased power expense, other operation expense and federal income taxes offset in part by a decrease in fuel expense. The decrease in operating expenses in 1999 was mainly due to a decline in purchased power expense. Changes in the components of operating expenses are as follows: Increase (Decrease) From Previous Year (dollars in millions) - --------------------- 2000 1999 ----------------------------- Amount % Amount % Fuel $(75.6) (17) $ 7.2 2 Purchased Power 223.8 88 (49.0) (16) Other Operation 33.0 13 (5.1) (2) Maintenance 0.7 1 (11.0) (8) Depreciation and Amortization 14.2 10 5.1 4 Taxes Other Than Federal Income Taxes 8.8 8 1.5 1 Federal Income Taxes 44.4 63 17.3 32 ------ ------ Total $249.3 18 $(34.0) (2) ====== ====== Fuel expense decreased in 2000 due to the combined effect of the discontinuance of deferral accounting for over or under recovery of fuel costs in the West Virginia jurisdiction effective January 1, 2000 under the terms of a rate settlement agreement and a decline in generation due to scheduled plant maintenance. The increase in fuel expense in 1999 was primarily due to increases in generation reflecting greater utilization of internally generated power. The significant increase in purchased power expense in 2000 reflects additional purchases of power from the AEP Power Pool as a result of increased availability of generation. The AEP Power Pool was able to supply more energy to APCo since an affiliate's out of service nuclear unit went on line in June 2000, a major industrial customer discontinued purchasing power from an affiliate in January 2000, and generating unit outage management improved. The reduction in purchased power expense in 1999 was primarily due to reduced capacity charges from the AEP Power Pool as a result of declines in APCo's MLR and decreased purchases from the AEP Power Pool. The decline in purchases from the AEP Power Pool can be attributed to increased internal generation and the termination of a contract with several municipal customers. The increase in other operation expense in 2000 was due to increased marketing and trading costs including increased accruals for incentive compensation and increased use of emission allowances due to stricter air quality standards of Phase II of the 1990 Clean Air Act Amendments which became effective January 1, 2000. Maintenance expense decreased in 1999 primarily as a result of expenditures during 1998 to restore service and make repairs following two severe snowstorms. Depreciation and amortization expense increased in 2000 due to the amortization, beginning in July 2000, of a new transition regulatory asset established in June 2000 for the net generation-related regulatory assets related to the Company's Virginia and West Virginia jurisdictions that were transferred to the distribution portion of the business and are being recovered through regulated rates (see Note 7 for further discussion of the effects of restructuring). Additional investments in distribution plant also contributed to the increase in depreciation and amortization expense. The increase in taxes other than federal income taxes in 2000 is primarily due to an increase in the WV state income taxes due to disallowance of the COLI program interest deductions. Federal income taxes attributable to operations increased in 2000 due to the disallowance of COLI interest deductions. The increase in 1999 is primarily due to an increase in pre-tax operating income and changes in certain book/tax differences accounted for on a flow-through basis for rate-making purposes. Nonoperating Income The increase in nonoperating income in 1999 is primarily due to the effect of non-regulated electricity trading and a gain on the sale of coal lands and mining assets by APCo's inactive coal mining subsidiaries. In 1999 nonoperating income included a gain from APCo's share of the AEP Power Pool's trading transactions outside of the AEP System's traditional marketing area. In November 1999 the subsidiaries sold coal lands and mining assets to an unaffiliated company that had been leasing the assets. Interest Charges Interest charges increased in 2000 due to recognizing previously deferred interest payments to the IRS related to the COLI disallowances and interest on resultant state income tax deficiencies. Extraordinary Gain The extraordinary gain recorded in June 2000 was the result of the discontinuance of SFAS 71 for the generation portion of APCo's business.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Income Year Ended December 31, 2000 1999 1998 ---- ---- ---- (in thousands) OPERATING REVENUES $1,860,165 $1,650,937 $1,672,244 ---------- ---------- ---------- OPERATING EXPENSES: Fuel 369,161 444,711 437,500 Purchased Power 477,910 254,100 303,116 Other Operation 282,610 249,616 254,718 Maintenance 124,493 123,834 134,856 Depreciation and Amortization 163,089 148,874 143,809 Taxes Other Than Federal Income Taxes 126,447 117,641 116,070 Federal Income Taxes 115,301 70,925 53,632 ---------- ---------- ---------- Total Operating Expenses 1,659,011 1,409,701 1,443,701 ---------- ---------- ---------- OPERATING INCOME 201,154 241,236 228,543 NONOPERATING INCOME (LOSS) 11,752 8,096 (8,301) ---------- ---------- ---------- INCOME BEFORE INTEREST CHARGES 212,906 249,332 220,242 INTEREST CHARGES 148,000 128,840 126,912 ---------- ---------- ---------- INCOME BEFORE EXTRAORDINARY ITEM 64,906 120,492 93,330 EXTRAORDINARY GAIN - DISCONTINUANCE OF REGULATORY ACCOUNTING FOR GENERATION (Inclusive of Tax Benefit of $7,872,000) 8,938 - - ---------- ---------- ----------- NET INCOME 73,844 120,492 93,330 PREFERRED STOCK DIVIDEND REQUIREMENTS 2,504 2,706 2,497 ---------- ---------- ---------- EARNINGS APPLICABLE TO COMMON STOCK $ 71,340 $ 117,786 $ 90,833 ========== ========== ========== See Notes to Consolidated Financial Statements Beginning on Page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES Consolidated Balance Sheets - ------------------------------------------------------------------------------------------ December 31, --------------------------- 2000 1999 ---- ---- (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production $2,058,952 $2,014,968 Transmission 1,177,079 1,151,377 Distribution 1,816,925 1,741,685 General 254,371 247,798 Construction Work in Progress 110,951 107,123 ---------- ---------- Total Electric Utility Plant 5,418,278 5,262,951 Accumulated Depreciation and Amortization 2,188,796 2,079,490 ---------- ---------- NET ELECTRIC UTILITY PLANT 3,229,482 3,183,461 ---------- ---------- OTHER PROPERTY AND INVESTMENTS 56,967 126,592 ---------- ---------- LONG-TERM ENERGY TRADING CONTRACTS 322,688 33,954 ---------- ---------- CURRENT ASSETS: Cash and Cash Equivalents 5,847 64,828 Advances to Affiliates 8,387 - Accounts Receivable: Customers 243,298 109,525 Affiliated Companies 63,919 37,827 Miscellaneous 16,179 9,154 Allowance for Uncollectible Accounts (2,588) (2,609) Fuel - at average cost 39,076 58,161 Materials and Supplies - at average cost 57,515 56,917 Accrued Utility Revenues 66,499 53,418 Energy Trading Contracts 2,036,001 143,777 Prepayments 6,307 7,713 ---------- ---------- TOTAL CURRENT ASSETS 2,540,440 538,711 ---------- ---------- REGULATORY ASSETS 447,750 436,894 ---------- ---------- DEFERRED CHARGES 48,826 34,788 ---------- ---------- TOTAL $6,646,153 $4,354,400 ========== ========== See Notes to Consolidated Financial Statements Beginning on Page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES - ------------------------------------------------------------------------------------------------------------- December 31, ----------------------------- 2000 1999 ---- ---- (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock - No Par Value: Authorized - 30,000,000 Shares Outstanding - 13,499,500 Shares $ 260,458 $ 260,458 Paid-in Capital 715,218 714,259 Retained Earnings 120,584 175,854 ---------- ----------- Total Common Shareholder's Equity 1,096,260 1,150,571 Cumulative Preferred Stock: Not Subject to Mandatory Redemption 17,790 18,491 Subject to Mandatory Redemption 10,860 20,310 Long-term Debt 1,430,812 1,539,302 ---------- ---------- TOTAL CAPITALIZATION 2,555,722 2,728,674 ---------- ---------- OTHER NONCURRENT LIABILITIES 105,883 132,130 ---------- ---------- CURRENT LIABILITIES: Long-term Debt Due Within One Year 175,006 126,005 Short-term Debt 191,495 123,480 Accounts Payable - General 153,422 59,150 Accounts Payable - Affiliated Companies 107,556 42,459 Taxes Accrued 63,258 49,038 Customer Deposits 12,612 12,898 Interest Accrued 21,555 19,079 Energy Trading Contracts 2,091,804 140,279 Other 85,378 71,044 ---------- ---------- TOTAL CURRENT LIABILITIES 2,902,086 643,432 ---------- ---------- DEFERRED INCOME TAXES 682,474 671,917 ---------- ---------- DEFERRED INVESTMENT TAX CREDITS 43,093 57,259 ---------- ---------- LONG-TERM ENERGY TRADING CONTRACTS 259,438 26,256 ---------- ---------- REGULATORY LIABILITIES AND DEFERRED CREDITS 97,457 94,732 ---------- ---------- COMMITMENTS AND CONTINGENCIES (Note 8) TOTAL $6,646,153 $4,354,400 ========== ========== See Notes to Consolidated Financial Statements Beginning on Page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Cash Flows Year Ended December 31, -------------------------------------- 2000 1999 1998 ---- ---- ---- (in thousands) OPERATING ACTIVITIES: Net Income $ 73,844 $ 120,492 $ 93,330 Adjustments for Noncash Items: Depreciation and Amortization 163,202 149,791 144,967 Deferred Federal Income Taxes 8,602 13,033 (2,338) Deferred Investment Tax Credits (4,915) (4,972) (5,265) Deferred Power Supply Costs (net) (84,408) 35,955 30,081 Provision for Rate Refunds (4,818) 4,818 (31,019) Extraordinary Gain - Discontinuance of SFAS 71 (8,938) - - Changes in Certain Current Assets and Liabilities: Accounts Receivable (net) (166,911) 10,989 (1,562) Fuel, Materials and Supplies 18,487 (4,812) (5,006) Accrued Utility Revenues (13,081) (7,433) 5,223 Accounts Payable 159,369 (9,273) 14,066 Taxes Accrued 14,220 13,319 (5,830) Revenue Refunds Accrued 181 (95,267) 91,956 Incentive Plan Accrued 10,662 1,507 (3,429) Disputed Tax and Interest Related to COLI 72,440 (4,124) (68,316) Change in Operating Reserves (19,770) 7,451 10,052 Net Change in Energy Trading Contracts 3,749 (14,531) 3,529 Rate Stabilization Deferral 75,601 - - Other (net) (9,647) (24,681) 13,011 ---------- --------- --------- Net Cash Flows From Operating Activities 287,869 192,262 283,450 ---------- --------- --------- INVESTING ACTIVITIES: Construction Expenditures (199,285) (211,416) (204,869) Proceeds from Sales of Property and Other 159 19,296 2,930 Net Cost of Removal and Other (7,500) (24,373) (9,286) ---------- --------- --------- Net Cash Flows Used For Investing Activities (206,626) (216,493) (211,225) ---------- --------- --------- FINANCING ACTIVITIES: Capital Contributions from Parent Company - 50,000 50,000 Issuance of Long-term Debt 74,788 227,236 211,944 Retirement of Cumulative Preferred Stock (9,924) (2,675) (294) Retirement of Long-term Debt (136,166) (116,688) (157,973) Change in Short-term Debt (net) 68,015 47,080 (53,900) Change in Advances to Affiliates (8,387) - - Dividends Paid on Common Stock (126,612) (121,392) (118,916) Dividends Paid on Cumulative Preferred Stock (1,938) (2,257) (2,278) ---------- --------- --------- Net Cash Flows From (Used For) Financing Activities (140,224) 81,304 (71,417) ---------- --------- --------- Net Increase (Decrease) in Cash and Cash Equivalents (58,981) 57,073 808 Cash and Cash Equivalents January 1 64,828 7,755 6,947 ---------- --------- --------- Cash and Cash Equivalents December 31 $ 5,847 $ 64,828 $ 7,755 ========== ========= ========= Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $124,579,000, $125,900,000 and $124,027,000 and for income taxes was $63,682,000, $55,157,000 and $65,102,000 in 2000, 1999 and 1998, respectively. Noncash acquisitions under capital leases were $14,116,000, $13,868,000 and $21,146,000 in 2000, 1999 and 1998, respectively. See Notes to Consolidated Financial Statements Beginning on Page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Retained Earnings Year Ended December 31, ----------------------------------- 2000 1999 1998 ---- ---- ---- (in thousands) Retained Earnings January 1 $175,854 $179,461 $207,544 Net Income 73,844 120,492 93,330 -------- -------- -------- 249,698 299,953 300,874 -------- -------- -------- Deductions: Cash Dividends Declared: Common Stock 126,612 121,392 118,916 Cumulative Preferred Stock: 4-1/2% Series 811 850 875 5.90% Series 307 425 455 5.92% Series 364 364 364 6.85% Series 289 579 579 -------- -------- -------- Total Cash Dividends Declared 128,383 123,610 121,189 Capital Stock Expense 731 489 224 -------- -------- -------- Total Deductions 129,114 124,099 121,413 -------- -------- -------- Retained Earnings December 31 $120,584 $175,854 $179,461 ======== ======== ======== See Notes to Consolidated Financial Statements Beginning on Page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Capitalization December 31, ----------------------------- 2000 1999 ---- ---- (in thousands) COMMON SHAREHOLDER'S EQUITY $1,096,260 $1,150,571 ---------- ---------- PREFERRED STOCK - authorized shares 8,000,000 no par value Call Price Shares December 31, Number of Shares Redeemed Outstanding Series(a) 2000 (b) Year Ended December 31, December 31, 2000 - ------ ------------ ---------------------------- ----------------- 2000 1999 1998 ---- ---- ---- Not Subject to Mandatory Redemption: 4-1/2% $110.00 7,011 8,671 3,878 177,905 17,790 18,491 ------ ------ Subject to Mandatory Redemption: 5.90% (c) (e) 10,000 20,000 - 47,100 4,710 5,710 5.92% (c) (e) - - - 61,500 6,150 6,150 6.85% (d) (f) 84,500 - - - - 8,450 ------ ------ 10,860 20,310 ------ ------ LONG-TERM DEBT (See Schedule of Long-term Debt): First Mortgage Bonds 739,015 844,472 Installment Purchase Contracts 234,782 264,217 Senior Unsecured Notes 468,113 392,844 Junior Debentures 161,367 161,228 Other Long-term Debt 2,541 2,546 Less Portion Due Within One Year (175,006) (126,005) ---------- ---------- Long-term Debt Excluding Portion Due Within One Year 1,430,812 1,539,302 ---------- ---------- TOTAL CAPITALIZATION $2,555,722 $2,728,674 ========== ========== (a) The sinking fund provisions of each series subject to mandatory redemption have been met by purchase of shares in advance of the due date. (b) The cumulative preferred stock is callable at the price indicated plus accrued dividends. The involuntary liquidation preference is $100 per share. The aggregate involuntary liquidation price for all shares of cumulative preferred stock may not exceed $300 million. The unissued shares of the cumulative preferred stock may or may not possess mandatory redemption characteristics upon issuance. (c) Commencing in 2003 and continuing through 2007 APCo may redeem at $100 per share 25,000 shares of the 5.90% series and 30,000 shares of the 5.92% series outstanding under sinking fund provisions at its option and all outstanding shares must be reacquired in 2008. Shares redeemed in 2000 and 1999 may be applied to meet the sinking fund requirement. (d) Commencing in 2000 and continuing through date of redemption, a sinking fund for the 6.85% cumulative preferred stock will require the redemption of 60,000 shares each year, in each case at $100 per share. The Company has the non-cumulative option to redeem up to 60,000 additional shares on any sinking fund date at a redemption price of $100 per share. (e) Not callable until after 2002. (f) This series of preferred stock was redeemed in 2000. See Notes to Consolidated 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, -------------------- 2000 1999 ---- ---- (in thousands) % Rate Due 6.35 2000 - March 1 $ - $ 48,000 6.71 2000 - June 1 - 48,000 6-3/8 2001 - March 1 100,000 100,000 7.38 2002 - August 15 50,000 50,000 7.40 2002 - December 1 30,000 30,000 6.65 2003 - May 1 40,000 40,000 6.85 2003 - June 1 30,000 30,000 6.00 2003 - November 1 30,000 30,000 7.70 2004 - September 1 21,000 21,000 7.85 2004 - November 1 50,000 50,000 8.00 2005 - May 1 50,000 50,000 6.89 2005 - June 22 30,000 30,000 6.80 2006 - March 1 100,000 100,000 8.50 2022 - December 1 70,000 70,000 7.80 2023 - May 1 30,237 30,237 7.15 2023 - November 1 20,000 20,000 7.125 2024 - May 1 45,000 50,000 8.00 2025 - June 1 45,000 50,000 Unamortized Discount (2,222) (2,765) -------- -------- Total $739,015 $844,472 ======== ======== Certain indentures relating to the first mortgage bonds contain improvement, maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. Installment purchase contracts have been entered into, in connection with the issuance of pollution control revenue bonds by governmental authorities as follows: December 31, 2000 1999 ---- ---- (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 7.40 2014 - January 1 - 30,000 6.85 2022 - June 1 40,000 40,000 6.60 2022 - October 1 50,000 50,000 6.05 2024 - December 1 30,000 30,000 Unamortized Discount (2,218) (2,783) -------- -------- Total $234,782 $264,217 ======== ======== Under the terms of the installment purchase contracts, APCo is required to pay amounts sufficient to enable the payment of interest on and the principal (at stated maturities and upon mandatory redemptions) of related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants. Senior unsecured notes outstanding were as follows: December 31, 2000 1999 ---- ---- (in thousands) % Rate Due - ------ ------------------ (a) 2001 - June 27 $ 75,000 $ - 7.45 2004 - November 1 50,000 50,000 6.60 2009 - May 1 150,000 150,000 7.20 2038 - March 31 100,000 100,000 7.30 2038 - June 30 100,000 100,000 Unamortized Discount (6,887) (7,156) -------- -------- Total $468,113 $392,844 ======== ======== (a) A floating interest rate is determined monthly. The rate on December 31, 2000 was 6.95%. Junior debentures outstanding were as follows: December 31, 2000 1999 ---- ---- (in thousands) 8-1/4% Series A due 2026 - September 30 $ 75,000 $ 75,000 8% Series B due 2027 - March 31 90,000 90,000 Unamortized Discount (3,633) (3,772) -------- -------- Total $161,367 $161,228 ======== ======== 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, 2000, future annual long-term debt payments are as follows: Amount ------ (in thousands) 2001 $ 175,006 2002 80,006 2003 100,007 2004 121,008 2005 80,010 Later Years 1,064,741 ---------- Total Principal Amount 1,620,778 Unamortized Discount (14,960) ---------- Total $1,605,818 ========== APPALACHIAN POWER COMPANY AND SUBSIDIARIES Index to Notes to Consolidated Financial Statements The notes listed below are combined with the notes to financial statements for AEP and its other subsidiary registrants. The combined footnotes begin on page L-1. Combined Footnote Reference Significant Accounting Policies Note 1 Extraordinary Items Note 2 Rate Matters Note 5 Effects of Regulation Note 6 Industry Restructuring Note 7 Commitments and Contingencies Note 8 Staff Reduction Note 11 Benefit Plans Note 12 Business Segments Note 14 Financial Instruments, Credit and Risk Management Note 15 Income Taxes Note 16 Supplementary Information Note 17 Leases Note 18 Lines of Credit and Factoring of Receivables Note 19 Unaudited Quarterly Financial Information Note 20 Related Party Transactions Note 23 INDEPENDENT AUDITORS' REPORT To the Shareholders and Board of Directors of Appalachian Power Company: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Appalachian Power Company and its subsidiaries as of December 31, 2000 and 1999, and the related consolidated statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2000. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Appalachian Power Company and its subsidiaries as of December 31, 2000 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2000 in conformity with accounting principles generally accepted in the United States of America. DELOITTE & TOUCHE LLP Columbus, Ohio February 26, 2001 CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
D-13 CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES Selected Consolidated Financial Data Year Ended December 31, --------------------------------------------------------------- 2000 1999 1998 1997 1996 ---- ---- ---- ---- ---- (in thousands) INCOME STATEMENTS DATA: Operating Revenues $1,771,177 $1,482,475 $1,406,117 $1,376,282 $1,300,688 Operating Expenses 1,464,079 1,188,490 1,123,330 1,124,963 1,019,498 ---------- ---------- ---------- ---------- ---------- Operating Income 307,098 293,985 282,787 251,319 281,190 Nonoperating Income (Loss) 7,235 8,113 760 8,277 (11,145) ---------- ---------- ---------- ---------- ---------- Income Before Interest Charges 314,333 302,098 283,547 259,596 270,045 Interest Charges 124,766 114,380 122,036 131,173 127,451 ---------- ---------- ---------- ---------- ---------- Income Before Extraordinary Item 189,567 187,718 161,511 128,423 142,594 Extraordinary Loss - (5,517) - - - ---------- ---------- ---------- ---------- ----------- Net Income 189,567 182,201 161,511 128,423 142,594 Preferred Stock Dividend Requirements 241 6,931 6,901 9,523 13,563 Gain (Loss) on Reacquired Preferred Stock - (2,763) - 2,402 - ---------- ---------- ---------- ---------- ----------- Earnings Applicable to Common Stock $ 189,326 $ 172,507 $ 154,610 $ 121,302 $ 129,031 ========== ========== ========== ========== ========== December 31, --------------------------------------------------------------- 2000 1999 1998 1997 1996 ---- ---- ---- ---- ---- (in thousands) BALANCE SHEETS DATA: Electric Utility Plant $5,592,444 $5,511,894 $5,336,191 $5,215,749 $5,116,570 Accumulated Depreciation and Amortization 2,297,189 2,247,225 2,072,686 1,891,406 1,732,252 ---------- ---------- ---------- ---------- ---------- Net Electric Utility Plant $3,295,255 $3,264,669 $3,263,505 $3,324,343 $3,384,318 ========== ========== ========== ========== ========== Total Assets $5,472,496 $4,847,850 $4,735,476 $4,897,380 $4,919,014 ========== ========== ========== ========== ========== Common Stock and Paid-in Capital $ 573,888 $ 573,888 $ 573,888 $ 573,888 $ 573,888 Retained Earnings 792,219 758,894 734,387 828,777 864,475 ---------- ---------- ---------- ---------- ---------- Total Common Shareholder's Equity $1,366,107 $1,332,782 $1,308,275 $1,402,665 $1,438,363 ========== ========== ========== ========== ========== Preferred Stock $ 5,967 $ 5,967 $ 163,204 $ 163,204 $ 250,351 ========== ========== ========== ========== ========== CPL - Obligated, Mandatorily Redeemable Preferred Securities of Subsidiary Trust Holding Solely Junior Subordinated Dentures of CPL 148,500 150,000 150,000 150,000 - ---------- ---------- ---------- ---------- ----------- Long-term Debt (a) $1,454,559 $1,454,541 $1,350,706 $1,414,335 $1,613,805 ========== ========== ========== ========== ========== Total Capitalization and Liabilities $5,472,496 $4,847,850 $4,735,476 $4,897,380 $4,919,014 ========== ========== ========== ========== ========== (a) Including portion due within one year.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES Management's Discussion and Analysis of Results of Operations - -------------------------------------------------- CPL is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power and provides electric power to approximately 680,000 retail customers in southern Texas. CPL also sells electric power at wholesale to other utilities, municipalities and rural electric cooperatives. CPL participates in power marketing and trading activities conducted on its behalf by the AEP System. CPL shares in the revenues and costs of the AEP Power Pool's wholesale sales to and net forward trades with other utility systems and power marketers. Revenues from trading of electricity are recorded net of purchases as operating revenues. Results of Operations Income before extraordinary item increased $2 million or 1% in 2000 primarily as a result of increased retail energy sales, the post merger implementation of AEP's power marketing and trading operations which increased wholesale sales to neighboring utilities and power marketers and the effect of an unfavorable adjustment in 1999 as a result of FERC's approval of a transmission coordination agreement. These items were offset in part by a rise in interest expense. Income before extraordinary item increased $26 million or 16% in 1999 as a result of lower interest charges and increased retail sales. In 1999 CPL recorded an extraordinary loss as a result of a write-off of unamortized expenses associated with the reacquisition of long-term debt. Operating Revenues Operating revenues increased 19% in 2000 and 5% in 1999. The increase in 2000 was primarily due to an increase in fuel-related revenues and a rise in energy sales. Increases in retail and transmission revenues were the primary reasons for the increase in 1999. The following analyzes the changes in operating revenues: Increase (Decrease) From Previous Year (dollars in millions) - --------------------- 2000 1999 ----------------------------- Amount % Amount % Retail: Residential $109.5 $13.4 Commercial 66.9 16.1 Industrial 39.5 21.1 Other 6.9 3.7 ------ ----- 222.8 17 54.3 4 Wholesale 64.8 85 9.2 14 Transmission and Other 1.1 1 12.9 15 ------ ----- Total $288.7 19 $76.4 5 ====== ===== Retail operating revenues increased 17% in 2000 due to an increase in fuel and purchased power related revenues, reflecting rising prices for natural gas and purchased power, and an increase in weather-related demand for electricity. In 1999 an increase in fuel and purchased power related revenues and a modest increase in usage accounted for the increase in retail revenues. The increase in 1999 revenues was partially offset by a reduction in base rates resulting from a PUCT rate order. Since the Texas fuel and purchased power clause recovery mechanism provides for the accrual of revenues to recover fuel and purchased power cost increases until reviewed and approved for billing to customers by the PUCT, increases in fuel and purchased power expenses and related accrued revenues do not adversely affect results of operations. The significant increase in wholesale revenues in 2000 is attributable to increased sales to other utilities and CPL's initial participation after the merger in the AEP System's power marketing and trading operations. The volume of electricity sales to other utilities, both affiliated and unaffiliated, increased as demand for energy rose in response to warmer summer weather. Since CPL became a subsidiary of AEP as a result of the merger in June 2000, CPL shares in the AEP System's power marketing and trading transactions with other non-affiliated entities. Trading involves the purchase and sale of substantial amounts of electricity with non-affiliated parties. Revenues from trading are recorded net of purchases. Operating Expenses Increase Total operating expenses increased 23% in 2000 and 6% in 1999 primarily due to increased costs of fuel and purchased power and a rise in other operation expense. The changes in the components of operating expenses were: Increase (Decrease) From Previous Year (dollars in millions) - --------------------- 2000 1999 ---------------------------- Amount % Amount % Fuel $146.9 36 $ 18.0 5 Purchased Power 109.2 160 28.1 70 Other Operation 28.4 10 30.1 12 Maintenance (9.6) (14) 6.4 10 Depreciation and Amortization 1.1 1 (7.1) (4) Taxes Other Than Federal Income Taxes (4.5) (5) 13.6 19 Federal Income Taxes 4.1 4 (23.9) (21) ------ ------ Total $275.6 23 $ 65.2 6 ====== ====== Fuel expense increased in 2000 and 1999 primarily due to a rise in the average cost of fuel primarily from a large increases in natural gas prices. CPL uses natural gas as fuel for 71% of its generating capacity. The nature of the natural gas market is such that both long-term and short-term contracts are generally based on the current spot market price. Changes in natural gas prices affect CPL's fuel expense, however, as explained above, they generally do not impact results of operations. The rise in purchased power expense in 2000 was due to an increase in the cost of purchased electricity as a result of the rise in spot market natural gas prices, an increase in the quantity of energy purchased to meet the rise in demand, and increased cogeneration purchases. Purchased power expense increased 70% in 1999 due primarily to higher economy energy purchases reflecting the rise in natural gas prices. Other operation expense increased in 2000 due primarily to an increase in transmission expenses that resulted from new prices for the ERCOT transmission grid. Each year ERCOT establishes new rates to allocate the costs of the Texas transmission system to Texas electric utilities. In addition to higher transmission expenses, other operation expense increased due to higher administrative expenses resulting from the Company's share of STP voluntary severance expenses and Texas regulatory expenses. In 1999 the increase in other operation expense was caused mainly by a rise in outside service expenses associated with the Texas Legislation and securitization of generation-related regulatory assets, as well as higher transmission expenses. The increase in transmission expense was due primarily to the settlement of a complaint with Texas Utilities Electric Company and the absence in 1999 of a transmission service agreement adjustment made in 1998 related to a final order by the PUCT on a joint complaint filed by CPL and WTU asserting that Texas Utilities Electric Company had been effectively double charging for transmission service within ERCOT. Maintenance expenses decreased in 2000 and increased in 1999 as a result of a 10-year service inspection and refueling of STP Units 1 and 2 performed in 1999. Also contributing to the increase in maintenance expense in 1999 were scheduled power plant repairs at some of CPL's other generating plants. Taxes other than income taxes increased in 1999 due primarily to higher franchise tax expenses. Federal income tax expense associated with utility operations decreased in 1999 as a result of reduced taxable income, the reclassification of certain income tax related regulatory assets designated for securitization consistent with the Texas Legislation, and prior year income tax liability adjustments. Interest Charges The increase in interest charges in 2000 can be attributed to higher average interest rates associated with short term and long term debt. Interest charges decreased in 1999 due primarily to the maturity and reacquisition of long-term debt during 1998 and 1999. Preferred Stock Dividends Preferred stock dividends decreased in 2000 as a result of the redemption of preferred stock in the fourth quarter of 1999, which resulted in a loss on reacquired preferred stock recorded in 1999.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES Consolidated Statements of Income Year Ended December 31, --------------------------------------- 2000 1999 1998 ---- ---- ---- (in thousands) OPERATING REVENUES $1,771,177 $1,482,475 $1,406,117 ---------- ---------- ---------- OPERATING EXPENSES: Fuel 550,903 403,989 385,944 Purchased Power 177,387 68,155 40,062 Other Operation 319,539 291,131 261,058 Maintenance 60,528 70,165 63,779 Depreciation and Amortization 178,786 177,702 184,805 Taxes Other Than Federal Income Taxes 80,009 84,538 70,927 Federal Income Tax 96,927 92,810 116,755 ---------- ---------- ---------- Total Operating Expenses 1,464,079 1,188,490 1,123,330 ---------- ---------- ---------- OPERATING INCOME 307,098 293,985 282,787 NONOPERATING INCOME 7,235 8,113 760 ---------- ---------- ---------- INCOME BEFORE INTEREST CHARGES 314,333 302,098 283,547 INTEREST CHARGES 124,766 114,380 122,036 ---------- ---------- ---------- INCOME BEFORE EXTRAORDINARY ITEM 189,567 187,718 161,511 EXTRAORDINARY LOSS ON REACQUIRED DEBT (INCLUSIVE OF TAX $2,971,000) - (5,517) - ---------- ---------- ----------- NET INCOME 189,567 182,201 161,511 PREFERRED STOCK DIVIDEND REQUIREMENTS 241 6,931 6,901 LOSS ON REACQUIRED PREFERRED STOCK - (2,763) - ---------- ---------- ----------- EARNINGS APPLICABLE TO COMMON STOCK $ 189,326 $ 172,507 $ 154,610 ========== ========== ========== See Notes to Consolidated Financial Statements beginning on page L-1.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES Consolidated Balance Sheets - ------------------------------------------------------------------------------------------ December 31, 2000 1999 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production $3,175,867 $3,152,319 Transmission 581,931 566,629 Distribution 1,221,750 1,157,091 General 237,764 307,378 Construction Work in Progress 138,273 101,550 Nuclear Fuel 236,859 226,927 ---------- ---------- Total Electric Utility Plant 5,592,444 5,511,894 Accumulated Depreciation and Amortization 2,297,189 2,247,225 ---------- ---------- NET ELECTRIC UTILITY PLANT 3,295,255 3,264,669 ---------- ---------- OTHER PROPERTY AND INVESTMENTS 44,225 41,433 ---------- ---------- LONG-TERM ENERGY TRADING CONTRACTS 66,231 - ---------- ----------- CURRENT ASSETS: Cash and Cash Equivalents 14,253 7,995 Special Deposits for Reacquisition of Long-term Debt - 50,000 Accounts Receivable: General 67,787 49,228 Affiliated Companies 31,272 15,254 Allowance for Uncollectible Accounts (1,675) - Fuel Inventory - at LIFO cost 22,842 26,434 Materials and Supplies - at average cost 53,108 58,196 Under-recovered Fuel Costs 127,295 30,423 Energy Trading Contracts 481,206 - Prepayments 3,014 3,188 ---------- ---------- TOTAL CURRENT ASSETS 799,102 240,718 ---------- ---------- REGULATORY ASSETS 202,440 223,359 ---------- ---------- REGULATORY ASSETS DESIGNATED FOR SECURITIZATION 953,249 953,249 ---------- ---------- NUCLEAR DECOMMISSIONING TRUST FUND 93,592 86,122 ---------- ---------- DEFERRED CHARGES 18,402 38,300 ---------- ---------- TOTAL $5,472,496 $4,847,850 ========== ========== See Notes to Consolidated Financial Statements beginning on page L-1.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES - ----------------------------------------------------------------------------------------------------- December 31, --------------------------- 2000 1999 ---- ---- (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock - $25 Par Value: Authorized - 12,000,000 Shares Outstanding - 6,755,535 Shares $ 168,888 $ 168,888 Paid-in Capital 405,000 405,000 Retained Earnings 792,219 758,894 ---------- ---------- Total Common Shareholder's Equity 1,366,107 1,332,782 Preferred Stock 5,967 5,967 CPL - Obligated, Mandatorily Redeemable Preferred Securities of Subsidiary Trust Holding Solely Junior Subordinated Debentures of CPL 148,500 150,000 Long-term Debt 1,254,559 1,304,541 ---------- ---------- TOTAL CAPITALIZATION 2,775,133 2,793,290 ---------- ---------- CURRENT LIABILITIES: Long-term Debt Due Within One Year 200,000 150,000 Advances from Affiliates 269,712 322,158 Accounts Payable - General 128,957 88,702 Accounts Payable - Affiliated Companies 40,962 35,344 Taxes Accrued 55,526 41,121 Interest Accrued 26,217 14,723 Energy Trading Contracts 489,888 - Other 40,630 25,349 ---------- ---------- TOTAL CURRENT LIABILITIES 1,251,892 677,397 ---------- ---------- DEFERRED INCOME TAXES 1,242,797 1,234,175 ---------- ---------- DEFERRED INVESTMENT TAX CREDITS 128,100 133,306 ---------- ---------- LONG-TERM ENERGY TRADING CONTRACTS 65,740 - ---------- ----------- DEFERRED CREDITS 8,834 9,682 ---------- ---------- COMMITMENTS AND CONTINGENCIES (Note 8) TOTAL $5,472,496 $4,847,850 ========== ========== See Notes to Consolidated Financial Statements beginning on page L-1.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES Consolidated Statements of Cash Flows Year Ended December 31, 2000 1999 1998 ---- ---- ---- (in thousands) OPERATING ACTIVITIES: Net Income $ 189,567 $ 182,201 $ 161,511 Adjustments for Noncash Items: Depreciation and Amortization 178,786 177,702 184,805 Refunds Due Customers - - (63,713) Changes for Investments and Assets - - 18,669 Extraordinary Loss on Reacquired Debt - 5,517 - Deferred Income Taxes 16,263 19,938 (8,328) Deferred Investment Tax Credits (5,207) (5,207) (3,858) Changes in Certain Current Assets and Liabilities: Accounts Receivable (net) (32,902) (13,426) 10,255 Fuel, Materials and Supplies 8,680 (4,476) (48) Interest Accrued 11,494 (12,313) (1,343) Fuel Recovery (96,872) (40,046) 52,364 Accounts Payable 45,873 (3,061) 41,179 Taxes Accrued 14,405 (5,734) 33,297 Transmission Coordination Agreement Settlement 15,519 (15,519) - Other (net) 21,023 19,420 12,839 --------- --------- --------- Net Cash Flows From Operating Activities 366,629 304,996 437,629 --------- --------- --------- INVESTING ACTIVITIES: Construction Expenditures (199,484) (210,823) (123,803) Proceeds from Sales of Property and Other - 15,063 (7,181) --------- --------- --------- Net Cash Flows Used For Investing Activities (199,484) (195,760) (130,984) --------- --------- --------- FINANCING ACTIVITIES: Issuance of Long-term Debt 149,248 358,887 - Redemption of Preferred Stock - (160,001) - Retirement of Long-term Debt (151,440) (261,700) (64,000) Change in Advances from Affiliates (net) (52,446) 161,860 17,517 Special Deposit for Reacquisitions 50,000 (50,000) - Dividends Paid on Common Stock (156,000) (148,000) (249,000) Dividends Paid on Cumulative Preferred Stock (249) (7,835) (7,219) --------- --------- --------- Net Cash Flows Used For Financing Activities (160,887) (106,789) (302,702) --------- --------- --------- Net Increase in Cash and Cash Equivalents 6,258 2,447 3,943 Cash and Cash Equivalents January 1 7,995 5,548 1,605 --------- --------- --------- Cash and Cash Equivalents December 31 $ 14,253 $ 7,995 $ 5,548 ========= ========= ========= Supplemental Disclosure: Cash paid for interest net of capitalized amounts (including distributions on Trust Preferred Securities) was $110,010,000, $125,222,000 and $99,239,000 and for income taxes was $48,141,000, $78,393,000 and $94,245,000 in 2000, 1999 and 1998, respectively. See Notes to Consolidated Financial Statements beginning on page L-1.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES Consolidated Statements of Retained Earnings Year Ended December 31, 2000 1999 1998 ---- ---- ---- (in thousands) BALANCE AT BEGINNING OF PERIOD AS PREVIOUSLY REPORTED $764,225 $739,031 $833,282 CONFORMING CHANGE IN ACCOUNTING POLICY (5,331) (4,644) (4,505) -------- -------- -------- ADJUSTED BALANCE AT BEGINNING OF PERIOD 758,894 734,387 828,777 NET INCOME 189,567 182,201 161,511 DEDUCTIONS: Cash Dividends Declared: Common Stock 156,000 148,000 249,000 Preferred Stock 241 6,931 6,901 Other 1 - - LOSS ON REACQUIRED PREFERRED STOCK - (2,763) - -------- -------- --------- BALANCE AT END OF PERIOD $792,219 $758,894 $734,387 ======== ======== ======== See Notes to Consolidated Financial Statements beginning on page L-1.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES Consolidated Statements of Capitalization December 31, ----------------------------- 2000 1999 ---- ---- (in thousands) COMMON SHAREHOLDERS' EQUITY $1,366,107 $1,332,782 ---------- ---------- PREFERRED STOCK - authorized shares 3,035,000 $100 par value Call Price Shares December 31, Number of Shares Redeemed Outstanding Series 2000 Year Ended December 31, December 31, 2000 - ------ ------------ ---------------------------- ----------------- 2000 1999 1998 ---- ---- ---- Not Subject to Mandatory Redemption: 4.00% $105.75 - - - 42,038 4,204 4,204 4.20% 103.75 - - - 17,476 1,748 1,748 Premium 15 15 ---------- ---------- Total Preferred Stock 5,967 5,967 ---------- ---------- TRUST PREFERRED SECURITIES: CPL-obligated, mandatorily redeemable preferred securities of subsidiary trust holding solely Junior Subordinated Debentures of CPL, 8.00%, due April 30, 2037 148,500 150,000 ---------- ---------- LONG-TERM (See Schedule of Long-term Debt): First Mortgage Bonds 615,000 764,991 Installment Purchase Contracts 489,559 489,550 Senior Unsecured Notes 350,000 200,000 Less Portion Due Within One year (200,000) (150,000) ---------- ---------- Long-term Debt Excluding Portion Due Within One Year 1,254,559 1,304,541 ---------- ---------- TOTAL CAPITALIZATION $2,775,133 $2,793,290 ========== ========== See Notes to Consolidated Financial Statements beginning on page L-1.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES Schedule of Long-term Debt First mortgage bonds outstanding were as follows: December 31, -------------------- 2000 1999 ---- ---- (in thousands) % Rate Due 7.50 2020 - March 1 $ - $ 50,000 7.25 2004 - October 1 100,000 100,000 7.50 2002 - December 1 115,000 115,000 6-7/8 2003 - February 1 50,000 50,000 7-1/8 2008 - February 1 75,000 75,000 6.00 2000 - April 1 - 100,000 7.50 2023 - April 1 75,000 75,000 6-5/8 2005 - July 1 200,000 200,000 Unamortized Discount - (9) -------- -------- Total $615,000 $764,991 ======== ======== Certain indentures relating to the first mortgage bonds contain improvement, maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. Installment purchase contracts have been entered into in connection with the issuance of pollution control revenue bonds by governmental authorities as follows: December 31, 2000 1999 ---- ---- (in thousands) % Rate Due Matagorda County Naviagation District, Texas: 6.00 2028 - July 1 $120,265 $120,265 6.10 2028 - July 1 100,635 100,635 6-1/8 2030 - May 1 60,000 60,000 4.90 2030 - May 1 111,700 111,700 4.95 2030 - May 1 50,000 50,000 Guadalupe-Blanco River Authority District, Texas: (a) 2015 - November 1 40,890 40,890 Red River Authority District, Texas: 6.00 2020 - June 1 6,330 6,330 Unamortized Discount (261) (270) -------- -------- Total $489,559 $489,550 ======== ======== (a) A floating interest rate is determined monthly. The rate on December 31, 2000 was 4.90%. Under the terms of the installment purchase contracts, CPL is required to pay amounts sufficient to enable the payment of interest on and the principal (at stated maturities and upon mandatory redemptions) of related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants. Senior unsecured notes outstanding were as follows: December 31, 2000 1999 ---- ---- (in thousands) % Rate Due - ------ ------------------ (b) 2001 - November 23 $200,000 $200,000 (c) 2002 - February 22 150,000 - -------- --------- Total $350,000 $200,000 ======== ======== (b) A floating interest rate is determined monthly. The rate on December 31, 2000 was 7.35063%. (c) A floating interest rate is determined monthly. The rate on December 31, 2000 was 7.20313%. At December 31, 2000, future annual long-term debt payments are as follows: Amount ------ (in thousands) 2001 $ 200,000 2002 265,000 2003 50,000 2004 100,000 2005 200,000 Later Years 639,820 ---------- Total Principal Amount 1,454,820 Unamortized Discount (261) ---------- Total $1,454,559 ========== CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES Index to Notes to Consolidated Financial Statements - ------------------------------------------------------------ The notes listed below are combined with the notes to financial statements for AEP and its other subsidiary registrants. The combined footnotes begin on page L-1. Combined Footnote Reference Significant Accounting Policies Note 1 Extraordinary Items Note 2 Merger Note 3 Rate Matters Note 5 Effects of Regulation Note 6 Industry Restructuring Note 7 Commitments and Contingencies Note 8 Benefit Plans Note 12 Business Segments Note 14 Financial Instruments, Credit and Risk Management Note 15 Income Taxes Note 16 Lines of Credit and Factoring of Receivables Note 19 Unaudited Quarterly Financial Information Note 20 Trust Preferred Securities Note 21 Jointly Owned Electric Utility Plant Note 22 Related Party Transactions Note 23 INDEPENDENT AUDITORS' REPORT - -------------------------------------------- To the Shareholders and Board of Directors of Central Power and Light Company: We have audited the accompanying consolidated balance sheet and consolidated statement of capitalization of Central Power and Light Company and subsidiary as of December 31, 2000, and the related consolidated statements of income, retained earnings, and cash flows for the year then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit. The consolidated financial statements of the Company for the years ended December 31, 1999 and 1998, before the restatement described in Note 3 to the consolidated financial statements, were audited by other auditors whose report, dated February 25, 2000, expressed an unqualified opinion on those statements. We conducted our audit 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 audit provides a reasonable basis for our opinion. In our opinion, the 2000 consolidated financial statements present fairly, in all material respects, the financial position of Central Power and Light Company and subsidiary as of December 31, 2000, and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America. We also audited the adjustments described in Note 3 that were applied to restate the 1999 and 1998 consolidated financial statements to give retroactive effect to the conforming change in the method of accounting for vacation pay accruals. In our opinion, such adjustments are appropriate and have been properly applied. Deloitte & Touche LLP Columbus, Ohio February 26, 2001 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Stockholders and Board of Directors of Central Power and Light Company: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Central Power and Light Company (a Texas corporation and a wholly owned subsidiary of Central and South West Corporation) and subsidiary company as of December 31, 1999, and the related consolidated statements of income, retained earnings and cash flows, for each of the two years in the period ended December 31, 1999 prior to the restatement (and, therefore, are not presented herein) for the retroactive effect of the conforming change in the method of accounting for vacation pay accruals and certain conforming reclassifications to the historical financial statements as described in Note 3 to the restated consolidated financial statements. These financial statements are the responsibility of Central Power and Light Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. 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 prior to the restatement referred to above present fairly, in all material respects, the financial position of Central Power and Light Company and subsidiary company as of December 31, 1999, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 1999, in conformity with accounting principles generally accepted in the United States. Arthur Anderson LLP Dallas, Texas February 25, 2000 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
E-12 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Selected Consolidated Financial Data - ---------------------------------------------------------------------------------------------- Year Ended December 31, ---------------------------------------------------------- 2000 1999 1998 1997 1996 ---- ---- ---- ---- ---- (in thousands) INCOME STATEMENTS DATA: Operating Revenues $1,356,408 $1,229,994 $1,187,745 $1,094,851 $1,105,683 Operating Expenses 1,160,531 1,007,204 975,534 899,724 920,136 ---------- ---------- ---------- ---------- ---------- Operating Income 195,877 222,790 212,211 195,127 185,547 Nonoperating Income (Loss) 5,153 2,709 (1,343) 3,137 (970) ---------- ---------- ---------- ---------- ---------- Income Before Interest Charges 201,030 225,499 210,868 198,264 184,577 Interest Charges (net) 80,828 75,229 77,824 78,885 77,469 ---------- ---------- ---------- ---------- ---------- Income Before Extraordinary Item 120,202 150,270 133,044 119,379 107,108 Extraordinary Item (25,236) - - - - ---------- ---------- ---------- ---------- ----------- Net Income 94,966 150,270 133,044 119,379 107,108 Preferred Stock Dividend Requirements 1,783 2,131 2,131 2,442 6,029 ---------- ---------- ---------- ---------- ---------- Earnings Applicable to Common Stock $ 93,183 $ 148,139 $ 130,913 $ 116,937 $ 101,079 ========== ========== ========== ========== ========== December 31, ------------------------------------------------------------ 2000 1999 1998 1997 1996 ---- ---- ---- ---- ---- BALANCE SHEETS DATA: (in thousands) Electric Utility Plant $3,266,794 $3,151,619 $3,053,565 $2,976,110 $2,899,893 Accumulated Depreciation 1,299,697 1,210,994 1,134,348 1,074,588 1,016,909 ---------- ---------- ---------- ---------- ---------- Net Electric Utility Plant $1,967,097 $1,940,625 $1,919,217 $1,901,522 $1,882,984 ========== ========== ========== ========== ========== Total Assets $3,894,934 $2,809,990 $2,681,690 $2,613,860 $2,541,586 ========== ========== ========== ========== ========== Common Stock and Paid-in Capital $ 614,380 $ 613,899 $ 613,518 $ 613,138 $ 615,735 Retained Earnings 99,069 246,584 186,441 138,172 99,582 ---------- ---------- ---------- ---------- ---------- Total Common Shareholder's Equity $ 713,449 $ 860,483 $ 799,959 $ 751,310 $ 715,317 ========== ========== ========== ========== ========== Cumulative Preferred Stock - Subject to Mandatory Redemption (a) $ 15,000 $ 25,000 $ 25,000 $ 25,000 $ 75,000 ========== ========== ========== ========== ========== Long-term Debt (a) $ 899,615 $ 924,545 $ 959,786 $ 969,600 $ 897,281 ========== ========== ========== ========== ========== Obligations Under Capital Leases (a) $ 42,932 $ 40,270 $ 42,362 $ 38,587 $ 36,134 ========== ========== ========== ========== ========== Total Capitalization and Liabilities $3,894,934 $2,809,990 $2,681,690 $2,613,860 $2,541,586 ========== ========== ========== ========== ========== (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 667,000 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. CSPCo also sells wholesale power to municipalities. The cost of the AEP System's generating capacity is allocated among the AEP Power Pool members based on their relative peak demands and generating reserves through the payment of capacity charges and receipt of capacity credits. AEP Power Pool members are also compensated for their out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each company's prior twelve month peak demand relative to the total peak demand of all member companies as a basis for sharing AEP Power Pool revenues and costs. The result of this calculation is the member load ratio (MLR) which determines each company's percentage share of AEP Power Pool revenues and costs. CSPCo as a member of the AEP Power Pool shares in the revenues and costs of the AEP Power Pool's wholesale sales to and net forward trades with other utility systems and power marketers. Revenues from forward electricity trades are recorded net of purchases as operating revenues for transactions in AEP's traditional marketing area (up to two trans-mission systems from the AEP service territory) and as nonoperating income for transactions beyond two transmission systems from AEP. The AEP Power Pool also enters into power trading transactions for options, futures and swaps. CSPCo's share of these transactions is recorded in nonoperating income. In February 2001 the U.S. District Court for the Southern District of Ohio ruled against AEP and certain of its subsidiaries, including CSPCo, in a suit over deductibility of interest claimed in AEP's consolidated tax return related to a corporate owned life insurance (COLI) program. In 1998 and 1999 CSPCo paid the disputed taxes and interest attributable to the COLI interest deductions for taxable years 1991-98. The payments were included in Other Property and Investments pending the resolution of this matter. As a result of the Court's decision, net income was reduced by $41 million in 2000. Results of Operations Net Income Decreases Income before extraordinary item decreased by $30 million or 20% primarily due to increases in federal income tax expense and related interest charges as a result of the U.S. District Court's decision denying COLI deductions. An extraordinary loss related to the discontinuance of SFAS 71 regulatory accounting of $25 million after tax was recorded in September 2000 in connection with the PUCO approval of a plan to transition CSPCo's generation business from cost based rate regulation to customer choice and market pricing. Operating Revenues Increase Operating revenues increased $126.4 million in 2000 due to a significant increase in AEP Power Pool wholesale marketing and trading transactions. Changes in the components of operating revenues were as follows: Increase (Decrease) From Previous Year (dollars in millions) Amount % - ---------------------- ------ - Retail: Residential $ 0.8 Commercial 14.1 Industrial (6.0) Other 0.9 ------ Wholesale 123.5 102.6 Transmission (0.1) (0.2) Other (6.8) (32.1) ------ Total $126.4 10.3 ====== The increase in wholesale revenues is due to a significant increase in AEP Power Pool transactions. As a result of a major industrial customer's decision in January 2000 not to continue purchasing power from an affiliate, additional power was available to the AEP Power Pool for sale on the wholesale market accounting in part for the increase in the CSPCo's wholesale Power Pool revenues. The increase in AEP Power Pool wholesale sales also resulted from growing AEP's power marketing and trading operation, favorable wholesale market conditions and increased availability of generation. AEP generating unit availability was increased due to the return to service of one of an affiliate's nuclear generating units and improved generating unit outage management. With the return to service in June 2000 of one of an affiliate's two nuclear generating units that affiliate supplied more power to the AEP Power Pool at a lower cost reducing the need to acquire higher cost power on the open market. Operating Expenses Rise Operating expenses increased by 15% in 2000 mostly due to increases in purchased power expense, other operation expense and federal income taxes. Changes in the components of operating expenses were: Increase (Decrease) From Previous Year (dollars in millions) Amount % - ---------------------- ------ - Fuel $ 3.6 2.0 Purchased Power Expense 82.2 31.0 Other Operation Expense 31.2 16.3 Maintenance Expense 4.5 6.8 Depreciation 5.1 5.4 Taxes Other Than Federal Income Taxes 3.1 2.6 Federal Income Taxes 23.6 27.5 ------ Total $153.3 15.2 ====== The increase in other operation expense was due to increased power generation costs that resulted from higher emission allowance consumption, increased emission allowance cost and increased costs for power trading reflecting the growth of the power marketing and trading operation. The increase in purchased power expense reflects additional purchases of power from the AEP Power Pool as a result of increased availability of AEP Pool generation. The AEP Power Pool was able to supply more energy to CSPCo since an affiliate's out of service nuclear unit went on line in June 2000, a major industrial customer discontinued purchasing power from an affiliate in January 2000, and generating unit outage managements improved. Additional generating unit boiler repairs and maintenance of overhead transmission and distribution lines accounted for the increase in maintenance expense. Depreciation expenses increased due to additional plant investment. The increase in federal income tax expense was primarily due to the court ruling related to the AEP's COLI program. Nonoperating Income The increase in nonoperating income in 2000 was due to an increase in net gains from non-regulated 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. The Company'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 increase in nonoperating income is also attributable to the reversal in the first quarter of 2000 of a remaining provision for potential liability for clean-up of possible environmental contamination after the state of Ohio reviewed the matter and determined that no further corrective action would be required. Interest Charges Increase Interest charges increased as a result of the recognition of deferred interest payments to the IRS related to the COLI disallowances. Extraordinary Loss An extraordinary loss was recorded in the third quarter of 2000 when CSPCo discontinued the application of SFAS 71 regulatory accounting for the generation portion of its business due to the approval by the PUCO in September 2000 of a stipulation agreement providing for a transition from cost based rate regulation for CSPCo's generation business to customer choice and market pricing.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Income - ------------------------------------------------------------------------------------------------------------- Year Ended December 31, 2000 1999 1998 ---- ---- ---- (in thousands) OPERATING REVENUES $1,356,408 $1,229,994 $1,187,745 ---------- ---------- ---------- OPERATING EXPENSES: Fuel 189,155 185,511 189,031 Purchased Power 347,693 265,457 237,688 Other Operation 221,775 190,614 202,720 Maintenance 69,676 65,229 62,095 Depreciation 99,640 94,532 91,218 Taxes Other Than Federal Income Taxes 123,291 120,147 116,548 Federal Income Taxes 109,301 85,714 76,234 ---------- ---------- ---------- TOTAL OPERATING EXPENSES 1,160,531 1,007,204 975,534 ---------- ---------- ---------- OPERATING INCOME 195,877 222,790 212,211 NONOPERATING INCOME (LOSS) 5,153 2,709 (1,343) ---------- ---------- ---------- INCOME BEFORE INTEREST CHARGES 201,030 225,499 210,868 INTEREST CHARGES 80,828 75,229 77,824 ---------- ---------- ---------- INCOME BEFORE EXTRAORDINARY ITEM 120,202 150,270 133,044 EXTRAORDINARY LOSS: Discontinuance of Regulatory Accounting for Generation (inclusive of tax benefit of $14,148,000) (25,236) - - ---------- ---------- ---------- NET INCOME 94,966 150,270 133,044 PREFERRED STOCK DIVIDEND REQUIREMENTS 1,783 2,131 2,131 ---------- ---------- ---------- EARNINGS APPLICABLE TO COMMON STOCK $ 93,183 $ 148,139 $ 130,913 ========== ========== ========== Consolidated Statements of Retained Earnings - ---------------------------------------------------------------------------------------------------------------------------------- Year Ended December 31, ------------------------------------- 2000 1999 1998 ---- ---- ---- (in thousands) Retained Earnings January 1 $246,584 $186,441 $138,172 Net Income 94,966 150,270 133,044 -------- -------- -------- 341,550 336,711 271,216 -------- -------- -------- Deductions: Cash Dividends Declared: Common Stock 240,600 87,996 82,644 Cumulative Preferred Stock - 7% Series 1,400 1,750 1,750 -------- -------- -------- Total Cash Dividends Declared 242,000 89,746 84,394 Capital Stock Expense 481 381 381 -------- -------- -------- Total Deductions 242,481 90,127 84,775 -------- -------- -------- Retained Earnings December 31 $ 99,069 $246,584 $186,441 ======== ======== ======== See Notes to Consolidated Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Consolidated Balance Sheets - ------------------------------------------------------------------------------------------ December 31, ------------------------------- 2000 1999 ---- ---- (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production $1,564,254 $1,544,858 Transmission 360,302 350,826 Distribution 1,096,365 1,032,550 General 156,534 141,137 Construction Work in Progress 89,339 82,248 ---------- ---------- Total Electric Utility Plant 3,266,794 3,151,619 Accumulated Depreciation 1,299,697 1,210,994 ---------- ---------- NET ELECTRIC UTILITY PLANT 1,967,097 1,940,625 ---------- ---------- OTHER PROPERTY AND INVESTMENTS 39,848 80,008 ---------- ---------- LONG-TERM ENERGY TRADING CONTRACTS 172,167 21,278 ---------- ---------- CURRENT ASSETS: Cash and Cash Equivalents 11,600 5,107 Accounts Receivable: Customers 73,711 77,418 Affiliated Companies 49,591 28,453 Miscellaneous 18,807 8,887 Allowance for Uncollectible Accounts (659) (3,045) Fuel - at average cost 13,126 21,484 Materials and Supplies - at average cost 38,097 41,696 Accrued Utility Revenues 9,638 48,117 Energy Trading Contracts 1,085,989 90,103 Prepayments 46,735 37,969 ---------- ---------- TOTAL CURRENT ASSETS 1,346,635 356,189 ---------- ---------- REGULATORY ASSETS 291,553 339,103 ---------- ---------- DEFERRED CHARGES 77,634 72,787 ---------- ---------- TOTAL $3,894,934 $2,809,990 ========== ========== See Notes to Consolidated Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES - ------------------------------------------------------------------------------------------------- December 31, ------------------------------- 2000 1999 ---- ---- (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 573,354 572,873 Retained Earnings 99,069 246,584 ---------- ---------- Total Common Shareholder's Equity 713,449 860,483 Cumulative Preferred Stock - Subject to Mandatory Redemption 15,000 25,000 Long-term Debt 899,615 924,545 ---------- ---------- TOTAL CAPITALIZATION 1,628,064 1,810,028 ---------- ---------- OTHER NONCURRENT LIABILITIES 47,584 43,056 ---------- ---------- CURRENT LIABILITIES: Short-term Debt - 45,500 Advances from Affiliates 88,732 - Accounts Payable - General 89,846 28,279 Accounts Payable - Affiliated Companies 72,493 52,776 Taxes Accrued 162,904 143,477 Interest Accrued 13,369 13,936 Energy Trading Contracts 1,115,967 87,911 Other 60,701 34,375 ---------- ---------- TOTAL CURRENT LIABILITIES 1,604,012 406,254 ---------- ---------- DEFERRED INCOME TAXES 422,759 447,607 ---------- ---------- DEFERRED INVESTMENT TAX CREDITS 41,234 44,716 ---------- ---------- DEFERRED CREDITS 12,861 41,875 ---------- ---------- LONG-TERM ENERGY TRADING CONTRACTS 138,420 16,454 ---------- ---------- COMMITMENTS AND CONTINGENCIES (Note 8) TOTAL $3,894,934 $2,809,990 ========== ==========
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Cash Flows - -------------------------------------------------------- Year Ended December 31, 2000 1999 1998 ---- ---- ---- (in thousands) OPERATING ACTIVITIES: Net Income $ 94,966 $ 150,270 $133,044 Adjustments for Noncash Items: Depreciation 100,182 94,962 91,426 Deferred Federal Income Taxes (4,063) 10,481 17,101 Deferred Investment Tax Credits (3,482) (3,994) (4,224) Deferred Fuel Costs (net) 5,352 8,889 (11,311) Extraordinary Loss - Discontinuance of SFAS 71 25,236 - - Changes in Certain Current Assets and Liabilities: Accounts Receivable (net) (29,737) 5,166 (5,910) Fuel, Materials and Supplies 11,957 (7,777) (8,226) Accrued Utility Revenues 38,479 (7,990) 11,638 Accounts Payable 81,284 9,292 476 Disputed Tax and Interest Related to COLI 39,483 (2,240) (37,243) Other (net) 7,480 (13,426) 29,776 ---------- --------- --------- Net Cash Flows From Operating Activities 367,137 243,633 216,547 ---------- --------- --------- INVESTING ACTIVITIES: Construction Expenditures (127,987) (115,321) (114,979) Proceeds from Sale and Leaseback Transactions and Other 1,560 1,858 2,637 ---------- --------- --------- Net Cash Flows Used For Investing Activities (126,427) (113,463) (112,342) ---------- --------- --------- FINANCING ACTIVITIES: Change in Advances from Affiliates (net) 88,732 - - Issuance of Long-term Debt - - 111,075 Retirement of Preferred Stock (10,000) - - Retirement of Long-term Debt (25,274) (35,523) (122,206) Change in Short-term Debt (net) (45,500) (7,000) (14,100) Dividends Paid on Common Stock (240,600) (87,996) (82,644) Dividends Paid on Cumulative Preferred Stock (1,575) (1,750) (1,750) ---------- --------- --------- Net Cash Flows Used For Financing Activities (234,217) (132,269) (109,625) ---------- --------- --------- Net Increase (Decrease) in Cash and Cash Equivalents 6,493 (2,099) (5,420) Cash and Cash Equivalents January 1 5,107 7,206 12,626 ---------- --------- --------- Cash and Cash Equivalents December 31 $ 11,600 $ 5,107 $ 7,206 ========== ========= ========= Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $68,506,000, $72,007,000 and $73,917,000 and for income taxes was $81,109,000, $71,809,000 and $53,410,000 in 2000, 1999 and 1998, respectively. Noncash acquisitions under capital leases were $10,777,000, $6,855,000 and $11,107,000 in 2000, 1999 and 1998, respectively. See Notes to Consolidated Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Capitalization December 31, ----------------------------- 2000 1999 ---- ---- (in thousands) COMMON SHAREHOLDER'S EQUITY $ 713,449 $ 860,483 ---------- ---------- PREFERRED STOCK - authorized shares 2,500,000 $100 par value authorized shares 7,000,000 $25 par value Call Price Shares December 31, Number of Shares Redeemed Outstanding Series 2000 Year Ended December 31, December 31, 2000 - ------ ------------ ---------------------------- ----------------- 2000 1999 1998 ---- ---- ---- Subject to Mandatory Redemption: 7.00% (a) 100,000 - - 150,000 15,000 25,000 ---------- ---------- LONG-TERM DEBT (See Schedule of Long-term Debt): First Mortgage Bonds 537,119 562,327 Installment Purchase Contracts 91,166 91,112 Senior Unsecured Notes 159,318 159,212 Junior Debentures 112,012 111,894 ---------- ---------- Total Long-term Debt 899,615 924,545 ---------- ---------- TOTAL CAPITALIZATION $1,628,064 $1,810,028 ========== ========== (a) Commencing in 2000, a sinking fund will require the redemption of 50,000 shares at $100 a share on or before August 1 of each year. The Company has the right, on each sinking fund date, to redeem an additional 50,000 shares which the company did in August 2000. Redemption of this series is prohibited prior to August 1, 2000. The sinking fund provisions of the 7% series aggregate $5,000,000 in 2002, 2003 and 2004. See Notes to Consolidated 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, -------------------- 2000 1999 ---- ---- (in thousands) % Rate Due 7.25 2002 - October 1 $ 56,500 $ 75,000 7.15 2002 - November 1 20,000 20,000 6.80 2003 - May 1 45,000 50,000 6.60 2003 - August 1 40,000 40,000 6.10 2003 - November 1 20,000 20,000 6.55 2004 - March 1 50,000 50,000 6.75 2004 - May 1 50,000 50,000 8.70 2022 - July 1 35,000 35,000 8.40 2022 - August 1 15,000 15,000 8.55 2022 - August 1 15,000 15,000 8.40 2022 - August 15 25,500 25,500 8.40 2022 - October 15 13,000 15,000 7.90 2023 - May 1 50,000 50,000 7.75 2023 - August 1 33,000 33,000 7.45 2024 - March 1 30,000 30,000 7.60 2024 - May 1 41,000 41,000 Unamortized Discount (1,881) (2,173) -------- -------- Total $537,119 $562,327 ======== ======== Certain indentures relating to the first mortgage bonds contain improvement, maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. Installment purchase contracts have been entered into in connection with the issuance of pollution control revenue bonds by the Ohio Air Quality Development Authority: December 31, 2000 1999 ---- ---- (in thousands) % Rate Due - ------ ----------------- 6-3/8 2020 - December 1 $48,550 $48,550 6-1/4 2020 - December 1 43,695 43,695 Unamortized Discount (1,079) (1,133) ------- ------- Total $91,166 $91,112 ======= ======= Under the terms of the installment purchase contracts, CSPCo is required to pay amounts sufficient to enable the payment of interest on and the principal (at stated maturities and upon mandatory redemptions) of related pollution control revenue bonds issued to finance the construction of pollution control facilities at the Zimmer Plant. Senior unsecured notes outstanding were as follows: December 31, 2000 1999 ---- ---- (in thousands) % Rate Due - ------ ------------------ 6.85 2005 - October 3 $ 48,000 $ 48,000 6.51 2008 - February 1 52,000 52,000 6.55 2008 - June 26 60,000 60,000 Unamortized Discount (682) (788) -------- -------- Total $159,318 $159,212 ======== ======== Junior debentures outstanding were as follows: December 31, 2000 1999 ---- ---- (in thousands) % Rate Due - ------ ------------------ 8-3/8 2025 - September 30 $ 75,000 $ 75,000 7.92 2027 - March 31 40,000 40,000 Unamortized Discount (2,988) (3,106) -------- -------- Total $112,012 $111,894 ======== ======== 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, 2000, future annual long-term debt payments are as follows: Amount ------ (in thousands) 2001 $ - 2002 76,500 2003 105,000 2004 100,000 2005 48,000 Later Years 576,745 -------- Total Principal Amount 906,245 Unamortized Discount (6,630) -------- Total $899,615 ======== COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Index to Notes to Consolidated Financial Statements - -------------------------------------------------------------- The notes listed below are combined with the notes to financial statements for AEP and its other subsidiary registrants. The combined footnotes begin on page L-1. Combined Footnote Reference Significant Accounting Policies Note 1 Extraordinary Items Note 2 Rate Matters Note 5 Effects of Regulation Note 6 Industry Restructuring Note 7 Commitments and Contingencies Note 8 Staff Reductions Note 11 Benefit Plans Note 12 Business Segments Note 14 Financial Instruments, Credit and Risk Management Note 15 Income Taxes Note 16 Supplementary Information Note 17 Leases Note 18 Lines of Credit and Factoring of Receivable Note 19 Unaudited Quarterly Financial Information Note 20 Jointly Owned Electric Utility Plant Note 22 Related Party Transactions Note 23 INDEPENDENT AUDITORS' REPORT - -------------------------------------------------- To the Shareholders and Board of Directors of Columbus Southern Power Company: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Columbus Southern Power Company and its subsidiaries as of December 31, 2000 and 1999, and the related consolidated statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2000. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Columbus Southern Power Company and its subsidiaries as of December 31, 2000 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2000 in conformity with accounting principles generally accepted in the United States of America. Deloitte & Touche LLP Columbus, Ohio February 26, 2001 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
F-14 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Selected Consolidated Financial Data - ------------------------------------------------------------------------------------------------------------------------------ Year Ended December 31, ----------------------------------------------------------------- 2000 1999 1998 1997 1996 ---- ---- ---- ---- ---- (in thousands) INCOME STATEMENTS DATA: Operating Revenues $1,548,476 $1,394,119 $1,405,794 $1,339,232 $1,328,493 Operating Expenses 1,583,178 1,285,467 1,239,787 1,131,444 1,108,076 ---------- ---------- ---------- ---------- ---------- Operating Income (Loss) (34,702) 108,652 166,007 207,788 220,417 Nonoperating Income (Loss) 9,933 4,530 (839) 4,415 2,729 ---------- ---------- ---------- ---------- ---------- Income (Loss) Before Interest Charges (24,769) 113,182 165,168 212,203 223,146 Interest Charges 107,263 80,406 68,540 65,463 65,993 ---------- ---------- ---------- ---------- ---------- Net Income (Loss) (132,032) 32,776 96,628 146,740 157,153 Preferred Stock Dividend Requirements 4,624 4,885 4,824 5,736 10,681 ---------- ---------- ---------- ---------- ---------- Earnings (Loss) Applicable to Common Stock $ (136,656) $ 27,891 $ 91,804 $ 141,004 $ 146,472 ========== ========== ========== ========== ========== December 31, ----------------------------------------------------------------- 2000 1999 1998 1997 1996 ---- ---- ---- ---- ---- (in thousands) BALANCE SHEETS DATA: Electric Utility Plant $4,871,473 $4,770,027 $4,631,848 $4,514,497 $4,377,669 Accumulated Depreciation and Amortization 2,280,521 2,194,397 2,081,355 1,973,937 1,861,893 ---------- ---------- ---------- ---------- ---------- Net Electric Utility Plant $2,590,952 $2,575,630 $2,550,493 $2,540,560 $2,515,776 ========== ========== ========== ========== ========== Total Assets $5,818,547 $4,576,696 $4,148,523 $3,967,798 $3,897,484 ========== ========== ========== ========== ========== Common Stock and Paid-in Capital $ 789,656 $ 789,323 $ 789,189 $ 789,056 $ 787,856 Retained Earnings 3,443 166,389 253,154 278,814 269,071 ---------- ---------- ---------- ---------- ---------- Total Common Shareholder's Equity $ 793,099 $ 955,712 $1,042,343 $1,067,870 $1,056,927 ========== ========== ========== ========== ========== Cumulative Preferred Stock: Not Subject to Mandatory Redemption $ 8,736 $ 9,248 $ 9,273 $ 9,435 $ 21,977 Subject to Mandatory Redemption (a) 64,945 64,945 68,445 68,445 135,000 ---------- ---------- ---------- ---------- ---------- Total Cumulative Preferred Stock $ 73,681 $ 74,193 $ 77,718 $ 77,880 $ 156,977 ========== ========== ========== ========== ========== Long-term Debt (a) $1,388,939 $1,324,326 $1,175,789 $1,049,237 $1,042,104 ========== ========== ========== ========== ========== Obligations Under Capital Leases (a) $ 163,173 $ 187,965 $ 186,427 $ 195,227 $ 130,965 ========== ========== ========== ========== ========== Total Capitalization and Liabilities $5,818,547 $4,576,696 $4,148,523 $3,967,798 $3,897,484 ========== ========== ========== ========== ========== (a) Including portion due within one year.
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 565,000 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 System's generating capacity is allocated among the AEP Power Pool members based on their relative peak demands and generating reserves through the payment of capacity charges or 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 or costs. I&M as a member of the AEP Power Pool shares in the revenues and costs of the AEP Power Pool's wholesale sales to and net forward trades with other utility systems and power marketers. Revenues from forward electricity trades in AEP's traditional marketing area (up to two transmission systems from the AEP service territory) are recorded net of purchases as operating revenues and as nonoperating income for trades beyond two transmission systems from AEP. The AEP Power Pool also enters into power trading transactions for options, futures and swaps. I&M's share of these transactions is recorded in nonoperating income. I&M is committed under unit power agreements to purchase all of AEGCo's 50% share of the 2,600 MW Rockport Plant capacity unless it is sold to other utilities. AEGCo is an affiliate that is not a member of the AEP Power Pool. A long-term unit power agreement with an unaffiliated utility expired at the end of 1999 for the sale of 455 MW of AEGCo's Rockport Plant capacity. An agreement between AEGCo and KPCo provides for the sale of 390 MW of AEGCo's Rockport Plant capacity to KPCo through 2004. Therefore, effective January 1, 2000, I&M began purchasing 910 MW of AEGCo's 50% share of Rockport Plant capacity. Results of Operations During 2000 both of the Cook Plant nuclear units were successfully restarted after being shutdown in September 1997 due to questions regarding the operability of certain safety systems which arose during a NRC architect engineer design inspection. See discussion in Note 4 of the Notes to Consolidated Financial Statements. 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 a corporate owned life insurance (COLI) program. In 1998 and 1999 I&M paid the disputed taxes and interest attributable to the COLI interest deductions for the taxable years 1991-98. The payments were included in Other Property and Investments pending the resolution of this matter. As a result of the Court's decision, I&M's net income was reduced by $66 million in 2000. As a result of the costs incurred in 2000 to restart the Cook Plant nuclear units and the disallowance of COLI interest deductions, net income declined $165 million in 2000. In 1999 net income declined $64 million due primarily to the cost of efforts to restart the Cook Plant units. Operating Revenues Operating revenues increased 11% in 2000 and decreased 1% in 1999. The increase in operating revenues in 2000 was primarily due to increased wholesale sales to the AEP Power Pool. The decrease in 1999 was primarily due to a decline in margins on wholesale sales and net power trading transactions within the AEP Power Pool's traditional marketing area. The following analyzes the changes in operating revenues: Increase (Decrease) From Previous Year (dollars in millions) - --------------------- 2000 1999 ------------------------------ Amount % Amount % Retail: Residential $(37.3) $ 3.4 Commercial (16.2) 0.7 Industrial (30.0) (5.7) Other (5.0) (0.2) ------ ------ (88.5) (9) (1.8) - Wholesale 253.7 84 (18.2) (6) Transmission and Other (10.8) (21) 8.3 20 ------ ------ Total $154.4 11 $(11.7) (1) ====== ====== The increase in operating revenues in 2000 is primarily due to increased wholesale sales to the AEP Power Pool. With the return to service of the Cook Plant units and purchasing more power from AEGCo due to the expiration of AEGCo's contract to sell power to an unaffiliated entity, I&M had more electricity available to sell to the AEP Power Pool. A decline in retail sales and retail price which led to a decrease in retail operating revenues partly offset the increase in wholesale revenues. Operating revenues decreased slightly in 1999 primarily due to reduced margins on I&M's MLR share of wholesale sales and net revenues from regulated power trading transactions in the AEP Power Pool's traditional marketing area. The decline in margins reflects the moderation in 1999 of extreme weather in 1998 and capacity shortages experienced in the summer of 1998. Operating Expenses Increase Total operating expenses increased 23% in 2000 and 4% in 1999 primarily due to costs related to the extended Cook Plant outage and efforts to restart the Cook Plant units. Also contributing to the increase in operating expenses in 2000 was the unfavorable COLI tax ruling and the additional purchases of power due to the expiration of an AEGCo unit power agreement to sell part of its Rockport Plant generation to an unaffiliated utility. The changes in the components of operating expenses were: Increase (Decrease) From Previous Year (dollars in millions) - --------------------- 2000 1999 ----------------------------- Amount % Amount % Fuel $ 25.5 14 $ 12.8 7 Purchased Power 60.4 22 (21.1) (7) Other Operation 137.5 30 114.3 33 Maintenance 84.5 62 (22.3) (14) Depreciation and Amortization 4.9 3 4.9 3 Taxes Other Than Federal Income Taxes 11.0 19 (8.8) (13) Federal Income Taxes (26.1) (149) (34.1) (66) ------ ------ Total $297.7 23 $ 45.7 4 ====== ====== The increase in fuel expense in 2000 reflects an increase in nuclear generation as the Cook Plant units returned to service following an extended outage. Fuel expense increased in 1999 primarily due to an increase in coal-fired generation replacing power purchases from the AEP Power Pool. Purchased power expense increased in 2000 due to increased purchases from AEGCo. As a result of the expiration of AEGCo's power sale contract with an unaffiliated utility on December 31, 1999, I&M was obligated to buy more of AEGCo's share of Rockport Plant power. The decrease in purchased power expense in 1999 reflects the purchase of less power in 1999 at lower prices from the AEP Power Pool, AEGCo and unaffiliated entities. The increases in other operation expense in 2000 and 1999 were primarily due to expenditures to prepare the Cook Plant nuclear units for restart. Maintenance expense increased in 2000 primarily due to expenditures to prepare the Cook Plant units for restart. The decline in maintenance expense in 1999 was due to cost containment efforts including staff reductions at I&M's fossil-fired power plants, in the engineering and maintenance staff of AEP Service Corporation and in I&M's transmission and distribution operations. In 1999 the IURC and MPSC approved settlement agreements which allowed the deferral of $200 million of Cook Plant restart costs in 1999 for amortization over five years from 1999 through 2003. As a result, other operation and maintenance expense in 1999 reflected a net deferral of $160 million. See discussion in Note 4 of the Notes to Consolidated Financial Statements. The increase in taxes other than federal income tax in 2000 is primarily attributable to an increase in Indiana supplemental net income tax reflecting the COLI decision related interest deduction disallowance and a favorable accrual adjustment recorded in December 1999 related to the filing of the 1998 tax return. The decrease in taxes other than federal income taxes in 1999 was primarily due to a decline in estimated taxable income for Indiana supplemental income tax. Federal income taxes attributable to operations decreased in 2000 and 1999 due to decreases in pre-tax operating income. In 2000 the decrease was partially offset by an increase in tax expense related to the unfavorable ruling in the suit against the IRS over interest deductions claimed for the COLI program. Nonoperating Income The increase in nonoperating income in 2000 and 1999 is primarily due to the effect of net gains on non-regulated electricity trading transactions. The AEP Power Pool enters into non-regulated 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. I&M's share of the AEP Power Pool's non-regulated trading transactions are included in nonoperating income. Interest Charges Interest charges increased in 2000 and 1999 due to increased borrowings to support expenditures for the Cook Plant restart effort and in 2000 also due to the recognition of deferred interest payments to the IRS on the disputed taxes.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Income - ------------------------------------------------------------------------------------------------------------------------------------ Year Ended December 31, --------------------------------------- 2000 1999 1998 ---- ---- ---- (in thousands) OPERATING REVENUES $1,548,476 $1,394,119 $1,405,794 ---------- ---------- ---------- OPERATING EXPENSES: Fuel 210,870 185,419 172,592 Purchased Power 337,376 276,962 298,046 Other Operation 599,012 461,494 347,207 Maintenance 219,854 135,331 157,593 Depreciation and Amortization 154,920 149,988 145,112 Taxes Other Than Federal Income Taxes 69,761 58,713 67,592 Federal Income Tax Expense (Credit) (8,615) 17,560 51,645 ---------- ---------- ---------- Total Operating Expenses 1,583,178 1,285,467 1,239,787 ---------- ---------- ---------- OPERATING INCOME (LOSS) (34,702) 108,652 166,007 NONOPERATING INCOME (LOSS) 9,933 4,530 (839) ---------- ---------- ---------- INCOME (LOSS) BEFORE INTEREST CHARGES (24,769) 113,182 165,168 INTEREST CHARGES 107,263 80,406 68,540 ---------- ---------- ---------- NET INCOME (LOSS) (132,032) 32,776 96,628 PREFERRED STOCK DIVIDEND REQUIREMENTS 4,624 4,885 4,824 ---------- ---------- ---------- EARNINGS (LOSS) APPLICABLE TO COMMON STOCK $ (136,656) $ 27,891 $ 91,804 ==========- ========== ========== See Notes to Consolidated Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Consolidated Balance Sheets - ------------------------------------------------------------------------ December 31, 2000 1999 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production $2,708,436 $2,587,288 Transmission 945,709 928,758 Distribution 863,736 818,697 General (including nuclear fuel) 257,152 244,981 Construction Work in Progress 96,440 190,303 ---------- ---------- Total Electric Utility Plant 4,871,473 4,770,027 Accumulated Depreciation and Amortization 2,280,521 2,194,397 ---------- ---------- NET ELECTRIC UTILITY PLANT 2,590,952 2,575,630 ---------- ---------- NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR FUEL DISPOSAL TRUST FUNDS 778,720 707,967 ---------- ---------- LONG-TERM ENERGY TRADING CONTRACTS 194,947 23,131 ---------- ---------- OTHER PROPERTY AND INVESTMENTS 131,417 190,527 ---------- ---------- CURRENT ASSETS: Cash and Cash Equivalents 14,835 3,863 Accounts Receivable: Customers 106,832 91,268 Affiliated Companies 48,706 48,901 Miscellaneous 27,491 18,644 Allowance for Uncollectible Accounts (759) (1,848) Fuel - at average cost 16,532 27,597 Materials and Supplies - at average cost 84,471 84,149 Accrued Utility Revenues - 44,428 Energy Trading Contracts 1,229,683 97,946 Prepayments 6,424 7,631 ---------- ---------- TOTAL CURRENT ASSETS 1,534,215 422,579 ---------- ---------- REGULATORY ASSETS 552,140 624,810 ---------- ---------- DEFERRED CHARGES 36,156 32,052 ---------- ---------- TOTAL $5,818,547 $4,576,696 ========== ========== See Notes to Consolidated Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES - --------------------------------------------------------------------------------------------------------- December 31, --------------------------- 2000 1999 ---- ---- (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock - No Par Value: Authorized - 2,500,000 Shares Outstanding - 1,400,000 Shares $ 56,584 $ 56,584 Paid-in Capital 733,072 732,739 Retained Earnings 3,443 166,389 ---------- ---------- Total Common Shareholder's Equity 793,099 955,712 Cumulative Preferred Stock: Not Subject to Mandatory Redemption 8,736 9,248 Subject to Mandatory Redemption 64,945 64,945 Long-term Debt 1,298,939 1,126,326 ---------- ---------- TOTAL CAPITALIZATION 2,165,719 2,156,231 ---------- ---------- OTHER NONCURRENT LIABILITIES: Nuclear Decommissioning 560,628 501,185 Other 108,600 242,522 ---------- ---------- TOTAL OTHER NONCURRENT LIABILITIES 669,228 743,707 ---------- ---------- CURRENT LIABILITIES: Long-term Debt Due Within One Year 90,000 198,000 Short-term Debt - 224,262 Advances from Affiliates 253,582 - Accounts Payable - General 119,472 78,784 Accounts Payable - Affiliated Companies 75,486 31,118 Taxes Accrued 68,416 48,970 Interest Accrued 21,639 13,955 Obligations Under Capital Leases 100,848 11,072 Energy Trading Contracts 1,275,097 95,564 Other 97,070 91,684 ---------- ---------- TOTAL CURRENT LIABILITIES 2,101,610 793,409 ---------- ---------- DEFERRED INCOME TAXES 487,945 622,157 ---------- ---------- DEFERRED INVESTMENT TAX CREDITS 113,773 121,627 ---------- ---------- DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2 81,299 85,005 ---------- ---------- LONG-TERM ENERGY TRADING CONTRACTS 156,736 17,887 ---------- ---------- DEFERRED CREDITS 42,237 36,673 ---------- ---------- COMMITMENTS AND CONTINGENCIES (Note 8) TOTAL $5,818,547 $4,576,696 ========== ========== See Notes to Consolidated Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Cash Flows - ------------------------------------------ Year Ended December 31, 2000 1999 1998 ---- ---- ---- (in thousands) OPERATING ACTIVITIES: Net Income (Loss) $(132,032) $ 32,776 $ 96,628 Adjustments for Noncash Items: Depreciation and Amortization 163,391 153,921 149,209 Amortization of Incremental Nuclear Refueling Outage Expenses (net) 5,737 8,480 14,142 Amortization (Deferral) of Nuclear Outage Costs (net) 40,000 (160,000) - Deferred Federal Income Taxes (125,179) 85,727 17,905 Deferred Investment Tax Credits (7,854) (8,152) (8,266) Unrecovered Fuel and Purchased Power Costs 37,501 (84,696) (46,846) Changes in Certain Current Assets and Liabilities: Accounts Receivable (net) (25,305) (19,178) 1,462 Fuel, Materials and Supplies 10,743 (12,880) (2,983) Accrued Utility Revenues 44,428 (7,151) (6,756) Accounts Payable 85,056 19,068 22,440 Taxes Accrued 19,446 13,809 (11,689) Disputed Tax and Interest Related to COLI 56,856 (3,228) (53,628) Other (net) (41,900) 12,831 (8,176) --------- --------- --------- Net Cash Flows From Operating Activities 130,888 31,327 163,442 --------- --------- --------- INVESTING ACTIVITIES: Construction Expenditures (171,071) (165,331) (147,627) Proceeds from Sales of Property and Other 587 2,501 4,419 --------- --------- --------- Net Cash Flows Used For Investing Activities (170,484) (162,830) (143,208) --------- --------- --------- FINANCING ACTIVITIES: Issuance of Long-term Debt 199,220 247,989 170,675 Retirement of Cumulative Preferred Stock (314) (3,597) (120) Retirement of Long-term Debt (148,000) (109,500) (55,000) Changes in Advances from Affiliates (net) 253,582 - - Change in Short-term Debt (net) (224,262) 115,562 (10,900) Dividends Paid on Common Stock (26,290) (114,656) (117,464) Dividends Paid on Cumulative Preferred Stock (3,368) (5,856) (4,734) --------- --------- --------- Net Cash Flows From (Used For) Financing Activities 50,568 129,942 (17,543) --------- --------- --------- Net Increase (Decrease) in Cash and Cash Equivalents 10,972 (1,561) 2,691 Cash and Cash Equivalents January 1 3,863 5,424 2,733 --------- --------- --------- Cash and Cash Equivalents December 31 $ 14,835 $ 3,863 $ 5,424 ========= ========= ========= Supplemental Disclosure: Cash paid (received) for interest net of capitalized amounts was $82,511,000, $78,703,000 and $66,313,000 and for income taxes was $73,254,000, $(71,395,000) and $36,413,000 in 2000, 1999 and 1998, respectively. Noncash acquisitions under capital leases were $22,218,000, $10,852,000 and $9,658,000 in 2000, 1999 and 1998, respectively. See Notes to Consolidated Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Retained Earnings - ------------------------------------- Year Ended December 31, 2000 1999 1998 ---- ---- ---- (in thousands) Retained Earnings January 1 $ 166,389 $253,154 $278,814 Net Income (Loss) (132,032) 32,776 96,628 --------- -------- -------- 34,357 285,930 375,442 --------- -------- -------- Deductions: Cash Dividends Declared: Common Stock 26,290 114,656 117,464 Cumulative Preferred Stock: 4-1/8% Series 230 244 247 4.56% Series 66 66 67 4.12% Series 74 78 79 5.90% Series 897 963 985 6-1/4% Series 1,203 1,250 1,266 6.30% Series 834 834 834 6-7/8% Series 1,186 1,238 1,255 --------- -------- -------- Total Cash Dividends Declared 30,780 119,329 122,197 Capital Stock Expense 134 212 91 --------- -------- -------- Total Deductions 30,914 119,541 122,288 --------- -------- -------- Retained Earnings December 31 $ 3,443 $166,389 $253,154 ========= ======== ======== See Notes to Consolidated Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Capitalization - ------------------------------------------------------------------------------- December 31, ----------------------------- 2000 1999 ---- ---- (in thousands) COMMON SHAREHOLDER'S EQUITY $ 793,099 $ 955,712 ---------- ---------- PREFERRED STOCK: $100 Par Value - Authorized 2,250,000 shares $25 Par Value - Authorized 11,200,000 shares Call Price Number of Shares Redeemed Shares December 31, Year Ended December 31, Outstanding Series 2000 2000 1999 1998 December 31, 2000 - -------------------------------------------------------------------------------- Not Subject to Mandatory Redemption: 4-1/8% 106.125 3,750 97 771 55,389 5,539 5,914 4.56% 102 - 150 650 14,412 1,441 1,441 4.12% 102.728 1,375 - 200 17,556 1,756 1,893 ---------- ---------- 8,736 9,248 ---------- ---------- Subject to Mandatory Redemption: 5.90% (a,b) - 15,000 - 152,000 15,200 15,200 6-1/4% (a,b) - 10,000 - 192,500 19,250 19,250 6.30% (a,b) - - - 132,450 13,245 13,245 6-7/8% (a,c) - 10,000 - 172,500 17,250 17,250 ---------- ---------- 64,945 64,945 ---------- ---------- LONG-TERM DEBT (See Schedule of Long-term Debt): First Mortgage Bonds 308,976 356,820 Installment Purchase Contracts 309,717 309,568 Senior Unsecured Notes 397,435 297,282 Other Long-term Debt 211,307 199,259 Junior Debentures 161,504 161,397 Less Portion Due Within One Year (90,000) (198,000) ---------- ---------- Long-term Debt Excluding Portion Due Within One Year 1,298,939 1,126,326 ---------- ---------- TOTAL CAPITALIZATION $2,165,719 $2,156,231 ========== ========== (a) Not callable until after 2002. There are no aggregate sinking fund provisions through 2002. Sinking fund provisions require the redemption of 15,000 shares in 2003 and 67,500 shares in each 2004 and 2005. (b) Commencing in 2004 and continuing through 2008 the Company may redeem, at $100 per share, 20,000 shares of the 5.90% series, 15,000 shares of the 6-1/4% series and 17,500 shares of the 6.30% series outstanding under sinking fund provisions at its option and all remaining outstanding shares must be redeemed not later than 2009. Shares redeemed in 1999 and 1997 may be applied to meet the sinking fund requirement. (c) Commencing in 2003 and continuing through the year 2007, a sinking fund will require the redemption of 15,000 shares each year and the redemption of the remaining shares outstanding on April 1, 2008, in each case at $100 per share. Shares redeemed in 1999 and 1997 may be applied to meet the sinking fund requirement. See Notes to Consolidated 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, -------------------- 2000 1999 ---- ---- (in thousands) % Rate Due 6.40 2000 - March 1 $ - $ 48,000 7.63 2001 - June 1 40,000 40,000 7.60 2002 - November 1 50,000 50,000 7.70 2002 - December 15 40,000 40,000 6.10 2003 - November 1 30,000 30,000 8.50 2022 - December 15 75,000 75,000 7.35 2023 - October 1 20,000 20,000 7.20 2024 - February 1 30,000 30,000 7.50 2024 - March 1 25,000 25,000 Unamortized Discount (1,024) (1,180) -------- -------- $308,976 $356,820 Certain indentures relating to the first mortgage bonds contain improvement, maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. Installment purchase contracts have been entered into, in connection with the issuance of pollution control revenue bonds by governmental authorities as follows: December 31, 2000 1999 ---- ---- (in thousands) % Rate Due - ------ ----------------- City of Lawrenceburg, Indiana: 7.00 2015 - April 1 $ 25,000 $ 25,000 5.90 2019 - November 1 52,000 52,000 City of Rockport, Indiana: (a) 2014 - August 1 50,000 50,000 7.60 2016 - March 1 40,000 40,000 6.55 2025 - June 1 50,000 50,000 (b) 2025 - June 1 50,000 50,000 City of Sullivan, Indiana: 5.95 2009 - May 1 45,000 45,000 Unamortized Discount (2,283) (2,432) -------- -------- $309,717 $309,568 (a) A variable interest rate is determined weekly. The average weighted interest rate was 4.5% for 2000 and 3.2% for 1999. (b) An adjustable interest rate can be a daily, weekly, commercial paper or term rate as designated by I&M. A weekly rate was selected which ranged from 2.9% to 5.9% in 2000 and from 2.2% to 5.6% in 1999 and averaged 4.2% and 3.2% during 2000 and 1999, respectively. Under the terms of the installment purchase contracts, I&M is required to pay amounts sufficient to enable the cities to pay interest on and the principal (at stated maturities and upon mandatory redemptions) of related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain generating plants. On the two variable rate series the principal is payable at the stated maturities or on the demand of the bondholders at periodic interest adjustment dates which occur weekly. The variable rate bonds due in 2014 are supported by a bank letter of credit which expires in 2002. I&M has agreements that provide for brokers to remarket the adjustable rate bonds due in 2025 tendered at interest adjustment dates. In the event certain bonds cannot be remarketed, I&M has a standby bond purchase agreement with a bank that provides for the bank to purchase any bonds not remarketed. The purchase agreement expires in 2001. Accordingly, the variable and adjustable rate installment purchase contracts have been classified for repayment purposes based on the expiration dates of the standby purchase agreement and the letter of credit. Senior unsecured notes outstanding were as follows: December 31, --------------------- 2000 1999 ---- ---- (in thousands) % Rate Due - ------ ------------------ (a) 2000 - November 22 $ - $100,000 (b) 2002 - September 3 200,000 - 6-7/8 2004 - July 1 150,000 150,000 6.45 2008 - November 10 50,000 50,000 Unamortized Discount (2,565) (2,718) -------- -------- $397,435 $297,282 (a) A floating interest rate is determined monthly. The rate on December 31, 1999 was 7.1%. (b) A floating interest rate is determined quarterly. The rate on December 31, 2000 was 7.31%. Junior debentures outstanding were as follows: December 31, 2000 1999 ---- ---- (in thousands) % Rate Due - ------ ----------------- 8.00 2026 - March 31 $ 40,000 $ 40,000 7.60 2038 - June 30 125,000 125,000 Unamortized Discount (3,496) (3,603) -------- -------- Total $161,504 $161,397 ======== ======== 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, 2000, future annual long-term debt payments are as follows: Amount ------ (in thousands) 2001 $ 90,000 2002 340,000 2003 30,000 2004 150,000 2005 - Later Years 788,307 ---------- Total Principal Amount 1,398,307 Unamortized Discount (9,368) ---------- Total $1,388,939 ========== INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Index to Notes to Consolidated Financial Statements The notes listed below are combined with the notes to financial statements for AEP and its other subsidiary registrants. The combined footnotes begin on page L-1. Combined Footnote Reference Significant Accounting Policies Note 1 Merger Note 3 Nuclear Plant Restart Note 4 Rate Matters Note 5 Effects of Regulation Note 6 Industry Restructuring Note 7 Commitments and Contingencies Note 8 Staff Reductions Note 11 Benefit Plans Note 12 Business Segments Note 14 Financial Instruments, Credit and Risk Management Note 15 Income Taxes Note 16 Supplementary Information Note 17 Leases Note 18 Lines of Credit and Factoring of Receivables Note 19 Unaudited Quarterly Financial Information Note 20 Related Party Transactions Note 23 INDEPENDENT AUDITORS' REPORT To the Shareholders and Board of Directors of Indiana Michigan Power Company: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Indiana Michigan Power Company and its subsidiaries as of December 31, 2000 and 1999, and the related consolidated statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2000. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Indiana Michigan Power Company and its subsidiaries as of December 31, 2000 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2000 in conformity with accounting principles generally accepted in the United States of America. DELOITTE & TOUCHE LLP Columbus, Ohio February 26, 2001 KENTUCKY POWER COMPANY
G-11 KENTUCKY POWER COMPANY Selected Financial Data - ----------------------------------------------------------- Year Ended December 31, --------------------------------------------------------- 2000 1999 1998 1997 1996 ---- ---- ---- ---- ---- (in thousands) INCOME STATEMENTS DATA: Operating Revenues $410,403 $373,982 $362,999 $340,635 $323,321 Operating Expenses 360,665 319,307 311,106 293,779 281,978 -------- -------- -------- -------- -------- Operating Income 49,738 54,675 51,893 46,856 41,343 Nonoperating Income (Loss) 2,070 (327) (1,726) (464) (594) -------- -------- -------- -------- -------- Income Before Interest Charges 51,808 54,348 50,167 46,392 40,749 Interest Charges 31,045 28,918 28,491 25,646 23,776 -------- -------- -------- -------- -------- Net Income $ 20,763 $ 25,430 $ 21,676 $ 20,746 $ 16,973 ======== ======== ======== ======== ======== December 31, --------------------------------------------------------- 2000 1999 1998 1997 1996 ---- ---- ---- ---- ---- (in thousands) BALANCE SHEETS DATA: Electric Utility Plant $1,103,064 $1,079,048 $1,043,711 $1,006,955 $951,602 Accumulated Depreciation and Amortization 360,648 340,008 315,546 296,318 286,640 ---------- ---------- ---------- ---------- -------- Net Electric Utility Plant $ 742,416 $ 739,040 $ 728,165 $ 710,637 $664,962 ========== ========== ========== ========== ======== Total Assets $1,512,016 $ 986,638 $ 921,847 $ 886,671 $833,579 ========== ========== ========== ========== ======== Common Stock and Paid-in Capital $ 209,200 $ 209,200 $ 199,200 $ 179,200 $159,200 Retained Earnings 57,513 67,110 71,452 78,076 84,090 ---------- ---------- ---------- ---------- -------- Total Common Shareholder's Equity $ 266,713 $ 276,310 $ 270,652 $ 257,276 $243,290 ========== ========== ========== ========== ======== Long-term Debt(a) $ 330,880 $ 365,782 $ 368,838 $ 341,051 $293,198 ========== ========== ========== ========== ======== Obligations Under Capital leases (a) $ 14,184 $ 15,141 $ 18,977 $ 18,725 $ 12,850 ========== ========== ========== ========== ======== Total Capitalization and Liabilities $1,512,016 $ 986,638 $ 921,847 $ 886,671 $833,579 ========== ========== ========== ========== ======== (a) Including portion due within one year.
KENTUCKY POWER COMPANY Management's Narrative Analysis of Results of Operations - ---------------------------------------------------- KPCo is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power serving 172,000 retail customers in eastern Kentucky. KPCo as a member of the AEP System Power Pool (AEP Power Pool) shares in the revenues and costs of the AEP Power Pool's wholesale sales to neighboring utility systems and power marketers. KPCo also sells wholesale power to municipalities. The cost of the AEP System's generating capacity is allocated among the AEP Power Pool members based on their relative peak demands and generating reserves through the payment of capacity charges or the receipt of credits. AEP Power Pool members are also compensated for their out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each company's prior twelve month peak demand relative to the total peak demand of all member companies as a basis for sharing AEP Power Pool revenues and costs. The result of this calculation is the member load ratio (MLR) which determines each company's percentage share of AEP Power Pool revenues or costs. KPCo as a member of the AEP Power Pool shares in the revenues and costs of the AEP Power Pool's wholesale sales to and net forward trades with other utility systems and power marketers. Revenues from forward electricity trades are recorded net of purchases as operating revenues for transactions in AEP's traditional marketing area (up to two transmission systems from the AEP service territory) and as nonoperating income for transactions beyond two transmission systems from AEP. The AEP Power Pool also enters into power trading transactions for options, futures and swaps. KPCo's share of these transactions is recorded in nonoperating income. In February 2001 the U.S. District Court for the Southern District of Ohio ruled against AEP and certain of its subsidiaries, including KPCo, in a suit over deductibility of interest claimed in AEP's consolidated tax return related to a corporate owned life insurance (COLI) program. In 1998 and 1999 KPCo paid the disputed taxes and interest attributable to the COLI interest deductions for taxable years 1992-98. The payments were included in Other Property and Investments pending the resolution of this matter. As a result of the Court's decision, net income was reduced by $8 million in 2000. Net Income Decreases Net income decreased $4.7 million or 18% in 2000 primarily due to the COLI decision and an increase in maintenance expense. Operating Revenues Increase Operating revenues increased $36 million or 10% in 2000 due to a significant increase in AEP Power Pool transactions. Changes in the components of operating revenues were as follows: Increase (Decrease) (dollars in millions) From Previous Year Amount % Retail: Residential $ 6.1 5.7 Commercial (0.2) (0.3) Industrial (3.5) (3.7) ----- 2.4 0.9 Wholesale 37.2 49.0 Transmission 2.8 62.6 Other (6.0) (22.3) ----- Total $36.4 9.7 ===== The increase in operating revenues is due to increased KWH sales to residential customers as a result of colder weather and a significant increase in AEP Power Pool wholesale transactions. As a result of an affiliated company's major industrial customer's decision not to continue its purchased power agreement, additional power was available to the AEP Power Pool for wholesale sales contributing to the increase in the company's revenue. Purchased power also increased due to the availability of the Rockport Plant from which the company, under a unit power agreement, purchases 15% of the available power from Rockport. Rockport Plant generated 8% more KWH in the year 2000 than in the year 1999. In 2000 other revenues decreased substantially due to the effect of favorable adjustment to rental income in 1999 reflecting agreed to retroactive revisions to the billings for pole attachments with telecommunications companies. Operating Expenses Increase Operating expenses increased $41.4 million primarily due to increased purchased power, maintenance costs and federal income taxes. Changes in the components of operating expenses were as follows: Increase (Decrease) (dollars in millions) From Previous Year Amount % Fuel $(9.7) (11.5) Purchased Power 41.6 38.6 Other Operation 0.8 1.6 Maintenance 4.4 20.6 Depreciation and Amortization 1.8 6.2 Taxes Other Than Federal Income Taxes (1.1) (10.6) Federal Income Taxes 3.6 27.1 ----- Total $41.4 13.0 ===== Fuel expense decreased due to a decline in internal generation as a result of planned outages in 2000 at the company's Big Sandy Plant Unit 2. Purchased Power expense increased due to a significant increase in AEP Power Pool wholesale transactions and affiliated power purchases under a unit power agreement. The planned outages at Big Sandy Plant caused the increase in maintenance expense. Comparing 2000 to 1999, unit 1 of the Big Sandy Plant, experienced 3.6 weeks of various outages compared to 1 week of outages in 1999. Unit 2 experienced 6.8 weeks of outages in 2000 compared to 4.6 weeks in 1999. An increase in transmission plant investment and improvements to distribution facilities accounted for the increase in depreciation expense. Taxes other than federal income taxes decreased due to decreased Kentucky state income taxes as a result of lower pre-tax operating income partly offset by the unfavorable ruling in AEP's suit against the government over interest deductions claimed in prior years related to a COLI program. The increase in federal income tax expense was primarily due to the unfavorable ruling in AEP's suit against the government over interest deductions claimed in prior years related to a COLI program. Nonoperating Income Increase Nonoperating income increased due to the favorable effect of non-regulated electric trading outside the AEP Power Pool's traditional marketing area. The AEP Power Pool enters into transactions for the purchase and sale of electricity options, futures and swaps, and for the forward purchase and sale of electricity outside of the AEP System's traditional marketing area. The company's share of the AEP Power Pool's non-regulated trading transactions are included in nonoperating income. Interest Charges Increase The increase in interest charges resulted from the U.S. District Court's unfavorable decision denying Federal income tax deductions for COLI interest resulting in the incurrance of interest on taxes owed for prior years.
KENTUCKY POWER COMPANY Statements of Income - --------------------------------------------------------------------------------------- Year Ended December 31, 2000 1999 1998 ---- ---- ---- (in thousands) OPERATING REVENUES $410,403 $373,982 $362,999 -------- -------- -------- OPERATING EXPENSES: Fuel 74,638 84,369 83,303 Purchased Power 149,345 107,763 100,620 Other Operation 53,325 52,468 47,802 Maintenance 25,866 21,452 30,462 Depreciation and Amortization 31,028 29,221 28,080 Taxes Other Than Federal Income Taxes 9,709 10,854 9,687 Federal Income Taxes 16,754 13,180 11,152 -------- -------- -------- TOTAL OPERATING EXPENSES 360,665 319,307 311,106 -------- -------- -------- OPERATING INCOME 49,738 54,675 51,893 NONOPERATING INCOME (LOSS) 2,070 (327) (1,726) -------- -------- -------- INCOME BEFORE INTEREST CHARGES 51,808 54,348 50,167 INTEREST CHARGES 31,045 28,918 28,491 -------- -------- -------- NET INCOME $ 20,763 $ 25,430 $ 21,676 ======== ======== ======== Statements of Retained Earnings - -------------------------------------------------------------------------------------------------------------------------------- Year Ended December 31, 2000 1999 1998 ---- ---- ---- (in thousands) RETAINED EARNINGS JANUARY 1 $67,110 $71,452 $78,076 NET INCOME 20,763 25,430 21,676 CASH DIVIDENDS DECLARED 30,360 29,772 28,300 ------- ------- ------- RETAINED EARNINGS DECEMBER 31 $57,513 $67,110 $71,452 ======= ======= ======= See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY Balance Sheets - ---------------------------------------------------------------------------------------------------------------------------------- December 31, --------------------------- 2000 1999 ---- ---- (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production $ 271,107 $ 268,618 Transmission 360,563 355,442 Distribution 387,499 372,752 General 67,476 67,608 Construction Work in Progress 16,419 14,628 ---------- ---------- Total Electric Utility Plant 1,103,064 1,079,048 Accumulated Depreciation and Amortization 360,648 340,008 ---------- ---------- NET ELECTRIC UTILITY PLANT 742,416 739,040 ---------- ---------- OTHER PROPERTY AND INVESTMENTS 6,559 12,406 ---------- ---------- LONG-TERM ENERGY TRADING CONTRACTS 76,657 8,010 ---------- ---------- CURRENT ASSETS: Cash and Cash Equivalents 2,270 674 Accounts Receivable: Customers 34,555 18,952 Affiliated Companies 22,119 15,223 Miscellaneous 6,419 8,343 Allowance for Uncollectible Accounts (282) (637) Fuel - at average cost 4,760 10,441 Materials and Supplies - at average cost 15,408 18,113 Accrued Utility Revenues 6,500 13,737 Energy Trading Contracts 483,537 33,919 Prepayments 766 1,450 ---------- ---------- TOTAL CURRENT ASSETS 576,052 120,215 ---------- ---------- REGULATORY ASSETS 98,515 96,296 ---------- ---------- DEFERRED CHARGES 11,817 10,671 ---------- ---------- TOTAL $1,512,016 $ 986,638 ========== ========== See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY - -------------------------------------------------------------------------------------------------------------------- December 31, ----------------------- 2000 1999 ---- ---- (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock - Par Value $50: Authorized - 2,000,000 Shares Outstanding - 1,009,000 Shares $ 50,450 $ 50,450 Paid-in Capital 158,750 158,750 Retained Earnings 57,513 67,110 ---------- -------- Total Common Shareholder's Equity 266,713 276,310 Long-term Debt 270,880 260,782 ---------- -------- TOTAL CAPITALIZATION 537,593 537,092 ---------- -------- OTHER NONCURRENT LIABILITIES 18,348 23,797 ---------- -------- CURRENT LIABILITIES: Long-term Debt Due Within One Year 60,000 105,000 Short-term Debt - 39,665 Advances from Affiliates 47,636 - Accounts Payable - General 32,043 9,923 Accounts Payable - Affiliated Companies 37,506 19,743 Customer Deposits 4,389 4,143 Taxes Accrued 11,885 9,860 Interest Accrued 5,610 4,843 Energy Trading Contracts 496,884 33,094 Other 14,517 12,020 ---------- -------- TOTAL CURRENT LIABILITIES 710,470 238,291 ---------- -------- DEFERRED INCOME TAXES 165,935 165,007 ---------- -------- DEFERRED INVESTMENT TAX CREDITS 11,656 12,908 ---------- -------- LONG-TERM ENERGY TRADING CONTRACTS 61,632 6,194 ---------- -------- DEFERRED CREDITS 6,382 3,349 ---------- -------- COMMITMENTS AND CONTINGENCIES (Note 8) TOTAL $1,512,016 $986,638 ========== ========
KENTUCKY POWER COMPANY Statements of Cash Flows - ----------------------------------------------------------------------------------------------------------------------------------- Year Ended December 31, 2000 1999 1998 ---- ---- ---- (in thousands) OPERATING ACTIVITIES: Net Income $ 20,763 $ 25,430 $ 21,676 Adjustments for Noncash Items: Depreciation and Amortization 31,034 29,228 28,092 Deferred Income Taxes 3,765 2,596 3,607 Deferred Investment Tax Credits (1,252) (1,292) (1,415) Deferred Fuel Costs (net) 2,948 828 (449) Changes in Certain Current Assets and Liabilities: Accounts Receivable (net) (20,930) (6,618) (6,663) Fuel, Materials and Supplies 8,386 (7,014) 3,199 Accrued Utility Revenues 7,237 (177) (579) Accounts Payable 39,883 4,935 157 Taxes Accrued 2,025 2,604 1,126 Disputed Tax and Interest Related to COLI 5,943 (567) (5,376) Other (net) (4,559) (3,019) (2,215) --------- -------- -------- Net Cash Flows From Operating Activities 95,243 46,934 41,160 --------- -------- -------- INVESTING ACTIVITIES: Construction Expenditures (36,209) (44,339) (43,769) Proceeds from Sales of Property 266 168 - --------- -------- -------- Net Cash Flows Used For Investing Activities (35,943) (44,171) (43,769) --------- -------- -------- FINANCING ACTIVITIES: Capital Contributions from Parent Company - 10,000 20,000 Issuance of Long-term Debt 69,685 79,740 29,816 Retirement of Long-term Debt (105,000) (83,307) (2,203) Change in Short-term Debt (net) (39,665) 19,315 (16,150) Change in Advances from Affiliates (net) 47,636 - - Dividends Paid (30,360) (29,772) (28,300) --------- -------- -------- Net Cash Flows From (Used For) Financing Activities (57,704) (4,024) 3,163 --------- -------- -------- Net Increase (Decrease) in Cash and Cash Equivalents 1,596 (1,261) 554 Cash and Cash Equivalents January 1 674 1,935 1,381 --------- -------- -------- Cash and Cash Equivalents December 31 $ 2,270 $ 674 $ 1,935 ========= ======== ======== Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $28,619,000, $29,845,000 and $27,857,000 and for income taxes was $7,923,000, $12,050,000 and $8,607,000 in 2000, 1999 and 1998, respectively. Noncash acquisitions under capital leases were $2,817,000, $2,219,000 and $4,890,000 in 2000, 1999 and 1998, respectively. See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY Statements of Capitalization - ----------------------------------------------------------------- December 31, 2000 1999 ---- ---- (in thousands) COMMON SHAREHOLDER'S EQUITY $266,713 $276,310 -------- -------- LONG-TERM DEBT (See Schedule of Long-term Debt): First Mortgage Bonds 119,341 119,270 Senior Unsecured Notes 147,490 157,502 Notes Payable 25,000 50,000 Junior Debentures 39,049 39,010 Less Portion Due Within One Year (60,000) (105,000) -------- -------- Long-term Debt Excluding Portion Due Within One Year 270,880 260,782 -------- -------- TOTAL CAPITALIZATION $537,593 $537,092 ======== ======== 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, -------------------- 2000 1999 ---- ---- (in thousands) % Rate Due 8.95 2001 - May 10 $ 20,000 $ 20,000 8.90 2001 - May 21 40,000 40,000 6.65 2003 - May 1 15,000 15,000 6.70 2003 - June 1 15,000 15,000 6.70 2003 - June 1 15,000 15,000 7.90 2023 - June 1 14,500 14,500 Unamortized Discount (159) (230) -------- -------- $119,341 $119,270 Certain indentures relating to the first mortgage bonds contain improvement, maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. Senior unsecured notes outstanding were as follows: December 31, 2000 1999 ---- ---- (in thousands) % Rate Due - ------ ------------------ (a) 2000 - November 2 $ - $ 80,000 (b) 2002 - November 19 70,000 - 6.91 2007 - October 1 48,000 48,000 6.45 2008 - November 10 30,000 30,000 Unamortized Discount (510) (498) -------- -------- 147,490 157,502 Less Portion Due Within One Year - 80,000 -------- -------- Total $147,490 $ 77,502 ======== ======== (a) A floating interest rate is determined monthly. The rate on December 31, 1999 was 7.23%. (b) A floating interest rate is determined monthly. The rate on December 31, 2000 was 7.4075%. Notes Payable to Banks outstandings were as follows: 6.57 2000 - April 1 $ - $25,000 7.45 2002 - September 20 25,000 25,000 ------- ------- Total $25,000 $50,000 ======= ======= Junior debentures outstanding were as follows: December 31, 2000 1999 ---- ---- (in thousands) % Rate Due - ------ ----------------- 8.72 2025 - June 30 $40,000 $40,000 Unamortized Discount (951) (990) ------- ------- Total $39,049 $39,010 ======= ======= 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, 2000, future annual long-term debt payments are as follows: Amount ------ (in thousands) 2001 $ 60,000 2002 95,000 2003 45,000 2004 - 2005 - Later Years 132,500 -------- Total Principal Amount 332,500 Unamortized Discount (1,620) -------- Total $330,880 ======== KENTUCKY POWER COMPANY Index to Notes to 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 Merger Note 3 Rate Matters Note 5 Effects of Regulation Note 6 Commitments and Contingencies Note 8 Staff Reductions Note 11 Benefit Plans Note 12 Business Segments Note 14 Financial Instruments, Credit and Risk Management Note 15 Income Taxes Note 16 Leases Note 18 Lines of Credit and Factoring of Receivables Note 19 Unaudited Quarterly Financial Information Note 20 Related Party Transactions Note 23 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, 2000 and 1999, and the related statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2000. 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, 2000 and 1999, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2000 in conformity with accounting principles generally accepted in the United States of America. DELOITTE & TOUCHE LLP Columbus, Ohio February 26, 2001 OHIO POWER COMPANY AND SUBSIDIARIES
H-14 OHIO POWER COMPANY AND SUBSIDIARIES Selected Consolidated Financial Data - ------------------------------------------------------------------------------------------------------- Year Ended December 31, ---------------------------------------------------------- 2000 1999 1998 1997 1996 ---- ---- ---- ---- ---- (in thousands) INCOME STATEMENTS DATA: Operating Revenues $2,227,902 $2,039,263 $2,105,547 $1,892,110 $1,911,708 Operating Expenses 2,001,075 1,750,434 1,816,175 1,615,717 1,614,547 ---------- ---------- ---------- ---------- ---------- Operating Income 226,827 288,829 289,372 276,393 297,161 Nonoperating Income (Loss) (5,004) 7,000 588 14,822 6,374 ---------- ---------- ---------- ---------- ---------- Income Before Interest Charges 221,823 295,829 289,960 291,215 303,535 Interest Charges 119,210 83,672 80,035 82,526 85,880 ---------- ---------- ---------- ---------- ---------- Income Before Extraordinary Item 102,613 212,157 209,925 208,689 217,655 Extraordinary Loss (18,876) - - - - ---------- ---------- ---------- ---------- ---------- Net Income 83,737 212,157 209,925 208,689 217,655 Preferred Stock Dividend Requirements 1,266 1,417 1,474 2,647 8,778 ---------- ---------- ---------- ---------- ---------- Earnings Applicable to Common Stock $ 82,471 $ 210,740 $ 208,451 $ 206,042 $ 208,877 ========== ========== ========== ========== ========== December 31, ---------------------------------------------------------- 2000 1999 1998 1997 1996 ---- ---- ---- ---- ---- (in thousands) BALANCE SHEETS DATA: Electric Utility Plant $5,577,631 $5,400,917 $5,257,841 $5,155,797 $4,996,621 Accumulated Depreciation and Amortization 2,764,130 2,621,711 2,461,376 2,349,995 2,216,534 ---------- ---------- ---------- ---------- ---------- Net Electric Utility Plant $2,813,501 $2,779,206 $2,796,465 $2,805,802 $2,780,087 ========== ========== ========== ========== ========== Total Assets $6,252,436 $4,677,209 $4,344,680 $4,163,202 $4,092,166 ========== ========== ========== ========== ========== Common Stock and Paid-in Capital $ 783,684 $ 783,577 $ 783,536 $ 783,497 $ 781,863 Retained Earnings 398,086 587,424 587,500 590,151 584,015 ---------- ---------- ---------- ---------- ---------- Total Common Shareholder's Equity $1,181,770 $1,371,001 $1,371,036 $1,373,648 $1,365,878 ========== ========== ========== ========== ========== Cumulative Preferred Stock: Not Subject to Mandatory Redemption $ 16,648 $ 16,937 $ 17,370 $ 17,542 $ 38,532 Subject to Mandatory Redemption (a) 8,850 8,850 11,850 11,850 109,900 ---------- ---------- ---------- ---------- ---------- Total Cumulative Preferred Stock $ 25,498 $ 25,787 $ 29,220 $ 29,392 $ 148,432 ========== ========== ========== ========== ========== Long-term Debt (a) $1,195,493 $1,151,511 $1,084,928 $1,095,226 $1,069,729 ========== ========== ========== ========== ========== Obligations Under Capital Leases (a) $ 116,581 $ 136,543 $ 142,635 $ 157,487 $ 131,285 ========== ========== ========== ========== ========== Total Capitalization and Liabilities $6,252,436 $4,677,209 $4,344,680 $4,163,202 $4,092,166 ========== ========== ========== ========== ========== (a) Including portion due within one year.
OHIO POWER COMPANY AND SUBSIDIARIES Management's Discussion and Analysis of Results of Operations OPCo is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to 696,000 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. OPCo also sells wholesale power to municipalities and cooperatives. The cost of the AEP System's generating capacity is allocated among the AEP Power Pool members based on their relative peak demands and generating reserves through the payment of capacity charges 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 or costs. OPCo as a member of the AEP Power Pool shares in the revenues and costs of the AEP Power Pool's wholesale sales to and net forward trades with other utility systems and power marketers. Revenues from forward electricity trades are recorded net of purchases as operating revenues for transactions in AEP's traditional marketing area (up to two transmission systems from the AEP service territory) and as nonoperating income for transactions beyond two transmission systems from AEP. The AEP Power Pool also enters into power trading transactions for options, futures and swaps. OPCo's share of these transactions is recorded in nonoperating income. Results of Operations 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 a corporate owned life insurance (COLI) program. 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. As a result of the Court's decision, net income was reduced by $118 million in 2000. Income before extraordinary item decreased $110 million or 52% in 2000 due predominantly to the disallowance of COLI related tax deductions. An extraordinary loss related to the discontinuance of SFAS 71 regulatory accounting, of approximately $19 million after tax, was recorded in September 2000 in connection with the PUCO's approval of a plan to transition OPCo's generation business from cost based rate regulation to customer choice and market pricing. Net income increased $2 million or 1% in 1999 primarily due to a decline in operation and maintenance costs reflecting cost containment efforts. Operating Revenues and Energy Sales Operating revenues increased 9% in 2000 following a decrease of 3% in 1999. The changes in the components of revenues were as follows: Increase (Decrease) From Previous Year (Dollars in Millions) 2000 1999 ----------------------------- Amount % Amount % Retail: Residential $ (4.2) $ 7.5 Commercial 1.7 0.4 Industrial (126.0) (5.0) Other 0.2 - ------- ------ (128.3) (9) 2.9 - Wholesale 322.1 56 (71.9) (11) Transmission and Other (5.2) (6) 2.7 3 ------- ------ Total $ 188.6 9 $(66.3) (3) ======= ====== The increase in operating revenues in 2000 resulted from increased wholesale sales to the AEP Power Pool and the Company's share of increased Power Pool wholesale sales to and net revenues from trading of electricity with other utility systems and power marketers. As a result of one of OPCo's major industrial customers deciding not to continue its power purchase agreement, OPCo was able to deliver additional power to the AEP Power Pool accounting for part of the increase in wholesale revenues. Wholesale revenues also benefited from the growth in AEP's marketing and trading operation, favorable wholesale market conditions and increased availability of AEP Power Pool generation for wholesale sales. The increase in AEP Power Pool generation availability was due to the return to service of one of an affiliate's nuclear units in June 2000 and improved generating unit outage management. Operating revenues declined 3% in 1999 primarily due to a decline in margins on wholesale sales and net power trading transactions and decreased sales to the AEP Power Pool. Operating Expenses Operating expenses increased by 14% in 2000 mostly due to increases in fuel expense, purchased power expense, other operation expense and federal income taxes. Operating expenses decreased 4% in 1999 from cost containment efforts and lower fuel costs due mainly to a decrease in generation reflecting lower demand for wholesale energy. Changes in the components of operating expenses were as follows: Increase (Decrease) From Previous Year (dollars in millions) --------------------- 2000 1999 Amount % Amount % ---------------------------- ------ --- ------ ---- Fuel $ 84.3 12 $(50.8) (7) Purchased Power 20.9 13 12.4 8 Other Operation 80.2 25 (26.1) (7) Maintenance 3.4 3 (18.3) (13) Depreciation and Amortization 6.9 5 4.6 3 Taxes Other Than Federal Income Taxes (0.3) - (3.5) (2) Federal Income Taxes 55.2 41 16.0 13 ------ ------ Total Operating Expenses $250.6 14 $(65.7) (4) ====== ====== Fuel expense increased in 2000 due to increases in generation and the average cost of fuel consumed reflecting shutdown costs included in the cost of coal delivered from affiliated mining operations. Fuel expense decreased in 1999 due to a 6% decrease in generation reflecting the decline in wholesale sales. The increase in purchased power expense was due to a significant increase in AEP Power Pool transactions. Other operation expense increased in 2000 mainly due to increased power generation costs. Increased emission allowance consumption and allowance prices and increased costs of AEP's growing power marketing and trading operation, including incentive compensation, accounted for the increase in generation costs. The increase in emission allowance usage and prices resulted from the stricter air quality standards of Phase II of the 1990 Clean Air Act Amendments which became effective on January 1, 2000. The decrease in other operation expense in 1999 was due to lower coal-fired power plant expenses reflecting cost containment efforts, and an increase in gains on emission allowance sales. The cost containment efforts included staff reductions in transmission and distribution operations, at the power plants and within the engineering and maintenance group of AEP Service Corporation which bills OPCo for operations support services. These cost containment efforts were the primary reason for the decrease in maintenance expense in 1999. The increase in federal income tax expense in 2000 was primarily due to the unfavorable ruling relating to AEP's COLI program. Federal income taxes attributable to operations increased in 1999 due to changes in certain book/tax differences accounted for on a flow-through basis for rate-making purposes and an increase in pre-tax operating income. Nonoperating Income The decrease in nonoperating income in 2000 is due to the disallowance of COLI-related tax deductions for coal-mining operations that are no longer operating. Extraordinary Loss An extraordinary loss was recorded in the third quarter of 2000 when OPCo discontinued the application of SFAS 71 regulatory accounting for the generation portion of its business due to the approval in September 2000 of a stipulation agreement by the PUCO providing for a transition from cost based rate regulation for OPCo's generation business to customer choice and market pricing.
OHIO POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Income - --------------------------------------------- Year Ended December 31, ------------------------------------------ 2000 1999 1998 ---- ---- ---- (in thousands) OPERATING REVENUES $2,227,902 $2,039,263 $2,105,547 ---------- ---------- ---------- OPERATING EXPENSES: Fuel 771,969 687,672 738,522 Purchased Power 184,004 163,143 150,733 Other Operation 407,375 327,132 353,194 Maintenance 124,735 121,299 139,611 Depreciation and Amortization 155,944 149,055 144,493 Taxes Other Than Federal Income Taxes 165,552 165,891 169,353 Federal Income Taxes 191,496 136,242 120,269 ---------- ---------- ---------- Total Operating Expenses 2,001,075 1,750,434 1,816,175 ---------- ---------- ---------- OPERATING INCOME 226,827 288,829 289,372 NONOPERATING INCOME (LOSS) (5,004) 7,000 588 ---------- ---------- ---------- INCOME BEFORE INTEREST CHARGES 221,823 295,829 289,960 INTEREST CHARGES 119,210 83,672 80,035 ---------- ---------- ---------- INCOME BEFORE EXTRAORDINARY ITEM 102,613 212,157 209,925 EXTRAORDINARY LOSS - Discontinuance of Regulatory Accounting for Generation (inclusive of Tax Benefit of $21,281,000) (18,876) - - ---------- ---------- ----------- NET INCOME 83,737 212,157 209,925 PREFERRED STOCK DIVIDEND REQUIREMENTS 1,266 1,417 1,474 ---------- ---------- ---------- EARNINGS APPLICABLE TO COMMON STOCK $ 82,471 $ 210,740 $ 208,451 ========== ========== ========== See Notes to Consolidated Financial Statements beginning on page L-1.
OHIO POWER COMPANY AND SUBSIDIARIES Consolidated Balance Sheets - -------------------------------------------------------------------------------------------------- December 31, 2000 1999 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production $2,764,155 $2,713,421 Transmission 870,033 857,420 Distribution 1,040,940 999,679 General (including mining assets) 707,417 713,882 Construction Work in Progress 195,086 116,515 ---------- ----------- Total Electric Utility Plant 5,577,631 5,400,917 Accumulated Depreciation and Amortization 2,764,130 2,621,711 ---------- ----------- NET ELECTRIC UTILITY PLANT 2,813,501 2,779,206 ---------- ----------- OTHER PROPERTY AND INVESTMENTS 109,124 221,756 ---------- ----------- LONG-TERM ENERGY TRADING CONTRACTS 256,455 31,912 ---------- ----------- CURRENT ASSETS: Cash and Cash Equivalents 31,393 157,138 Advances to Affiliates 92,486 - Accounts Receivable: Customers 139,732 246,310 Affiliated Companies 126,203 89,215 Miscellaneous 39,046 22,055 Allowance for Uncollectible Accounts (1,054) (2,223) Fuel - at average cost 82,291 129,022 Materials and Supplies - at average cost 96,053 95,967 Accrued Utility Revenues 264 45,575 Energy Trading Contracts 1,617,660 134,567 Prepayments and Other 32,882 38,472 ---------- ----------- TOTAL CURRENT ASSETS 2,256,956 956,098 ---------- ----------- REGULATORY ASSETS 714,710 594,385 ---------- ----------- DEFERRED CHARGES 101,690 93,852 ---------- ----------- TOTAL $6,252,436 $ 4,677,209 ========== =========== See Notes to Consolidated Financial Statements beginning on page L-1.
OHIO POWER COMPANY AND SUBSIDIARIES - -------------------------------------------------------------------------------------------------------------------- December 31, 2000 1999 (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 462,483 462,376 Retained Earnings 398,086 587,424 ---------- ---------- Total Common Shareholder's Equity 1,181,770 1,371,001 Cumulative Preferred Stock: Not Subject to Mandatory Redemption 16,648 16,937 Subject to Mandatory Redemption 8,850 8,850 Long-term Debt 1,077,987 1,139,834 ---------- ---------- TOTAL CAPITALIZATION 2,285,255 2,536,622 ---------- ---------- OTHER NONCURRENT LIABILITIES 542,017 414,837 ---------- ---------- CURRENT LIABILITIES: Long-term Debt Due Within One Year 117,506 11,677 Short-term Debt - 194,918 Accounts Payable - General 179,691 180,383 Accounts Payable - Affiliated Companies 121,360 64,599 Customer Deposits 39,736 8,196 Taxes Accrued 223,101 179,112 Interest Accrued 20,458 16,863 Obligations Under Capital Leases 32,716 34,284 Energy Trading Contracts 1,662,315 131,844 Other 151,934 88,249 ---------- ---------- TOTAL CURRENT LIABILITIES 2,548,817 910,125 ---------- ---------- DEFERRED INCOME TAXES 621,941 676,460 ---------- ---------- DEFERRED INVESTMENT TAX CREDITS 25,214 35,838 ---------- ---------- LONG-TERM ENERGY TRADING CONTRACTS 206,187 24,677 ---------- ---------- DEFERRED CREDITS 23,005 78,650 ---------- ---------- COMMITMENTS AND CONTINGENCIES (Note 8) TOTAL $6,252,436 $4,677,209 ========== ========== See Notes to Consolidated Financial Statements beginning on page L-1.
OHIO POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Cash Flows - -------------------------------------------------------------------------------------------------------------------------- Year Ended December 31, 2000 1999 1998 ---- ---- ---- (in thousands) OPERATING ACTIVITIES: Net Income $ 83,737 $ 212,157 $ 209,925 Adjustments for Noncash Items: Depreciation, Depletion and Amortization 200,350 193,780 172,085 Deferred Income Taxes (65,956) 3,666 3,042 Deferred Investment Tax Credits (3,399) (3,458) (3,525) Deferred Fuel Costs (net) (56,869) (76,978) (44,694) Extraordinary Loss - Discontinuance of SFAS 71 18,876 - - Changes in Certain Current Assets and Liabilities: Accounts Receivable (net) 51,430 (49,309) (12,376) Fuel, Materials and Supplies 46,645 (60,500) 18,612 Accrued Utility Revenues 45,311 (2,074) (5,915) Accounts Payable 56,069 9,195 51,040 Disputed Tax and Interest Related to COLI 110,494 (6,272) (104,222) Change in Operating Reserves 145,573 66,573 77,811 Other (net) 6,232 48,718 42,981 --------- --------- --------- Net Cash Flows From Operating Activities 638,493 335,498 404,764 --------- --------- --------- INVESTING ACTIVITIES: Construction Expenditures (254,016) (193,870) (185,036) Proceeds from Sales of Property and Other 6,354 5,900 5,910 --------- --------- --------- Net Cash Flows Used For Investing Activities (247,662) (187,970) (179,126) --------- --------- --------- FINANCING ACTIVITIES: Issuance of Long-term Debt 74,748 222,308 186,126 Changes in Advances to Affiliates (net) (92,486) - - Retirement of Cumulative Preferred Stock (182) (3,392) (133) Retirement of Long-term Debt (30,663) (158,638) (197,911) Change in Short-term Debt (net) (194,918) 71,913 44,305 Dividends Paid on Common Stock (271,813) (210,813) (211,101) Dividends Paid on Cumulative Preferred Stock (1,262) (1,420) (1,475) --------- --------- --------- Net Cash Flows Used For Financing Activities (516,576) (80,042) (180,189) --------- --------- --------- Net Increase (Decrease) in Cash and Cash Equivalents (125,745) 67,486 45,449 Cash and Cash Equivalents January 1 157,138 89,652 44,203 --------- --------- --------- Cash and Cash Equivalents December 31 $ 31,393 $ 157,138 $ 89,652 ========= ========= ========= Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $87,120,000, $78,739,000 and $79,667,000 and for income taxes was $142,710,000, $94,606,000 and $118,548,000 in 2000, 1999 and 1998, respectively. Noncash acquisitions under capital leases were $17,005,000, $28,561,000 and $29,938,000 in 2000, 1999 and 1998, respectively. See Notes to Consolidated Financial Statements beginning on page L-1.
OHIO POWER COMPANY AND SUBSIDIARIES Consolidated Statement of Retained Earnings - ---------------------------------------------------------------------------------------------------------------------------------- Year Ended December 31, 2000 1999 1998 ---- ---- ---- (in thousands) Retained Earnings January 1 $587,424 $587,500 $590,151 Net Income 83,737 212,157 209,925 -------- -------- -------- 671,161 799,657 800,076 -------- -------- -------- Deductions: Cash Dividends Declared: Common Stock 271,813 210,813 211,101 Cumulative Preferred Stock: 4.08% Series 59 61 63 4.20% Series 96 97 97 4.40% Series 139 142 143 4-1/2% Series 442 460 467 5.90% Series 428 472 487 6.02% Series 66 156 186 6.35% Series 32 32 32 -------- -------- -------- Total Dividends 273,075 212,233 212,576 -------- -------- -------- Retained Earnings December 31 $398,086 $587,424 $587,500 ======== ======== ======== See Notes to Consolidated Financial Statements beginning on page L-1.
OHIO POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Capitalization - ------------------------------------------------------------------------------------------------------------------------------------ December 31, ----------------------------- 2000 1999 ---- ---- (in thousands) COMMON SHAREHOLDER'S EQUITY $1,181,770 $1,371,001 ---------- ---------- PREFERRED STOCK - authorized shares 3,762,403 $100 par value authorized shares 4,000,000 $25 par value Call Price Shares December 31, Par Number of Shares Redeemed Outstanding Series(a) 2000 Value Year Ended December 31, December 31, 2000 - ------ ------------ ----- ---------------------------- ----------------- 2000 1999 1998 ---- ---- ---- Not Subject to Mandatory Redemption: 4.08% $103 $100 - 373 425 14,595 1,460 1,460 4.20% 103.20 100 276 - - 22,824 2,282 2,310 4.40% 104 100 432 330 200 31,512 3,151 3,194 4-1/2% 110.00 100 2,181 3,631 1,096 97,546 9,755 9,973 ------ ------ 16,648 16,937 ------ ------ Subject to Mandatory Redemption: 5.90% (b) - $100 - 10,000 - 72,500 7,250 7,250 6.02% (c) - 100 - 20,000 - 11,000 1,100 1,100 6.35% (c) - 100 - - - 5,000 500 500 ------ ------ 8,850 8,850 ------ ------ LONG-TERM DEBT (See Schedule of Long-term Debt): First Mortgage Bonds 316,294 323,772 Installment Purchase Contracts 233,130 233,025 Senior Unsecured Notes 471,583 408,671 Notes Payable 30,000 30,000 Junior Debentures 131,980 131,860 Other Long-term Debt 12,506 24,183 Less Portion Due Within One Year (117,506) (11,677) ---------- ---------- Long-term Debt Excluding Portion Due Within One Year 1,077,987 1,139,834 ---------- ---------- TOTAL CAPITALIZATION $2,285,255 $2,536,622 ========== ========== (a) The series subject to mandatory redemption are not callable until after 2002. The sinking fund provisions of each series subject to mandatory redemption have been met by purchase of shares in advance of the due date. (b) Commencing in 2004 and continuing through the year 2008, a sinking fund for the 5.90% cumulative preferred stock will require the redemption of 22,500 shares each year and the redemption of the remaining shares outstanding on January 1, 2009, in each case at $100 per share. Shares previously redeemed may be applied to meet sinking fund requirements. (c) Commencing in 2003 and continuing through 2007 cumulative preferred stock sinking funds will require the redemption of 20,000 shares each year of the 6.02% series and 15,000 shares each year of the 6.35% series, in each case at $100 per share. All remaining outstanding shares must be redeemed in 2008. Shares previously redeemed may be applied to meet the sinking fund requirements. See Notes to Consolidated Financial Statements beginning on page L-1.
OHIO POWER COMPANY AND SUBSIDIARIES Schedule of Long-term Debt - ------------------------------------------------------ First mortgage bonds outstanding were as follows: December 31, -------------------- 2000 1999 ---- ---- (in thousands) % Rate Due 6.75 2003 - April 1 $ 38,850 $ 40,000 6.55 2003 - October 1 32,135 32,135 6.00 2003 - November 1 25,000 25,000 6.15 2003 - December 1 50,000 50,000 8.80 2022 - February 10 50,000 50,000 7.75 2023 - April 1 40,000 40,000 7.375 2023 - October 1 40,000 40,000 7.10 2023 - November 1 20,000 23,000 7.30 2024 - April 1 21,500 25,000 Unamortized Discount (1,191) (1,363) -------- -------- Total $316,294 $323,772 ======== ======== Certain indentures relating to the first mortgage bonds contain improvement, maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. Installment purchase contracts have been entered into in connection with the issuance of pollution control revenue bonds by governmental authorities as follows: December 31, 2000 1999 ---- ---- (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 (1,870) (1,975) -------- -------- Total $233,130 $233,025 ======== ======== Under the terms of the installment purchase contracts, OPCo is required to pay amounts sufficient to enable the payment of interest on and the principal (at stated maturities and upon mandatory redemptions) of related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants. Senior unsecured notes outstanding were as follows: December 31, -------------------- 2000 1999 ---- ---- (in thousands) % Rate Due - ------ ------------------ (a) 2001 - May 16 $ 75,000 $ - 6.75 2004 - July 1 100,000 100,000 7.00 2004 - July 1 75,000 75,000 6.73 2004 - November 1 48,000 48,000 6.24 2008 - December 4 37,225 50,000 7-3/8 2038 - June 30 140,000 140,000 Unamortized Discount (3,642) (4,329) -------- -------- Total $471,583 $408,671 ======== ======== (a) A floating interest rate is determined monthly. The rate on December 31, 2000 was 7.26%. Notes payable outstanding were as follows: December 31, 2000 1999 ---- ---- (in thousands) % Rate Due 6.20 2001 - January 31 $ 5,000 $ 5,000 6.20 2001 - January 31 7,000 7,000 6.20 2001 - January 31 18,000 18,000 ------- ------- Total $30,000 $30,000 ======= ======= Junior debentures outstanding were as follows: December 31, 2000 1999 ---- ---- (in thousands) % Rate Due - ------ ----------------- 8.16 2025 - September 30 $ 85,000 $ 85,000 7.92 2027 - March 31 50,000 50,000 Unamortized Discount (3,020) (3,140) -------- -------- Total $131,980 $131,860 ======== ======== Interest may be deferred and payment of principal and interest on the junior debentures is subordinated and subject in right to the prior payment in full of all senior indebtedness of the Company. Finance obligations were entered into by the Company's coal mining subsidiaries for mining facilities and equipment through sale and leaseback transactions. In accordance with SFAS 98, the transactions did not qualify as sales and leasebacks for accounting purposes and therefore are shown as other long-term debt. The terms on the remaining long-term debt obligation including renewals end on December 24, 2001 and contain a bargain purchase option at expiration of the agreement. At December 31, 2000, the interest rate was 6.98%. At December 31, 2000, future annual long-term debt payments are as follows: Amount ------ (in thousands) 2001 $ 117,506 2002 - 2003 145,985 2004 223,000 2005 - Later Years 718,725 ---------- Total Principal Amount 1,205,216 Unamortized Discount (9,723) ---------- Total $1,195,493 ========== OHIO POWER COMPANY AND SUBSIDIARIES Index to Notes to Consolidated Financial Statements The notes listed below are combined with the notes to financial statements for AEP and its other subsidiary registrants. The combined footnotes begin on page L-1. Combined Footnote Reference Significant Accounting Policies Note 1 Extraordinary Items Note 2 Rate Matters Note 5 Effects of Regulation Note 6 Industry Restructuring Note 7 Commitments and Contingencies Note 8 Staff Reductions Note 11 Benefit Plans Note 12 Business Segments Note 14 Financial Instruments, Credit and Risk Management Note 15 Income Taxes Note 16 Supplementary Information Note 17 Leases Note 18 Lines of Credit and Factoring of Receivables Note 19 Unaudited Quarterly Financial Information Note 20 Related Party Transactions Note 23 INDEPENDENT AUDITORS' REPORT To the Shareholders and Board of Directors of Ohio Power Company: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Ohio Power Company and its subsidiaries as of December 31, 2000 and 1999, and the related consolidated statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2000. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Ohio Power Company and its subsidiaries as of December 31, 2000 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2000 in conformity with accounting principles generally accepted in the United States of America. DELOITTE & TOUCHE LLP Columbus, Ohio February 26, 2001 PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
I-11 PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES Selected Consolidated Financial Data Year Ended December 31, ----------------------------------------------------------- 2000 1999 1998 1997 1996 ---- ---- ---- ---- ---- (in thousands) INCOME STATEMENTS DATA: Operating Revenues $ 962,609 $749,390 $780,159 $712,690 $735,265 Operating Expenses 865,940 650,677 665,085 630,666 635,527 ---------- -------- -------- -------- -------- Operating Income 96,669 98,713 115,074 82,024 99,738 Nonoperating Income (Loss) 8,974 946 (91) 1,649 (35,511) ---------- -------- -------- -------- -------- Income Before Interest Charges 105,643 99,659 114,983 83,673 64,227 Interest Charges 38,980 38,151 38,074 37,218 34,748 ---------- -------- -------- -------- -------- Net Income 66,663 61,508 76,909 46,455 29,479 Preferred Stock Dividend Requirements 212 212 213 364 816 Gain On Reacquired Preferred Stock - - - 4,211 - ---------- -------- -------- -------- -------- Earnings Applicable to Common Stock $ 66,451 $ 61,296 $ 76,696 $ 50,302 $ 28,663 ========== ======== ======== ======== ======== December 31, ----------------------------------------------------------- 2000 1999 1998 1997 1996 ---- ---- ---- ---- ---- (in thousands) BALANCE SHEETS DATA: Electric Utility Plant $2,604,670 $2,459,705 $2,391,722 $2,339,908 $2,290,175 Accumulated Depreciation and Amortization 1,150,253 1,114,255 1,082,081 1,031,322 987,283 ---------- ---------- ---------- ---------- ---------- Net Electric Utility Plant $1,454,417 $1,345,450 $1,309,641 $1,308,586 $1,302,892 ========== ========== ========== ========== ========== Total Assets $2,142,156 $1,524,726 $1,470,939 $1,464,562 $1,447,107 ========== ========== ========== ========== ========== Common Stock and Paid-in Capital $ 337,230 $ 337,230 $ 337,230 $ 337,230 $ 337,230 Retained Earnings 137,688 139,237 142,941 135,245 143,944 ---------- ---------- ---------- ---------- ---------- Total Common Shareholder's Equity $ 474,918 $ 476,467 $ 480,171 $ 472,475 $ 481,174 ========== ========== ========== ========== ========== Cumulative Preferred Stock: Not Subject to Mandatory Redemption $ 5,283 $ 5,286 $ 5,287 $ 5,287 $ 19,826 ========== ========== ========== ========== ========== Preferred Securities of Subsidiary Trust $ 75,000 $ 75,000 $ 75,000 $ 75,000 $ - ========== ========== ========== ========== =========== Long-term Debt (a) $ 470,822 $ 384,516 $ 384,064 $ 438,703 $ 438,369 ========== ========== ========== ========== ========== Total Capitalization and Liabilities $2,142,156 $1,524,726 $1,470,939 $1,464,562 $1,447,107 ========== ========== ========== ========== ========== (a) Including portion due within one year.
PUBLIC SERVICE COMPANY OF OKLAHOMA Management's Narrative Analysis of Results of Operations PSO is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to approximately 499,000 retail customers in eastern and southwestern Oklahoma. PSO also sells electric power at wholesale to other utilities, municipalities and rural electric cooperatives. PSO participates in power marketing and trading activities conducted on its behalf by the AEP System. PSO shares in the revenues and costs of the AEP Power Pool wholesale sales to and net forward trades with other utility systems and power marketers. Revenues from trading of electricity are recorded net of purchases as operating revenues. Results of Operations Rise Net income increased $5.2 million or 8.4% in 2000 due mainly to a gain from the sale of a minority interest in Scientech, Inc. Scientech provides services, systems and instruments, which describe, regulate, monitor and enhance the safety and reliability of power plant operations and their environmental impact. Operating Revenues Operating revenues rose 28% due to an increase in fuel and purchased power revenues, reflecting price increases in fuel and purchased power expenses, and an increase in power sales to neighboring utilities and power marketers. Changes in the components of operating revenues were as follows: Increase From Previous Year (dollars in millions) Amount % - ---------------------- ------ - Retail: Residential $ 65.8 22 Commercial 52.2 23 Industrial 37.4 23 Other 1.9 20 ------ 157.3 Wholesale 54.8 140 Transmission and Other 1.1 6 ------ --- Total $213.2 28 ====== === Revenues from retail customers increased as a result of an increase in fuel-related revenues that reflect rising prices for natural gas used for generation and higher purchased power prices. The Oklahoma fuel clause recovery mechanism provides for the accrual of fuel-related revenues until reviewed and approved for billing to customers by the Oklahoma Corporation Commission. The accrual of additional fuel and purchased power revenues is offset by increases in fuel and purchased power expenses. As a result, accrued fuel-related revenues do not impact results of operations. The increase in wholesale revenues is attributable to increased sales volumes to other utilities and prices reflecting the increase in gas prices and PSO's participation in the AEP System's power marketing and trading operations. The volume of electricity sales to other utilities, both affiliated and unaffiliated, increased as demand for energy rose in response to warmer summer weather. Since PSO became a subsidiary of AEP in June 2000 as a result of a merger with CSW, PSO shares in the AEP System's power marketing and trading transactions with other entities. Trading involves the purchase and sale of substantial amounts of electricity at wholesale to non-affiliated parties. Revenues from trading are recorded net of purchases. Operating Expenses Increase Operating expenses were $215.3 million more in 2000 than in 1999 largely as a result of increased fuel and purchased power expenses. Changes in the components of operating expenses were as follows: Increase (Decrease) From Previous Year (dollars in millions) Amount % - ---------------------- ------ - Fuel Expense $133.6 50 Purchased Power Expense 80.2 107 Other Operation (0.2) N.M. Depreciation and Amortization 1.7 2 Taxes Other Than Federal Income Taxes (1.7) (5) Federal Income Taxes 1.7 6 ------ Total $215.3 33 ====== N.M. = Not Meaningful The increases in fuel and purchased power were due primarily to a rise in the average unit fuel cost and higher prices for economy energy purchases reflecting an increase in natural gas prices. As discussed above, changes in fuel and purchased power expenses are generally reflected in revenues on an accrual basis and as such did not impact results of operations. Nonoperating Income Nonoperating income increased $8 million primarily due to the gain from the sale of PSO's minority interest in Scientech, Inc. in 2000.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES Consolidated Statements of Income - ----------------------------------------------------------------------------------------------- Year Ended December 31, --------------------------------------- 2000 1999 1998 ---- ---- ---- (in thousands) OPERATING REVENUES $962,609 $749,390 $780,159 -------- -------- -------- OPERATING EXPENSES: Fuel 402,933 269,316 309,969 Purchased Power 155,087 74,893 57,222 Other Operation 121,697 121,896 109,285 Maintenance 45,858 45,809 36,981 Depreciation and Amortization 76,418 74,736 72,671 Taxes Other Than Federal Income Taxes 33,235 34,970 36,733 Federal Income Taxes 30,712 29,057 42,224 -------- -------- -------- Total Operating Expenses 865,940 650,677 665,085 -------- -------- -------- OPERATING INCOME 96,669 98,713 115,074 NONOPERATING INCOME (LOSS) 8,974 946 (91) -------- -------- -------- INCOME BEFORE INTEREST CHARGES 105,643 99,659 114,983 INTEREST CHARGES 38,980 38,151 38,074 -------- -------- -------- NET INCOME 66,663 61,508 76,909 PREFERRED STOCK DIVIDEND REQUIREMENTS 212 212 213 -------- -------- -------- EARNINGS APPLICABLE TO COMMON STOCK $ 66,451 $ 61,296 $ 76,696 ======== ======== ======== Consolidated Statements of Retained Earnings - ------------------------------------------------------------------------------------------------------------------------------- Year Ended December 31, --------------------------------------- 2000 1999 1998 ---- ---- ---- (in thousands) BALANCE AT BEGINNING OF PERIOD AS PREVIOUSLY REPORTED $142,019 $144,626 $136,996 CONFORMING CHANGE IN ACCOUNTING POLICY (2,782) (1,685) (1,751) -------- -------- -------- ADJUSTED BALANCE AT BEGINNING OF PERIOD 139,237 142,941 135,245 NET INCOME 66,663 61,508 76,909 DEDUCTIONS: Cash Dividends Declared: Common Stock 68,000 65,000 69,000 Preferred Stock 212 212 213 -------- -------- -------- BALANCE AT END OF PERIOD $137,688 $139,237 $142,941 ======== ======== ======== See Notes to Consolidated Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES Consolidated Balance Sheets - ----------------------------------------------------------------------------- December 31, 2000 1999 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production $ 914,096 $ 916,889 Transmission 396,695 392,029 Distribution 938,053 897,516 General 206,731 217,368 Construction Work in Progress 149,095 35,903 ---------- ---------- Total Electric Utility Plant 2,604,670 2,459,705 Accumulated Depreciation and Amortization 1,150,253 1,114,255 ---------- ---------- NET ELECTRIC UTILITY PLANT 1,454,417 1,345,450 ---------- ---------- OTHER PROPERTY AND INVESTMENTS 38,211 46,205 ---------- ---------- LONG-TERM ENERGY TRADING CONTRACTS 52,629 - ---------- ----------- CURRENT ASSETS: Cash and Cash Equivalents 11,301 3,173 Accounts Receivable: Customers 60,424 32,301 Affiliated Companies 3,453 2,283 Allowance for Uncollectible Accounts (467) - Fuel - at LIFO cost 28,113 24,143 Materials and Supplies - at average cost 29,642 34,289 Under-recovered Fuel Costs 43,267 6,469 Energy Trading Contracts 382,380 - Prepayments 1,559 1,572 ---------- ---------- TOTAL CURRENT ASSETS 559,672 104,230 ---------- ---------- REGULATORY ASSETS 29,338 16,717 ---------- ---------- DEFERRED CHARGES 7,889 12,124 ---------- ---------- TOTAL $2,142,156 $1,524,726 ========== ========== See Notes to Consolidated Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES - --------------------------------------------------------------------------------------------------- December 31, -------------------------- 2000 1999 ---- ---- (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock - $15 Par Value: Authorized Shares: 11,000,000 Issued Shares: 10,482,000 Outstanding Shares: 9,013,000 $ 157,230 $ 157,230 Paid-in Capital 180,000 180,000 Retained Earnings 137,688 139,237 ---------- ---------- Total Common Shareholder's Equity 474,918 476,467 ---------- ---------- Cumulative Preferred Stock Not Subject To Mandatory Redemption 5,283 5,286 PSO-Obligated, Mandatorily Redeemable Preferred Securities of Subsidiary Trust Holding Solely Junior Subordinated Debentures of PSO 75,000 75,000 Long-term Debt 450,822 364,516 ---------- ---------- TOTAL CAPITALIZATION 1,006,023 921,269 ---------- ---------- CURRENT LIABILITIES: Long-term Debt Due Within One Year 20,000 20,000 Advances from Affiliates 81,120 79,169 Accounts Payable - General 104,379 44,088 Accounts Payable - Affiliated Companies 64,556 35,517 Customer Deposits 19,294 17,751 Taxes Accrued 1,659 18,480 Interest Accrued 8,336 5,420 Energy Trading Contracts 389,279 - Other 12,137 8,059 ---------- ---------- TOTAL CURRENT LIABILITIES 700,760 228,484 ---------- ---------- DEFERRED INCOME TAXES 312,060 281,916 ---------- ---------- DEFERRED INVESTMENT TAX CREDITS 35,783 37,574 ---------- ---------- REGULATORY LIABILITIES AND DEFERRED CREDITS 35,292 55,483 ---------- ---------- LONG-TERM ENERGY TRADING CONTRACTS 52,238 - ---------- ----------- CONTINGENCIES (Note 8) TOTAL $2,142,156 $1,524,726 ========== ========== See Notes to Consolidated Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES Consolidated Statements of Cash Flows - ------------------------------------------------------------------------------------------------------------------------ Year Ended December 31, ------------------------------------- 2000 1999 1998 ---- ---- ---- (in thousands) OPERATING ACTIVITIES: Net Income $ 66,663 $ 61,508 $ 76,909 Adjustments for Noncash Items: Depreciation and Amortization 76,418 74,736 72,671 Deferred Income Taxes 25,453 14,521 (1,651) Deferred Investment Tax Credits (1,791) (1,791) (1,795) Changes in Certain Assets and Liabilities: Accounts Receivable (net) (28,826) (1,668) (13,308) Fuel, Materials and Supplies 677 (8,985) (5,809) Other Property and Investments 7,994 (2,108) (2,835) Accounts Payable 89,330 (8,000) 2,196 Taxes Accrued (16,821) (4,615) 23,095 Fuel Recovery (36,798) (21,709) 30,605 Transmission Coordination Agreement Settlement (15,063) 15,063 - Other (net) (1,621) (5,509) 13,035 --------- --------- --------- Net Cash Flows From Operating Activities 165,615 111,443 193,113 --------- --------- --------- INVESTING ACTIVITIES: Construction Expenditures (176,851) (103,122) (68,897) Proceeds from Sales of Property and Other Items - (8,659) (8,271) --------- --------- --------- Net Cash Flows Used For Investing Activities (176,851) (111,781) (77,168) --------- --------- --------- FINANCING ACTIVITIES: Issuance of Long-term Debt 105,625 33,232 - Retirement of Long-term Debt (20,000) (33,700) (55,231) Change in Advances from Affiliates (net) 1,951 63,277 11,018 Dividends Paid on Common Stock (68,000) (65,000) (69,000) Dividends Paid on Cumulative Preferred Stock (212) (212) (213) --------- --------- --------- Net Cash Flows From (Used For) Financing Activities 19,364 (2,403) (113,426) --------- --------- --------- Net Increase (Decrease) in Cash and Cash Equivalents 8,128 (2,741) 2,519 Cash and Cash Equivalents January 1 3,173 5,914 3,395 --------- --------- --------- Cash and Cash Equivalents December 31 $ 11,301 $ 3,173 $ 5,914 ========= ========= ========= Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $33,732,000, $37,081,000 and $37,772,000 and for income taxes was $25,786,000, $23,871,000 and $37,712,000 in 2000, 1999, and 1998, respectively. See Notes to Consolidated Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES Consolidated Statements of Capitalization - ---------------------------------------------------------------------------------------------------------------------------- December 31, ----------------------------- 2000 1999 ---- ---- (in thousands) COMMON SHAREHOLDER'S EQUITY $ 474,918 $ 476,467 ---------- ---------- PREFERRED STOCK - authorized shares 700,000, cumulative $100 par value redeemable at the option of PSO upon 30 days notice. Call Price Shares December 31, Number of Shares Redeemed Outstanding Series 2000 Year Ended December 31, December 31, 2000 - ------ ------------ ---------------------------- ----------------- 2000 1999 1998 ---- ---- ---- Not Subject to Mandatory Redemption: 4.00% $105.75 25 9 - 44,606 4,460 4,463 4.24% 103.19 - - - 8,069 807 807 Premium 16 16 ---------- ---------- 5,283 5,286 ---------- ---------- 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 317,465 337,160 Installment Purchase Contracts 47,357 47,356 Senior Unsecured Notes 106,000 - Less Portion Due Within One Year (20,000) (20,000) ---------- ---------- Long-term Debt Excluding Portion Due Within One Year 450,822 364,516 ---------- ---------- TOTAL CAPITALIZATION $1,006,023 $ 921,269 ========== ========== See Notes to Consolidated Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES Schedule of Long-term Debt - ------------------------------------------------------- First mortgage bonds outstanding were as follows: December 31, -------------------- 2000 1999 ---- ---- (in thousands) % Rate Due 6.43 2000 - March 30 $ - $ 10,000 5.89 2000 - December 15 - 10,000 5.91 2001 - March 1 6,000 6,000 6.02 2001 - March 1 5,000 5,000 6.02 2001 - March 1 9,000 9,000 6.25 2003 - April 1 35,000 35,000 7.25 2003 - July 1 65,000 65,000 7.38 2004 - December 1 50,000 50,000 6.50 2005 - June 1 50,000 50,000 7.38 2023 - April 1 100,000 100,000 Unamortized Discount (2,535) (2,840) -------- -------- $317,465 $337,160 Certain indentures relating to the first mortgage bonds contain improvement, maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. Installment purchase contracts have been entered into in connection with the issuance of pollution control revenue bonds by governmental authorities as follows: December 31, 2000 1999 ---- ---- (in thousands) % Rate Due Oklahoma Environmental Finance Authority (OEFA): 5.90 2007 - December 1 $ 1,000 $ 1,000 Oklahoma Development Finance Authority (ODFA): 4.875 2014 - June 1 33,700 33,700 Red River Authority of Texas: 6.00 2020 - June 1 12,660 12,660 Unamortized Discount (3) (4) ------- ------- Total $47,357 $47,356 ======= ======= Under the terms of the installment purchase contracts, PSO is required to pay amounts sufficient to enable the payment of interest on and the principal (at stated maturities and upon mandatory redemptions) of related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants. Senior unsecured notes outstanding were as follows: December 31, 2000 1999 ---- ---- (in thousands) % Rate Due - ------ ------------------ (a) 2002 - November 21 $106,000 $ - ======== ========= (a) A floating interest rate is determined monthly. The rate on December 31, 2000 was 7.376%. At December 31, 2000, future annual long-term debt payments are as follows: Amount ------ (in thousands) 2001 $ 20,000 2002 106,000 2003 100,000 2004 50,000 2005 50,000 Later Years 147,360 -------- Total Principal Amount 473,360 Unamortized Discount (2,538) -------- Total $470,822 ======== PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES Index to Notes to Consolidated Financial Statements The notes listed below are combined with the notes to financial statements for AEP and its other subsidiary registrants. The combined footnotes begin on page L-1. Combined Footnote Reference Significant Accounting Policies Note 1 Merger Note 3 Effects of Regulation Note 6 Industry Restructuring Note 7 Commitments and Contingencies Note 8 Benefit Plans Note 12 Business Segments Note 14 Financial Instruments, Credit and Risk Management Note 15 Income Taxes Note 16 Lines of Credit and Factoring of Receivables Note 19 Unaudited Quarterly Financial Information Note 20 Trust Preferred Securities Note 21 Jointly Owned Electric Utility Plant Note 22 Related Party Transactions Note 23 INDEPENDENT AUDITORS' REPORT To the Shareholders and Board of Directors of Public Service Company of Oklahoma: We have audited the accompanying consolidated balance sheet and consolidated statement of capitalization of Public Service Company of Oklahoma and subsidiaries as of December 31, 2000, and the related consolidated statements of income, retained earnings, and cash flows for the year then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit. The consolidated financial statements of the Company for the years ended December 31, 1999 and 1998, before the restatement described in Note 3 to the consolidated financial statements, were audited by other auditors whose report, dated February 25, 2000, expressed an unqualified opinion on those statements. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provide a reasonable basis for our opinion. In our opinion, the 2000 consolidated financial statements present fairly, in all material respects, the financial position of Public Service Company of Oklahoma and subsidiaries as of December 31, 2000, and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America. We also audited the adjustments described in Note 3 that were applied to restate the 1999 and 1998 consolidated financial statements to give retroactive effect to the conforming change in the method of accounting for vacation pay accruals. In our opinion, such adjustments are appropriate and have been properly applied. DELOITTE & TOUCHE LLP Columbus, Ohio February 26, 2001 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Stockholders and Board of Directors of Public Service Company Oklahoma: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Public Service Company of Oklahoma (an Oklahoma corporation and a wholly owned subsidiary of Central and South West Corporation) and subsidiary companies as of December 31, 1999, and the related consolidated statements of income, retained earnings and cash flows, for each of the two years in the period ended December 31, 1999 prior to the restatement (and, therefore, are not presented herein) for the retroactive effect of the conforming change in the method of accounting for vacation pay accruals and certain conforming reclassifications to the historical financial statements as described in Note 3 to the restated consolidated financial statements. These financial statements are the responsibility of Public Service Company of Oklahoma's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. 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 prior to the restatement referred to above present fairly, in all material respects, the financial position of Public Service Company of Oklahoma and subsidiary companies as of December 31, 1999, and results of their operations and their cash flows for each of the two years in the period ended December 31, 1999, in conformity with accounting principles generally accepted in the United States. Arthur Andersen LLP Dallas, Texas February 25, 2000 SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
J-12 SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Selected Consolidated Financial Data - ------------------------------------------------------------------------------------------------------------------------------ Year Ended December 31, ----------------------------------------------------------- 2000 1999 1998 1997 1996 ---- ---- ---- ---- ---- (in thousands) INCOME STATEMENTS DATA: Operating Revenues $1,124,210 $971,527 $952,952 $939,869 $920,786 Operating Expenses 995,932 824,465 802,274 800,396 786,669 ---------- -------- -------- -------- -------- Operating Income 128,278 147,062 150,678 139,473 134,117 Nonoperating Income (Loss) 3,851 (1,965) 2,451 4,029 (21,178) ---------- -------- -------- -------- -------- Income Before Interest Charges 132,129 145,097 153,129 143,502 112,939 Interest Charges 59,457 58,892 55,135 50,536 50,349 ---------- -------- -------- -------- -------- Income Before Extraordinary Item 72,672 86,205 97,994 92,966 62,590 Extraordinary Loss - (3,011) - - - ---------- -------- -------- -------- -------- Net Income 72,672 83,194 97,994 92,966 62,590 Preferred Stock Dividend Requirements 229 229 705 2,467 3,053 Gain (Loss) on Reacquired Preferred Stock - - (856) 1,819 - ---------- -------- -------- -------- --------- Earnings Applicable to Common Stock $ 72,443 $ 82,965 $ 96,433 $ 92,318 $ 59,537 ========== ======== ======== ======== ======== December 31, ----------------------------------------------------------- 2000 1999 1998 1997 1996 ---- ---- ---- ---- ---- (in thousands) BALANCE SHEETS DATA: Electric Utility Plant $3,319,024 $3,231,431 $3,157,911 $3,081,443 $3,044,314 Accumulated Depreciation and Amortization 1,457,005 1,384,242 1,317,057 1,225,865 1,192,356 ---------- ---------- ---------- ---------- ---------- Net Electric Utility Plant $1,862,019 $1,847,189 $1,840,854 $1,855,578 $1,851,958 ========== ========== ========== ========== ========== Total Assets $2,662,534 $2,106,215 $2,081,454 $2,134,618 $2,141,999 ========== ========== ========== ========== ========== Common Stock and Paid-in Capital $ 380,660 $ 380,660 $ 380,660 $ 380,660 $ 380,660 Retained Earnings 293,989 283,546 296,581 320,148 317,835 ---------- ---------- ---------- ---------- ---------- Total Common Shareholder's Equity $ 674,649 $ 664,206 $ 677,241 $ 700,808 $ 698,495 ========== ========== ========== ========== ========== Preferred Stock $ 4,704 $ 4,706 $ 4,707 $ 30,639 $ 48,496 ========== ========== ========== ========== ========== Trust Preferred Securities $ 110,000 $ 110,000 $ 110,000 $ 110,000 $ - ========== ========== ========== ========== ========== Long-term Debt (a) $ 645,963 $ 541,568 $ 587,673 $ 589,980 $ 642,555 ========== ========== ========== ========== ========== Total Capitalization and Liabilities $2,662,534 $2,106,215 $2,081,454 $2,134,618 $2,141,999 ========== ========== ========== ========== ========== (a) Including portion due within one year.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Management's Discussion and Analysis of Results of Operations SWEPCo is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to approximately 428,000 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. SWEPCo participates in power marketing and trading activities conducted on its behalf by the AEP System. SWEPCo shares in the revenues and costs of the AEP Power Pool's wholesale sales to and net forward trades with other utility systems and power marketers. Revenues from trading of electricity are recorded net of purchases as operating revenues. Results of Operations The $10.5 million or 13% decrease in net income in 2000 is due to increased operating expenses. While the $14.8 million or 15% decrease in 1999 is primarily the result of increased other operation and maintenance expenses, the write-off of acquisition expenses attributable to CSW's efforts to acquire the non-nuclear assets of Cajun Power Cooperative, increased interest charges and the effect of an extraordinary loss from the discontinued regulatory accounting for SWEPCo's Texas and Arkansas generating business. Operating Revenues Operating revenues significantly increased in 2000 from higher fuel and purchased power revenues due to increased fuel and purchased power expense, increased retail energy sales, the post merger favorable impact of AEP's power marketing and trading operations, which added new wholesale revenues, and the effect of an unfavorable revenue adjustment in 1999 as a result of FERC's approval of a transmission coordination agreement. The transmission coordination agreement provides the means by which the AEP West electric operating companies plan, operate and maintain their separate transmission assets as a single system. The agreement also establishes the method by which these companies allocate transmission revenues received under open access transmission tariffs. In 1999 the AEP West electric operating companies filed a revised transmission coordination agreement which included changes that ensure a revenue allocation in proportion to each company's respective revenue requirement for service it provides under a revised open access transmission tariff. In the third quarter of 1999, SWEPCo and the other AEP West electric operating companies recorded the estimated impact of the reallocation of open access transmission tariff revenues to 1997 which caused SWEPCo to record a reduction to revenues in the third quarter of 1999. The following analyzes the changes in operating revenues: Increase (Decrease) From Previous Year (dollars in millions) - --------------------- 2000 1999 ------------------------------ Amount % Amount % Retail: Residential $ 32.7 $(19.9) Commercial 21.1 0.5 Industrial 18.4 1.6 Other 3.3 1.0 ------ ------ 75.5 10 (16.8) (2) Wholesale 68.7 40 32.2 23 Transmission 32.1 N.M. (5.3) N.M. Other (23.6) (86) 8.5 44 ------ ------ Total $152.7 16 $ 18.6 2 ====== ====== N.M. = Not Meaningful Revenues from retail customers increased in 2000 as a result of an increase in fuel and purchased power revenues and a rise in sales volume caused by warmer summer temperatures. The increase in fuel and purchased power revenues reflects rising prices for natural gas used for generation and related higher costs for purchased power. The Texas and Arkansas fuel clause recovery mechanisms provide for the accrual of fuel-related revenues until reviewed and approved for billing to customers by the regulator. The accrual of additional fuel-related revenues is generally offset by increases in fuel and purchased power expenses. As a result fuel-related revenues do not impact results of operations. The significant increase in wholesale revenues in 2000 is attributable to increased sales to other utilities and SWEPCo's initial participation in the AEP System's power marketing and trading operations after the merger of CSW and AEP. The volume of wholesale electricity sales to other utilities, both affiliated and unaffiliated, increased as demand for energy rose in response to warmer summer weather. Since SWEPCo became a subsidiary of AEP as a result of the merger in June 2000, SWEPCo shares in the AEP System's power marketing and trading transactions with other entities. Trading transactions involve the purchase and sale of substantial amounts of electricity which are accounted for as revenues net of purchases. Wholesale revenues increased 23% in 1999 due mainly to an increase in sales to other utilities as a result of increased demand. Operating Expenses Increase Total operating expenses increased 21% in 2000 primarily due to significant increases in the cost of fuel and purchased power. In 1999 the operating expenses increased 3% primarily due to increased maintenance expense. The changes in the components of operating expenses were: Increase (Decrease) From Previous Year (dollars in millions) --------------------- 2000 1999 ------------------------------ Amount % Amount % Fuel $119.2 31 $ 8.2 2 Purchased Power 40.4 108 1.9 5 Other Operation 17.1 12 1.8 1 Maintenance 10.9 17 13.0 25 Depreciation and Amortization (4.2) (4) 10.3 11 Taxes Other Than Federal Income Taxes (2.2) (4) (3.7) (6) Federal Income Taxes (9.8) (29) (9.3) (22) ------ ----- Total $171.4 21 $22.2 3 ====== ===== Fuel expense increased in 2000 and 1999 due to an increase in the average unit cost of fuel as a result of an increase in the spot market price for natural gas and an increase in generation to meet the rise in retail and wholesale demand for electricity. The modest increase in fuel expense in 1999 resulted from an increase in the generation of electricity to meet the rising wholesale demand for electricity. The major increase in purchased power expense in 2000 was primarily caused by an increase in firm energy contract purchases, increased capacity charges and increased economy energy purchases. Purchased power expense for 1999 increased due primarily to an increase in economy energy purchases. Other operation expense increased in 2000 due primarily to increased regulatory and consulting expenses. Maintenance expense increased in 2000 as a result of costs to restore service and make repairs following a severe ice storm in December. The increase in 1999 can be attributed to higher power station maintenance, increased tree-trimming and additional overhead line maintenance. The increase in depreciation and amortization in 1999 is the result of increased depreciable plant and a provision for excess earnings. The Texas Legislation provides that each year during the 1999 through 2001 rate freeze period, electric utilities are subject to an earnings test. See description of earnings test in Note 7 of the Notes to Consolidated Financial Statements. A decline in franchise taxes in 2000 and ad valorem taxes in 1999 led to the reduction in taxes other than federal income taxes in 2000 and 1999. The decreases in federal income tax expense attributable to operations in 2000 and 1999 were primarily due to decreases in pre-tax operating income and an unfavorable tax accrual adjustment made in 1998. Nonoperating Income The increase in nonoperating income in 2000 was due to the effect of a 1999 write off of Cajun Electric Power Cooperative acquisition expenses following CSW's decision not to continue to pursue the acquisition of Cajun Electric Power Cooperative non-nuclear assets. SWEPCo had deferred approximately $13 million in acquisition costs related to its attempt to acquire Cajun's non-nuclear assets. Interest Charges Interest charges for 1999 increased primarily due to increased levels of short-term borrowings and additional interest expenses in connection with changes to the transmission coordination agreements. Extraordinary Loss An extraordinary loss of $3 million net of tax was recorded in the third quarter of 1999 when SWEPCo discontinued the application of SFAS 71 regulatory accounting for the generation portion of its business in Texas and Arkansas as a result of legislation passed in those states providing for a transition from cost based rate regulation for SWEPCo's generation business to customer choice market pricing.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Income - ----------------------------------------------------------- Year Ended December 31, 2000 1999 1998 ---- ---- ---- (in thousands) OPERATING REVENUES $1,124,210 $971,527 $952,952 ---------- -------- -------- OPERATING EXPENSES: Fuel 498,805 379,597 371,414 Purchased Power 77,792 37,371 35,483 Other Operation 159,459 142,385 140,627 Maintenance 75,123 64,241 51,219 Depreciation and Amortization 104,679 108,831 98,479 Taxes Other Than Federal Income Taxes 56,283 58,458 62,207 Federal Income Taxes 23,791 33,582 42,845 ---------- -------- -------- Total Operating Expenses 995,932 824,465 802,274 ---------- -------- -------- OPERATING INCOME 128,278 147,062 150,678 NONOPERATING INCOME (LOSS) 3,851 (1,965) 2,451 ---------- -------- -------- INCOME BEFORE INTEREST CHARGES 132,129 145,097 153,129 INTEREST CHARGES 59,457 58,892 55,135 ---------- -------- -------- INCOME BEFORE EXTRAORDINARY ITEM 72,672 86,205 97,994 EXTRAORDINARY LOSS (net of tax of $1,621,000) - (3,011) - ---------- -------- --------- NET INCOME 72,672 83,194 97,994 PREFERRED STOCK DIVIDEND REQUIREMENTS 229 229 705 LOSS ON REACQUIRED PREFERRED STOCK - - (856) ---------- -------- -------- EARNINGS APPLICABLE TO COMMON STOCK $ 72,443 $ 82,965 $ 96,433 ========== ======== ======== Consolidated Statements of Retained Earnings BALANCE AT BEGINNING OF PERIOD AS PREVIOUSLY REPORTED $288,019 $300,592 $324,050 Conforming Change in Accounting Policy (4,473) (4,011) (3,902) -------- -------- -------- ADJUSTED BALANCE AT BEGINNING OF PERIOD 283,546 296,581 320,148 NET INCOME 72,672 83,194 97,994 LOSS ON REACQUIRED PREFERRED STOCK - - (856) DEDUCTIONS: Cash Dividends Declared: Common Stock 62,000 96,000 120,000 Preferred Stock 229 229 705 -------- -------- -------- BALANCE AT END OF PERIOD $293,989 $283,546 $296,581 ======== ======== ======== See Notes to Consolidated Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Consolidated Balance Sheets - ---------------------------------------------------------------------------------------- December 31, 2000 1999 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production $1,414,527 $1,402,062 Transmission 519,317 484,327 Distribution 1,001,237 958,318 General 325,948 333,949 Construction Work in Progress 57,995 52,775 ---------- ---------- Total Electric Utility Plant 3,319,024 3,231,431 Accumulated Depreciation and Amortization 1,457,005 1,384,242 ---------- ---------- NET ELECTRIC UTILITY PLANT 1,862,019 1,847,189 ---------- ---------- OTHER PROPERTY AND INVESTMENTS 39,627 37,080 ---------- ---------- LONG-TERM ENERGY TRADING CONTRACTS 63,028 - ---------- ----------- CURRENT ASSETS: Cash and Cash Equivalents 1,907 3,043 Accounts Receivable: Customers 42,310 49,939 Affiliated Companies 11,419 6,053 Allowance for Uncollectible Accounts (911) (4,428) Fuel Inventory - at average cost 40,024 60,844 Materials and Supplies - at average cost 25,137 26,420 Under-recovered Fuel Costs 35,469 - Energy Trading Contracts 457,936 - Prepayments 16,780 15,953 ---------- ---------- TOTAL CURRENT ASSETS 630,071 157,824 ---------- ---------- REGULATORY ASSETS 57,082 47,180 ---------- ---------- DEFERRED CHARGES 10,707 16,942 ---------- ---------- TOTAL $2,662,534 $2,106,215 ========== ========== See Notes to Consolidated Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES December 31, --------------------------- 2000 1999 ---- ---- (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock - $18 Par Value: Authorized - 7,600,000 Shares Outstanding - 7,536,640 Shares $ 135,660 $ 135,660 Paid-in Capital 245,000 245,000 Retained Earnings 293,989 283,546 ---------- ---------- Total Common Shareholder's Equity 674,649 664,206 Preferred Stock 4,704 4,706 SWEPCO - obligated, mandatorily redeemable preferred securities of subsidiary trust holding solely Junior Subordinated Debentures of SWEPCO 110,000 110,000 Long-term Debt 645,368 495,973 ---------- ---------- TOTAL CAPITALIZATION 1,434,721 1,274,885 ---------- ---------- OTHER NONCURRENT LIABILITIES 11,290 9,255 ---------- ---------- CURRENT LIABILITIES: Long-term Debt Due Within One Year 595 45,595 Advances from Affiliates 16,823 140,897 Accounts Payable - General 107,747 60,689 Accounts Payable - Affiliated Companies 36,021 39,117 Customer Deposits 16,433 14,236 Taxes Accrued 11,224 24,374 Interest Accrued 13,198 9,792 Energy Trading Contracts 466,198 - Other 15,064 12,623 ---------- ---------- TOTAL CURRENT LIABILITIES 683,303 347,323 ---------- ---------- DEFERRED INCOME TAXES 399,204 376,504 ---------- ---------- DEFERRED INVESTMENT TAX CREDITS 53,167 57,649 ---------- ---------- REGULATORY LIABILITIES AND DEFERRED CREDITS 18,288 40,599 ---------- ---------- LONG-TERM ENERGY TRADING CONTRACTS 62,561 - ---------- ----------- COMMITMENTS AND CONTINGENCIES (Note 8) TOTAL $2,662,534 $2,106,215 ========== ========== See Notes to Consolidated Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Cash Flows - -------------------------------------------- Year Ended December 31, ------------------------------------- 2000 1999 1998 ---- ---- ---- (in thousands) OPERATING ACTIVITIES: Net Income $ 72,672 $ 83,194 $ 97,994 Adjustments for Noncash Items: Depreciation and Amortization 104,679 108,831 98,479 Deferred Income Taxes 14,653 (17,347) (11,909) Deferred Investment Tax Credits (4,482) (4,565) (4,631) Changes in Certain Assets and Liabilities: Accounts Receivable (net) (1,254) (11,134) 41,077 Fuel, Materials and Supplies 22,103 (21,891) (14,436) Accounts Payable 43,962 (12,953) (25,852) Taxes Accrued (13,150) 1,185 10,305 Transmission Coordination Agreement Settlement (24,406) 24,406 - Fuel Recovery (38,357) (2,490) 18,391 Other (net) 25,208 8,731 17,045 --------- --------- --------- Net Cash Flows From Operating Activities 201,628 155,967 226,463 --------- --------- --------- INVESTING ACTIVITIES: Construction Expenditures (120,671) (111,019) (83,120) Other 446 (4,167) (5,202) --------- --------- --------- Net Cash Flows Used For Investing Activities (120,225) (115,186) (88,322) --------- --------- --------- FINANCING ACTIVITIES: Issuance of Long-term Debt 149,360 - - Retirement of Cumulative Preferred Stock (1) (1) (27,988) Retirement of Long-term Debt (45,595) (46,144) (2,354) Change in Advances from Affiliates (net) (124,074) 100,192 15,530 Dividends Paid on Common Stock (62,000) (96,000) (120,000) Dividends Paid on Cumulative Preferred Stock (229) (229) (1,183) --------- --------- --------- Net Cash Flows Used For Financing Activities (82,539) (42,182) (135,995) --------- --------- --------- Net Increase (Decrease) in Cash and Cash Equivalents (1,136) (1,401) 2,146 Cash and Cash Equivalents January 1 3,043 4,444 2,298 --------- --------- --------- Cash and Cash Equivalents December 31 $ 1,907 $ 3,043 $ 4,444 ========= ========= ========= Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $51,110,611, $55,254,000 and $50,341,000 and for income taxes was $27,993,879, $55,677,000 and $57,977,000 in 2000, 1999, and 1998, respectively. See Notes to Consolidated Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Capitalization - ------------------------------------------------------------------------------------------------ December 31, ----------------------------- 2000 1999 ---- ---- (in thousands) COMMON SHAREHOLDER'S EQUITY $ 674,649 $ 664,206 ---------- ---------- PREFERRED STOCK - authorized 1,860,000 shares $100 par value Call Price Shares December 31, Number of Shares Redeemed Outstanding Series 2000 Year Ended December 31, December 31, 2000 - ------ ------------ ---------------------------- ----------------- 2000 1999 1998 ---- ---- ---- Not Subject to Mandatory Redemption: 4.28% $103.90 - - - 7,386 739 739 4.65% $102.75 - 1 - 1,907 190 191 5.00% $109.00 12 2 20 37,715 3,771 3,772 Premium 4 4 ---------- ---------- 4,704 4,706 ---------- ---------- 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 315,477 360,430 Installment Purchase Contracts 180,486 181,138 Senior Unsecured Notes 150,000 - Less Portion Due Within One Year (595) (45,595) ---------- ---------- Long-term Debt Excluding Portion Due Within One Year 645,368 495,973 ---------- ---------- TOTAL CAPITALIZATION $1,434,721 $1,274,885 ========== ========== See Notes to Consolidated 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, -------------------- 2000 1999 ---- ---- (in thousands) % Rate Due 5-1/4 2000 - April 1 $ - $ 45,000 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 5,795 5,940 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 (1,318) (1,510) -------- -------- $315,477 $360,430 Certain indentures relating to the first mortgage bonds contain improvement, maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. Installment purchase contracts have been entered into in connection with the issuance of pollution control revenue bonds by governmental authorities as follows: December 31, 2000 1999 ---- ---- (in thousands) % Rate Due - ------ ----------------- DeSoto: 7.60 2019 - January 1 $ 53,500 $ 53,500 Sabine: 6.10 2018 - April 1 81,700 81,700 Titus County: 6.90 2004 - November 1 12,290 12,290 6.00 2008 - January 1 13,520 13,970 8.20 2011 - August 1 17,125 17,125 Unamortized Premium 2,351 2,553 -------- -------- $180,486 $181,138 Under the terms of the installment purchase contracts, SWEPCo is required to pay amounts sufficient to enable the payment of interest on and the principal (at stated maturities and upon mandatory redemptions) of related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants. Senior unsecured notes outstanding were as follows: December 31, 2000 1999 ---- ---- (in thousands) % Rate Due - ------ ------------------ (a) 2002 - March 1 $150,000 $ - ======== ======== (a) A floating interest rate is determined monthly. The rate on December 31, 2000 was 6.97%. At December 31, 2000, future annual long-term debt payments are as follows: Amount ------ (in thousands) 2001 $ 595 2002 150,595 2003 55,595 2004 52,885 2005 595 Later Years 384,665 -------- Total Principal Amount 644,930 Unamortized Premium 1,033 -------- Total $645,963 ======== SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Index to Notes to Consolidated Financial Statements The notes listed below are combined with the notes to financial statements for AEP and its other subsidiary registrants. The combined footnotes begin on page L-1. Combined Footnote Reference Significant Accounting Policies Note 1 Extraordinary Items Note 2 Merger Note 3 Rate Matters Note 5 Effects of Regulation Note 6 Industry Restructuring Note 7 Commitments and Contingencies Note 8 Benefit Plans Note 12 Business Segments Note 14 Financial Instruments, Credit and Risk Management Note 15 Income Taxes Note 16 Lines of Credit and Factoring of Receivables Note 19 Unaudited Quarterly Financial Information Note 20 Trust Preferred Securities Note 21 Jointly Owned Electric Utility Plant Note 22 Related Party Transactions Note 23 INDEPENDENT AUDITORS' REPORT To the Shareholders and Board of Directors of Southwestern Electric Power Company: We have audited the accompanying consolidated balance sheet and consolidated statement of capitalization of Southwestern Electric Power Company and subsidiaries as of December 31, 2000, and the related consolidated statements of income, retained earnings, and cash flows for the year then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit. The consolidated financial statements of the Company for the years ended December 31, 1999 and 1998, before the restatement described in Note 3 to the consolidated financial statements, were audited by other auditors whose report, dated February 25, 2000, expressed an unqualified opinion on those statements. We conducted our audit 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 audit provides a reasonable basis for our opinion. In our opinion, the 2000 consolidated financial statements present fairly, in all material respects, the financial position of Southwestern Electric Power Company and subsidiary as of December 31, 2000, and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America. We also audited the adjustments described in Note 3 that were applied to restate the 1999 and 1998 consolidated financial statements to give retroactive effect to the conforming change in the method of accounting for vacation pay accruals. In our opinion, such adjustments are appropriate and have been properly applied. DELOITTE & TOUCHE LLP Columbus, Ohio February 26, 2001 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Stockholders 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 (a Delaware corporation and a wholly owned subsidiary of Central and South West Corporation) and subsidiary company as of December 31, 1999, and the related consolidated statements of income, retained earnings and cash flows, for each of the two years in the period ended December 31, 1999 prior to the restatement (and, therefore, are not presented herein) for the retroactive effect of the conforming change in the method of accounting for vacation pay accruals and certain conforming reclassifications to the historical financial statements as described in Note 3 to the restated consolidated financial statements. These financial statements are the responsibility of Southwestern Electric Power Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. 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 prior to the restatement referred to above present fairly, in all material respects, the financial position of Southwestern Electric Power Company and subsidiary company as of December 31, 1999, and results of their operations and their cash flows for each of the two years in the period ended December 31, 1999, in conformity with accounting principles generally accepted in the United States. Arthur Andersen LLP Dallas, Texas February 25, 2000 WEST TEXAS UTILITIES COMPANY
K-11 WEST TEXAS UTILITIES COMPANY Selected Financial Data - ---------------------------------------------------------------------------------------------------- Year Ended December 31, ----------------------------------------------------------- 2000 1999 1998 1997 1996 ---- ---- ---- ---- ---- (in thousands) INCOME STATEMENTS DATA: Operating Revenues $ 572,794 $ 445,709 $ 424,953 $ 397,779 $ 377,057 Operating Expenses 520,453 391,910 365,677 353,195 327,499 ---------- ---------- ---------- ---------- ---------- Operating Income 52,341 53,799 59,276 44,584 49,558 Nonoperating Income (Loss) (1,675) 2,488 2,712 1,463 (9,922) ---------- ---------- ---------- ---------- ---------- Income Before Interest Charges 50,666 56,287 61,988 46,047 39,636 Interest Charges 23,216 24,420 24,263 24,570 25,241 ---------- ---------- ---------- ---------- ---------- Income Before Extraordinary Item 27,450 31,867 37,725 21,477 14,395 Extraordinary Loss - (5,461) - - - ---------- ---------- ---------- ---------- ----------- Net Income 27,450 26,406 37,725 21,477 14,395 Preferred Stock Dividend Requirements 104 104 104 144 264 ---------- ---------- ---------- ---------- ---------- Gain on Reacquired Preferred Stock - - - 1,085 - ---------- ---------- ---------- ---------- ---------- Earnings Applicable to Common Stock $ 27,346 $ 26,302 $ 37,621 $ 22,418 $ 14,131 ========== ========== ========== ========== ========== December 31, ------------------------------------------------------------ 2000 1999 1998 1997 1996 ---- ---- ---- ---- ---- (in thousands) BALANCE SHEETS DATA: Electric Utility Plant $1,229,339 $1,182,544 $1,146,582 $1,108,845 $1,088,141 Accumulated Depreciation and Amortization 515,041 495,847 473,503 441,281 414,777 ---------- ---------- ---------- ---------- ---------- Net Electric Utility Plant $ 714,298 $ 686,697 $ 673,079 $ 667,564 $ 673,364 ========== ========== ========== ========== ========== Total Assets $1,088,932 $ 861,205 $ 819,446 $ 826,858 $ 837,412 ========== ========== ========== ========== ========== Common Stock and Paid-in Capital $ 139,450 $ 139,450 $ 139,450 $ 139,450 $ 139,450 Retained Earnings 122,588 113,242 114,940 117,319 120,901 ---------- ---------- ---------- ---------- ---------- Total Common Shareholder's Equity $ 262,038 $ 252,692 $ 254,390 $ 256,769 $ 260,351 ========== ========== ========== ========== ========== Cumulative Preferred Stock: Not Subject to Mandatory Redemption $ 2,482 $ 2,482 $ 2,482 $ 2,483 $ 6,291 ========== ========== ========== ========== ========== Long-term Debt (a) $ 255,843 $ 303,686 $ 303,518 $ 303,351 $ 303,182 ========== ========== ========== ========== ========== Total Capitalization and Liabilities $1,088,932 $ 861,205 $ 819,446 $ 826,858 $ 837,412 ========== ========== ========== ========== ========== (a) Including portion due within one year.
WEST TEXAS UTILITIES COMPANY Management's Narrative Analysis of Results of Operations - ------------------------------------------------------ WTU is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power and provides electric power to approximately 190,000 retail customers in west and central Texas. WTU also sells electric power at wholesale to other utilities, municipalities and rural electric cooperatives. WTU participates in power marketing and trading activities conducted on its behalf by the AEP System. WTU shares in the revenues and costs of the AEP Power Pool's wholesale sales to and net forward trades with other utility systems and power marketers. Revenues from trading of electricity are recorded net of purchases as operating revenues. Results of Operations Income before extraordinary items decreased $4.4 million or 14%. The decrease was primarily due to a decrease in nonoperating income, as a result of the termination of merchandise sales and the cost of phasing out the merchandise sales program. The decrease in nonoperating income is partially offset by a decrease in interest charges. An extraordinary loss related to the discontinuance of SFAS 71 regulatory accounting for WTU's generation business of $5.5 million after tax was recorded in September 1999. Operating Revenues A 29% increase in operating revenues was due to increased fuel and purchases power revenues, reflecting higher fuel and purchased power expenses, and an increase in weather-related demand for electricity. Under the operation of a fuel and purchase power clause mechanism in Texas, revenues are accrued to reflect fuel and purchased power cost increases. The accrued revenues are subsequently reviewed and approved for recovery by the PUCT. As a result changes in fuel and purchase power revenues do not generally impact results of operations. Changes in the components of operating revenues were as follows: Increase (Decrease) From Previous Year (dollars in millions) Amount % - ---------------------- ------ - Retail: Residential $ 31.7 24 Commercial 18.9 24 Industrial 13.3 26 Other 9.3 25 ------ 73.2 Wholesale 47.8 46 Transmission 3.7 11 Other 2.4 128 ------ Total $127.1 29 ====== Revenues from retail customers increased significantly as a result of an increase in fuel and purchase power related revenues reflecting rising prices for natural gas used for generation and related higher purchased power prices. Since the Texas fuel and purchase power clause recovery mechanism provides for the accrual of revenues to recover fuel and purchase power cost changes until reviewed and approved for billing to customers by the PUCT, increases in fuel and purchased power expenses and related accrued revenues do not adversely effect results of operations. The significant increase in wholesale revenues is attributable to increased sales to other utilities and WTU's participation in the AEP System's power marketing and trading operations. The volume of electricity sales to other utilities, both affiliated and unaffiliated, increased as demand for energy rose in response to warmer summer weather. Since WTU became a subsidiary of AEP as a result of the merger in June 2000, WTU shares in the AEP System's power marketing and trading transactions with other non-affiliated entities. Trading involves the purchase and sale of substantial amounts of electricity to non-affiliated parties. Revenues from trading are recorded net of purchases. Operating Expenses Operating expenses were $520.5 million or 33% more than in 1999 largely as a result of increased fuel and purchased power expenses. Changes in the components of operating expenses were as follows: Increase (Decrease) From Previous Year (dollars in millions) Amount % - ---------------------- ------ - Fuel $ 59.8 48 Purchased Power 66.1 107 Other Operation (1.2) (1) Maintenance 1.6 8 Depreciation and Amortization 4.4 9 Taxes Other Than Federal Income (2.9) (10) Federal Income Taxes 0.8 6 ------ Total $128.6 33 ====== The substantial increase in fuel expense was primarily due to a rise in the average cost of fuel resulting from an increase in spot market prices of natural gas. WTU uses natural gas as fuel for 72% of its generating capacity. The nature of the natural gas market is such that both long-term and short-term contracts are generally based on the current spot market price. Consequently, changes in natural gas prices affect WTU's fuel expense. However, as explained above they generally do not impact results of operations. Purchased power expense increased due primarily to an increase in the cost per MWH purchased to replace generation at a power plant which was out of service for 90 days as a result of a control room fire and to the adverse impact of natural gas prices on wholesale purchased power prices. The increase in maintenance expense was due to an increase in power plant maintenance and overhead line maintenance. The increase in power plant maintenance was partly due to repair of the fire damaged control room. Depreciation and amortization expense increased due to the recordation of increased accruals for estimated excess earnings under the Texas Legislation. The decrease in taxes other than federal income taxes was primarily due to lower ad valorem and state franchise taxes. Nonoperating Income Nonoperating income decreased $4.2 million primarily due to the termination of merchandise sales and the cost of phasing out the merchandise sales program. Interest Charges The decrease in interest charges of $1.2 million or 5% resulted from a reduction in long-term borrowings. Extraordinary Loss The extraordinary loss of $5.5 million was recorded in the third quarter of 1999 when WTU discontinued the application of SFAS 71 regulatory accounting for the generation portion of its business as a result of Texas Jurisdictional Legislation which provides for a transition from cost based rate regulation for WTU's generation business to customer choice and market based pricing for the supply of electricity at retail.
WEST TEXAS UTILITIES COMPANY Statements of Income - --------------------------------------------------------------- Year Ended December 31, --------------------------------------- 2000 1999 1998 ---- ---- ---- (in thousands) OPERATING REVENUES $ 572,794 $ 445,709 $ 424,953 ---------- ---------- ---------- OPERATING EXPENSES: Fuel 183,154 123,348 122,836 Purchased Power 127,583 61,532 48,131 Other Operation 93,078 94,290 90,061 Maintenance 21,241 19,604 16,666 Depreciation and Amortization 55,172 50,789 42,750 Taxes Other Than Federal Income Taxes 25,321 28,267 24,638 Federal Income Taxes 14,904 14,080 20,595 ---------- ---------- ---------- Total Operating Expenses 520,453 391,910 365,677 ---------- ---------- ---------- OPERATING INCOME 52,341 53,799 59,276 NONOPERATING INCOME (LOSS) (1,675) 2,488 2,712 ---------- ---------- ---------- INCOME BEFORE INTEREST CHARGES 50,666 56,287 61,988 INTEREST CHARGES 23,216 24,420 24,263 ---------- ---------- ----------- INCOME BEFORE EXTRAORDINARY ITEMS 27,450 31,867 37,725 EXTRAORDINARY LOSS - (net of tax of $2,941,000) - (5,461) - ---------- ---------- ----------- NET INCOME 27,450 26,406 37,725 PREFERRED STOCK DIVIDEND REQUIREMENTS 104 104 104 ---------- ---------- ---------- EARNINGS APPLICABLE TO COMMON STOCK $ 27,346 $ 26,302 $ 37,621 ========== ========== ========== Statements of Retained Earnings - ----------------------------------------------------------------------------------------------------------------- Year Ended December 31, 2000 1999 1998 ---- ---- ---- (in thousands) BALANCE AT BEGINNING OF PERIOD AS PREVIOUSLY REPORTED $115,856 $117,189 $119,479 CONFORMING CHANGE IN ACCOUNTING POLICY (2,614) (2,249) (2,160) -------- -------- -------- ADJUSTED BALANCE AT BEGINNING OF PERIOD 113,242 114,940 117,319 NET INCOME 27,450 26,406 37,725 DEDUCTIONS: Cash Dividends Declared: Common Stock 18,000 28,000 40,000 Preferred Stock 104 104 104 -------- -------- -------- BALANCE AT END OF PERIOD $122,588 $113,242 $114,940 ======== ======== ======== See Notes to Financial Statements beginning on page L-1.
WEST TEXAS UTILITIES COMPANY Balance Sheets - ----------------------------------------------------------------------------------------------------------------- December 31, 2000 1999 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production $ 431,793 $ 429,783 Transmission 235,303 220,479 Distribution 416,587 403,206 General (including nuclear fuel) 110,832 113,945 Construction Work in Progress 34,824 15,131 ---------- ---------- Total Electric Utility Plant 1,229,339 1,182,544 Accumulated Depreciation and Amortization 515,041 495,847 ---------- ---------- NET ELECTRIC UTILITY PLANT 714,298 686,697 ---------- ---------- OTHER PROPERTY AND INVESTMENTS 23,154 21,570 ---------- ---------- ENERGY TRADING CONTRACTS - LONG-TERM 20,944 - ---------- ----------- CURRENT ASSETS: Cash and Cash Equivalents 6,941 6,074 Accounts Receivable: Customers 36,217 45,928 Affiliated Companies 16,095 4,837 Allowance for Uncollectible Accounts (288) (186) Fuel - at average cost 12,174 17,133 Materials and Supplies - at average cost 10,510 14,029 Underrecovered Fuel Costs 67,655 14,652 Energy Trading Contracts 152,174 - Prepayments 851 619 ---------- ---------- TOTAL CURRENT ASSETS 302,329 103,086 ---------- ---------- REGULATORY ASSETS 24,808 29,745 ---------- ---------- DEFERRED CHARGES 3,399 20,107 ---------- ---------- TOTAL $1,088,932 $ 861,205 ========== ========== See Notes to Financial Statements beginning on page L-1.
WEST TEXAS UTILITIES COMPANY - ------------------------------------------------------------------------------------------------------------------------------- December 31, --------------------------- 2000 1999 ---- ---- (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock - $25 Par Value: Authorized - 7,800,000 Shares Outstanding - 5,488,560 Shares $ 137,214 $137,214 Paid-in Capital 2,236 2,236 Retained Earnings 122,588 113,242 ---------- -------- Total Common Shareholder's Equity 262,038 252,692 Cumulative Preferred Stock: Not Subject to Mandatory Redemption 2,482 2,482 Long-term Debt 255,843 263,686 ---------- -------- TOTAL CAPITALIZATION 520,363 518,860 ---------- -------- CURRENT LIABILITIES: Long-term Debt Due Within One Year - 40,000 Advances from Affiliates 58,578 21,408 Accounts Payable - General 45,562 39,611 Accounts Payable - Affiliated Companies 42,212 19,770 Customer Deposits 2,659 2,396 Taxes Accrued 18,901 12,458 Interest Accrued 3,717 4,165 Energy Trading Contracts 154,919 - Other 7,906 5,510 ---------- -------- TOTAL CURRENT LIABILITIES 334,454 145,318 ---------- -------- DEFERRED INCOME TAXES 157,038 148,992 ---------- -------- DEFERRED INVESTMENT TAX CREDITS 24,052 25,323 ---------- -------- REGULATORY LIABILITIES AND DEFERRED CREDITS 32,236 22,712 ---------- -------- ENERGY TRADING CONTRACTS - LONG-TERM 20,789 - ---------- --------- COMMITMENTS AND CONTINGENCIES (Note 8) TOTAL $1,088,932 $861,205 ========== ======== See Notes to Financial Statements beginning on page L-1.
WEST TEXAS UTILITIES COMPANY Statements of Cash Flows - ---------------------------------------- Year Ended December 31, -------------------------------------- 2000 1999 1998 ---- ---- ---- (in thousands) OPERATING ACTIVITIES: Net Income $ 27,450 $ 26,406 $ 37,725 Adjustments for Noncash Items: Depreciation and Amortization 55,172 50,789 42,750 Deferred Federal Income Taxes 8,164 12,026 (6,626) Deferred Investment Tax Credits (1,271) (1,275) (1,321) Extraordinary Loss - Discontinuance of SFAS 71 - 5,461 - CHANGES IN CERTAIN ASSETS AND LIABILITIES: Accounts Receivable (net) (1,445) (18,890) (21,119) Fuel, Materials and Supplies 8,478 (3,785) (660) Accounts Payable 28,393 7,229 305 Taxes Accrued 6,443 2,427 (1,344) Fuel Recovery (53,003) (10,672) 7,988 Other Property and Investments (1,584) (2,057) (1,344) Transmission Coordination Agreement Settlement 15,465 (15,465) - Other (net) 2,016 10,448 4,972 --------- --------- --------- Net Cash Flows From Operating Activities 94,278 62,642 61,326 --------- --------- --------- INVESTING ACTIVITIES: Construction Expenditures (64,477) (49,443) (36,867) Other - (3,832) (5,782) --------- --------- --------- Net Cash Flows Used For Investing Activities (64,477) (53,275) (42,649) --------- --------- --------- FINANCING ACTIVITIES: Retirement of Long-term Debt (48,000) - - Change in Advances from Affiliates (net) 37,170 16,835 4,573 Dividends Paid on Common Stock (18,000) (28,000) (40,000) Dividends Paid on Cumulative Preferred Stock (104) (105) (104) --------- --------- --------- Net Cash Flows From (Used For) Financing Activities (28,934) (11,270) (35,531) --------- --------- --------- Net Increase (Decrease) in Cash and Cash Equivalents 867 (1,903) (16,854) Cash and Cash Equivalents at Beginning of Period 6,074 7,977 24,831 --------- --------- --------- Cash and Cash Equivalents at End of Period $ 6,941 $ 6,074 $ 7,977 ========= ========= ========= Supplemental Disclosure: Cash paid (received) for interest net of capitalized amounts was $19,088,000, $17,577,000 and $17,250,000 and for income taxes was $(906,000), $3,309,000 and $29,533,000 in 2000, 1999 and 1998, respectively. See Notes to Financial Statements beginning on page L-1.
WEST TEXAS UTILITIES COMPANY Statements of Capitalization - --------------------------------------------------------------------------- December 31, ----------------------------- 2000 1999 ---- ---- (in thousands) COMMON SHAREHOLDER'S EQUITY $262,038 $252,692 -------- -------- PREFERRED STOCK - authorized 810,000 shares $100 par value Call Price Shares December 31, Number of Shares Redeemed Outstanding Series 2000 Year Ended December 31, December 31, 2000 - ------ ------------ ---------------------------- ----------------- 2000 1999 1998 ---- ---- ---- Not Subject to Mandatory Redemption: 4.40% $107.00 1 2 - 23,672 2,367 2,367 Premium 115 115 -------- -------- 2,482 2,482 -------- -------- LONG-TERM DEBT (See Schedule of Long-term Debt): First Mortgage Bonds 211,533 259,376 Installment Purchase Contracts 44,310 44,310 Less Portion Due Within One Year - (40,000) -------- -------- Long-term Debt Excluding Portion Due Within One Year 255,843 263,686 -------- -------- TOTAL CAPITALIZATION $520,363 $518,860 ======== ======== See Notes to Financial Statements beginning on page L-1.
WEST TEXAS UTILITIES COMPANY Schedule of Long-term Debt - -------------------------------------------------- First mortgage bonds outstanding were as follows: December 31, -------------------- 2000 1999 ---- ---- (in thousands) % Rate Due 7-3/4 2007 - June 1 $ 25,000 $ 25,000 6-7/8 2002 - October 1 35,000 35,000 7 2004 - October 1 40,000 40,000 6-1/8 2004 - February 1 40,000 40,000 7-1/2 2000 - April 1 - 40,000 6-3/8 2005 - October 1 72,000 80,000 Unamortized Discount (467) (624) -------- -------- $211,533 $259,376 Certain indentures relating to the first mortgage bonds contain improvement, maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. Installment purchase contracts have been entered into, in connection with the issuance of pollution control revenue bonds by governmental authorities as follows: December 31, 2000 1999 ---- ---- (in thousands) % Rate Due Red River Authority of Texas: 6 2020 - June 1 $44,310 $44,310 ======= ======= Under the terms of the installment purchase contracts, WTU is required to pay amounts sufficient to enable the payment of interest on and the principal (at stated maturities and upon mandatory redemptions) of related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants. At December 31, 2000, future annual long-term debt payments are as follows: Amount ------ (in thousands) 2001 $ - 2002 35,000 2003 - 2004 80,000 2005 72,000 Later Years 69,310 -------- Total $256,310 ======== WEST TEXAS UTILITIES COMPANY Index to Notes to 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 Note 2 Merger Note 3 Rate Matters Note 5 Effects of Regulation Note 6 Industry Restructuring Note 7 Commitments and Contingencies Note 8 Benefit Plans Note 12 Business Segments Note 14 Financial Instrument, Credit and Risk Management Note 15 Income Taxes Note 16 Lines of Credit and Factoring of Receivables Note 19 Unaudited Quarterly Financial Information Note 20 Jointly Owned Electric Utility Plant Note 22 Related Party Transactions Note 23 INDEPENDENT AUDITORS' REPORT - ----------------------------------------------- To the Shareholders and Board of Directors of West Texas Utilities Company: We have audited the accompanying balance sheet and statement of capitalization of West Texas Utilities Company as of December 31, 2000, and the related statements of income, retained earnings, and cash flows for the year then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit. The financial statements of the Company for the years ended December 31, 1999 and 1998, before the restatement described in Note 3 to the financial statements, were audited by other auditors whose report, dated February 25, 2000, expressed an unqualified opinion on those statements. We conducted our audit 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 audit provides a reasonable basis for our opinion. In our opinion, the 2000 financial statements present fairly, in all material respects, the financial position of West Texas Utilities Company as of December 31, 2000, and the results of its operations and its cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America. We also audited the adjustments described in Note 3 that were applied to restate the 1999 and 1998 financial statements to give retroactive effect to the conforming change in the method of accounting for vacation pay accruals. In our opinion, such adjustments are appropriate and have been properly applied. DELOITTE & TOUCHE LLP Columbus, Ohio February 26, 2001 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Stockholders and Board of Directors of West Texas Utilities Company: We have audited the accompanying balance sheets and statements of capitalization of West Texas Utilities Company (a Texas corporation and a wholly owned subsidiary of Central and South West Corporation) as of December 31, 1999, and the related statement of income, retained earnings and cash flows, for each of the two years in the period ended December 31, 1999 prior to the restatement (and, therefore, are not presented herein) for the retroactive effect of the conforming change in the method of accounting for vacation pay accruals and certain conforming reclassifications to the historical financial statements as described in Note 3 to the restated financial statements. These financial statements are the responsibility of West Texas Utilities 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. 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 financial statements prior to the restatement referred to above present fairly, in all material respects, the financial position of West Texas Utilities Company as of December 31, 1999, and results of its operations and its cash flows for each of the two years in the period ended December 31, 1999, in conformity with accounting principles generally accepted in the United States. Arthur Andersen LLP Dallas, Texas February 25, 2000 L-48 NOTES TO FINANCIAL STATEMENTS - ----------------------------------------------------------------------------- The notes to financial statements that follow are a combined presentation for AEP and its subsidiary registrants. The following list of footnotes shows the registrant to which they apply: 1. Significant Accounting Policies AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU 2. Extraordinary Items AEP, APCo, CPL, CSPCo, OPCo, SWEPCo, WTU 3. Merger AEP, CPL, I&M, KPCo, PSO, SWEPCo, WTU 4. Nuclear Plant Restart AEP, I&M 5. Rate Matters AEP, APCo, CPL, CSPCo, I&M, KPCo, OPCo, OPCo, SWEPCo, WTU 6. Effects of Regulation AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, KPCo, OPCo, PSO, SWEPCo, WTU 7. Industry Restructuring AEP, APCo, CPL, CSPCo, I&M, OPCo, PSO, SWEPCo, WTU 8. Commitments and Contingencies AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU 9. Acquisitions AEP 10. International Investments AEP 11. Staff Reductions AEP, APCo, CSPCo, I&M, KPCo, OPCo 12. Benefit Plans AEP, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU 13. Stock Based Compensation AEP 14. Business Segments AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU 15. Financial Instruments, Credit AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, and Risk Management OPCo, PSO, SWEPCo, WTU 16. Income Taxes AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, KPCo, OPCo, PSO, SWEPCo, WTU 17. Supplementary Information AEP, APCo, CSPCo, I&M, OPCo 18. Leases AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo 19. Lines of Credit AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, and Commitment Fees OPCo, PSO, SWEPCo, WTU 20. Unaudited Quarterly AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, Financial Information OPCo, PSO, SWEPCo, WTU 21. Trust Preferred Securities AEP, CPL, PSO, SWEPCo, 22. Jointly Owned Electric Utility Plant CPL, CSPCo, PSO, SWEPCo, WTU 23. Related Party Transactions AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU 1. Significant Accounting Policies: Business Operations - AEP's principal business conducted by its eleven domestic electric utility operating companies is the generation, transmission and distribution of electric power. Nine of AEP's eleven domestic electric utility operating companies, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU, are SEC registrants. AEGCo is a domestic generating company wholly-owned by AEP that is an SEC registrant. These companies are subject to regulation by the FERC under the Federal Power Act and follow the Uniform System of Accounts prescribed by FERC. They are subject to further regulation with regard to rates and other matters by state regulatory commissions. Wholesale marketing and trading of electricity and gas is conducted in the United States and Europe. In addition AEP's domestic operations includes non-regulated independent power and cogeneration facilities and an intra-state midstream natural gas operation in Louisiana. AEP's international operations include regulated supply and distribution of electricity and other non-regulated power generation projects in the United Kingdom, Australia, Mexico, South America and China. In addition to the above energy related operations, AEP is also involved in domestic factoring of accounts receivable, investing in leveraged leases and providing energy services worldwide and communications related services domestically. Rate Regulation - The AEP System 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 generation and distribution rates. The prices charged by foreign subsidiaries located in the UK, Australia, China, Mexico and Brazil are regulated by the authorities of that country and are generally subject to price controls. Principles of Consolidation - AEP's consolidated financial statements include AEP Co., Inc. and its wholly-owned and majority-owned subsidiaries consolidated with their wholly-owned subsidiaries. The consolidated financial statements for APCo, CPL, CSPCo, I&M, OPCo, PSO and SWEPCo include the registrant and its wholly-owned subsidiaries. Significant intercompany items are eliminated in consolidation. Equity investments that are 50% or less owned are accounted for using the equity method with their equity earnings included in Other Income, net for AEP and nonoperating income for the registrant subsidiaries. Basis of Accounting - As cost-based rate-regulated electric public utility companies, the financial statements for AEP and each of the registrant subsidiaries 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 (deferred revenues) are recorded to reflect the economic effects of regulation by matching expenses with their recovery through regulated revenues. Application of SFAS 71 for the generation portion of the business was discontinued as follows: in Ohio by OPCo and CSPCo in September 2000, in Virginia and West Virginia by APCo in June 2000, in Texas by CPL, WTU, and SWEPCo in September 1999 and in Arkansas by SWEPCo in September 1999. See Note 7, "Industry Restructuring" for additional information. Use of Estimates - The preparation of these financial statements in conformity with generally accepted accounting principles requires in certain instances the use of estimates and assumptions that affect the reported amounts of assets and liabilities along with the disclosure of contingent liabilities at the date of financial statements and the reported amounts of revenues and expenses during the reporting period. 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. The property, plant and equipment of SEEBOARD, CitiPower and LIG are stated at their fair market value at acquisition plus the original cost of property acquired or constructed since the acquisition, less disposals. Additions, major replacements and betterments are added to the plant accounts. For cost-based rate regulated operations retirements from the plant accounts and associated removal costs, net of salvage, are deducted from accumulated depreciation. The costs of labor, materials and overheads incurred to operate and maintain plant are included in operating expenses. Allowance for Funds Used During Construction (AFUDC) - AFUDC is a noncash nonoperating income item that is capitalized and recovered through depreciation over the service life of domestic regulated electric utility plant. For 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 2000, 1999 and 1998 were not significant. Effective with the discontinuance of the application of SFAS 71 regulatory accounting for domestic generating assets in Arkansas, Ohio, Texas, Virginia and West Virginia and for AEP's other nonregulated operations interest is capitalized during construction in accordance with SFAS 34, "Capitalization of Interest Costs." The amounts of interest capitalized was not material in 2000, 1999, and 1998. 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: Functional Class Annual Composite of Property Depreciation Rates Ranges 2000 Production: Steam-Nuclear 2.8% to 3.4% Steam-Fossil-Fired 2.3% to 4.5% Hydroelectric- Conventional and Pumped Storage 2.7% to 3.4% Transmission 1.7% to 3.1% Distribution 3.3% to 4.2% Other 2.5% to 20.0% Functional Class Annual Composite of Property Depreciation Rates Ranges 1999 Production: Steam-Nuclear 2.8% to 3.4% Steam-Fossil-Fired 3.2% to 5.0% Hydroelectric- Conventional and Pumped Storage 2.7% to 3.4% Transmission 1.7% to 2.7% Distribution 2.8% to 4.2% Other 2.0% to 20.0% Functional Class Annual Composite of Property Depreciation Rates Ranges 1998 Production: Steam-Nuclear 2.8% to 3.4% Steam-Fossil-Fired 3.2% to 4.4% Hydroelectric- Conventional and Pumped Storage 2.7% to 3.4% Transmission 1.7% to 2.7% Distribution 3.3% to 4.2% Other 2.5% to 20.0% The following table provides the annual composite depreciation rates generally used by the AEP registrant subsidiaries for the years 2000, 1999 and 1998 which were as follows: Nuclear Steam Hydro Transmission Distribution General AEGCo - % 3.5% - % - % - % 2.8% APCo - 3.4 2.9 2.2 3.3 3.2 CPL 2.8 2.3 - 2.3 3.5 4.2 CSPCo - 3.2 - 2.3 3.6 3.3 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 6.4 SWEPCo - 3.3 - 2.7 3.6 4.6 WTU - 2.7 - 3.1 3.3 6.8 Depreciation, depletion and amortization of OPCo's coal-mining assets is provided over each asset's estimated useful life or the estimated life of the mine, whichever is shorter, and is calculated using the straight-line method for mining structures and equipment. The units-of-production method is used to amortize coal rights and mine development costs based on estimated recoverable tonnages at a current average rate of $5.07 per ton in 2000, $2.32 per ton in 1999 and $1.85 per ton in 1998. These costs are included in the cost of coal charged to fuel expense. See Note 5 "Rate Matters" regarding the closure and possible sale of affiliated mines. Cash and Cash Equivalents - Cash and cash equivalents include temporary cash investments with original maturities of three months or less. Inventory - Except for CPL, PSO and WTU, the domestic utility companies value fossil fuel inventories using a weighted average cost method. CPL, PSO and WTU, utilize the LIFO method to value fossil fuel inventories. SWEPCo continues to use the weighted average cost method pending approval of its request to the Arkansas Commission to utilize the LIFO method. Natural gas inventories held by LIG are marked-to-market. Accounts Receivable - AEP Credit Inc. (formerly CSW Credit) factors accounts receivable for the domestic utility subsidiaries, except APCo, and unaffiliated companies. Foreign Currency Translation - The financial statements of subsidiaries outside the U.S. which are included in AEP's consolidated financial statements are measured using the local currency as the functional currency and translated into U.S. dollars in accordance with SFAS 52 "Foreign Currency Translation". Assets and liabilities are translated to U.S. dollars at year-end rates of exchange and revenues and expenses are translated at monthly average exchange rates throughout the year. Currency translation gain and loss adjustments are recorded in shareholders' equity as "Accumulated Other Comprehensive Income (Loss)". The non-cash impact of the changes in exchange rates on cash, resulting from the translation of items at different exchange rates is shown on AEP's Consolidated Statement of Cash Flows in "Effect of Exchange Rate Change on Cash." Actual currency transaction gains and losses are recorded in income. Energy Marketing and Trading Transactions - The AEP System engages in wholesale electricity and natural gas marketing and trading transactions (trading activities). Trading activities involve the sale of energy under physical forward contracts at fixed and variable prices and the trading of energy contracts including exchange traded futures and options, over-the-counter options and swaps. The majority of these transactions represent physical forward electricity contracts in AEP's traditional marketing area (up to two transmission systems from AEP's service territory) and are typically settled by entering into offsetting contracts. The net revenues from these transactions in AEP's traditional marketing area are included in revenues from domestic electric utility operations on AEP's consolidated statements of income. The AEP System also purchases and sells electricity and gas options, futures and swaps, and enters into forward purchase and sale contracts for electricity (outside its traditional marketing area) and gas. These transactions represent non-regulated trading activities that are included in revenues from worldwide electric and gas operations on AEP's consolidated statements of income. All of the registrant subsidiaries except AEGCo participate in the AEP System's wholesale marketing and trading of electricity. APCo, CSPCo, I&M, KPCo and OPCo record revenues from trading of electricity net of purchases as operating revenues for forward electricity trades in AEP's traditional marketing area and as nonoperating income for forward electricity trades beyond two transmission systems from AEP and for speculative financial transactions (options, futures and swaps). CPL, PSO, SWEPCo and WTU record revenues from trading of electricity net of purchases as operating revenues. The AEP System follows EITF 98-10 and EITF 00-17, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" and "Measuring the Fair Value of Energy-Related Contracts in Applying Issue 98-10", respectively. EITF 98-10 requires that all energy trading contracts be marked-to-market. The effect on AEP's consolidated statements of income of marking open trading contracts to market in the regulated jurisdictions are deferred as regulatory assets or liabilities for those open electricity trading transactions within AEP's marketing area that are included in cost of service on a settlement basis for ratemaking purposes. Non-regulated jurisdictions with open electricity trading transactions within AEP's marketing area are marked-to-market and included in domestic electric utility operations revenues on AEP's consolidated statements of income. Non-regulated and regulated jurisdictions open electricity trading contracts outside the traditional marketing area are accounted for on a mark-to-market basis and included in worldwide electric and gas operations revenues on AEP's consolidated statements of income. Open gas trading contracts are accounted for on a mark-to-market basis and included in worldwide electric and gas operations on AEP's consolidated statements of income. APCo, CSPCo and OPCo account for open forward electricity trading contracts on a mark-to-market basis and include the mark-to-market change in revenues for open contracts in AEP's traditional marketing area and in nonoperating income for open contracts beyond AEP's traditional marketing area. I&M and KPCo account for open forward electricity trading contracts on a mark-to-market basis and defer the mark-to-market change as regulatory assets or liabilities for those open contracts in AEP's traditional marketing area and include the mark-to-market change in nonoperating income for open contracts beyond AEP's traditional marketing area. CPL, PSO, SWEPCo and WTU account for open forward electricity trading contracts on a mark-to-market basis. CPL includes the mark-to-market change for open electricity trading contracts in revenues. PSO defers as regulatory assets or liabilities the mark-to-market change for open forward electricity trading contracts that are included in cost of service on a settlement basis for ratemaking purposes. SWEPCo and WTU include the jurisdictional share of the mark-to-market change in revenues for open electricity trading contracts for those jurisdictions that are not subject to SFAS 71 cost based rate regulation and defer as regulatory assets or liabilities the jurisdictional share of the mark-to-market change for open contracts that are included in cost of service on a settlement basis for ratemaking purposes. Unrealized mark-to-market gains and losses from all trading activity are reported as assets and liabilities, respectively. Hedging and Related Activities - In order to mitigate the risks of market price and interest rate fluctuations, AEP's foreign subsidiaries, SEEBOARD and CitiPower, utilize interest swaps, currency swaps and forward contracts to hedge such market fluctuations. Changes in the market value of these swaps and contracts are deferred until the gain or loss is realized on the underlying hedged asset, liability or commodity. To qualify as a hedge, these transactions must be designated as a hedge and changes in their fair value must correlate with changes in the price and interest rate movement of the underlying asset, liability or commodity. This in effect reduces AEP's exposure to the effects of market fluctuations related to price and interest rates. AEP, APCo, CSPCo, I&M, and OPCo enter into contracts to manage the exposure to unfavorable changes in the cost of debt to be issued. These anticipatory debt instruments are entered into in order to manage the change in interest rates between the time a debt offering is initiated and the issuance of the debt (usually a period of 60 days). Gains or losses from these transactions are deferred and amortized over the life of the debt issuance with the amortization included in interest charges. There were no such forward contracts outstanding at December 31, 2000 or 1999. See Note 15 - "Financial Instruments, Credit and Risk Management" for further discussion of the accounting for risk management transactions. Revenues and Fuel Costs - Domestic revenues include the accrual of service provided but un-billed at month-end as well as billed revenues. The cost of fuel consumed is charged to expense as incurred. Under governing regulatory com-mission retail rate orders, any resulting fuel cost over or under-recoveries are deferred as regula-tory liabilities or regulatory assets in accordance with SFAS 71. These deferrals generally are billed or refunded to customers in later months with the regulator's review and approval. Wholesale jurisdictional fuel cost increases and decreases over amounts included in base rates are expensed and billed as incurred. See Note 5 "Rate Matters" and Note 7 "Industry Restruct-uring" for further information about fuel recovery. Levelization of Nuclear Refueling Outage Costs - In order to match costs with regulated revenues, which include outage costs on a normalized basis, 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. Amortization of Cook Plant Deferred Restart Costs - Pursuant to settlement agreements approved by the IURC and the MPSC to resolve all issues related to an extended outage of the Cook Plant, I&M deferred $200 million of incremental operation and maintenance costs during 1999. The deferred amount is being amortized to expense on a straight-line basis over five years from January 1, 1999 to December 31, 2003. I&M amortized $40 million in 1999 and 2000, leaving $120 million as an SFAS 71 regulatory asset at December 31, 2000 on the Consolidated Balance Sheets of AEP and I&M. 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. Debt and Preferred Stock - Where appropriate 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 the debt is refinanced, the reacquisition costs attributable to the portions of the business that are subject to cost based regulatory accounting under SFAS 71 are generally deferred and amortized over the term of the replacement debt commensurate with their recovery in rates. Gains and losses on the reacquisition of debt for operations not subject to SFAS 71 are reported as a component of net income. Debt discount or premium and debt issuances expenses are deferred and amortized over the term of the related debt, with the amortization included in interest charges. Where rates are regulated redemption premiums paid to reacquire preferred stock of the domestic utility subsidiaries are included in paid-in capital and amortized to retained earnings commensurate with their recovery in rates. The excess of par value over costs of preferred stock reacquired is credited to paid-in capital and amortized to retained earnings consistent with the timing of its recovery in rates in accordance with SFAS 71. Goodwill - The amount of acquisition cost in excess of the fair value allocated to tangible assets obtained through an acquisition accounted for as a purchase combination is recorded as goodwill on AEP's consolidated balance sheet. Amortization of goodwill is on a straight-line basis generally over 40 years except for the portion of goodwill associated with gas trading and marketing activities which is being amortized on a straight-line basis over 10 years. The recoverability of goodwill (evaluated on undiscounted operating cash flow analysis) is reviewed when events or changes in circumstances indicate that the carrying amount may exceed fair value. Other Assets - Other assets on AEP's consolidated balance sheet are comprised primarily of nuclear decommissioning and spent nuclear fuel disposal trust funds and licenses for CitiPower operating franchises. 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. Under the provisions of SFAS 71, unrealized gains and losses from securities in these trust funds are not reported in equity but result in adjustments to the liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the spent nuclear fuel disposal trust funds in accordance with their treatment in rates. Comprehensive Income - Comprehensive income is defined as the change in equity (net assets) of a business enterprise during a period from transactions and other events and circumstances from non-owner sources. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. There were no material differences between net income and comprehensive income for AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, and WTU. Components of Other Comprehensive Income - The following table provides the components that comprise the balance sheet amount in Accumulated Other Comprehensive Income for AEP. December 31, Components 2000 1999 1998 - ------------------------------------------------- (millions) Foreign Currency Adjustments $ (99) $ 20 $ 33 Unrealized Losses on Securities - (20) (20) Minimum Pension Liability (4) (4) (6) ----- ---- ---- $(103) $ (4) $ 7 ===== ==== ==== 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 14 "Business Segments" for further discussion and details regarding segments. Common Stock Options - AEP follows Accounting Principles Board Opinion 25 to account for stock options. Compensation expense is not recognized at the date of grant, because the exercise price of stock options awarded under the stock option plan equals the market price of the underlying stock on the date of grant. EPS - AEP's basic earnings per share is determined based upon the weighted average number of common shares outstanding during the years presented. Diluted earnings per share for AEP is based upon the weighted average number of common shares and stock options outstanding during the years presented. Basic and diluted are the same in 2000, 1999 and 1998. AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, and WTU are wholly-owned subsidiaries of AEP and are not required to report EPS. Reclassification - Certain prior year financial statement items have been reclassified to conform to current year presentation. Such reclassification had no impact on previously reported net income. 2. Extraordinary Items: 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 "Industry Restructuring" for descriptions of the restructuring plans and related accounting effects. The following table shows the components of the extraordinary items reported on AEP's consolidated statements of income: Year Ended December 31, 2000 1999 ---- ---- (in millions) Extraordinary Items: Discontinuance of Regulatory Accounting for Generation: Ohio Jurisdiction (Net of Tax of $35 Million) $(44) $ - Virginia and West Virginia Jurisdictions (Inclusive of Tax Benefit of $8 Million) 9 - Texas and Arkansas Jurisdictions (Net of Tax of $5 Million) - (8) Loss on Reacquired Debt (Net of Tax of $3 Million) - (6) ---- ---- Extraordinary Items $(35) $(14) ==== ==== There were no extraordinary items in 1998. 3. Merger: On June 15, 2000, AEP merged with CSW so that CSW became a wholly-owned subsidiary of AEP. Under the terms of the merger agreement, approximately 127.9 million shares of AEP Common Stock were issued in exchange for all the outstanding shares of CSW Common Stock based upon an exchange ratio of 0.6 share of AEP Common Stock for each share of CSW Common Stock. Following the exchange, former shareholders of AEP owned approximately 61.4 percent of the corporation, while former CSW shareholders owned approximately 38.6 percent of the corporation. The merger was accounted for as a pooling of interests. Accordingly, AEP's consolidated financial statements give retroactive effect to the merger, with all periods presented as if AEP and CSW had always been combined. Certain reclassifications have been made to conform the historical financial statement presentation of AEP and CSW. The following table sets forth revenues, extraordinary items and net income previously reported by AEP and CSW and the combined amounts shown in the accompanying financial statements for 1999 and 1998: Year Ended December 31, 1999 1998 ---- ---- (in millions) Revenues: AEP $ 6,870 $ 6,358 CSW 5,537 5,482 ------- ------- AEP After Pooling $12,407 $11,840 ======= ======= Year Ended December 31, 1999 1998 ---- ---- (in millions) Extraordinary Items: AEP $ - $ - CSW (14) - ---- --- AEP After Pooling $(14) $ - ==== === Net Income: AEP $520 $536 CSW 455 440 Conforming Adjustment (3) (1) ---- ---- AEP After Pooling $972 $975 ==== ==== The combined financial statements include an adjustment to conform CSW's accounting for vacation pay accruals with AEP's accounting. The effect of the conforming adjustment was to reduce net assets by $16 million at December 31, 1999 and reduce net income by $3 million and $1 million for the years ended December 31, 1999 and 1998, respectively. The following table shows the vacation accrual conforming adjustment for CSW's registrant utility subsidiaries: Net Asset Net Income Reductions - Reduction At Year Ended December 31, ----------------------- December 31, 1999 1999 1998 ----------------- ------ ------ (in millions) (in millions) CPL $5.3 $0.7 $0.1 PSO 2.8 1.1 - SWEPCo 4.5 0.5 0.1 WTU 2.6 0.4 0.1 In connection with the merger, $203 million ($180 million after tax) of non-recoverable merger costs were expensed by AEP through December 31, 2000. Such costs included transaction and transition costs not recoverable from ratepayers. Also included in the merger costs were non-recoverable change in control payments. Merger transaction and transition costs of $45 million recoverable from ratepayers were deferred pursuant to state regulator approved settlement agreements. 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 ($4 million for AEP for the year 2000) included in depreciation and amortization expense. The following table shows the deferred merger cost and amortization expense of the applicable subsidiary registrants: Amortization Expense for the Merger Cost Deferral Year Ended at December 31, 2000 December 31, 2000 -------------------- ----------------- (in millions) CPL $15.7 $1.3 I&M 7.6 0.7 KPCo 2.7 0.3 PSO 8.3 0.5 SWEPCo 6.6 0.5 WTU 4.6 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. 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 beginning in the third quarter of 2000. In connection with the merger, the PUCT approved a settlement agreement that provides for, among other things, sharing net merger savings with Texas customers of CPL, SWEPCo and WTU over six years after consummation of the merger through rate reduction riders. The settlement agreement results in rate reductions for Texas customers totaling $221 million over a six-year period commencing with the merger's consummation. The rate reduction was composed of $84 million of net merger savings and $137 million to resolve issues associated with CPL's, SWEPCo's and WTU's rate and fuel reconciliation proceedings in Texas. Under the terms of the settlement agreement, base rates cannot be increased until three years after consummation of the merger. The IURC and MPSC approved merger settlement agreements that, among other things, provide for sharing net merger savings with I&M's retail customers over eight years through reductions to customers' bills. The terms of the Indiana settlement require reductions in customers' bills of approximately $67 million over eight years. Under the Michigan settlement, billing credits will be used to reduce customers' bills by approximately $14 million over eight years for net guaranteed merger savings. The Indiana settlement extends the base rate freeze in the Cook Plant extended outage settlement agreement until January 1, 2005 and requires additional annual deposits of $6 million to the nuclear decommissioning trust fund for the Indiana jurisdiction for the years 2001 through 2003. As a result of an appeal of the Indiana settlement agreement by a consumer group, I&M has not reflected the reductions in Indiana jurisdictional customers' bills. Instead, pending the result of the appeal, I&M recorded a liability ($1 million at December 31, 2000) for the reduction due to its Indiana customers under the settlement. The KPSC approved a settlement agreement that, among other things, provides for sharing net merger savings with KPCo's customers over eight years through reductions to customers' bills and prohibits a general increase in base rates or other charges for three years following consummation of the merger. The Kentucky customers' share of the net merger savings is expected to be approximately $28 million. A merger settlement agreement for PSO was approved by the Oklahoma Corporation Commission that, among other things, provides for sharing approximately $28 million in guaranteed net merger savings over five years with Oklahoma customers, prohibits an increase in Oklahoma base rates prior to January 1, 2003 and requires an application to join an RTO be filed with FERC by December 31, 2001. The Arkansas Commission approved an agreement related to the merger which, among other things, provides for $6 million of net merger savings to reduce SWEPCo customers rates over five years in Arkansas and prohibits a base rate increase being effective prior to January 1, 2002. SWEPCo's Louisiana customers will receive approximately $18 million of merger savings over eight years according to a merger approval order issued by the Louisiana Public Service Commission. In addition, the order capped base rates for five years after the consummation of the merger (until June 2005) and required that benefits from off-system sales be shared with ratepayers. 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. Most of the merger settlement agreements approved by the regulatory commissions require the electric operating companies to join regional transmission organizations. APCo, CSPCo, I&M, KPCo, OPCo and several other unaffiliated utilities formed the Alliance RTO before the consummation of the merger. As a condition of FERC's approval of the merger, CPL, PSO, SWEPCo and WTU were required to join an RTO prior to December 31, 2000 and to transfer the operation and control of their transmission facilities to that RTO by December 15, 2001. CPL and WTU are members of ERCOT. PSO and SWEPCo are members of SPP. ERCOT and SPP are transmission pooling organizations in certain geographic areas of the U.S. whose goals include enhancement of bulk electric transmission reliability. The SPP has filed with FERC to be approved as an RTO. Due to the FERC's inaction on approving the SPP RTO, in December 2000 PSO and SWEPCo filed with the FERC requesting an extension of time to join an RTO until 75 days following the FERC's approval of an RTO for the SPP service area. Initial filings to gain FERC approval for the Alliance RTO were made and conditional approval was granted by the FERC. The Alliance RTO made compliance filings as requested by the FERC and these were accepted in January 2001. Final FERC approval of the SPP RTO is pending. The divestiture of 1,904 MW of generating capacity was required as a condition of regulatory approval of the merger by the FERC and PUCT. Under the FERC-approved merger agreement the divestiture of 550 MW of generating capacity comprised of 300 MW of capacity in SPP and 250 MW of capacity in ERCOT is required. The FERC is requiring AEP and CSW to divest their entire ownership interest in and operational control of the entire generating facilities that produce the capacity to be divested. The FERC required divestiture of the identified ERCOT capacity must be completed by March 15, 2001 and for the SPP capacity by July 1, 2002. The FERC found that certain energy sales in SPP and ERCOT would be a reasonable and effective interim mitigation measure until the required SPP and ERCOT divestitures could be completed. In February 2001, AEP announced the sale of Frontera, one of the plants required to be divested by the settlement agreements approved by the FERC. The Texas settlement calls for the divestiture of a total of 1,604 MW of generating capacity within Texas inclusive of 250 MW ordered to be divested by FERC. The Texas divestiture cannot proceed until two years after the merger closes to satisfy the requirements to use pooling-of-interests accounting treatment. The FERC divestiture is not limited by the pooling rules because it is regulatory ordered. The current annual dividend rate per share of AEP Common Stock is $2.40. The dividends per share reported on the statements of income for prior periods represent pro forma amounts and are based on AEP's historical annual dividend rate of $2.40 per share. If the dividends per share reported for prior periods were based on the sum of the historical dividends declared by AEP and CSW, the annual dividend rate would be $2.60 per combined share for the years ended December 31, 1999 and 1998. 4. Nuclear Plant Restart: The restart of both units of I&M's Cook Plant was completed with Unit 2 reaching 100% power on July 5, 2000 and Unit 1 achieving 100% power on January 3, 2001. 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 in March 1999 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 settlement agreement provided for, among other things, the deferral of unrecovered fuel revenues accrued between September 9, 1997 and December 31, 1999; the deferral of up to $150 million of restart related nuclear operation and maintenance costs in 1999 above the amount included in base rates; the amortization of the deferred fuel revenues and non-fuel operation and maintenance cost deferrals over a five-year period ending December 31, 2003; a freeze in base rates through December 31, 2003; and a fixed fuel recovery charge through March 1, 2004. The regulatory approved deferrals were recorded in 1999 as a regulatory asset in accordance with SFAS 71. In December 1999 the MPSC approved a settlement agreement for two open Michigan power supply cost recovery reconciliation cases that resolves all issues related to the Cook Plant extended outage. The settlement agreement limits I&M's ability to increase base rates and freezes the power supply cost recovery factor until January 1, 2004; permits the deferral of up to $50 million in 1999 of jurisdictional non-fuel nuclear operation and maintenance expenses; authorizes the amortization of power supply cost recovery revenues accrued from September 9, 1997 to December 31, 1999 and non-fuel nuclear operation and maintenance cost deferrals over a five-year period ending December 31, 2003. The regulatory approved deferrals were recorded in the fourth quarter of 1999. The amounts of restart costs charged to other operation and maintenance expenses were as follows: Year Ended December 31, 2000 1999 1998 ---- ---- ---- Costs Incurred $297 $ 289 $78 Deferred Pursuant to Settlement Agreements - (200) - Amortization of Deferrals 40 40 - ---- ----- --- Charged to O&M Expense $337 $ 129 $78 ==== ===== === At December 31, 2000 and 1999, deferred restart costs of $120 million and $160 million, respectively, remained in regulatory assets to be amortized through 2003. Also pursuant to the settlement agreements, accrued fuel-related revenues of $38 million and $37 million in 2000 and 1999, respectively, were amortized. At December 31, 2000 and 1999, fuel-related revenues of $113 million and $150 million, respectively, were included in regulatory assets and will be amortized through December 31, 2003 for both jurisdictions. The amortization of restart costs and fuel-related revenues deferred under Indiana and Michigan retail jurisdictional settlement agreements will adversely affect results of operations through December 31, 2003 when the amortization period ends. The annual amortization of restart cost and fuel-related revenue deferrals is $78 million. 5. Rate Matters: Texas Jurisdictional Fuel Filings - AEP's Texas electric operating companies (CPL, SWEPCo and WTU) have been experiencing significant natural gas fuel price increases which have resulted in under-recoveries of fuel costs and the need to seek increases in fuel rates and surcharges to recover these under-recoveries. CPL Fuel Filings - In July 2000 CPL filed with the PUCT an application to implement an increase in fuel factor revenues effective with the September 2000 billing month. Additionally, CPL proposed to implement an interim fuel surcharge to collect its under-recovered fuel costs, including accumu-lated interest, over a twelve-month period begin-ing in October 2000. In September 2000 the PUCT approved a settlement. The settlement provided for an increase in fuel factor revenues of $173.5 million annually and provided for a two-phase surcharge totaling $86.4 million. The recovery of the first phase surcharge of $21.3 million for previously under-recovered fuel costs including accumulated interest for the period from December 1, 1999 through May 31, 2000 was authorized to be collected in September through December 2000. The second surcharge was not to exceed $65.1 million for projected under-recoveries for the period from June 2000 through August 2000 and was authorized to be collected January through September 2001. A September 2000 compliance filing showed the actual under-recovery for June 2000 through August 2000 to be $93.7 million. The remaining under-recovery amount of $28.6 was carried forward into a January 2001 filing. In January 2001 CPL filed with the PUCT an application to implement an increase in fuel factors of $175.9 million, effective with the March 2001 billing month over the ten months March 2001 through December 2001. Additionally, CPL proposed to implement an interim fuel surcharge of $51.8 million, including accumulated interest, over a nine-month period beginning in April 2001 to collect its under-recovered fuel costs. Approval by the PUCT is pending. SWEPCo Fuel Filings - In November 2000 SWEPCo filed with the PUCT an application for authority to implement an increase in fuel factor revenues effective with the January 2001 billing month. SWEPCo also proposed to implement an interim fuel surcharge to collect its under-recovered fuel costs, including accumulated interest, over a six-month period beginning in January 2001. In January 2001 the PUCT approved SWEPCo's application. The order allows an increase in fuel factors of $12 million on an annual basis including accumulated interest beginning in January 2001 and a surcharge of $11.8 million for the billing months of February through July 2001. In June 2000 SWEPCo filed with the PUCT an application for authority to reconcile fuel costs and to request authorization to carry the unrecovered balance forward into the next reconciliation period. During the reconciliation period of January 1, 1997 through December 31, 1999, SWEPCo incurred $347 million of Texas jurisdiction eligible fuel and fuel-related expenses. On December 27, 2000, SWEPCo reached a settlement. The settlement resulted in a reduction of $2.25 million of eligible Texas jurisdictional fuel expense, which was prorated equally over thirty-six months of the reconciliation period. The settlement also provides that depreciation and lease expense associated with new aluminum railcars will qualify for treatment as eligible fuel expense from January 1, 2000 forward. Parties to the settlement will support SWEPCo in seeking to amend its 1999 excess earnings report to include 1999 railcar depreciation expense in the depreciation component of the calculation. In February 2001, the PUCT approved the settlement, which did not have a material effect on SWEPCo's results of operations. WTU Fuel Filings - In August 2000 WTU filed with the PUCT an application for authority to implement an increase in fuel factors effective with the October 2000 billing month. WTU also proposed to implement an interim fuel surcharge to collect its under-recovered fuel costs from August 1, 1999 through June 30, 2000 including accumulated interest, over a six-month period beginning in November 2000. In December 2000, the PUCT approved WTU's application. The order allows an increase in fuel factors of $42.6 million on an annual basis including accumulated interest and provides for a surcharge of $19.6 million for previously under-recovered fuel costs. In January 2001 WTU filed with the PUCT an application for authority to implement an increase in fuel factor revenues of $46.5 million effective with the March 2001 billing. Approval by the PUCT is pending. In December 2000 WTU filed with the PUCT an application for authority to reconcile fuel costs. During the reconciliation period of July 1, 1997 through June 30, 2000, WTU incurred $348 million of Texas jurisdiction eligible fuel and fuel-related expenses. Approval by the PUCT is pending. OPCo's Recovery of Fuel Costs - Pursuant to PUCO - approved stipulation agreements the cost of coal burned at the Gavin Plant was subject to a 15-year predetermined price of $1.575 per million Btu's with quarterly escalation adjustments through November 2009. To the extent the actual cost of coal burned at the Gavin Plant was below the predetermined prices, the stipulation agreement provided OPCo with the opportunity to recover over its term the Ohio jurisdictional share of OPCo's investment in and the liabilities and future shutdown costs of its affiliated mines as well as any fuel costs incurred above the pre-determined rate and deferred for future recovery under the agreements. As a result of the Ohio Act introducing customer choice and a transition to market based pricing for electricity supply in Ohio, these stipulation agreements were superseded effective January 1, 2001. OPCo filed under the provisions of the Ohio Act for recovery of all of its generation related regulatory assets including fuel costs deferred under these predetermined price stipulation agreements. Under the terms of OPCo's PUCO-approved stipulated transition plan, recovery of generation-related regulatory assets at December 31, 2000, which were $518 million, over seven years was approved. The Muskingum coal strip mine and Windsor deep coal mine which supplied all of their output to OPCo have been closed. Efforts are underway to reclaim the properties, sell or scrap all mining equipment, terminate both capital and operating leases and perform other activities necessary to reclaim the mines. Mine reclamation activities should be completed within two to three years; postremediation monitoring is anticipated to continue for five years after completion of reclamation. OPCo currently plans to close the Meigs deep coal mine by the end of 2001 unless ongoing efforts to sell it are successful. Currently efforts are being made to sell the active Meigs and shutdown Windsor and Muskingum mines. FERC - The FERC issued orders 888 and 889 in April 1996 which required 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, and to pay their own transmission service tariffs in making off-system and third-party sales. As part of the orders, the FERC issued a pro-forma tariff, which reflects the Commission's views on the minimum non-price terms and conditions for non-discriminatory transmission service. The FERC orders also allow a utility to seek recovery of certain prudently-incurred stranded costs that result from unbundled transmission service. On July 9, 1996, the AEP System companies filed an Open Access Transmission Tariff conforming with the FERC's pro-forma transmission tariff, subject to the resolution of certain pricing issues. The 1996 tariff incorporated transmission rates which were the result of a settlement of a pending rate case, but which were being collected subject to refund from certain customers who opposed the settlement and continued to litigate the reasonableness of AEP's transmission rates. On July 30, 1999, the FERC issued an order in the litigated rate case that would reduce AEP's rates for the affected customers below the settlement rate. AEP and certain of the affected customers sought rehearing of the Commission's Order. On December 10, 1999, AEP filed a settlement agreement with the FERC resolving the issues on rehearing of the July 30, 1999 order. On March 16, 2000, the FERC approved the settlement agreement. Under terms of the settlement, the AEP System is required to make refunds retroactive to September 7, 1993 to certain customers affected by the July 30, 1999 FERC order. The refunds were made in two payments. Pursuant to FERC orders the first payment was made in February 2000 and the second payment was made on August 1, 2000. APCo, CSPCo, I&M, KPCo, and OPCo recorded provisions in 1999 and 2000 for the earnings impact of the required refunds including interest. The settlement agreement also reduced the rates for transmission service. A new lower rate of $1.55 kw/month was made effective January 1, 2000, for all transmission service customers. Also as agreed, a new rate of $1.42 kw/month took effect on June 16, 2000 upon consummation of the AEP/CSW merger. Prior to January 1, 2000, the rate was $2.04 kw/month. Unless the market volume of physical power transactions grows to increase the utilization of the AEP System's transmission lines, the new open access transmission rate will adversely impact future results of operations and cash flows. Since the rate has been reduced the volume of transmission usage has increased on the AEP System mainly due to increased competition in the wholesale electricity market. West Virginia On May 12, 1999, APCo, an AEP subsidiary doing business in WV, filed with the WVPSC for a base rate increase of $50 million annually and a reduction in ENEC rates of $38 million annually. On February 7, 2000, APCo and other parties to the proceeding filed a Joint Stipulation with the WVPSC for approval. The Joint Stipulation's main provisions include no change in either base or ENEC rates effective January 1, 2000 from those base and ENEC rates in effect from November 1, 1996 until December 31, 1999 (these rates provide for recovery of regulatory assets including any generation-related regulatory assets through frozen transition rates and a wires charge of 0.5 mills per KWH); the continued suspension of annual ENEC recovery proceedings and cessation of existing deferral accounting for all over or under recovery of fuel and purchased power costs net of system sales effective January 1, 2000; and the retention, as a regulatory liability, on the books of a net cumulative deferred ENEC overrecovery balance of $66 million as established by a WVPSC order on December 27, 1996. The Joint Stipulation also provides that when deregulation of generation occurs in WV, APCo will use this retained regulatory liability to reduce generation-related regulatory assets and, to the extent possible, any additional costs or obligations that restructuring and deregulation of APCo's generation business may impose. The elimination of ENEC recovery proceedings in WV will subject AEP and APCo to the risk of fuel market price increases and reductions in wholesale sales levels which could adversely affect results of operations and cash flows. Also, under the Joint Stipulation, APCo's share of any net savings from the merger between AEP and CSW prior to December 31, 2004 shall be retained by APCo. As a result, all costs incurred in the merger that were allocated to APCo shall be fully charged to expense to partially offset merger savings through December 31, 2004 and shall not be included in any WV rate proceeding after that date. After December 31, 2004, current distribution savings related to the merger will be reflected in rates in any future rate proceeding before the WVPSC to establish distribution rates or to adjust rate caps during the transition to market based generation rates. When deregulation of generation occurs in WV, the net retained generation-related merger savings shall be used to recover any generation-related regulatory assets that are not recovered under the other provisions of the Joint Stipulation and the mechanisms provided for in the deregulation legislation and, to the extent possible, to recover any additional costs or obligations that deregulation may impose on APCo. Regardless of whether the net cumulative deferred ENEC overrecovery balance and the net merger savings are sufficient to offset all of APCo's generation-related regulatory assets, under the terms of the Joint Stipulation there will be no further explicit adjustment to APCo's rates to provide for recovery of generation-related regulatory assets beyond the above discussed specific adjustment provisions in the Joint Stipulation and the 0.5 mills per KWH wires charge in the WV Restructuring Plan (see Note 7 "Industry Restructuring" for discussion of WV Restructuring Plan). On June 2, 2000, the WVPSC issued an order approving the Joint Stipulation. Management expects that the stipulation agreement plus the provisions of pending restructuring legislation will, if the legislation becomes effective, provide for the recovery of existing regulatory assets, other stranded costs and the cost of such deregulation in WV. 6. Effects of Regulation: In accordance with SFAS 71 the consolidated financial statements include regulatory assets (deferred expenses) and regulatory liabilities (deferred revenues) recorded in accordance with regulatory actions in order to match expenses and revenues from cost-based rates in the same accounting period. Regulatory assets are expected to be recovered in future periods through the rate-making process and regulatory liabilities are expected to reduce future cost recoveries. Among other things, application of SFAS 71 requires that the AEP System's regulated rates be cost-based and the recovery of regulatory assets 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 WV no longer met the requirements to apply SFAS 71, net regulatory assets were written off for that portion of the business unless they were determined to be recoverable as a stranded cost through regulated distribution rates or wire charges in accordance with SFAS 101 "Regulated Enterprises - Accounting for the Discontinuation of FASB Statement No. 71" and EITF 97-4 "Deregulation of the Pricing of Electricity - Issues Related to the Application of FASB No. 71, Accounting for the Effects of Certain Types of Regulation, and No. 101, Regulated Enterprises - Accounting for the Discontinuation of the Application of FASB Statement No. 71." In the Ohio, Virginia and WV jurisdictions the generation-related regulated 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. In the Texas jurisdiction generation-related regulatory assets that have been tentatively approved for recovery through securitization have been classified as "regulatory assets designated for securitization." (See Note 7 "Industry Restructuring" for further details.) AEP's recognized regulatory assets and liabilities are comprised of the following at: December 31, 2000 1999 (in millions) Regulatory Assets: Amounts Due From Customers For Future Income Taxes $ 914 $1,450 Transition - Regulatory Assets 963 - Regulatory Assets Designated for Securitization 953 953 Deferred Fuel Costs 407 477 Unamortized Loss on Reacquired Debt 113 154 Cook Plant Restart Costs 120 160 DOE Decontamination and Decommissioning Assessment 35 39 Other 193 231 ------ ------ Total Regulatory Assets $3,698 $3,464 ====== ====== Regulatory Liabilities: Deferred Investment Tax Credits $528 $580 Other 208 315 ---- ---- Total Regulatory Liabilities $736 $895 ==== ==== The recognized regulatory assets and liabilities for the registrant subsidiaries are comprised of the following at:
AEGCo APCo CPL CSPCo I&M --------------------------------------------------------- December 31, 2000 (in thousands) Regulatory Assets: Amounts Due From Customers For Future Income Taxes $217,540 $ 206,930 $ 31,853 $229,466 Transition - Regulatory Assets 191,469 247,852 Excess Earnings (39,700) Regulatory Assets Designated For Securitization 953,249 Deferred Fuel Costs 14,669 127,295 112,503 Unamortized Loss on Reacquired Debt $5,504 11,676 12,773 8,340 17,740 Deferred Storm Damage 1,244 Cook Plant Restart Costs 120,000 DOE Decontamination and Decommissioning Assessment 3,622 31,744 Other 11,152 18,815 3,508 40,687 ------ -------- ---------- -------- -------- Total Regulatory Assets $5,504 $447,750 $1,282,984 $291,553 $552,140 ====== ======== ========== ======== ======== Regulatory Liabilities: Deferred Investment Tax Credits $59,718 $ 43,093 $128,100 $41,234 $113,773 Amounts Due To Customers For Future Income Taxes 23,996 WV Rate Stabilization 75,601 Other 2,614 11,510 9,930 ------- -------- -------- ------- -------- Total Regulatory Liabilities $83,714 $121,308 $128,100 $52,744 $123,703 ======= ======== ======== ======= ======== KPCo OPCo PSO SWEPCo WTU ------------------------------------------------------ December 31, 2000 (in thousands) Regulatory Assets: Amounts Due From Customers For Future Income Taxes $85,926 $180,602 $14,558 Transition - Regulatory Assets 517,851 Deferred Fuel Costs $43,267 35,469 $67,655 Unamortized Loss on Reacquired Debt 459 6,106 13,600 22,626 11,204 Other 12,130 10,151 15,738 19,898 13,604 ------- -------- ------- ------- ------- Total Regulatory Assets $98,515 $714,710 $72,605 $92,551 $92,463 ======= ======== ======= ======= ======= Regulatory Liabilities: Deferred Investment Tax Credits $11,656 $25,214 $35,783 $53,167 $24,052 Excess Earnings 500 15,100 Amounts Due To Customers For Future Income Taxes 28,652 13,493 Other 3,172 10,994 2,015 8,140 ------- ------- ------- ------- -------- Total Regulatory Liabilities $14,828 $36,208 $66,450 $61,807 $52,645 ======= ======= ======= ======= ======= AEGCo APCo CPL CSPCo I&M ------------------------------------------------------ December 31, 1999 (in thousands) Regulatory Assets: Amounts Due From Customers For Future Income Taxes $389,922 $212,364 $243,031 $236,783 Excess Earnings (18,400) Regulatory Assets - Designated For Securitization 953,249 Deferred Fuel Costs 30,423 150,004 Unamortized Loss on Reacquired Debt $5,744 20,828 13,983 23,307 14,780 Deferred Zimmer Plant Carrying Charges 42,826 Deferred Storm Damage 6,619 Cook Plant Restart Costs 160,000 DOE Decontamination and Decommissioning Assessment 4,022 35,238 Other 19,525 11,390 29,939 28,005 ------ -------- ---------- -------- -------- Total Regulatory Assets $5,744 $436,894 $1,207,031 $339,103 $624,810 ====== ======== ========== ======== ======== Regulatory Liabilities: Deferred Investment Tax Credits $63,114 $ 57,259 $ 133,306 $ 44,716 $121,627 Amounts Due To Customers For Future Income Taxes 26,266 50% Share - Net WV ENEC 36,589 Over Recovery - Fuel Costs 34,676 Deferred Gains From Emission Allowance Sales 1,867 13,539 Other 7,180 24,082 17,238 ------- -------- --------- -------- -------- Total Regulatory Liabilities $89,380 $137,571 $ 133,306 $ 82,337 $138,865 ======= ======== ========= ======== ======== KPCo OPCo PSO SWEPCo WTU ----------------------------------------------------- December 31, 1999 (in thousands) Regulatory Assets: Amounts Due From Customers For Future Income Taxes $88,764 $331,164 $ 7,128 Deferred Fuel Costs 197,631 $6,469 $14,652 Unamortized Loss on Reacquired Debt 711 15,666 14,880 25,539 14,700 Other 6,821 49,924 1,837 14,513 15,045 ------- -------- ------- ------- ------- Total Regulatory Assets $96,296 $594,385 $23,186 $47,180 $44,397 ======= ======== ======= ======= ======= Regulatory Liabilities: Deferred Investment Tax Credits $12,908 $ 35,838 $37,574 $57,649 $25,323 Excess Earnings 6,500 6,000 Amounts Due To Customers For Future Income Taxes 32,826 13,146 Deferred Gains From Emission Allowance Sales 53,738 Other 2,792 13,043 2,480 ------- -------- ------- ------- ------- Total Regulatory Liabilities $15,700 $102,619 $70,400 $66,629 $44,469 ======= ======== ======= ======= =======
7. Industry Restructuring: Restructuring legislation has been enacted in seven of the eleven state retail jurisdictions in which AEP's domestic electric utility companies operate. The legislation provides for a transition from cost-based regulation of bundled electric service to unbundled cost-based rate regulation of transmission and distribution service and customer choice market pricing for the supply of electricity. The enactment of restructuring legislation and the ability to determine transition rates, wires charges and any resultant extraordinary gain or loss under restructuring legislation enabled APCo, CPL, CSPCo, OPCo, SWEPCo and WTU to discontinue regulatory accounting for the generation portion of their business in those jurisdictions. Prior to restructuring, the electric utility companies accounted for their operations according to the cost-based regulatory accounting principles of SFAS 71. Under the provisions of SFAS 71, regulatory assets and regulatory liabilities are recorded to reflect the economic effects of regulation to account for the difference between regulatory accounting and GAAP and to match expenses with regulated revenues. The discontinuance of the application of SFAS 71 is in accordance with the provisions of SFAS 101. Pursuant to those provisions and further guidance provided in EITF Issue 97-4, a company is required to write-off regulatory assets and liabilities related to the deregulated operations, unless recovery of such amounts is provided through cost-based regulated rates to be collected in the portion of operations which continues to be rate regulated. Additionally, a company experiencing a discontinuance of cost-based rate regulation is required to determine if any plant assets are impaired under SFAS 121. A SFAS 121 accounting impairment analysis involves estimating cumulative future non-discounted net cash flows arising from the use of assets. If the cumulative undiscounted net cash flows exceed the net book value of the assets, then there is no impairment of the assets for accounting purposes. If there is any accounting impairment, it would be recorded on a discounted basis. As legislative and regulatory proceedings evolve, the electric operating companies doing business in the seven states that have passed restructuring legislation are applying the standards discussed above to discontinue SFAS 71 regulatory accounting. The following is a summary of the restructuring legislation, the status of the transition plans and the status of the electric utility operating companies' accounting to comply with the changes in each of the seven state regulatory jurisdictions affected by restructuring legislation. Ohio Restructuring - Affecting AEP, CSPCo and OPCo Effective January 1, 2001, customer choice of electricity supplier began under the Ohio Act. In February 2001, one supplier announced its plan to offer service to CSPCo's residential customers. Currently for residential customers of OPCo, no alternative suppliers have registered with the PUCO as required by the Ohio Act. Two alternative suppliers have been approved to compete for CSPCo's and OPCo's commercial and industrial customers. Presently, customers continue to be served by CSPCo and OPCo with a legislatively required residential rate reduction of 5% for the generation portion of rates and a freezing of generation rates including fuel rates starting on January 1, 2001. The Ohio Act provides for a five-year transition period to move from cost based rates to market pricing for generation services. It granted the PUCO broad oversight responsibility for promul-gation of rules for competitive retail electric generation service, approval of a transition plan for each electric utility company and addressing certain major transition issues including unbund-ling of rates and the recovery of stranded costs including regulatory assets and transition costs. The Ohio Act also provides for a reduction in property tax assessments, the imposition of replacement franchise and income taxes, and the replacement of a gross receipts tax with a KWH based excise tax. The property tax assessment percentage on generation property was lowered from 100% to 25% of value effective January 1, 2001 and Ohio electric utilities will become subject to the Ohio Corporate Franchise Tax and municipal income taxes on January 1, 2002. The last year for which Ohio electric utilities will pay the excise tax based on gross receipts is the tax year ending April 30, 2002. As of May 1, 2001 electric distribution companies will be subject to an excise tax based on KWH sold to Ohio customers. The gross receipts tax is paid at the beginning of the tax year (May 1), deferred by CSPCo and OPCo as a prepaid expense and amortized to expense during the tax year pursuant to the tax law whereby the payment of the tax results in the privilege to conduct business in the year following the payment of the tax. As a result a duplicate tax will be expensed from May 1, 2001 through April 30, 2002 adding approximately $90 million ($40 million for CSPCo and $50 million for OPCo) to tax expense during that period. Unless CSPCo and OPCo can recover the duplicate amount from ratepayers it will negatively impact results of operations. On September 28, 2000, the PUCO approved, with minor modifications, a stipulation agreement between CSPCo, OPCo, the PUCO staff, the Ohio Consumers' Counsel and other concerned parties regarding transition plans filed by CSPCo and OPCo. The key provisions of this stipulation agreement are: o Recovery of generation-related regulatory assets at December 31, 2000 over seven years for OPCo ($518 million) and over eight years for CSPCo ($248 million) through frozen transition rates for the first five years of the recovery period and a wires charge for the remaining years. o A shopping incentive (a price credit) of 2.5 mills per KWH for the first 25% of CSPCo residential customers that switch suppliers. There is no shopping incentive for OPCo customers. o The absorption of $40 million by CSPCo and OPCo ($20 million per company) of consumer education, implementation and transition plan filing costs with deferral of the remaining costs, plus a carrying charge, as a regulatory asset for recovery in future distribution rates. o CSPCo and OPCo will make available a fund of up to $10 million to reimburse customers who choose to purchase their power from another company for certain transmission charges imposed by PJM and/or a Midwest ISO on generation originating in the Midwest ISO or PJM areas. o The statutory 5% reduction in the generation component of residential tariffs will remain in effect for the entire five year transition period. o CSPCo's and OPCo's request for a $90 million gross receipts tax rider to recover the duplicate gross receipts KWH based excise tax would be considered separately by the PUCO. The approved stipulation agreement also accepted the following provisions contained in CSPCo's and OPCo's filed transition plans: o a corporate separation plan to segregate generation, transmission and distribution assets into separate legal entities, and o a plan for independent operation of transmission facilities. The gross receipts tax issue was considered by the PUCO in hearings held in June 2000. In the September 28, 2000 order approving the stipulation agreement, the PUCO determined that there was no duplicate tax overlap period and denied the request for a $90 million gross receipts tax rider. CSPCo's and OPCo's request for rehearing of the gross receipts tax issue was denied. An appeal of this issue to the Ohio Supreme Court has been filed. Unless this issue is resolved in CSPCo's and OPCo's favor, it will have an adverse effect on future results of operations and financial position. One of the intervenors at the hearings for approval of the settlement agreement (whose request for rehearing was denied by the PUCO) has filed with the Ohio Supreme Court for review of the settlement agreement including recovery of regulatory assets. Management is unable to predict the outcome of litigation but the resolution of this matter could negatively impact results of operation. Beginning January 1, 2001, CSPCo's and OPCo's fuel costs will not be subject to PUCO fuel recovery proceedings. Deferred fuel costs at December 31, 2000 which represent under or over recoveries were one of the items included in the PUCO's final determination of net regulatory assets to be collected (recovered) during the transition period. The elimination of fuel clause recoveries in 2001 in Ohio will subject AEP, CSPCo and OPCo to the risk of fuel market price increases and could adversely affect their future results of operations and cash flows. CSPCo and OPCo Discontinue Application of SFAS 71 Regulatory Accounting for the Ohio Jurisdiction In September 2000 CSPCo and OPCo discontinued the application of SFAS 71 for their Ohio retail jurisdictional generation business since generation is no longer cost-based regulated in the Ohio jurisdiction and management was able to determine their transition rates and wires charges. The discontinuance in the Ohio jurisdiction was possible as a result of the PUCO's September 28, 2000 approval of the stipulation agreement which established rates, wires charges and net regulatory asset recovery procedures during the transition to market rates. CSPCo's and OPCo's discontinuance of SFAS 71 for generation resulted in after tax extraordinary losses in the third quarter of 2000 of $25 million and $19 million, respectively, due to certain unrecoverable generation-related regulatory assets and transition expenses. Management believes that substantially all of the remaining net regulatory assets related to the Ohio generation business will be recovered under the PUCO's September 28, 2000 order. Therefore, under the provisions of EITF 97-4, CSPCo's and OPCo's generation-related recoverable net regulatory assets were transferred to the transmission and distribution portion of the business and will be amortized as they are recovered through transition rates to customers. CSPCo and OPCo performed an accounting impairment analysis on their generating assets under SFAS 121 as required when discontinuing the application of SFAS 71 and concluded there was no impairment of generation assets. Virginia - Affecting AEP and APCo In Virginia, a restructuring law provides for a transition to choice of electricity supplier for retail customers beginning on January 1, 2002. In February 2001 restructuring revision legislation was approved by the Virginia Legislature which could modify the terms of restructuring. Presently, the transition period is to be completed, subject to a finding by the Virginia SCC that an effective competitive market exists by January 1, 2004 but no later than January 1, 2005. The restructuring law also 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. The restructuring law provides for the establishment of capped rates prior to January 1, 2001 based either on a request by APCo for a change in rates prior to January 1, 2001 or on the rates in effect at July 1, 1999 if no rate change request is made and the establishment of a wires charge by the fourth quarter of 2001. APCo did not request new rates; therefore, its current rates are the capped rates. In the third quarter of 2000, the Virginia SCC directed APCo to file a cost of service study using 1999 as a test year to review the reasonableness of APCo's capped rates. The cost of service study was filed on January 3, 2001. In the opinion of APCo's Virginia counsel, Virginia's restructuring law does not permit the Virginia SCC to change rates for the transition period except for changes in the fuel factor, changes in state gross receipts taxes, or to address the utility's financial distress. However, if the Virginia SCC were to reduce APCo's capped rates or deny recovery of regulatory assets, it would adversely affect results of operations if such action is ultimately determined to be legal. The Virginia restructuring law also requires filings to be made that outline the functional separation of generation from transmission and distribution and a rate unbundling plan. On January 3, 2001, APCo filed its corporate separation plan and rate unbundling plan with the Virginia SCC which is based on the most recent rate case test year (1996). See the heading "Structural Separation" below in this footnote for a discussion of AEP's corporate separation plan filed with the SEC. West Virginia - Affecting AEP and APCo On January 28, 2000, the WVPSC issued an order approving an electricity restructuring plan for WV. On March 11, 2000, the WV Legislature approved the restructuring plan by joint resolution. The joint resolution provides that the WVPSC cannot implement the plan until the legislature makes necessary tax law changes to preserve the revenues of the state and local governments. The Joint Committee on Government and Finance of the WV Legislature hired a consultant to study and issue a report on the tax changes required to implement electric restructuring. Moreover, the committee also hired a consultant to study and issue a report on the electric restructuring plan in light of events occurring in California. The WV Legislature is not expected to consider these reports until the 2002 Legislative Session since the 2001 Legislative Session ends in April 2001. Since the WV Legislature has not yet passed the required tax law changes, the restructuring plan has not become effective. AEP subsidiaries, APCo and WPCo, provide electric service in WV. The provisions of the restructuring plan provide for customer choice to begin after all necessary rules are in place (the "starting date"); deregulation of generation assets on the starting date; functional separation of the generation, transmission and distribution businesses on the starting date and their legal corporate separation no later than January 1, 2005; a transition period of up to 13 years, during which the incumbent utility must provide default service for customers who do not change suppliers unless an alternative default supplier is selected through a WVPSC-sponsored bidding process; capped and fixed rates for the 13 year transition period as discussed below; deregulation of metering and billing; a 0.5 mills per KWH wires charge applicable to all retail customers for a 10-year period commencing with the starting date intended to provide for recovery of any stranded cost including net regulatory assets; establishment of a rate stabilization deferred liability balance of $81 million ($76 million by APCo and $5 million by WPCo) by the end of year ten of the transition period to be used as determined by the WVPSC to offset market prices paid in the eleventh, twelfth, and thirteenth year of the transition period by residential and small commercial customers that do not choose an alternative supplier. Default rates for residential and small commercial customers are capped for four years after the starting date and then increase as specified in the plan for the next six years. In years eleven, twelve and thirteen of the transition period, the power supply rate shall equal the market price of comparable power. Default rates for industrial and large commercial customers are discounted by 1% for four and a half years, beginning July 1, 2000, and then increased at pre-defined levels for the next three years. After seven years the power supply rate for industrial and large commercial customers will be market based. APCo's Joint Stipulation agreement, discussed in Note 5 "Rate Matters", which was approved by the WVPSC on June 2, 2000 in connection with a base rate filing, also provides additional mechanisms to recover regulatory assets. APCo Discontinues Application of SFAS 71 Regulatory Accounting In June 2000 APCo discontinued the application of SFAS 71 for its Virginia and WV retail jurisdictional portions of its generation business since generation is no longer considered to be cost-based regulated in those jurisdictions and management was able to determine APCo's transition rates and wires charges. The discontinuance in the WV jurisdiction was made possible by the June 2, 2000 approval of the Joint Stipulation which established rates, wires charges and regulatory asset recovery procedures for the transition period to market rates which was determined to be probable. APCo was also able to discontinue application of SFAS 71 for the generation portion of its Virginia retail jurisdiction after management decided that APCo would not request capped rates different from its current rates. The existence of effective restructuring legislation in Virginia and the probability that the WV legislation would become effective with the expected probable passage of required enabling tax legislation in 2001 supported management's decision in 2000 to discontinue SFAS 71 regulatory accounting for APCo's electricity generation and supply business. APCo's discontinuance of SFAS 71 for generation resulted in an after tax extraordinary gain, in the second quarter of 2000, of $9 million. Management believes that it is probable that substantially all net regulatory assets related to the Virginia and WV generation business will be recovered. Therefore, under the provisions of EITF 97-4, APCo's generation-related net regulatory assets were transferred to the distribution portion of the business and are being amortized as they are recovered through charges to regulated distribution customers. As required by SFAS 101 when discontinuing SFAS 71 regulatory accounting, APCo performed an accounting impairment analysis on its generating assets under SFAS 121 and concluded that there was no accounting impairment of generation assets. The studies requested by the WV Legislature, discussed above, could result in the WV Legislature deciding not to enact the required tax changes, thereby, effectively continuing cost based rate regulation in West Virginia or it could modify the restructuring plan. Modifications in the restructuring plan could adversely affect future results of operations if they were to occur. Management is carefully monitoring the situation in West Virginia and continues to work with all concerned parties to get approval to successfully transition APCo's generation business in West Virginia. Failure to pass the required enabling tax changes could ultimately require APCo to reinstate regulatory accounting principles under SFAS 71 for its generation operations in West Virginia. Arkansas Restructuring - Affecting AEP and SWEPCo In 1999 legislation was enacted in Arkansas that will ultimately restructure the electric utility industry. Its major provisions are: o retail competition begins January 1, 2002 but can be delayed until as late as June 30, 2003 by the Arkansas Commission; o transmission facilities must be operated by an ISO if owned by a company which also owns generation assets; o rates will be frozen for one to three years; o market power issues will be addressed by the Arkansas Commission; and o an annual progress report to the Arkansas General Assembly on the development of competition in electric markets and its impact on retail customers is required. In November 2000 the Arkansas Commission filed its annual progress report with the Arkansas General Assembly recommending a delay in the start date of retail competition to a date between October 1, 2003 and October 1, 2005. The report also asks the Arkansas General Assembly to delegate authority to the Arkansas Commission to determine the appropriate retail competition start date within the approved time frame. In February 2001 the Arkansas General Assembly passed legislation that was signed into law by the Governor that changes the date of electric retail competition to October 1, 2003, and provided the Arkansas Commission with the authority to delay that date for up to two years. Texas Restructuring - Affecting AEP, CPL, SWEPCo and WTU In June 1999 Texas restructuring legislation was signed into law which, among other things: o gives Texas customers of investor-owned utilities the opportunity to choose their electricity provider beginning January 1, 2002; o provides for the recovery of regulatory assets and of other stranded costs through securitization and non-bypassable wires charges; o requires reductions in NOx and sulfur dioxide emissions; o provides for a rate freeze until January 1, 2002 followed by a 6% rate reduction for residential and small commercial customers and a number of customer protections; o provides for an earnings test for each of the three years of the rate freeze period (1999 through 2001) which will reduce stranded cost recoveries or if there is no stranded cost provides for a refund or their use to fund certain capital expenditures in the amount of the excess earnings; o requires each utility to structurally unbundle into a retail electric provider, a power generation company and a transmission and distribution utility; o provides for certain limits for ownership and control of generating capacity by companies; o provides for elimination of the fuel clause reconciliation process beginning January 1, 2002; and o provides for a 2004 true-up proceeding to determine recovery of stranded costs including final fuel recovery balances, net regulatory assets, certain environmental costs, accumulated excess earnings and other issues. Under the Texas Legislation, delivery of electricity will continue to be the responsibility of the local electric transmission and distribution utility company at regulated prices. Each electric utility was required to submit a plan to structurally unbundle its business activities into a retail electric provider, a power generation company, and a transmission and distribution utility. In May 2000 CPL, SWEPCo and WTU filed a revised business separation plan that the PUCT approved on July 7, 2000 in an interim order. The revised business separation plans provided for CPL and WTU, which operate in Texas only, to establish separate companies and divide their integrated utility operations and assets into a power generation company, a transmission and distribution utility and a retail electric provider. SWEPCo will separate its Texas jurisdictional transmission and distribution assets and operations into a new Texas regulated transmission and distribution subsidiary. In addition, a retail electric provider will be formed by SWEPCo to provide retail electric service to SWEPCo's Texas jurisdictional customers. Under the Texas Legislation, electric utilities are allowed, with the approval of the PUCT, to recover stranded generation costs including generation-related regulatory assets that may not be recoverable in a future competitive market. The approved stranded costs can be refinanced through securitization, which is a financing structure designed to provide lower financing costs than are available through conventional financings. Lower financing costs are achieved through the issuance of securitization bonds at a lower interest rate to finance 100% of the costs pursuant to a state pledge to ensure recovery of the bond principal and financing costs through a non-bypassable rate surcharge by the regulated transmission and distribution utility over the life of the securitization bonds. In 1999 CPL 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 permitting CPL to securitize approximately $764 million of net regulatory assets. The PUCT's order authorized issuance of up to $797 million of securitization bonds including the $764 million for recovery of net generation-related regulatory assets and $33 million for other qualified refinancing costs. The $764 million for recovery of net generation-related regulatory assets reflects the recovery of $949 million of generation-related regulatory assets offset by $185 million of customer benefits associated with accumulated deferred income taxes. CPL had previously proposed in its filing to flow these benefits back to customers over the 14-year term of the securitization bonds. On April 11, 2000, four parties appealed the PUCT's securitization order to the Travis County District Court. In July 2000 the Travis County District Court upheld the PUCT's securitization order. The securitization order is being appealed to the Supreme Court of Texas. One of these appeals challenges CPL's ability to recover securitization charges under the Texas Constitution. CPL will not be able to issue the securitization bonds until these appeals are resolved. The remaining regulatory assets of $206 million originally included by CPL in its 1999 securitization request were included in a March 2000 filing with the PUCT, requesting recovery of an additional $1.1 billion of stranded costs. The March 2000 filing of $1.1 billion included recovery of approximately $800 million of STP costs included in property, plant and equipment-electric on AEP's Consolidated Balance Sheets and in electric utility plant-production on CPL's Consolidated Balance Sheets. These STP costs had previously been identified as excess cost over market (ECOM) by the PUCT for regulatory purposes and were earning a lower return and were being amortized on an accelerated basis for rate-making purposes in Texas. The March 2000 filing will determine the initial amount of stranded costs in addition to the securitized regulatory assets to be recovered beginning January 1, 2002. CPL submitted a revised estimate of stranded costs on October 2, 2000 using assumptions developed in generic proceedings by the PUCT and an administrative model developed by the PUCT staff that reduced the amount of the initial stranded cost estimate to $361 million from the $1.1 billion requested by CPL. CPL subsequently agreed to accept adjustments proposed by intervenors that reduced ECOM to approximately $230 million. Hearings on CPL's requested ECOM were held in October 2000. In February 2001 the PUCT issued an interim decision determining an initial amount of CPL ECOM or stranded costs of negative $580 million. The decision indicated that CPL's costs were below market after securitization of regulatory assets. Management does not agree with the critical inputs to this model. Management believes CPL has a positive stranded cost exclusive of securitized regulatory assets. The final amount of CPL's stranded costs including regulatory assets and ECOM will be established by the PUCT in the legislatively required 2004 true-up proceeding. If CPL's total stranded costs determined in the 2004 true-up are less than the amount of securitized regulatory assets, the PUCT can implement an offsetting credit to transmission and distribution rates. The PUCT ruled that prior to the 2004 true-up proceeding, no adjustments would be made to the amount of regulatory costs authorized by the PUCT to be securitized. However, the PUCT also ruled that excess earnings for the period 1999-2001 should be refunded through transmission and distribution rates to the extent of any over-mitigation of stranded costs represented by negative ECOM. In the event that CPL will be required to refund excess earnings in the future instead of applying them to reduce ECOM or regulatory assets, it will adversely affect future cash flow but not results of operations since excess earnings for 1999 and 2000 were accrued and expensed in 1999 and 2000. The Texas Legislation allows for several alternative methods to be used to value stranded costs in the final 2004 true-up proceeding including the sale or exchange of generation assets, the issuance of power generation company stock to the public or the use of PUCT staff's ECOM model. To the extent that the final 2004 true-up proceeding determines that CPL should recover additional stranded costs, the total amount recoverable can be securitized. The Texas Legislation provides that each year during the 1999 through 2001 rate freeze period, electric utilities are subject to an earnings test. For electric utilities with stranded costs, such as CPL, any earnings in excess of the most recently approved cost of capital in its last rate case must be applied to reduce stranded costs. Utilities without stranded costs, such as SWEPCo and WTU, must either flow such excess earnings amounts back to customers or make capital expenditures to improve transmission or distribution facilities or to improve air quality. The Texas Legislation requires PUCT approval of the annual earnings test calculation. The 1999 earnings test reports filed by CPL, SWEPCo and WTU showed excess earnings of $21 million, $1 million and zero, respectively. The PUCT staff issued its report on the excess earnings calculations filed by CPL, SWEPCo and WTU and calculated the excess earnings amounts to be $41 million, $3 million and $11 million for CPL, SWEPCo and WTU, respectively. The Office of Public Utility Counsel also filed exceptions to the companies' earnings reports. Several issues were resolved via settlement and the remaining open issues were submitted to the PUCT. A final order was issued by the PUCT in February 2001 and adjustments to the accrued 1999 and 2000 excess earnings were recorded in results of operations in the fourth quarter of 2000. After adjustments the accruals for 1999 excess earnings for CPL and WTU were $24 million and $1 million, respectively. CPL and WTU also recorded an estimated provision for excess 2000 earnings of $16 million and $14 million, respectively. A Texas settlement agreement in connection with the AEP and CSW merger permits CPL to apply for regulatory purposes up to $20 million of STP ECOM plant assets a year in 2000 and 2001 to reduce excess earnings, if any. For book and financial reporting purposes, STP ECOM plant assets will be depreciated in accordance with GAAP, on a systematic and rational basis unless impaired. CPL will establish a regulatory liability or reduce regulatory assets by a charge to earnings to the extent excess earnings exceed $20 million in 2000 and 2001. Beginning January 1, 2002, fuel costs will not be subject to PUCT fuel reconciliation proceedings. Consequently, CPL, SWEPCo and WTU will file a final fuel reconciliation with the PUCT to reconcile their fuel costs through the period ending December 31, 2001. Fuel costs have been reconciled by CPL, SWEPCo and WTU through June 30, 1998, December 31, 1999 and June 30, 1997, respectively. WTU is currently reconciling its fuel through June 2000. See discussion in Note 5 "Rate Matters". At December 31, 2000, CPL's, SWEPCo's and WTU's Texas jurisdictional unrecovered deferred fuel balances were $127 million, $20 million and $59 million, respectively. Final unrecovered deferred fuel balances at December 31, 2001 will be included in each company's 2004 true-up proceeding. If the final fuel balances or any amount incurred but not yet reconciled were not recovered, they could have a negative impact on results of operations. The elimination of the fuel clause recoveries in 2002 in Texas will subject AEP, CPL, SWEPCo and WTU to greater risks of fuel market price increases and could adversely affect future results of operations beginning in 2002. The affiliated retail electric provider of CPL, SWEPCo and WTU will be required to offer residential and small commercial customers (with a peak usage of less than 1000 KW) a rate 6% below rates in effect on January 1, 1999 adjusted for any changes in fuel cost recovery factors since January 1, 1999 (price to beat). The price to beat must be offered to residential and small commercial customers until January 1, 2007. Customers with a peak usage of more than 1000 KW are subject to market rates. The Texas restructuring legislation provides for the price to beat to be adjusted up to two times annually to reflect significant changes in fuel and purchased energy costs. Discontinuance of the Application of SFAS 71 Regulatory Accounting in Arkansas and Texas The financial statements of CPL, SWEPCo and WTU have historically reflected the economic effects of regulation by applying the requirements of SFAS 71. As a result of the scheduled deregulation of generation in Arkansas and Texas, the application of SFAS 71 for the generation portion of the business in those states was discontinued in the third quarter of 1999. Under the provisions of EITF 97-4, CPL's generation-related net regulatory assets were transferred to the distribution portion of the business and will be amortized as they are recovered through wires charges to customers. Management believes that substantially all of CPL's generation-related regulatory assets will be recovered under the Texas Legislation. CPL's recovery of generation-related regulatory assets and stranded costs are subject to a final determination by the PUCT in 2004. If future events were to make the recovery through securitization of CPL's generation-related regulatory assets no longer probable, CPL would write-off the portion of such regulatory assets deemed unrecoverable as a non-cash extraordinary charge to earnings. The Texas Legislation provides that all finally determined stranded costs will be recovered. Since SWEPCo and WTU are not expected to have net stranded costs, all Arkansas and Texas jurisdictional generation-related net regulatory assets were written off as non-recoverable in 1999 when SWEPCo and WTU discontinued the application of SFAS 71 regulatory accounting. As required by SFAS 101 when SFAS 71 is discontinued, an accounting impairment analysis for generation assets under SFAS 121 was completed for CPL, SWEPCo and WTU. The analysis showed that there was no accounting impairment of generation assets when the application of SFAS 71 was discontinued. CPL, SWEPCo and WTU will test their generation assets for impairment under SFAS 121 if circumstances change. Management believes that on a discounted basis CPL's generation business net cash flows will likely be less than its generating assets' net book value and together with its generation-related regulatory assets should create a recoverable stranded cost for regulatory purposes under the Texas Legislation. Therefore, management continues to carry on the balance sheet at December 31, 2000, $953 million of generation-related regulatory assets already approved for securitization and $195 million of net generation-related regulatory assets pending approval for securitization in Texas. A final determination of whether they will be securitized and recovered will be made as part of the 2004 true-up proceeding. CPL, SWEPCo, and WTU continue to analyze the impact of electric utility industry restructuring legislation on their Arkansas and Texas electric operations. Although management believes that the Texas Legislation provides for full recovery of stranded costs and that the companies do not have a recordable accounting impairment, a final determination of whether CPL will experience an accounting loss or whether SWEPCo and WTU will experience any additional accounting loss from an inability to recover generation-related regulatory assets and other restructuring related costs in Texas and Arkansas cannot be made until such time as the regulatory process is complete following the 2004 true-up proceeding in Texas and a determination by the Arkansas Commission. In the event CPL, SWEPCo, and WTU are unable after the 2004 true-up proceeding and after the Arkansas Commission proceedings to recover all or a portion of their generation-related regulatory assets, stranded costs and other restructuring related costs, it could have a material adverse effect on results of operations, cash flows and possibly financial condition. Although Arkansas' delay of retail competition may be having a negative effect on the progress of efforts to transition SWEPCo's generation in Arkansas to market based pricing of electricity, it appears that Texas is moving forward as planned. Management is carefully monitoring the situation in Arkansas and is working with all concerned parties to prudently quicken the pace of the transition. However, changes could occur due to concerns stemming from the California energy crisis and other events which could adversely affect future results of operations in Arkansas and possibly Texas. Michigan Restructuring - Affecting AEP and I&M On June 5, 2000, the Michigan Legislation became law. Its major provisions, which were effective immediately, applied only to electric utilities with one million or more retail customers. I&M, AEP's electric operating subsidiary doing business in Michigan, has less than one million customers in Michigan. Consequently, I&M was not immediately required to comply with the Michigan Legislation. The Michigan Legislation gives the MPSC broad power to issue orders to implement retail customer choice of electric supplier no later than January 1, 2002 including recovery of regulatory assets and stranded costs. On October 2, 2000, I&M filed a restructuring implementation plan as required by a MPSC order. The plan identifies I&M's proposal to file with the MPSC on June 5, 2001 its unbundled rates, open access tariffs, terms of service and supporting schedules. Described in the plan are I&M's intentions and preparation for competition related to supplier transactions, customer transactions, rate unbundling, education programs, and regional transmission organization. The plan contains a proposed methodology to determine stranded costs and implementation costs and requests the continuation of a wires charge for recovery of nuclear decommissioning costs. Approval of the restructuring implementation plan is pending before the MPSC. Management has concluded that as of December 31, 2000 the requirements to apply SFAS 71 continue to be met since I&M's rates for generation in Michigan will continue to be cost-based regulated until the MPSC approves rates and wires charges in 2001. The establishment of rates and wires charges under a MPSC approved transition plan will enable management to determine the ability to recover stranded costs including regulatory assets and other implementation costs, a requirement of EITF 97-4 to discontinue the application of SFAS 71. Upon the discontinuance of SFAS 71, I&M will, if necessary, have to write off its Michigan jurisdictional generation-related regulatory assets and record its unrecorded Michigan jurisdictional liability for decommissioning the Cook Plant to the extent that they cannot be recovered under the transition rates and wires charges. As required by SFAS 101 when discontinuing SFAS 71 regulatory accounting, I&M will have to perform an accounting impairment analysis under SFAS 121 to determine if the Michigan jurisdictional portion of its generating assets are impaired for accounting purposes. The amount of regulatory assets recorded on the books at December 31, 2000 applicable to I&M's Michigan retail jurisdictional generation business is approximately $45 million before related tax effects. The estimated unrecorded liability for the Michigan jurisdiction to decommission the Cook Plant ranges from $114 million to $215 million in 2000 non-discounted dollars based upon studies completed during 2000. For the Michigan jurisdiction, I&M has accumulated approximately $100 million in trust funds to decommission the Cook Plant. Based on the current information available, management does not anticipate that I&M will experience any material tangible asset accounting impairment or regulatory asset write-offs. Ultimately, however, whether I&M will experience material regulatory asset write-offs will depend on whether the MPSC approves their recovery in future restructuring proceedings. A determination of whether I&M will experience any asset impairment loss regarding its Michigan retail jurisdictional generating assets and any loss from a possible inability to recover Michigan generation-related regulatory assets, de-commissioning obligations and transition costs cannot be made until such time as the rates and the wires charges are determined through the regulatory process. In the event I&M is unable to recover all or a portion of its generation-related regulatory assets, unrecorded decommissioning obligation, stranded costs and other implementation costs, it could have a material adverse effect on results of operations, cash flows and possibly financial condition. Oklahoma Restructuring - Affecting AEP and PSO In 1997, the Oklahoma Legislature passed restructuring legislation providing for retail open access by July 1, 2002. That legislation called for a number of studies to be completed on a variety of restructuring issues, including an independent system operator, technical, financial, transition and consumer issues. During 1998 and 1999 several of the studies were completed. The information from the studies was expected to be used in the development of additional industry restructuring legislation during the 2000 legislative session. Several additional electric industry restructuring bills were filed in the 2000 Oklahoma legislative session. The proposed bills generally supplemented the industry restructuring legislation previously enacted in Oklahoma which lacked specific procedures for a transition to market based competitive prices. The industry restructuring legislation previously passed did not delegate the establishment of transition procedures to the Oklahoma Corporation Commission. The 2000 Oklahoma legislative session adjourned in May without passing further restructuring legislation. The 2001 Oklahoma legislative session convened in early February. No further electric restructuring legislation has passed and proposals have been made to delay the implementation of the transition to customer choice and market based pricing under the restructuring legislation. If the necessary legislation is not passed, PSO's generation and retail electric supply business will remain regulated in Oklahoma. If implementation legislation were to modify the original restructuring legislation in Oklahoma it could have a adverse effect on results of operations. Management has concluded that as of December 31, 2000 the requirements to apply SFAS 71 continue to be met since PSO's rates for generation in Oklahoma will continue to be cost-based regulated until the Oklahoma Legislature approves further restructuring legislation and transition rates and wires charges are established under an approved transition plan. Until management is able to determine the ability to recover stranded costs which includes regulatory assets and other implementation costs, PSO cannot discontinue application of SFAS 71 accounting under GAAP. When PSO discontinues application of SFAS 71, it will be necessary to write off Oklahoma jurisdictional generation-related regulatory assets to the extent that they cannot be recovered under the transition rates and wires charges, when determined, and record any asset accounting impairments in accordance with SFAS 121. A determination of whether PSO will experience any asset impairment loss regarding its Oklahoma retail jurisdictional generating assets and any loss from a possible inability to recover Oklahoma generation-related regulatory assets and other transition costs cannot be made until such time as the rates and the wires charges are determined through the legislative and/or regulatory process. In the event PSO is unable to recover all or a portion of its generation-related regulatory assets and implementation costs, Oklahoma restructuring could have a material adverse effect on results of operations and cash flows. Structural Separation On November 1, 2000, AEP, AEPSC, APCo, CPL, CSPCo, OPCo, SWEPCo and WTU filed with the SEC for approval to form two separate legal holding company subsidiaries of AEP, the parent company. The purpose of these entities is to legally and functionally separate the competitive market business activities and the subsidiaries performing those competitive activities from the business activities which are cost-based regulated and the subsidiaries that perform those regulated activities. Corporate separation plans have also been filed with regulatory commissions in Arkansas, Ohio, Texas and Virginia to comply with requirements specified in their restructuring legislation. The Texas Legislation requires separate legal entities for generation and distribution assets by January 1, 2002. AEP, APCo, CPL, CSPCo, OPCo, SWEPCo and WTU will need approval from the SEC under PUHCA, FERC and certain state regulatory commissions to make these organization changes. 8. Commitments and Contingencies: Construction and Other Commitments - The AEP System has substantial construction commitments to support its operations. Aggregate construction expenditures for 2001-2003 for consolidated domestic and foreign operations are estimated to be $7 billion. The following table shows the estimated construction expenditures of the subsidiary registrants for 2001 - 2003: (in millions) AEGCo $ 9.1 APCo 1,164.3 CPL 770.2 CSPCo 422.2 I&M 439.6 KPCo 215.6 OPCo 1,085.2 PSO 310.8 SWEPCo 413.1 WTU 259.3 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 for APCo is 2006, CSPCo is 2007, I&M is 2014, KPCo is 2003, OPCo is 2012, PSO is 2014, SWEPCo is 2006 and WTU is 2006. The contracts provide for periodic price adjustments and contain various clauses that would release the subsidiaries from their obligations under certain force majeure conditions. The AEP System has contracted to sell approximately 1,174 MW of capacity domestically on a long-term basis to unaffiliated utilities. Certain of these contracts totaling 250 mw of capacity are unit power agreements requiring the delivery of energy only if the unit capacity is available. The power sales contracts expire from 2001 to 2010. Nuclear Plants - Affecting AEP, CPL and I&M I&M owns and operates the two-unit 2,110 MW Cook Plant under licenses granted by the NRC. CPL owns 25.2% of the two-unit 2,500 MW STP. STPNOC operates STP on behalf of the joint owners under licenses granted by the NRC. The operation of a nuclear facility involves special risks, potential liabilities, and specific regulatory and safety requirements. Should a nuclear incident occur at any nuclear power plant facility in the U.S., the resultant liability could be substantial. By agreement I&M and CPL are partially liable together with all other electric utility companies that own nuclear generating units for a nuclear power plant incident at any nuclear plant in the U.S. In the event nuclear losses or liabilities are underinsured or exceed accumulated funds and recovery in rates is not possible, results of operations, cash flows and financial condition would be adversely affected. Nuclear Incident Liability - Affecting AEP, CPL and I&M The Price-Anderson Act establishes insurance protection for public liability arising from a nuclear incident at $9.5 billion and covers any incident at a licensed reactor in the U.S. Commercially available insurance provides $200 million of coverage. In the event of a nuclear incident at any nuclear plant in the U.S. the remainder of the liability would be provided by a deferred premium assessment of $88 million on each licensed reactor in the U.S. payable in annual installments of $10 million. As a result, I&M could be assessed $176 million per nuclear incident payable in annual installments of $20 million. CPL could be assessed $44 million per nuclear incident payable in annual installments of $5 million as its share of a STPNOC assessment. The number of incidents for which payments could be required is not limited. Insurance coverage for property damage, decommissioning and decontamination at the Cook Plant and STP is carried by I&M and STPNOC in the amount of $1.8 billion each. Cook Plant and STPNOC jointly purchase $1 billion of excess coverage for property damage, de-commissioning and decontamination. Additional insurance provides coverage for extra costs resulting from a prolonged accidental outage. SNF Disposal - Affecting AEP, CPL, and I&M Federal law provides for government responsibility for permanent SNF disposal and assesses nuclear plant owners fees for SNF disposal. A fee of one mill per KWH for fuel consumed after April 6, 1983 at Cook Plant and STP is being collected from customers and remitted to the U.S. Treasury. Fees and related interest of $211 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, 2000, funds collected from customers towards payment of the pre-April 1983 fee and related earnings thereon are in external funds and approximate the liability. CPL is not liable for any assessments for nuclear fuel consumed prior to April 7, 1983 since the STP units began operation in 1988 and 1989. Decommissioning and Low Level Waste Accumulation Disposal - Affecting AEP, CPL and I&M Decommissioning costs are accrued over the service lives of the Cook Plant and STP. The licenses to operate the two nuclear units at Cook Plant expire in 2014 and 2017. After expiration of the licenses, Cook Plant is expected to be decommissioned through dismantlement. The estimated cost of decommissioning and low level radioactive waste accumulation disposal costs for Cook Plant ranges from $783 million to $1,481 million in 2000 nondiscounted dollars. The wide range is caused by variables in assumptions including the estimated length of time SNF may need to be stored at the plant site subsequent to ceasing operations. This, in turn, depends on future developments in the federal government's SNF disposal program. Continued delays in the federal fuel disposal program can result in increased decommissioning costs. I&M is re-covering estimated Cook Plant decommissioning costs in its three rate-making jurisdictions based on at least the lower end of the range in the most recent decommissioning study at the time of the last rate proceeding. The amount recovered in rates for decommissioning the Cook Plant and deposited in the external fund was $28 million in 2000, $28 million in 1999 and $29 million in 1998. The licenses to operate the two nuclear units at STP expire in 2027 and 2028. After expiration of the licenses, STP is expected to be decommissioned using the decontamination method. CPL estimates its portion of the costs of decommissioning STP to be $289 million in 1999 nondiscounted dollars. CPL is accruing and recovering these decommissioning costs through rates based on the service life of STP at a rate of $8 million per year. Decommissioning costs recovered from customers are deposited in external trusts. In 2000 and 1999 I&M deposited in its decommissioning trust an additional $6 million and $4 million, respectively, related to special regulatory commission approved funding for decommissioning of the Cook Plant. Trust fund earnings increase the fund assets and the recorded liability and decrease the amount needed to be recovered from ratepayers. Decommissioning costs including interest, unrealized gains and losses and expenses of the trust funds are recorded in other operation expense for Cook Plant. For STP, nuclear decommissioning costs are recorded in other operation expense, interest income of the trusts are recorded in nonoperating income and interest expense of the trust funds are included in interest charges. During 1999 and 1998 I&M withdrew $8 million and $3 million, respectively, from the trust funds for decommissioning of the original steam generators removed from Cook Plant Unit 2. On the AEP Consolidated Balance Sheets, nuclear decommissioning trust assets are included in other assets and a corresponding nuclear decommissioning liability is included in other noncurrent liabilities. On CPL's balance sheets, the nuclear decommissioning liability is included in electric utility plant-accumulated depreciation and amortization. At December 31, 2000 and 1999, the decommissioning liability for Cook Plant and STP combined totals $654 million and $587 million, respectively. Shareholders' Litigation - Affecting AEP On June 23, 2000, a complaint was filed in the U.S. District Court for the Eastern District of New York seeking unspecified compensatory damages against AEP and four former or present officers. The individual plaintiff also seeks certification as the representative of a class consisting of all persons and entities who purchased or otherwise acquired AEP common stock between July 25, 1997, and June 25, 1999. The complaint alleges that the defendants knowingly violated federal securities laws by disseminating materially false and misleading statements concerning, among other things, the undisclosed materially impaired condition of the Cook Plant, AEP's inability to properly monitor, manage, repair, supervise and report on operations at the Cook Plant and the materially adverse conditions these problems were having, and would continue to have, on AEP's deteriorating financial condition, and ultimately on AEP's operations, liquidity and stock price. Four other similar class action complaints have been filed and the court has consolidated the five cases. The plaintiffs filed a consolidated complaint pursuant to this court order. This case has been transferred to the U.S. District Court for the Southern District of Ohio. Although management believes these shareholder actions are without merit and intends to oppose them vigorously, management cannot predict the outcome of this litigation or its impact on results of operations, cash flows or financial condition. Municipal Franchise Fee Litigation - Affecting AEP and CPL CPL has been involved in litigation regarding municipal franchise fees in Texas as a result of a class action suit filed by the City of San Juan, Texas in 1996. The City of San Juan claims CPL underpaid municipal franchise fees and seeks damage of up to $300 million plus attorney's fees. CPL filed a counterclaim for overpayment of franchise fees. During 1997, 1998 and 1999 the litigation moved procedurally through the Texas Court System and was sent to mediation without resolution. In 1999 a class notice was mailed to each of the cities served by CPL. Over 90 of the 128 cities declined to participate in the lawsuit. However, CPL has pledged that if any final, non-appealable court decision in the litigation awards a judgement against CPL for a franchise underpayment, CPL will extend the principles of that decision, with regard to any franchise underpayment, to the cities that declined to participate in the litigation. In December 1999, the court ruled that the class of plaintiffs would consist of approximately 30 cities. A trial date for June 2001 has been set. Although management believes that it has substantial defenses to the cities' claims and intends to defend itself against the cities' claims and pursue its counterclaims vigorously, management cannot predict the outcome of this litigation or its impact on results of operations, cash flows or financial condition. Texas Base Rate Litigation - Affecting AEP and CPL In November 1995 CPL filed with the PUCT a request to increase its retail base rates by $71 million. In October 1997 the PUCT issued a final order which lowered CPL's annual retail base rates by $19 million from the rate level which existed prior to May 1996. The PUCT also included a "glide path" rate methodology in the final order pursuant to which annual rates were reduced by $13 million beginning May 1, 1998 with an additional annual reduction of $13 million commencing on May 1, 1999. CPL appealed the final order to the Travis District Court. The primary issues being appealed include: the classification of $800 million of invested capital in STP as ECOM and assigning it a lower return on equity than other generation property; the use of the "glide path" rate reduction methodology; and an $18 million disallowance of service billings from an affiliate, CSW Services. As part of the appeal, CPL sought a temporary injunction to prohibit the PUCT from implementing the "glide path" rate reduction methodology. The temporary injunction was denied and the "glide path" rate reduction was implemented. In February 1999 the Travis District Court affirmed the PUCT order in regard to the three major items discussed above. CPL appealed the Travis District Court's findings to the Texas Appeals Court which in July 2000, issued its opinion upholding the Travis District Court except for the disallowance of affiliated service company billings. Under Texas law, specific findings regarding affiliate transactions must be made by PUCT. In regards to the affiliate service billing issue, the findings were not complete in the opinion of the Texas Appeals Court who remanded the issue back to PUCT. CPL has sought a rehearing of the Texas Appeals Court's opinion. The Texas Appeals Court has requested briefs related to CPL's rehearing request from interested parties. Management is unable to predict the final resolution of its appeal. If the appeal is unsuccessful the PUCT's 1997 order will continue to adversely affect results of operations and cash flows. As part of the AEP/CSW merger approval process in Texas, a stipulation agreement was approved which resulted in the withdrawal of the appeal related to the "glide path" rate methodology. CPL will continue its appeal of the ECOM classification for STP property and the disallowed affiliated service billings. Lignite Mining Agreement Litigation - Affecting AEP and SWEPCo SWEPCo and CLECO are each a 50% owner of Dolet Hills Power Station Unit 1 and jointly own lignite reserves in the Dolet Hills area of northwestern Louisiana. In 1982, SWEPCo and CLECO entered into a lignite mining agreement with DHMV, a partnership for the mining and delivery of lignite from a portion of these reserves. In April 1997, SWEPCo and CLECO sued DHMV and its partners in U.S. District Court for the Western District of Louisiana seeking to enforce various obligations of DHMV under the lignite mining agreement, including provisions relating to the quality of delivered lignite, pricing, and mine reclamation practices. In June 1997, DHMV filed an answer denying the allegations in the suit and filed a counterclaim asserting various contract-related claims against SWEPCo and CLECO. SWEPCo and CLECO have denied the allegations contained in the counterclaims. In January 1999, SWEPCo and CLECO amended the claims against DHMV to include a request that the lignite mining agreement be terminated. In April 2000, the parties agreed to settle the litigation. As part of the settlement, DHMV's interest in the mining operations and related debt and other obligations will be purchased by SWEPCo and CLECO. The closing date for the settlement has been extended from December 31, 2000 to March 31, 2001. The litigation has been stayed until April 2001 to give the parties time to consummate the settlement agreement. Management believes that the resolution of this matter will not have a material effect on results of operations, cash flows or financial condition. Federal EPA Complaint and Notice of Violation - Affecting AEP, APCo, CSPCo, I&M, and OPCo 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. AEP, APCo, CSPCo, I&M, and OPCo have been involved in litigation regarding generating plant emissions under the Clean Air Act. In 1999 Notices of Violation were issued and complaints were filed by Federal EPA in various U.S. District Courts alleging APCo, CSPCo, I&M, OPCo and a number of unaffiliated utilities made modifications to generating units at certain of their coal-fired generating plants over the course of the past 25 years that extended unit operating lives or increased unit generating capacity without a preconstruction permit in violation of the Clean Air Act. The complaint was amended in March 2000 to add allegations for certain generating units previously named in the complaint and to include additional generating units previously named only in the Notices of Violation in the complaint. A number of northeastern and eastern states were granted leave to intervene in the Federal EPA's action against the AEP System under the Clean Air Act. A lawsuit against power plants owned by certain AEP System operating companies alleging similar violations to those in the Federal EPA complaint and Notices of Violation was filed by a number of special interest groups and has been consolidated with the Federal EPA action. 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). Civil penalties, if ultimately imposed by the court, and the cost of any required new pollution control equipment, if the court accepts Federal EPA's contentions, could be substantial. On May 10, 2000, the AEP System companies filed motions to dismiss all or portions of the complaints. Briefing on these motions was completed on August 2, 2000. On February 23, 2001, the government filed a motion for partial summary judgement seeking a determination that four projects undertaken on units at Sporn, Cardinal and Clinch River plants do not constitute "routine maintenance, repair and replacement" as used in the Clean Air Act. Management believes its maintenance, repair and replacement activities were in conformity with the Clean Air Act and intends to vigorously pursue its defense. In the event the AEP System companies do not prevail, any capital and operating costs of additional pollution control equipment that may be required as well as any penalties imposed would adversely affect future results of operations, cash flows and possibly financial condition unless such costs can be recovered through regulated rates, and where states are deregulating generation, unbundled transition period generation rates, stranded cost wires charges and future market prices for electricity. In December 2000 Cinergy Corp., an unaffiliated utility, which operates certain plants jointly owned by CSPCo reached a tentative agreement with Federal EPA and other parties to settle litigation regarding generating plant emissions under the Clean Air Act. Negotiations are continuing between the parties in an attempt to reach final settlement terms. Cinergy's settlement could impact the operation of Zimmer Plant and W.C. Beckjord Generating Station Unit 6 which are owned 25.4% and 12.5%, respectively, by CSPCo. Until a final settlement is reached, CSPCo will be unable to determine the settlement's impact on its jointly owned facilities and its future earnings and cash flows. NOx Reductions - Affecting AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo and SWEPCo Federal EPA issued a NOx rule that required substantial reductions in NOx emissions in a number of eastern states, including certain states in which the AEP System's generating plants are located. A number of utilities, including several AEP System companies, filed petitions seeking a review of the final rule in the D.C. Circuit Court. In March 2000, the D.C. Circuit Court issued a decision generally upholding the NOx rule. The D.C. Circuit Court issued an order in August 2000 which extends the final compliance date to May 31, 2004. In September 2000 following denial by the D.C. Circuit Court of a request for rehearing, the industry petitioners, including the AEP System companies, petitioned the U.S. Supreme Court for review, which was denied. In December 2000 Federal EPA ruled that eleven states, including states in which AEGCo's, APCo's, CSPCo's, I&M's, KPCo's and OPCo's generating units are located, failed to submit plans to comply with the mandates of the NOx rule. This determination means that those states could face stringent sanctions within the next 24 months including limits on construction of new sources of air emissions, loss of federal highway funding and possible Federal EPA takeover of state air quality management programs. In January 2000 Federal EPA adopted a revised rule granting petitions filed by certain northeastern states under Section 126 of the Clean Air Act seeking significant reductions in nitrogen oxide emissions from utility and industrial sources. The rule imposes emissions reduction requirements comparable to the NOx rule beginning May 1, 2003, for most of AEP's coal-fired generating units. Certain AEP operating companies and other utilities filed petitions for review in the D.C. Circuit Court. Briefing has been completed and oral argument was held in December 2000. In a related matter, on April 19, 2000, the Texas Natural Resource Conservation Commission adopted rules requiring significant reductions in NOx emissions from utility sources, including CPL and SWEPCo. The rule's compliance date is May 2003 for CPL and May 2005 for SWEPCo. In June 2000 OPCo announced that it was beginning a $175 million installation of selective catalytic reduction technology (expected to be operational in 2001) to reduce NOx emissions on its two-unit 2,600 MW Gavin Plant. Construction of selective catalytic reduction technology on Amos Plant Unit 3, which is jointly owned by OPCo and APCo, and APCo's Mountaineer Plant is scheduled to begin in 2001. The Amos and Mountaineer projects (expected to be completed in 2002) are estimated to cost a total of $230 million ($145 million for APCo and $85 million for OPCo). Preliminary estimates indicate that compliance with the NOx rule upheld by the D.C. Circuit Court as well as compliance with the Texas Natural Resource Conservation Commission rule and the Section 126 petitions could result in required capital expenditures of approximately $1.6 billion, including the amounts discussed in the previous paragraph, for AEP Consolidated. Estimated compliance costs by registrant subsidiaries are as follows: (in millions) AEGCo $125 APCo 365 CPL 57 CSPCo 106 I&M 202 KPCo 140 OPCo 606 SWEPCo 28 Since compliance costs cannot be estimated with certainty, the actual cost to comply could be significantly different than the preliminary estimates depending upon the compliance alternatives selected to achieve reductions in NOx emissions. Unless any capital and operating costs of additional pollution control equipment are recovered from customers through regulated rates and/or future market prices for electricity where generation is deregulated, they will have an adverse effect on future results of operations, cash flows and possibly financial condition. COLI Litigation - Affecting AEP, APCo, CSPCo, I&M, KPCo and OPCo On February 20, 2001, the U.S. District Court for the Southern District of Ohio ruled against the AEP System companies in their suit against the United States over deductibility of interest claimed in their consolidated federal income tax return related to a COLI program. The suit was filed to resolve the IRS' assertion that interest deductions for the COLI program should not be allowed. In 1998 and 1999 APCo, CSPCo, I&M, KPCo and OPCo paid the disputed taxes and interest attributable to COLI interest deductions for taxable years 1991-98 for APCo, CSPCo, I&M and OPCo and 1992-98 for KPCo to avoid the potential assessment by the IRS of additional interest on the contested tax. The payments were included in other assets on AEP's Consolidated Balance Sheet and in Other Property and Investment on the subsidiaries' balance sheets 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 for AEP Consolidated by $319 million in 2000. The appeal of this decision is planned. The earnings reductions for affected registrant subsidiaries are as follows: (in millions) APCo $ 82 CSPCo 41 I&M 66 KPCo 8 OPCo 118 Other - AEP and its registrant subsidiaries are involved in a number of other legal proceedings and claims. While management is unable to predict the ultimate outcome of these matters, it is not expected that their resolution will have a material adverse effect on results of operations, cash flows or financial condition. 9. Acquisitions: AEP completed two energy related acquisitions in 1998 through a subsidiary, AEPR. Both acquisitions have been accounted for using the purchase method. On December 31, 1998 CitiPower, an Australian distribution utility, that serves approximately 250,000 customers in Melbourne with 3,100 miles of distribution lines in a service area of approximately 100 square miles was acquired. All of the stock of CitiPower was acquired for approximately $1.1 billion. The acquisition of CitiPower had no effect on the results of operations for 1998 and a full year of CitiPower's results of operations are included in the consolidated statements of income for 1999 and 2000. Assets acquired and liabilities assumed have been recorded at their fair values. Based on an independent appraisal, $616 million of the purchase price was allocated to retail and wholesale distribution licenses which are being amortized on a straight-line basis over 20 years and 40 years, respectively. The excess of cost over fair value of the net assets acquired was approximately $34 million and is recorded as goodwill and is being amortized on a straight-line basis over 40 years. On December 1, 1998 AEPR acquired Louisiana Intrastate Gas (LIG) with midstream gas operations that include a fully integrated natural gas gathering, processing, storage and transportation operation in Louisiana and a gas trading and marketing operation. LIG was acquired for approximately $340 million, including working capital funds with one month of earnings reflected in AEP's consolidated results of operations for the year ended December 31, 1998. A full year of LIG's results of operations is included in AEP's consolidated statements of income for 1999 and 2000. Assets acquired and liabilities assumed have been recorded at their fair values. The excess of cost over fair value of the net assets acquired was approximately $158 million for the midstream gas storage operations and $17 million for the gas trading and marketing operation. The goodwill is being amortized on a straight-line basis over 40 years and 10 years, respectively. 10. International Investments: CSW International owns a 44% equity interest in Vale, a Brazilian electric operating company which it had purchased for a total of $149 million. The investment is covered by a put option, which, if exercised, requires CSW International's partners in Vale to purchase CSW International's Vale shares at a minimum price equal to the U.S. dollar equivalent of CSW International's purchase price. As a result, management has concluded that CSW International's investment carrying amount will not be reduced below the put option value unless it is deemed to be a permanent impairment and CSW International's partners in Vale are deemed unable to fulfill their responsibilities under the put option. Vale has experienced losses from operations and CSW International's investment has been affected by the devaluation of the Brazilian Real. CSW International's cumulative equity share of these operating and foreign currency translation losses through December 31, 2000 is approximately $33 million, net of tax, and $49 million, net of tax, respectively. Pursuant to the put option arrangement, these losses have not been applied to reduce the carrying value of the Vale investment. As a result, CSW International will not recognize any future earnings from Vale until the operating losses are recovered. In December 2000, CSW International 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 worldwide electric and gas expenses and includes $26 million ($17 million net of tax) of losses from foreign exchange rate changes that were previously reflected in other comprehensive income. In the second quarter of 2000 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). In December 2000 AEPR entered into negotiations to sell its 50% investment in Yorkshire, a U.K. electricity supply and distribution company. On February 26, 2001 an agreement to sell AEPR's 50% interest in Yorkshire was signed. As a result a $43 million impairment writedown ($30 million after tax) was recorded in the fourth quarter of 2000 to reflect the net loss from the expected sale in the first quarter of 2001. The impairment writedown is included in other income (net) on AEP's Consolidated Statements of Income. 11. Staff Reductions: During 1998 an internal evaluation of the power generation organization was conducted with a goal of developing an optimum organizational structure for a competitive generation market. The study was completed in October 1998 and called for the elimination of approximately 450 positions across the AEP System. In addition, a review of energy delivery staffing levels in 1998 identified 65 AEP System positions for elimination. A provision for severance costs totaling $26 million was recorded in December 1998 for reductions in power generation and energy delivery staffs and was charged to maintenance and other operation expense. The power generation and energy delivery staff reductions were made in the first quarter of 1999. The amount of severance benefits paid was not significantly different from the amount accrued. The following table shows the staff reductions information for the applicable registrant companies: Total Number Severance Accrual Company of Employees Amount - ------- ------------- ------------------ (in millions) APCo 180 $7.6 CSPCo 70 3.4 I&M 80 3.7 KPCo 35 1.9 OPCo 150 8.6 12. Benefit Plans: In the U.S. the AEP System sponsors two qualified pension plans and two nonqualified pension plans. All employees in the U.S., except participants in the UMWA pension plans are covered by one or both of the pension plans. OPEB plans are sponsored by the AEP System to provide medical and death benefits for retired employees in the U.S. The foreign pension plans are for employees of SEEBOARD in the U.K. and CitiPower in Australia. The majority of SEEBOARD's employees joined a pension plan that is administered for the U.K.'s electricity industry. The assets of this plan are actuarially valued every three years. SEEBOARD and its participating employees both contribute to the plan. Subsequent to July 1, 1995, new employees were no longer able to participate in that plan and two new pension plans were made available to new employees of SEEBOARD. CitiPower sponsors a defined benefit pension plan that covers all employees. The following tables provide a reconciliation of the changes in the plans' benefit obligations and fair value of assets over the two-year period ending December 31, 2000, and a statement of the funded status as of December 31 for both years:
U.S. Foreign U.S. Pension Plans Pension Plans OPEB Plans ------------------ ---------------- ------------------- 2000 1999 2000 1999 2000 1999 ---- ---- ---- ---- ---- ---- (in millions) Reconciliation of benefit obligation: Obligation at January 1 $2,934 $3,117 $1,176 $1,147 $1,365 $1,297 Service Cost 60 71 13 15 29 33 Interest Cost 227 211 64 59 106 90 Participant Contributions - - 5 4 7 9 Plan Amendments (71)(a) 7 (b) - 7 (c) (67) (d) - Foreign Currency Translation Adjustment - - (95) (26) - - Actuarial (Gain) Loss 218 (300) 80 37 262 - Benefit Payments (207) (172) (64) (67) (85) (74) Curtailments - - - - 51 (e) 10 (e) ------ ------ ------ ------ ------ ------ Obligation at December 31 $3,161 $2,934 $1,179 $1,176 $1,668 $1,365 ====== ====== ====== ====== ====== ====== Reconciliation of fair value of plan assets: Fair value of plan assets at January 1 $3,866 $3,665 $1,405 $1,338 $668 $560 Actual Return on Plan Assets 250 370 55 156 2 71 Company Contributions 2 2 - 7 112 103 Participant Contributions - - 5 4 7 9 Foreign Currency Translation Adjustment - - (111) (33) - - Benefit Payments (207) (172) (64) (67) (85) (74) ------ ------ ------ ------ ---- ---- Fair value of plan assets at December 31 $3,911 $3,865 $1,290 $1,405 $704 $669 ====== ====== ====== ====== ==== ==== Funded status: Funded status at December 31 $ 750 $ 931 $111 $ 229 $(964) $(696) Unrecognized Net Transition (Asset) Obligation (23) (31) - - 298 434 Unrecognized Prior-Service Cost (12) 71 10 11 - - Unrecognized Actuarial (Gain) Loss (628) (954) (67) (177) 448 135 ----- ----- ---- ----- ----- ----- Prepaid Benefit (Accrued Liability) $ 87 $ 17 $ 54 $ 63 $(218) $(127) ===== ===== ==== ===== ===== ===== (a) One of the qualified pension plans converted to the cash balance pension formula from a final average pay formula. (b) Early retirement factors for one of the pension plans was changed to provide more generous benefits to participants retiring between ages 55 and 60. (c) SEEBOARD made a one-time payment to all retired participants. (d) Change to a service-related formula for retirement health care costs and a 50% of pay life insurance benefit for retiree life insurance. (e) Related to the shutdown of OPCo's affiliated coal mine operations.
The following table provides the amounts recognized in AEP's consolidated balance sheets as of December 31 of both years: U.S. Foreign U.S. Pension Plan Pension Plans OPEB Plans ------------------- ---------------- ------------------- 2000 1999 2000 1999 2000 1999 ---- ---- ---- ---- ---- ---- (in millions) Prepaid Benefit Costs $ 159 $ 145 $54 $63 $ - $ - Accrued Benefit Liability (72) (128) - - (218) (127) Additional Minimum Liability (24) (14) - - N/A N/A Intangible Asset 14 8 - - N/A N/A Accumulated Other Comprehensive Income 10 6 - - N/A N/A ----- ----- --- --- ----- ------ Net Amount Recognized $ 87 $ 17 $54 $63 $(218) $(127) ===== ===== === === ===== ===== Other Comprehensive (Income) Expense Attributable to Change in Additional Pension Liability Recognition $4 $(2) - - N/A N/A == ==== === === === ==== N/A = Not Applicable
The AEP System's nonqualified pension plans had accumulated benefit obligations in excess of plan assets of $41 million and $26 million at December 31, 2000 and $29 million and $23 million at December 31, 1999. There are no plan assets in the nonqualified plans. The AEP System's OPEB plans had accumulated benefit obligations in excess of plan assets of $964 million and $696 million at December 31, 2000 and 1999, respectively. The following table provides the components of AEP's net periodic benefit cost for the plans for fiscal years 2000, 1999 and 1998: U.S. Foreign U.S. Pension Plans Pension Plans OPEB Plans -------------------- -------------------- ------------------- 2000 1999 1998 2000 1999 1998 2000 1999 1998 ---- ---- ---- ---- ---- ---- ---- ---- ---- (in millions) Service cost $ 60 $ 71 $ 67 $ 13 $ 15 $ 14 $ 29 $ 33 $ 26 Interest cost 227 211 202 64 59 68 106 90 76 Expected return on plan assets (321) (299) (269) (75) (71) (77) (57) (49) (40) Amortization of transition (asset) obligation (8) (8) (8) - - - 41 43 41 Amortization of prior-service cost 13 12 9 1 - - - - - Amortization of net actuarial (gain) loss (39) (15) (3) - - - 4 5 (2) ---- ----- ----- ---- ---- ---- ---- ---- ---- Net periodic benefit cost (68) (28) (2) 3 3 5 123 122 101 Curtailment loss(a) - - - - - - 79 18 24 ---- ----- ----- ---- ---- ---- ---- ---- ----- Net periodic benefit cost after curtailments $(68) $ (28) $ (2) $ 3 $ 3 $ 5 $202 $140 $125 ==== ===== ===== ==== ==== ==== ==== ==== ==== (a) Curtailment charges were recognized during 2000, 1999 and 1998 for the shutdown of affiliated coal mine operations.
The following table provides the net periodic benefit cost (credit) for the plans by the following AEP registrant subsidiaries for fiscal years 2000, 1999 and 1998: U.S. U.S Pension Plans OPEB Plans ---------------------------- --------------------------- 2000 1999 1998 2000 1999 1998 ---- ---- ---- ---- ---- ---- (in thousands) APCo $(14,047) $(3,925) $ 778 $ 22,139 $19,431 $16,569 CPL (2,986) (4,270) (2,850) 6,656 7,595 6,599 CSPCo (10,905) (4,893) (1,410) 9,643 8,623 7,467 I&M (8,565) (1,259) 2,104 14,155 13,664 11,994 KPCo (2,075) (393) 322 2,364 2,652 2,113 OPCo (15,041) (4,979) 26 116,205 52,518 54,578 PSO (2,196) (3,129) (2,190) 4,277 5,516 4,369 SWEPCo (2,606) (3,734) (2,581) 4,152 4,913 3,673 WTU (1,585) (2,221) (1,478) 2,929 3,377 3,002
The assumptions used in the measurement of the AEP System's benefit obligations are shown in the following tables: U.S. Foreign Pension Plans Pension Plans U.S. OPEB Plans ----------------------- ------------------------- -------------------- 2000 1999 1998 2000 1999 1998 2000 1999 1998 ---- ---- ---- ---- ---- ---- ---- ---- ---- % % % % % % % % % Weighted-average assumptions as of December 31: Discount rate 7.50 8.00 6.75 5-5.5 5.5-6 5-5.5 7.50 8.00 6.75 Expected return on plan assets 9.00 9.00 9.00 6-7.5 6.5-7.5 6.25-7 8.75 8.75 8.75 Rate of compensation increase 3.2 3.8 3.8 3.5-4.0 4-4.5 3.5-4 N/A N/A N/A
For measurement purposes, a 6.0% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2001. The rate was assumed to decrease gradually each year to a rate of 5.1% through 2005 and remain at that level thereafter. Assumed health care cost trend rates have a significant effect on the amounts reported for the OPEB health care plans. A 1% change in assumed health care cost trend rates would have the following effects: 1% Increase 1% Decrease ----------- ------------ (in millions) Effect on total service and interest cost components of net periodic postretirement health care benefit cost $ 15 $ (13) Effect on the health care component of the accumulated postretirement benefit obligation 197 (162) AEP System Savings Plans - The AEP System Savings Plans are defined contribution plans offered to non-UMWA U.S. employees. The cost for contributions to these plans totaled $37 million in 2000, $36 million in 1999 and $35 million in 1998. Beginning in 2001 AEP's contributions to the plans will increase to 4.5% of the initial 6% of employee pay contributed from the current 3% of the initial 6% of employee base pay contributed. The following table provides the cost for contributions to the savings plans by the following AEP registrant subsidiaries for fiscal years 2000, 1999 and 1998: 2000 1999 1998 ---- ---- ---- (in thousands) APCo $3,988 $4,091 $4,276 CPL 3,161 3,284 3,078 CSPCo 1,638 1,679 1,830 I&M 4,231 3,996 4,017 KPCo 544 561 714 OPCo 3,713 3,744 3,978 PSO 2,306 2,435 2,230 SWEPCo 2,880 2,961 2,728 WTU 1,708 1,766 1,594 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 based on hours worked and are expensed as paid as part of the cost of active mining operations and were not material in 2000, 1999 and 1998. 13. Stock-Based Compensation: In 2000, AEP adopted a Long-term Incentive Plan under which a maximum of 15,700,000 shares of common stock can be issued to key employees. Under the plan, the exercise price of each option granted equals the market price of AEP's common stock on the date of grant. These options will vest in equal increments, annually, over a three-year period beginning on January 1, 2002 with a maximum exercise term of ten years. CSW maintained a stock option plan prior to the merger with AEP. Effective with the merger, all CSW stock options outstanding were converted into AEP stock options at an exchange ratio of one CSW stock option for 0.6 of an AEP stock option. The exercise price for each CSW stock option was adjusted for the exchange ratio. The provisions of the CSW stock option plan will continue in effect until all options expire or there are no longer options outstanding. Under the CSW stock option plan, the option exercise price was equal to the stock's market price on the date of grant. The grant vested over three years, one-third on each of the first three anniversary dates of the grant, and expires 10 years after the original grant date. All CSW stock options were fully vested at December 31, 2000.
The following table summarizes share activity in the above plans, and the weighted-average exercise price: 2000 1999 1998 ---- ---- ---- 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 825 $40 866 $40 1,141 $40 Granted 6,046 $36 - $ - - $ - Exercised (26) $36 (22) $38 (202) $40 Forfeited (235) $39 (19) $43 (73) $40 ----- --- ----- Outstanding at end of year 6,610 $36 825 $40 866 $40 ===== === ===== Options Exercisable at end of year 588 $41 707 $42 606 $43 === === ===
The weighted-average fair value of options granted in 2000 is $36 per share. No options were granted in 1999 or 1998. Shares outstanding under the stock option plan have exercise prices ranging from $35 to $49 and a weighted-average remaining contractual life of 9.2 years. If compensation expense for stock options had been determined based on the fair value at the grant date, net income and earnings per share would have been the pro forma amounts shown below: 2000 1999 1998 ---- ---- ---- Pro forma net income (in millions) $264 $972 $975 Pro forma earnings per share (basic and diluted) $0.82 $3.03 $3.06 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 assumptions used to estimate the fair value of options granted in 2000: dividend yield of 6.02%; expected stock price volatility of 24.75%; risk-free interest rate of 5.02% and expected life of option of 7 years. 14. Business Segments: AEP's principal business segment is its cost-based rate regulated Domestic Electric Utility business consisting of eleven regulated utility operating companies providing generation, distribution and transmission electric services in eleven states. Also included in this segment are AEP's electric power wholesale marketing and trading activities conducted within two transmission systems of the AEP System. The AEP consolidated income statement caption "Revenues-Domestic Electric Utility Operations" includes both the retail and wholesale domestic electricity supply businesses which are cost-based rate regulated on a bundled basis with transmission and distribution services in Kentucky, Indiana, Michigan, Louisiana, Oklahoma and Tennessee and are in the process of transitioning to customer choice market based pricing in Arkansas, Ohio, Texas, WV and Virginia. Since the domestic electric utility companies have not yet functionally or structurally separated their retail and wholesale electricity supply business from their regulated transmission and distribution service business, separate financial data is not available and the Domestic Electric Utilities business will continue to be reported as one business segment which is the only reportable segment for the domestic electric operating subsidiaries. Therefore all registrant subsidiaries have one reportable segment, a regulated vertically integrated electricity generation and energy delivery business. All other activities for these registrant subsidiaries are insignificant. In 2000, 1999 and 1998 all the registrant subsidiaries revenues are derived from the generation, sale and delivery of electricity in the U.S. The AEP consolidated income statement caption "Revenues-Worldwide Electric and Gas Operations" includes three segments: Foreign Energy Delivery, Worldwide Energy Investments and other. The Foreign Energy Delivery segment includes investments in overseas electric distribution and supply companies (SEEBOARD and Yorkshire in the U.K. and CitiPower in Australia). The Worldwide Energy Investments segment represents domestic and international investments in energy-related gas and electric projects including the development and management of those projects. Such investment activities include electric generation in Florida, Texas, Colorado, Brazil and Mexico, and natural gas pipeline, storage and other natural gas services in the U.S. The other segment which is included in the AEP consolidated income statement as part of Worldwide Electric and Gas Operations includes non-regulated electric marketing and trading activities outside of AEP's marketing area (beyond two transmission systems from the AEP System) gas marketing and trading activities, telecommunication services, and the marketing of various energy related products and services. In the fourth quarter of 2000, management announced its intent to functionally and structurally separate its operations into two main business segments, a non-regulated business and a regulated business. Separation of AEP's regulated bundled generation, distribution and transmission businesses into an unbundled non-regulated generation business and regulated unbundled distribution and transmission business will not be completed until the required regulatory approvals are obtained and the electric operating subsidiaries operating in states that are deregulating the generation business are structurally separated and the remaining subsidiaries functionally separated and the necessary changes are made to their accounting software, books, and records. Management expects to begin reporting certain segmented information by the new business segments in the near future.
Domestic* Foreign Worldwide Electric Energy Energy Reconciling AEP Year Utilities Delivery Investments Other Adjustments Consolidated - ---- --------- -------- ----------- ----- ----------- ------------ (in millions) 2000 Revenues from: External unaffiliated customers $10,827 $1,934 $ 836 $ 97 - $13,694 Transactions with other operating segments - - 147 391 $(538) - Interest expense 734 163 129 91 (60) 1,057 Depreciation, depletion and amortization expense 1,062 149 25 13 (187) 1,062 Income tax expense (benefit) 641 (16) (19) (9) - 597 Segment net income (loss) 211 125 (56) (13) - 267 Total assets 35,741 4,446 2,089 12,272 - 54,548 Investments in equity method subsidiaries - 427 360 77 - 864 Gross property additions 1,386 177 149 61 - 1,773 1999 Revenues from: External unaffiliated customers $ 9,838 $2,023 $ 583 $ (37) - $12,407 Transactions with other operating segments - - 70 246 $(316) - Interest expense 688 172 109 55 (47) 977 Depreciation, depletion and amortization expense 1,011 166 26 9 (201) 1,011 Income tax expense (benefit) 490 18 (10) (16) - 482 Segment net income (loss) 794 170 34 (26) - 972 Total assets 27,288 4,739 1,669 2,023 - 35,719 Investments in equity method subsidiaries - 412 420 57 - 889 Gross property additions 1,215 206 205 54 - 1,680 1998 Revenues from: External unaffiliated customers $ 9,834 $1,769 $ 183 $ 54 - $11,840 Transactions with other operating segments - - - 49 $ (49) - Interest expense 682 116 68 51 (38) 879 Depreciation, depletion and amortization expense 989 95 13 7 (115) 989 Income tax expense (benefit) 532 4 (14) (20) - 502 Segment net income (loss) 884 155 (26) (38) - 975 Total assets 25,546 4,504 1,672 1,543 - 33,265 Investments in equity method subsidiaries - 352 287 59 - 698 Gross property additions 729 1,259 712 90 - 2,790 *Includes the domestic generation retail and wholesale supply businesses a significant portion of which is undergoing a transition from regulated cost based bundled rates to open access market pricing but which have not yet been unbundled i.e., structurally separated from the distribution and transmission portions of the vertically integrated electric utility business.
Geographic Areas Revenues - ---------------- ---------------------------------------------------------------------- United AEP United States Kingdom Other Foreign Consolidated --------------------------------------------------------------------- (in millions) 2000 $11,663 $1,632 $399 $13,694 1999 10,353 1,705 349 12,407 1998 10,063 1,769 8 11,840 Long-Lived Assets ---------------------------------------------------------------------- United AEP United States Kingdom Other Foreign Consolidated --------------------------------------------------------------------- (in millions) 2000 $20,463 $1,220 $710 $22,393 1999 19,958 1,124 783 21,865 1998 19,752 1,102 665 21,519
15. Financial Instruments, Credit and Risk Management: AEP and its subsidiaries are subject to market risk as a result of changes in commodity prices, foreign currency exchange rates, and interest rates. AEP has wholesale electricity and gas trading and marketing operations that manage the exposure to commodity price movements using physical forward purchase and sale contracts at fixed and variable prices, and financial derivative instruments including exchange traded futures and options, over-the-counter options, swaps and other financial derivative contracts at both fixed and variable prices. In the first quarter of 1999 AEP adopted the Financial Accounting Standards Board's EITF 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities". The EITF requires that all open energy trading contracts be marked-to-market. The effect on the Consolidated Statements of Income of marking open trading contracts to market in the AEP System's regulated jurisdictions are deferred as regulatory assets or liabilities in accordance with SFAS 71 for the portion of those open electricity trading transactions within AEP's marketing area that are included in cost of service on a settlement basis for ratemaking purposes. Open electricity trading transactions within AEP's marketing area allocated to non-regulated jurisdictions are marked-to-market and included in revenues from domestic electric utility operations. Open electricity trading contracts outside AEP's marketing area are accounted for on a mark-to-market basis and included in revenues from worldwide electric and gas operations. Open gas trading contracts are accounted for on a mark-to-market basis and included in revenues from worldwide electric and gas operations. Unrealized mark-to-market gains and losses from trading of financial instruments are reported as assets and liabilities, respectively. The amounts of net revenues recorded in 2000 and 1999 for electric and gas trading activities were: Revenues - Net Gain (Loss) 2000 1999 - -------------------------- ---- ---- (in millions) Domestic Electric Utility Operations $ 43 $27 Worldwide Electric and Gas Operations 213 14 The amounts of net revenues recorded in 2000 and 1999 for the registrant subsidiaries were: 2000 1999 ---- ---- (in thousands) APCo $23,712 $14,640 CPL (3,809) - CSPCo 22,032 5,819 I&M 29,344 6,384 KPCo 11,792 2,182 OPCo 34,582 10,921 PSO 3,553 - SWEPCo (441) - WTU (453) - Investment in foreign energy companies and projects exposes AEP to risk of foreign currency fluctuations. AEP is also exposed to changes in interest rates primarily due to short- and long-term borrowings used to fund its business operations. AEP does not presently utilize derivatives to manage its exposures to foreign currency exchange rate movements. Market Valuation - 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 AEP and I&M's best estimate of its fair value. The book values and fair values of AEP's and the registrant subsidiaries' significant financial instruments at December 31, 2000 and 1999 are summarized in the following table. 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 of the same remaining maturities. The fair value of those financial instruments that are marked-to-market are based on management's best estimates using over-the-counter quotations, exchange prices, volatility factors and a valuation methodology. The estimates presented herein are not necessarily indicative of the amounts that AEP and the registrant subsidiaries could realize in a current market exchange.
2000 1999 Book Value Fair Value Book Value Fair Value ---------- ---------- ---------- ---------- (in thousands) (in thousands) Non-Derivatives AEP Consolidated Long-term Debt $10,754,000 $10,812,000 $11,524,000 $11,037,000 Preferred Stock 100,000 98,000 119,000 117,000 Trust Preferred Securities 334,000 326,000 335,000 290,000 AEGCo Long-term Debt $45 $45 $45 $45 APCo Long-term Debt $1,605,818 $1,601,313 $1,665,307 $1,580,600 Preferred Stock 10,860 10,725 20,310 19,700 CPL Long-term Debt $1,454,559 $1,463,690 $1,454,541 $1,435,083 Trust Preferred Securities 148,500 147,431 150,000 129,360 CSPCo Long-term Debt $899,615 $908,620 $925,000 $889,000 Preferred Stock 15,000 14,892 25,000 25,438 I&M Long-term Debt $1,388,939 $1,377,230 $1,324,326 $1,283,300 Preferred Stock 64,945 63,941 64,945 63,500 KPCo Long-term Debt $330,880 $335,408 $365,782 $359,100 OPCo Long-term Debt $1,195,493 $1,176,367 $1,151,511 $1,027,000 Preferred Stock 8,850 8,780 8,850 8,500 PSO Long-term Debt $470,822 $476,964 $384,516 $378,437 Trust Preferred Securities 75,000 72,180 75,000 63,390 SWEPCo Long-term Debt $645,963 $651,586 $541,568 $537,354 Trust Preferred Securities 110,000 106,700 110,000 97,372 WTU Long-term Debt $255,843 $261,315 $303,686 $298,220
Derivatives 2000 1999 --------------------------- ---------------------------- Notional Fair Average Notional Fair Average Amount Value Fair Value Amount Value Fair Value -------- ----- ---------- -------- ----- ---------- GWH (in millions) GWH (in millions) AEP Consolidated Trading Assets Electric Futures and Options-NYMEX (net) - $ - $ - 224 $ 2 $ 1 Physicals 247,330 8,845 2,758 69,509 577 517 Options - OTC 8,981 215 99 6,203 39 62 Swaps 11,575 164 60 177 1 1 MMMBTU MMMBTU Gas Futures and Options-NYMEX (net) - $ - $ - - $ - $ - Physicals 597,251 455 97 345,830 37 39 Options - OTC 698,392 1,266 355 192,593 54 40 Swaps 4,677,142 7,328 1,730 2,682,033 410 312 Trading Liabilities GWH (in millions) GWH (in millions) Electric Futures and Options-NYMEX (net) - $ - $ - - $ - $ - Physicals 246,729 (8,906) (2,712) 74,764 (536) (498) Options - OTC 10,368 (133) (69) 8,907 (43) (56) Swaps 11,289 (144) (47) 180 (2) (2) MMMBTU MMMBTU Gas Futures and Options- NYMEX (net) 23,110 $ (81) $ (11) 69,840 $ (8) $ (5) Physicals 442,309 (420) (91) 301,271 (32) (26) Options - OTC 666,304 (934) (306) 227,225 (55) (37) Swaps 4,616,178 (7,592) (1,762) 2,601,644 (379) (303) 2000 1999 --------------------------- ---------------------------- Notional Fair Average Notional Fair Average Amount Value Fair Value Amount Value Fair Value -------- ----- ---------- -------- ----- ---------- GWH (in thousands) GWH (in thousands) APCo Trading Assets Electric Futures and Options-NYMEX (net) - $ - $ - 64 $ 535 $ 254 Physicals 45,406 2,246,952 757,757 19,953 165,624 150,377 Options - OTC 1,924 59,814 25,015 1,781 11,766 18,461 Swaps 3,652 51,470 18,387 51 112 90 Trading Liabilities Electric Futures and Options-NYMEX (net) - $ - $ - - $ - $ - Physicals 45,994 (2,271,026) (747,567) 21,461 (154,364)(144,876) Options - OTC 3,130 (35,955) (18,872) 2,557 (12,375) (16,811) Swaps 3,562 (44,855) (14,103) 52 (103) (85) KPCo Trading Assets Electric Futures and Options-NYMEX (net) - $ - $ - 15 $ 114 $ 49 Physicals 10,779 533,781 179,999 4,707 39,074 35,477 Options - OTC 456 14,207 5,938 420 2,773 4,353 Swaps 867 12,227 4,368 12 26 21 Trading Liabilities Electric Futures and Options-NYMEX (net) - $ - $ - - $ - $ - Physicals 10,919 (539,465) (177,581) 5,063 (36,422)(34,180) Options - OTC 743 (8,521) (4,461) 603 (2,900) (3,949) Swaps 846 (10,656) (3,350) 12 (24) (20) 2000 1999 --------------------------- ---------------------------- Notional Fair Average Notional Fair Average Amount Value Fair Value Amount Value Fair Value -------- ----- ---------- -------- ----- ---------- GWH (in thousands) GWH (in thousands) I&M Trading Assets Electric Futures and Options-NYMEX (net) - $ - $ - 43 $ 340 $ 171 Physicals 27,431 1,357,459 466,140 13,592 112,830 99,621 Options - OTC 1,162 36,139 15,464 1,213 8,010 12,125 Swaps 2,206 31,095 11,144 35 76 61 Trading Liabilities Electric Futures and Options-NYMEX (net) - $ - $ - - $ - $ - Physicals 27,786 (1,379,302) (460,348) 14,620 (105,169)(95,948) Options - OTC 1,891 (25,807) (13,031) 1,742 (8,391)(11,010) Swaps 2,152 (27,099) (8,552) 35 (70) (58) OPCo Trading Assets Electric Futures and Options-NYMEX (net) - $ - $ - 61 $ 583 $ 286 Physicals 36,080 1,786,137 639,632 18,753 155,507 146,395 Options - OTC 1,529 46,731 20,403 1,673 9,672 9,936 Swaps 2,902 41,788 16,172 48 987 967 Trading Liabilities Electric Futures and Options-NYMEX (net) - $ - $ - - $ - $ - Physicals 36,547 (1,802,295) (627,137) 20,171 (143,440)(135,015) Options - OTC 2,487 (29,350) (16,571) 2,403 (11,506) (7,084) Swaps 2,830 (37,398) (13,447) 49 (1,846) (1,829) CSPCo Trading Assets Electric Futures and Options-NYMEX (net) - $ - $ - 40 $ 312 $ 159 Physicals 24,221 1,198,835 420,090 12,503 103,794 91,570 Options - OTC 1,026 31,918 13,961 1,116 7,369 11,140 Swaps 1,948 27,461 9,914 32 70 56 Trading Liabilities Electric Futures and Options-NYMEX (net) - $ - $ - - $ - $ - Physicals 24,535 (1,211,580) (414,198) 13,449 (96,748)(88,194) Options - OTC 1,669 (19,220) (10,629) 1,602 (7,717)(10,114) Swaps 1,900 (23,932) (7,599) 32 (64) (53)
2000 Notional Fair Average Amount Value Fair Value -------- ----- ---------- GWH (in thousands) CPL Trading Assets Electric Physicals 31,040 $547,437 $ 210,189 Trading Liabilities Electric Physicals 31,442 (555,628) (211,482) PSO Trading Assets Electric Physicals 24,670 435,009 232,198 Trading Liabilities Electric Physicals 24,990 (441,517) (234,082) SWEPCo Trading Assets Electric Physicals 29,538 520,964 217,444 Trading Liabilities Electric Physicals 29,920 (528,759) (220,171) WTU Trading Assets Electric Physicals 9,821 173,118 58,048 Trading Liabilities Electric Physicals 9,948 (175,708) (58,071) There were no trading activities for CPL, PSO, SWEPCo, and WTU for the year ended 1999. AEP routinely enters into exchange traded futures and options transactions for electricity and natural gas as part of its wholesale trading operations. These transactions are executed through brokerage accounts with brokers who are registered with the Commodity Futures Trading Commission. Brokers require cash or cash related instruments to be deposited on these accounts as margin calls against the customer's open position. The amount of these deposits at December 31, 2000 and 1999 was $95 million and $25 million, respectively. Credit and Risk Management - In addition to market risk associated with price movements, AEP is also subject to the credit risk inherent in its risk management activities. Credit risk refers to the financial risk arising from commercial transactions and/or the intrinsic financial value of contractual agreements with trading counter parties, by which there exists a potential risk of non-performance. The AEP System has established and enforced credit policies that minimize or eliminate this risk. AEP accepts as counter parties to forwards, futures, and other derivative contracts primarily those entities that are classified as Investment Grade, or those that can be considered as such due to the effective placement of credit enhancements and/or collateral agreements. Investment Grade is the designation given to the four highest debt rating categories (i.e., AAA, AA, A, BBB) of the major rating services, e.g., ratings BBB- and above at Standard & Poor's and Baa3 and above at Moody's. When adverse market conditions have the potential to negatively affect a counter party's credit position, AEP will require further enhancements to mitigate risk. Since the formation of the trading business in July of 1997, AEP has not experienced a significant loss due to the credit risk; furthermore, AEP does not anticipate any future material effect on its results of operations, cash flow or financial condition as a result of counter party non-performance. Other Financial Instruments - Nuclear Trust Funds Recorded at Market Value - The trust investments for decommission and SNF disposal, reported in other assets, are recorded at market value. At December 31, 2000 and 1999 the fair values of the trust investments were $873 million and $795 million, respectively, and had a cost basis of $768 million and $696 million, respectively. The change in market value in 2000, 1999, and 1998 was a net unrealized holding gain of $6 million, $18 million, and $32 million, respectively. At December 31, 2000 and 1999 the fair value of CPL's trust investments for decommissioning were $94 million and $86 million, respectively, and had a cost basis of $70 million and $60 million, respectively. The change in market value for CPL was a net unrealized holding loss of $3 million in 2000 and a net unrealized holding gain of $10 million and $8 million in 1999 and 1998, respectively. At December 31, 2000 and 1999 the fair value of I&M's trust investments for decommissioning and SNF disposal were $779 million and $708 million, respectively, and had a cost basis of $698 million and $636 million, respectively. The change in market value for I&M in 2000, 1999, and 1998 was a net unrealized holding gain of $9 million, $8 million and $24 million, respectively. CitiPower entered into several interest rate swap agreements for $425 million of borrowings under a credit facility. The swap agreements involve the exchange of floating-rate for fixed-rate interest payments. Interest is recognized currently based on the fixed rate of interest resulting from use of these swap agreements. Market risks arise from the movements in interest rates. If counter parties to an interest rate swap agreement were to default on contractual payments, CitiPower could be exposed to increased costs related to replacing the original agreement. However, CitiPower does not anticipate non-performance by any counter party to any interest rate swap in effect as of December 31, 2000. As of December 31, 2000, CitiPower was a party to interest rate swaps having an aggregate notional amount of $626 million, with $224 million maturing on December 31, 2003, and $201 million maturing on December 29, 2003, $201 million commencing on December 29, 2003 and maturing on December 30, 2005. The average fixed interest rate payable on the aggregate of the interest rate swaps is 5.84%. The average floating rate for interest rate swaps was 6.04% at December 31, 2000. The estimated fair value of the interest rate swaps, which represents the estimated amount CitiPower would receive to terminate the swaps at December 31, 2000, based on quoted interest rates, is a net receivable of less than a million dollars. CitiPower entered into interest rate swap agreement for $112 million in January 2000, for the purpose of hedging a capital markets bond issue. The interest rate swap agreement exchanges a fixed-rate for a floating interest rate up to January 15, 2007. The $112 million interest rate swap agreement was terminated on December 18, 2000. The gain of $9 million earned upon termination of the swap agreement has been deferred and will be amortized through January 15, 2007. The CSW UK Holdings Group (Group) entered into two currency swaps in 1996 in respect of two tranches of $200 million notes ("Yankee Bonds") repayable on August 1, 2001 and August 1, 2006. The swaps convert fixed rate semi-annual U.S. Dollar interest payments at 6.95% and 7.45% to fixed rate sterling. As a result of the swaps the effective fixed sterling interest rates, including fees, are 7.98% and 8.75%. The estimated fair value of these swaps at December 31, 2000 is a net payable of $1 million. The Group also has an interest in two interest rate swaps entered into by its joint venture associate Power Asset Development Company Limited in 1998. The swaps convert floating rate interest payable on a $157 million bank project finance borrowing, maturing in 2021, to 6.00% fixed rate. The estimated fair value of these swaps at December 31, 2000 is a net payable of $3 million of which the Group's interest is $1 million. In addition, at December 31, 2000, the Group has an interest in a currency swap and an interest rate swap entered into by another joint venture associate, South Coast Power Limited. The estimated fair value of these swaps is a net receivable of $3 million of which the Group's share is $1 million. In accordance with the debt covenants included in the financing provisions of its credit facility, CitiPower must hedge at least 80% of its energy purchase requirements through energy trading derivative instruments entered into with market participants, predominantly generators. As of December 31, 2000, CitiPower had outstanding energy trading derivatives with a total contracted load of 10,144 GWH's. The maturities for these contracts range from three months to six years. Management's estimate of the fair value of these derivatives as of December 31, 2000 is $7 million in excess of net contract value. SEEBOARD manages its energy purchase costs through energy trading derivative instruments entered into with market participants. The Company buys derivative instruments to hedge purchase costs only and does not enter into any speculative trades. As of December 31, 2000, SEEBOARD had outstanding energy trading derivatives with a total contracted volume of 14,059 GWH's excluding Medway Power Limited. These contracts have maturities in the range of 1 to 27 months. In addition SEEBOARD has a 15 year contract with Medway Power Limited which owns and operates a 675 MW combined cycle gas generating station. SEEBOARD also has a 37.5% equity interest in Medway Power Limited. There are 29,025 GWH remaining under the contract which has 10 years and 9 months to run. Management's estimate of the fair value of these derivatives as of December 31, 2000 is $132 million below net contract value. 16. Income Taxes: The details of AEP's consolidated income taxes as reported are as follows: Year Ended December 31, ------------------------------ 2000 1999 1998 ---- ---- ---- (in millions) Federal: Current $ 766 $308 $492 Deferred (237) 129 (43) ----- ---- ---- Total 529 437 449 ----- ---- ---- State: Current 50 25 30 Deferred (9) - - ----- ---- ---- Total 41 25 30 ----- ---- ---- International: Current 6 3 14 Deferred 21 17 9 ----- ---- ----- Total 27 20 23 ----- ---- ----- Total Income Tax as Reported $ 597 $482 $502 ===== ==== ====
The details of the registrant subsidiaries income taxes as reported are as follows: AEGCo APCo CPL CSPCo I&M Year Ended December 31, 2000 (in thousands) Charged (Credited) to Operating Expenses (net): Current $ 8,746 $129,165 $ 89,403 $120,494 $ 134,796 Deferred (5,842) 3,838 16,263 (7,746) (126,748) Deferred Investment Tax Credits - (2,947) (5,207) (3,379) (7,524) ------- -------- -------- -------- --------- Total 2,904 130,056 100,459 109,369 524 ------- -------- -------- -------- --------- Charged (Credited) to Nonoperating Income (net): Current (44) 327 (5,073) 3,777 2,950 Deferred - 4,764 - 3,683 1,569 Deferred Investment Tax Credits (3,396) (1,968) - (103) (330) ------- -------- ------- -------- --------- Total (3,440) 3,123 (5,073) 7,357 4,189 ------- -------- ------- -------- --------- Total Income Tax as Reported $ (536) $133,179 $95,386 $116,726 $ 4,713 ======= ======== ======= ======== ========= KPCo OPCo PSO SWEPCo WTU Year Ended December 31, 2000 (in thousands) Charged (Credited) to Operating Expenses (net): Current $17,878 $259,608 $11,597 $16,073 $ 6,774 Deferred 2,521 (70,263) 25,453 14,653 9,401 Deferred Investment Tax Credits (1,187) (1,824) (1,791) (4,482) (1,271) ------- -------- ------- ------- ------- Total 19,212 187,521 35,259 26,244 14,904 ------- -------- ------- ------- ------- Charged (Credited) to Nonoperating Income (net): Current (50) 15,426 (1,306) (1,476) (222) Deferred 1,244 4,307 - - (1,237) Deferred Investment Tax Credits (65) (1,575) - - - ------- ------- ------- ------- -------- Total 1,129 18,158 (1,306) (1,476) (1,459) ------- ------- ------- ------- ------- Total Income Tax as Reported $20,341 $205,679 $33,953 $24,768 $13,445 ======= ======== ======= ======= ======= AEGCo APCo CPL CSPCo I&M Year Ended December 31, 1999 (in thousands) Charged (Credited) to Operating Expenses (net): Current $ 7,713 $69,522 $ 89,112 $79,410 $(67,368) Deferred (5,282) 8,981 19,620 9,737 85,345 Deferred Investment Tax Credits - (2,659) (5,207) (3,432) (7,547) ------- ------- -------- ------- -------- Total 2,431 75,844 103,525 85,715 10,430 ------- ------- -------- ------- -------- Charged (Credited) to Nonoperating Income (net): Current (146) (1,548) (5,604) (3,122) 1,529 Deferred - 4,052 318 744 382 Deferred Investment Tax Credits (3,448) (2,313) - (562) (605) ------- ------- -------- ------- -------- Total (3,594) 191 (5,286) (2,940) 1,306 ------- ------- -------- ------- -------- Total Income Taxes as Reported $(1,163) $76,035 $ 98,239 $82,775 $ 11,736 ======= ======= ======== ======= ======== KPCo OPCo PSO SWEPCo WTU Year Ended December 31, 1999 (in thousands) Charged (Credited) to Operating Expenses (net): Current $14,897 $135,540 $20,777 $ 60,169 $ 3,328 Deferred 2,239 4,205 14,521 (17,347) 12,026 Deferred Investment Tax Credits (1,193) (1,825) (1,791) (4,565) (1,275) ------- -------- ------- -------- ------- Total 15,943 137,920 33,507 38,257 14,079 ------- -------- ------- -------- ------- Charged (Credited) to Nonoperating Income (net): Current (424) (3,256) (2,215) (4,826) 858 Deferred 357 (539) - - - Deferred Investment Tax Credits (99) (1,633) - - - ------- -------- ------- -------- ------- Total (166) (5,428) (2,215) (4,826) 858 ------- -------- ------- -------- ------- Total Income Taxes as Reported $15,777 $132,492 $31,292 $ 33,431 $14,937 ======= ======== ======= ======== =======
AEGCo APCo CPL CSPCo I&M Year Ended December 31, 1998 (in thousands) Charged (Credited) to Operating Expenses (net): Current $(2,556) $63,291 $128,942 $62,123 $43,103 Deferred 5,544 (143) (8,328) 17,612 21,073 Deferred Investment Tax Credits - (2,671) (3,858) (3,498) (7,593) ------- ------- -------- ------- ------- Total 2,988 60,477 116,756 76,237 56,583 ------- ------- -------- ------- ------- Charged (Credited) to Nonoperating Income (net): Current (45) (4,902) (2,204) (3,795) (594) Deferred - (2,195) - (511) (3,168) Deferred Investment Tax Credits (3,454) (2,594) - (726) (673) ------- ------- -------- ------- ------- Total (3,499) (9,691) (2,204) (5,032) (4,435) ------- ------- -------- ------- ------- Total Income Taxes as Reported $ (511) $50,786 $114,552 $71,205 $52,148 ======= ======= ======== ======= ======= KPCo OPCo PSO SWEPCo WTU Year Ended December 31, 1998 (in thousands) Charged (Credited) to Operating Expenses (net): Current $10,788 $120,932 $52,587 $ 64,463 $28,542 Deferred 3,967 3,907 (1,651) (11,909) (6,626) Deferred Investment Tax Credits (1,202) (1,827) (1,795) (4,631) (1,321) ------- -------- ------- -------- ------- Total 13,553 123,012 49,141 47,923 20,595 ------- -------- ------- -------- ------- Charged (Credited) to Nonoperating Income (net): Current (794) (5,619) (93) (1,868) (454) Deferred (360) (865) - - - Deferred Investment Tax Credits (213) (1,698) - - - ------- -------- ------- -------- -------- Total (1,367) (8,182) (93) (1,868) (454) ------- -------- ------- -------- ------- Total Income Taxes as Reported $12,186 $114,830 $49,048 $ 46,055 $20,141 ======= ======== ======= ======== =======
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, --------------------------------- 2000 1999 1998 ---- ---- ---- (in millions) Net Income $267 $ 972 $ 975 Extraordinary Items (net of income tax $44 million in 2000 and $8 million in 1999) 35 14 - Preferred Stock Dividends 11 19 19 ---- ------ ------ Income Before Preferred Stock Dividends of Subsidiaries 313 1,005 994 Income Taxes 597 482 502 ---- ------ ------ Pre-Tax Income $910 $1,487 $1,496 ==== ====== ====== Income Tax on Pre-Tax Income at Statutory Rate (35%) $319 $520 $524 Increase (Decrease) in Income Tax Resulting from the Following Items: Depreciation 77 71 67 Corporate Owned Life Insurance 247 2 (16) Foreign Tax Credits (31) (63) (49) Investment Tax Credits (net) (36) (38) (37) Merger Transaction Costs 49 - - State Income Taxes 26 16 19 International 18 13 15 Other (72) (39) (21) ---- ---- ---- Total Income Taxes as Reported $597 $482 $502 ==== ==== ==== Effective Income Tax Rate 65.5% 32.5% 33.6% ==== ==== ====
Shown below is a reconciliation for each AEP registrant subsidiary of the difference between the amount of federal income taxes computed by multiplying book income before federal income taxes by the statutory rate, and the amount of income taxes reported. AEGCo APCo CPL CSPCo I&M Year Ended December 31, 2000 (in thousands) Net Income (Loss) $7,984 $ 73,844 $189,567 $ 94,966 $(132,032) Extraordinary (Gains) Loss (1,066) 39,384 Income Tax Benefit - (7,872) - (14,148) - Income Taxes (536) 133,179 95,386 116,726 4,713 ------ -------- -------- -------- --------- Pre-Tax Income (Loss) $7,448 $198,085 $284,953 $236,928 $(127,319) ====== ======== ======== ======== ========= Income Tax on Pre-Tax Income (Loss) at Statutory Rate (35%) $ 2,607 $ 69,330 $99,733 $ 82,925 $(44,561) Increase (Decrease) in Income Tax Resulting from the Following Items: Depreciation 452 7,606 7,556 10,529 20,378 Corporate Owned Life Insurance - 54,824 - 29,259 42,587 Nuclear Fuel Disposal Costs - - - - (3,957) Allowance for Funds Used During Construction (1,070) - - - (2,211) Rockport Plant Unit 2 Investment Tax Credit 374 - - - - Removal Costs - (1,197) - - - Investment Tax Credits (net) (3,396) (4,915) (5,207) (3,482) (7,854) State Income Taxes 784 9,950 2,296 89 6,004 Other (287) (2,419) (8,992) (2,594) (5,673) ------- -------- ------- -------- -------- Total Income Taxes as Reported $ (536) $133,179 $95,386 $116,726 $ 4,713 ======= ======== ======= ======== ======== Effective Income Tax Rate N.M. 67.2% 33.5% 49.3% N.M. ==== ==== ==== ==== ==== KPCo OPCo PSO SWEPCo WTU Year Ended December 31, 2000 (in thousands) Net Income $20,763 $ 83,737 $ 66,663 $72,672 $27,450 Extraordinary Loss 40,157 Income Tax Benefit - (21,281) - - - Income Taxes 20,342 205,679 33,953 24,768 13,445 ------- -------- -------- ------- ------- Pre-Tax Income $41,105 $308,292 $100,616 $97,440 $40,895 ======= ======== ======== ======= ======= Income Tax on Pre-Tax Income at Statutory Rate (35%) $14,387 $107,903 $35,216 $ 34,104 $14,313 Increase (Decrease) in Income Tax Resulting from the Following Items: Depreciation 1,827 27,577 - - 1,204 Corporate Owned Life Insurance 5,149 84,453 - - - Nuclear Fuel Disposal Costs - - - - - Allowance for Funds Used During Construction - - - - - Rockport Plant Unit 2 Investment Tax Credit - - - - - Removal Costs (420) - - - - Investment Tax Credits (net) (1,252) (3,398) (1,791) (4,482) (1,271) State Income Taxes 1,597 (1,988) 3,037 1,650 - Other (946) (8,868) (2,509) (6,504) (801) ------- -------- ------- -------- ------- - Total Income Taxes as Reported $20,342 $205,679 $33,953 $ 24,768 $13,445 ======= ======== ======= ======== ======= Effective Income Tax Rate 49.5% 66.8% 33.8% 25.4% 32.9% ==== ==== ==== ==== ==== AEGCo APCo CPL CSPCo I&M Year Ended December 31, 1999 (in thousands) Net Income $ 6,195 $120,492 $182,201 $150,270 $32,776 Extraordinary Loss 8,488 Income Tax Benefit - - (2,971) - - Income Taxes (1,163) 76,035 98,239 82,775 11,736 ------- -------- -------- -------- ------- Pre-Tax Income $ 5,032 $196,527 $285,957 $233,045 $44,512 ======= ======== ======== ======== ======= Income Tax on Pre-Tax Income at Statutory Rate (35%) $ 1,762 $ 68,785 $100,085 $ 81,566 $15,580 Increase (Decrease) in Income Tax Resulting from the Following Items: Depreciation 446 12,593 7,981 8,846 19,966 Corporate Owned Life Insurance - - - - 594 Nuclear Fuel Disposal Costs - - - - (3,347) Allowance for Funds Used During Construction (1,069) - - - (2,174) Rockport Plant Unit 2 Investment Tax Credit 374 - - - - Removal Costs - (3,220) - - - Investment Tax Credits (net) (3,448) (4,972) (5,207) (3,994) (8,152) State Income Taxes 467 3,305 6,965 58 (4,635) Other 305 (456) (11,585) (3,701) (6,096) ------- -------- -------- -------- ------- Total Income Taxes as Reported $(1,163) $ 76,035 $ 98,239 $ 82,775 $11,736 ======= ======== ======== ======== ======= Effective Income Tax Rate N.M. 38.7% 34.4% 35.6% 26.4% ==== ==== ==== ==== ==== KPCo OPCo PSO SWEPCo WTU Year Ended December 31, 1999 (in thousands) Net Income $25,430 $212,157 $61,508 $83,194 $26,406 Extraordinary Loss 4,632 8,402 Income Tax Benefit - - - (1,621) (2,941) Income Taxes 15,777 132,492 31,292 33,431 14,937 ------- -------- ------- -------- ------- Pre-Tax Income $41,207 $344,649 $92,800 $119,636 $46,804 ======= ======== ======= ======== ======= Income Tax on Pre-Tax Income at Statutory Rate (35%) $14,423 $120,628 $ 32,480 $ 41,873 $16,382 Increase (Decrease) in Income Tax Resulting from the Following Items: Depreciation 1,843 17,517 - - 1,120 Corporate Owned Life Insurance - 198 - - - Removal Costs (420) - - - - Investment Tax Credits (net) (1,292) (3,458) (1,791) (4,565) (1,275) State Income Taxes 1,809 1,090 3,054 2,924 - Other (586) (3,483) (2,451) (6,801) (1,290) ------- -------- -------- -------- ------- Total Income Taxes as Reported $15,777 $132,492 $ 31,292 $ 33,431 $14,937 ======= ======== ======== ======== ======= Effective Income Tax Rate 38.3% 38.5% 33.8% 28.0% 32.0% ==== ==== ==== ==== ==== AEGCo APCo CPL CSPCo I&M Year Ended December 31, 1998 (in thousands) Net Income $ 8,946 $ 93,330 $161,511 $133,044 $ 96,628 Income Taxes (511) 50,786 114,552 71,205 52,148 ------- -------- -------- -------- -------- Pre-Tax Income $ 8,435 $144,116 $276,063 $204,249 $148,776 ======= ======== ======== ======== ======== Income Tax on Pre-Tax Book Income at Statutory Rate (35%) $ 2,953 $ 50,441 $ 96,623 $ 71,488 $ 52,072 Increase (Decrease) in Income Tax Resulting from the Following Items: Depreciation 1,105 11,667 8,170 8,604 17,257 Corporate Owned Life Insurance - (4,212) - - (3,263) Allowance for Funds Used During Construction (1,070) - - - (2,184) Rockport Plant Unit 2 Investment Tax Credits 374 - - - - Nuclear Fuel Disposal Costs - - - - (3,397) Removal Costs - (4,200) - - - Investment Tax Credits (net) (3,454) (5,265) (3,858) (4,224) (8,266) State Income Taxes (203) 4,449 - 1 3,209 Mirror CWIP - - 10,055 - - Other (216) (2,094) 3,562 (4,664) (3,280) ------- -------- -------- -------- ------- Total Income Taxes as Reported $ (511) $ 50,786 $114,552 $ 71,205 $52,148 ======= ======== ======== ======== ======= Effective Income Tax Rate N.M. 35.3% 41.5% 34.9% 35.1% ==== ==== ==== ==== ==== KPCo OPCo PSO SWEPCo WTU Year Ended December 31, 1998 (in thousands) Net Income $21,676 $209,925 $ 76,909 $ 97,994 $37,725 Income Taxes 12,186 114,830 49,048 46,055 20,141 ------- -------- -------- -------- ------- Pre-Tax Income $33,862 $324,755 $125,957 $144,049 $57,866 ======= ======== ======== ======== ======= Income Tax on Pre-Tax Book Income at Statutory Rate (35%) $11,852 $113,665 $ 44,085 $ 50,418 $20,253 Increase (Decrease) in Income Tax Resulting from the Following Items: Depreciation 1,633 16,693 - - 964 Corporate Owned Life Insurance - (5,238) - - - Removal Costs (840) - - - - Investment Tax Credits (net) (1,415) (3,525) (1,795) (4,631) (1,321) State Income Taxes 1,560 1,782 4,478 3,308 - Other (604) (8,547) 2,280 (3,040) 245 ------- -------- -------- -------- ------- Total Income Taxes as Reported $12,186 $114,830 $ 49,048 $ 46,055 $20,141 ======= ======== ======== ======== ======= Effective Income Tax Rate 36.0% 35.4% 39.0% 32.0% 34.9% ==== ==== ==== ==== ====
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, -------------------------- 2000 1999 ---- ---- (in millions) Deferred Tax Assets $ 1,248 $ 1,241 Deferred Tax Liabilities (6,123) (6,391) ------- ------- Net Deferred Tax Liabilities $(4,875) $(5,150) =======- ======= Property Related Temporary Differences $(3,935) $(4,109) Amounts Due From Customers For Future Federal Income Taxes (415) (437) Deferred State Income Taxes (251) (220) Regulatory Assets Designated for Securitization (332) (332) All Other (net) 58 (52) ------- ------- Net Deferred Tax Liabilities $(4,875) $(5,150) ======= =======
AEGCo APCo CPL CSPCo I&M December 31, 2000 (in thousands) Deferred Tax Assets $ 81,480 $ 178,487 $ 67,184 $ 88,198 $ 342,900 Deferred Tax Liabilities (114,408) (860,961) (1,309,981) (510,957) (830,845) --------- --------- ----------- --------- --------- Net Deferred Tax Liabilities $ (32,928) $(682,474) $(1,242,797) $(422,759) $(487,945) ========= ========= =========== ========= ========= Property Related Temporary Differences $ (78,113) $(510,950) $ (773,454) $(343,045) $(324,198) Amounts Due From Customers For Future Federal Income Taxes 10,317 (95,639) (72,426) (79,959) (55,218) Deferred State Income Taxes (5,478) (86,351) - - (69,982) Net Deferred Gain on Sale and Leaseback-Rockport Plant Unit 2 42,766 - - - 28,454 Accrued Nuclear Decommissioning Expense - - - - 34,702 Deferred Fuel and Purchased Power - - - - (39,395) Deferred Cook Plant Restart Costs - - - - (42,000) Nuclear Fuel - - - - (28,319) Regulatory Assets Designated for Securitization - - (332,198) - - All Other (net) (2,420) 10,466 (64,719) 245 8,011 --------- --------- ----------- --------- --------- Net Deferred Tax Liabilities $ (32,928) $(682,474) $(1,242,797) $(422,759) $(487,945) ========= ========= =========== ========= ========= KPCo OPCo PSO SWEPCo WTU December 31, 2000 (in thousands) Deferred Tax Assets $ 32,807 $ 330,878 $ 60,010 $ 47,615 $ 16,604 Deferred Tax Liabilities (198,742) (952,819) (372,070) (446,819) (173,642) --------- --------- --------- --------- --------- Net Deferred Tax Liabilities $(165,935) $(621,941) $(312,060) $(399,204) $(157,038) ========= ========= ========= ========= ========= Property Related Temporary Differences $(116,109) $(586,039) $(313,248) $(375,427) $(150,264) Amounts Due From Customers For Future Federal Income Taxes (19,680) (110,908) 11,082 (6,015) 4,723 Deferred State Income Taxes (29,695) (14,282) (36,487) - - Deferred Fuel and Purchased Power - (116,224) - - - Provision for Mine Shutdown Costs - 63,995 - - - Postretirement Benefits - 93,306 - - - All Other (net) (451) 48,211 26,593 (17,762) (11,497) --------- --------- --------- --------- --------- Net Deferred Tax Liabilities $(165,935) $(621,941) $(312,060) $(399,204) $(157,038) ========= ========= ========= ========= ========= AEGCo APCo CPL CSPCo I&M December 31, 1999 (in thousands) Deferred Tax Assets $ 85,392 $ 173,038 $ 99,426 $ 79,510 $ 231,329 Deferred Tax Liabilities (121,892) (844,955) (1,334,601) (527,117) (853,486) --------- --------- ----------- --------- --------- Net Deferred Tax Liabilities $ (36,500) $(671,917) $(1,234,175) $(447,607) $(622,157) ========= ========= =========== ========= ========= Property Related Temporary Differences $ (84,149) $(510,143) $ (798,381) $(352,805) $(436,162) Amounts Due From Customers For Future Federal Income Taxes 11,283 (109,846) (74,328) (85,078) (61,311) Deferred State Income Taxes (5,970) (76,073) - - (61,700) Net Deferred Gain on Sale and Leaseback-Rockport Plant Unit 2 44,716 - - - 29,752 Accrued Nuclear Decommissioning Expense - - - - 32,097 Deferred Fuel and Purchased Power - - - - (52,713) Deferred Cook Plant Restart Costs - - - - (56,000) Nuclear Fuel - - - - (27,512) Regulatory Assets Designated for Securitization - - (332,198) - - All Other (net) (2,380) 24,145 (29,268) (9,724) 11,392 --------- --------- ----------- --------- --------- Net Deferred Tax Liabilities $ (36,500) $(671,917) $(1,234,175) $(447,607) $(622,157) ========= ========= =========== ========= ========= KPCo OPCo PSO SWEPCo WTU December 31, 1999 (in thousands) Deferred Tax Assets $ 32,186 $ 234,826 $ 68,488 $ 79,056 $ 26,916 Deferred Tax Liabilities (197,193) (911,286) (350,404) (455,560) (175,908) --------- --------- --------- --------- --------- Net Deferred Tax Liabilities $(165,007) $(676,460) $(281,916) $(376,504) $(148,992) ========= ========= ========= ========= ========= Property Related Temporary Differences $(114,903) $(599,863) $(308,497) $(389,680) $(153,027) Amounts Due From Customers For Future - Federal Income Taxes (19,616) (108,185) 12,697 (3,366) 4,569 Deferred State Income Taxes (32,715) (22,124) (13,001) - - Deferred Fuel and Purchase Power - (62,832) - - - Provision for Mine Shutdown Costs - 33,105 - - - Postretirement Benefits - 44,483 - - - All Other (net) 2,227 38,956 26,885 16,542 (534) --------- --------- --------- --------- --------- Net Deferred Tax Liabilities $(165,007) $(676,460) $(281,916) $(376,504) $(148,992) ========= ========= ========= ========= ========= The AEP System has settled with the IRS all issues from the audits of its consolidated federal income tax returns for the years prior to 1991. Returns for the years 1991 through 1999 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.
17. Supplementary Information: Year Ended December 31, 2000 1999 1998 ---- ---- ---- (in millions) AEP Consolidated Purchased Power - Ohio Valley Electric Corporation $86 $64 $43 (44.2% owned by AEP System) Cash was paid for: Interest (net of capitalized amounts) $842 $979 $859 Income Taxes $449 $270 $540 Noncash Investing and Financing Activities: Acquisitions under Capital Leases $118 $80 $119 Assumption of Liabilities Related to Acquisitions - - $152 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, 2000, 1999, and 1998 were: Year Ended December 31, APCo CSPCo I&M OPCo ------------ ---- ----- --- ---- (in thousands) 2000 $30,998 $8,706 $15,204 $31,134 1999 21,774 6,006 10,227 25,623 1998 10,388 5,947 14,271 12,006
18. Leases: Leases of property, plant and equipment are for periods up to 35 years and require payments of related property taxes, maintenance and operating costs. The majority of the leases have purchase or renewal options and will be renewed or replaced by other leases. Lease rentals for both operating and capital leases are generally charged to operating expenses in accordance with rate-making treatment. The components of rental costs are as follows: AEP AEGCo APCo CSPCo I&M KPCo OPCo Year Ended December 31, 2000 (in thousands) Lease Payments on Operating Leases $216,000 $73,858 $ 7,128 $ 7,683 $ 81,446 $1,978 $51,981 Amortization of Capital Leases 121,000 281 13,900 7,776 26,341 3,931 37,280 Interest on Capital Leases 38,000 55 3,930 2,690 10,908 1,054 9,584 -------- ------- ------- ------- -------- ------ ------- Total Lease Rental Costs $375,000 $74,194 $24,958 $18,149 $118,695 $6,963 $98,845 ======== ======= ======= ======= ======== ====== ======= AEP AEGCo APCo CSPCo I&M KPCo OPCo Year Ended December 31, 1999 (in thousands) Lease Payments on Operating Leases $247,000 $74,269 $ 5,647 $ 5,687 $ 81,611 $ 199 $ 60,026 Amortization of Capital Leases 97,000 364 13,749 7,427 11,320 4,299 35,622 Interest on Capital Leases 35,000 64 4,267 2,720 9,338 1,162 9,552 -------- ------- ------- ------- -------- ------ -------- Total Lease Rental Costs $379,000 $74,697 $23,663 $15,834 $102,269 $5,660 $105,200 ======== ======= ======= ======= ======== ====== ======== AEP AEGCo APCo CSPCo I&M KPCo OPCo Year Ended December 31, 1998 (in thousands) Lease Payments on Operating Leases $257,000 $76,387 $ 7,047 $ 8,107 $ 88,297 $ 931 $ 59,141 Amortization of Capital Leases 91,000 560 13,561 6,530 10,717 4,265 36,585 Interest on Capital Leases 37,000 97 3,541 2,626 10,302 1,173 14,309 -------- ------- ------- ------- -------- ------ -------- Total Lease Rental Costs $385,000 $77,044 $24,149 $17,263 $109,316 $6,369 $110,035 ======== ======= ======= ======= ======== ====== ======== CPL, PSO, SWEPCo and WTU do not have any operating leases.
Property, plant and equipment under capital leases and related obligations recorded on the Consolidated Balance Sheets are as follows: AEP AEGCo APCo CSPCo I&M KPCo OPCo Year Ended December 31, 2000 (in thousands) Property, Plant and Equipment Under Capital Leases Production $ 42,000 $2,017 $ 6,276 $ 2 $ 7,023 $ 1,730 $ 24,709 Distribution 151,000 14,595 Other: Nuclear Fuel (net of amortization) 90,000 89,872 Mining Assets and Other 619,000 177 93,437 $68,352 97,383 22,072 200,308 -------- ------ ------- ------- -------- ------- --------- Total Property, Plant and Equipment 902,000 2,194 99,713 68,354 208,873 23,802 225,017 Accumulated Amortization 288,000 1,603 36,553 25,422 45,700 9,618 108,436 -------- ------ ------- ------- -------- ------- --------- Net Property, Plant and Equipment Under Capital Leases $614,000 $ 591 $63,160 $42,932 $163,173 $14,184 $116,581 ======== ====== ======= ======= ======== ======= ======== Obligations Under Capital Leases: Noncurrent Liability $419,000 $ 358 $50,350 $35,199 $ 62,325 $11,091 $ 83,866 Liability Due Within One Year 195,000 233 12,810 7,733 100,848 3,093 32,715 -------- ------ ------- ------- -------- ------- --------- Total Obligations Under Capital Leases $614,000 $ 591 $63,160 $42,932 $163,173 $14,184 $116,581 ======== ====== ======= ======= ======== ======= =========
AEP AEGCo APCo CSPCo I&M KPCo OPCo Year Ended December 31, 1999 (in thousands) Property, Plant and Equipment Under Capital Leases Production $ 46,000 $2,350 $ 8,354 $ 8,348 $ 2,022 $ 24,428 Distribution 106,000 14,645 Other: Nuclear Fuel (net of amortization) 108,000 108,140 Mining Assets and Other 612,000 226 93,053 $63,386 99,367 24,225 205,209 -------- ------ -------- ------- -------- ------- -------- Total Property, Plant and Equipment 872,000 2,576 101,407 63,386 230,500 26,247 229,637 Accumulated Amortization 262,000 1,708 36,762 23,116 42,535 11,106 93,094 -------- ------ -------- ------- -------- ------- -------- Net Property, Plant and Equipment Under Capital Leases $610,000 $ 868 $ 64,645 $40,270 $187,965 $15,141 $136,543 ======== ====== ======== ======= ======== ======= ======== Obligations Under Capital Leases: Noncurrent Liability $510,000 $ 592 $ 52,009 $33,031 $176,893 $11,830 $102,259 Liability Due Within One Year 100,000 276 12,636 7,239 11,072 3,311 34,284 -------- ------ -------- ------- -------- ------- -------- Total Obligations Under Capital Leases $610,000 $ 868 $ 64,645 $40,270 $187,965 $15,141 $136,543 ======== ====== ======== ======= ======== ======= ======== Properties under operating leases and related obligations are not included in the Consolidated Balance Sheets. CPL, PSO, SWEPCo and WTU do not lease property, plant and equipment under capital leases.
Future minimum lease payments consisted of the following at December 31, 2000: AEP AEGCo APCo CSPCo I&M KPCo OPCo Capital (a) (in thousands) - ----------- 2001 $129,000 $255 $16,528 $10,480 $ 14,620 $ 3,929 $ 39,733 2002 99,000 217 15,526 9,426 13,535 3,501 21,332 2003 81,000 133 12,872 7,677 11,336 2,661 19,004 2004 63,000 20 10,336 6,331 9,397 2,004 15,445 2005 48,000 6 7,027 5,397 7,053 1,609 11,746 Later Years 397,000 1 13,748 15,376 25,427 3,417 38,710 -------- ---- ------- ------- -------- ------- --------- Total Future Minimum Lease Payments 817,000(a) 632 76,037 54,687 81,368 17,121 145,970 Less Estimated Interest Element 293,000 41 12,876 11,755 8,067 2,937 29,389 -------- ---- ------- ------- -------- ------- -------- Estimated Present Value of Future Minimum Lease Payments 524,000 $591 $63,161 $42,932 73,301 $14,184 $116,581 ==== ======= ======= ======= ======== Unamortized Nuclear Fuel 90,000 89,872 -------- -------- - Total $614,000 $163,173 ======== ======== (a) Minimum lease payments do not include nuclear fuel payments. The payments are paid in proportion to heat produced and carrying charges on the unamortized nuclear fuel balance. There are no minimum lease payment requirements for leased nuclear fuel.
AEP AEGCo APCo CSPCo I&M KPCo OPCo (in thousands) Noncancellable Operating Leases 2001 $ 244,000 $ 73,854 $ 726 $ 4,314 $ 99,249 $ 29 $ 62,560 2002 236,000 73,854 425 774 97,551 26 61,787 2003 235,000 73,854 412 735 97,385 23 61,109 2004 235,000 73,854 412 735 96,467 21 61,229 2005 243,000 73,854 412 735 95,201 21 71,304 Later Years 3,090,000 1,255,518 2,888 2,820 1,434,570 232 386,629 ---------- ---------- ------ ------- ---------- ---- --------- Total Future Minimum Lease Payments $4,283,000 $1,624,788 $5,275 $10,113 $1,920,423 $352 $704,618 ========== ========== ====== ======= ========== ==== =========
19. Lines of Credit and Factoring of Receivables: The AEP System uses short-term debt, primarily commercial paper, to meet fluctuations in working capital requirements and other interim capital needs. AEP has established a money pool to coordinate short-term borrowings for certain subsidiaries, including AEGCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU, and also incurs borrowings outside the money pool for other subsidiaries. As of December 31, 2000, AEP had revolving credit facilities totaling $3.5 billion to backup its commercial paper program. At December 31, 2000, AEP had $2.7 billion outstanding in short-term borrowings. The maximum amount of such short-term borrowings outstanding during the year, which had a weighted average interest rate for the year of 7.5%, was $2.7 billion during December 2000. The registrant subsidiaries incurred interest expense for amounts borrowed from the AEP money pool as follows Year Ended December 31, 2000 1999 1998 ---- ---- ---- (in millions) CPL $16.9 $14.1 $8.8 CSPCo 1.4 - - I&M 0.8 - - KPCo - - - OPCo 9.2 - - PSO 7.5 2.0 1.0 SWEPCo 4.2 4.7 1.8 WTU 2.7 0.6 0.3 Interest income earned from amounts advanced to the AEP money pool by the registrant subsidiaries were: Year Ended December 31, 2000 1999 1998 ---- ---- ---- (in millions) CSPCo $ 1.1 $ - $ - I&M 9.0 - - KPCo 1.8 - - OPCo 3.4 - - PSO - - 0.6 SWEPCo - 0.1 0.1 WTU - 0.2 0.4 AEP Credit, which does not participate in the money pool, issues commercial paper on a stand-alone basis. At December 31, 2000, AEP Credit had a $2.0 billion unsecured revolving credit agreement to back up its commercial paper program, which had $1.2 billion outstanding. The maximum amount of such commercial paper outstanding during the year, which had a weighted average interest rate for the year of 6.6% was $1.5 billion during September 2000. Outstanding short-term debt for AEP Consolidated consisted of: December 31, 2000 1999 ---- ---- (in millions) Balance Outstanding: Notes Payable $ 193 $ 232 Commercial Paper 4,140 2,780 ------ ------ Total $4,333 $3,012 ====== ====== In 2000 APCo did not participate in AEP's money pool. At December 31, 2000 and 1999, APCo had issued commercial paper in the amounts of $191.5 million and $123.5 million, respectively. At December 31, 2000, the weighted average interest rate for APCo's commercial paper borrowings was 8.24%. In January 2001 APCo became a participant in AEP's money pool and retired all outstanding short-term debt. AEP Credit factors electric customer accounts receivable for affiliated operating companies and unaffiliated companies. AEP Credit issues commercial paper on a stand alone basis and does not participate in the money pool. In June 2000 the factoring of customer accounts receivable for affiliated companies was expanded as a result of the merger. Under the factoring arrangement the registrant subsidiaries (excluding AEGCo and APCo) sell without recourse certain of their customer accounts receivable and accrued utility revenue balances to AEP Credit and are charged a fee based on AEP Credit financing costs, uncollectible accounts experience for each company's receivables and administrative costs. The costs of factoring customer accounts receivable is reported as an operating expense. At December 31, 2000, the amount of factored accounts receivable and accrued utility revenues for each registrant subsidiary was as follows: Company (in millions) - ------- CPL $153 CSPCo 116 I&M 103 KPCo 30 OPCo 104 PSO 108 SWEPCo 91 WTU 52 The fees paid by the registrant subsidiaries to AEP Credit for factoring customer accounts receivable were: Year Ended December 31, 2000 1999 1998 ---- ---- ---- (in millions) CPL $15.7 $14.7 $12.8 CSPCo 10.8 - - I&M 6.8 - - KPCo 1.9 - - OPCo 8.4 - - PSO 8.3 6.5 7.7 SWEPCo 9.2 9.3 9.1 WTU 4.0 3.5 3.7 20. Unaudited Quarterly Financial Information: The unaudited quarterly financial information for AEP Consolidated follows: 2000 Quarterly Periods Ended ------------------------------------------------------- March 31 June 30 Sept. 30 Dec. 31 ---------- ---------- ---------- ---------- (In Millions - Except Per Share Amounts) - ----------------------- Operating Revenues $3,021 $3,169 $3,915 $3,589 Operating Income 428 308 873 417 Income (Loss) Before Extraordinary Items 140 (18) 403 (223) Net Income (Loss) 140 (9) 359 (223) Earnings (Loss) per Share 0.43 (0.03) 1.11 (0.68) Fourth quarter 2000 earnings decreased $415 million from the prior year. The decrease was primarily due to various unfavorable items including: a ruling disallowing interest deductions claimed by AEP relating to its COLI program of $319 million; $35 million of the Cook Plant restart costs; and a $30 million writedown for the proposed sale of Yorkshire. Additionally, the fourth quarter of 1999 includes a $33 million gain on the sale of Sweeney in October. 1999 Quarterly Periods Ended ------------------------------------------------------- March 31 June 30 Sept. 30 Dec. 31 ---------- ---------- ---------- ---------- (In Millions - Except Per Share Amounts) - ----------------------- Operating Revenues $2,902 $2,963 $3,528 $3,014 Operating Income 525 552 802 446 Income Before Extraordinary Items 195 190 403 198 Net Income 195 190 395 192 Earnings per Share 0.61 0.59 1.23 0.60
The unaudited quarterly financial information for each AEP registrant subsidiary follows: Quarterly Periods Ended AEGCo APCo CPL CSPCo I&M ----------------- ----- ---- --- ----- --- (in thousands) 2000 March 31 Operating Revenues $56,866 $455,595 $316,328 $298,306 $343,986 Operating Income 2,395 78,246 38,650 44,124 (15,251) Income (Loss) Before Extraordinary Items 2,445 47,664 8,139 27,471 (36,553) Net Income (Loss) 2,445 47,664 8,139 27,471 (36,553) June 30 Operating Revenues $56,928 $430,000 $437,911 $330,914 $362,272 Operating Income 1,746 58,208 95,717 50,798 (18,599) Income (Loss) Before Extraordinary Items 1,653 30,240 67,553 35,335 (39,181) Net Income (Loss) 1,653 39,178 67,553 35,335 (39,181) September 30 Operating Revenues $55,658 $475,092 $601,369 $386,583 $423,217 Operating Income 2,209 65,750 120,653 83,562 36,056 Income Before Extraordinary Items 1,972 36,112 89,974 65,542 15,190 Net Income 1,972 36,112 89,974 40,306 15,190 December 31 Operating Revenues $59,064 $499,478 $415,569 $340,605 $419,001 Operating Income 2,074 (1,050) 52,078 17,393 (36,908) Income (Loss) Before Extraordinary Items 1,914 (49,110) 23,901 (8,146) (71,488) Net Income (Loss) 1,914 (49,110) 23,901 (8,146) (71,488) Quarterly Periods Ended KPCo OPCo PSO SWEPCo WTU ----------------- ---- ---- --- ------ --- (in thousands) 2000 March 31 Operating Revenues $ 97,204 $545,411 $161,329 $212,156 $ 96,535 Operating Income 15,557 65,113 10,860 22,731 9,781 Income Before Extraordinary Items 8,052 46,216 1,165 7,663 3,833 Net Income 8,052 46,216 1,165 7,663 3,833 June 30 Operating Revenues $ 97,759 $540,321 $209,172 $272,409 $130,742 Operating Income 9,456 79,968 24,502 33,296 16,938 Income Before Extraordinary Items 2,449 58,233 14,700 18,786 8,070 Net Income 2,449 58,233 14,700 18,786 8,070 September 30 Operating Revenues $106,698 $582,702 $358,710 $377,442 $201,191 Operating Income 13,790 96,652 56,437 61,312 16,565 Income Before Extraordinary Items 6,761 77,061 54,329 47,537 10,670 Net Income 6,761 58,185 54,329 47,537 10,670 December 31 Operating Revenues $108,742 $559,468 $233,398 $262,203 $144,326 Operating Income 10,935 (14,906) 4,870 10,939 9,057 Income (Loss) Before Extraordinary Items 3,501 (78,897) (3,531) (1,314) 4,877 Net Income (Loss) 3,501 (78,897) (3,531) (1,314) 4,877 In the fourth quarter of 2000 earnings for APCo, CSPCo, I&M, and OPCo were effected by a ruling disallowing interest deductions claimed by AEP relating to its COLI program. The unfavorable amounts are $82 million for APCo, $41 million for CSPCo, $66 million for I&M, $8 million for KPCo and $118 million for OPCo. Additionally I&M incurred costs in the fourth quarter of 2000 for the Cook Plant restart of $35 million.
Quarterly Periods Ended AEGCo APCo CPL CSPCo I&M ----------------- ----- ---- --- ----- --- (in thousands) 1999 March 31 Operating Revenues $52,827 $427,702 $282,278 $279,067 $334,113 Operating Income 2,360 71,607 46,091 46,047 38,838 Income Before Extraordinary Items 2,614 39,261 17,020 27,418 20,070 Net Income 2,614 39,261 17,020 27,418 20,070 June 30 Operating Revenues $51,612 $373,766 $383,783 $301,419 $336,553 Operating Income 1,002 43,099 79,679 54,473 26,966 Income Before Extraordinary Items 1,222 11,036 51,024 34,559 9,745 Net Income 1,222 11,036 51,024 34,559 9,745 September 30 Operating Revenues $57,235 $441,435 $495,653 $368,946 $411,248 Operating Income 921 66,309 127,499 83,478 26,085 Income Before Extraordinary Items 958 35,661 103,989 63,719 8,084 Net Income 958 35,661 103,989 63,719 8,084 December 31 Operating Revenues $55,515 $408,034 $320,761 $280,562 $312,205 Operating Income 1,057 60,221 40,716 38,792 16,763 Income (Loss) Before Extraordinary Items 1,401 34,534 15,685 24,574 (5,123) Net Income (Loss) 1,401 34,534 10,168 24,574 (5,123) Quarterly Periods Ended KPCo OPCo PSO SWEPCo WTU ----------------- ---- ---- --- ------ --- (in thousands) 1999 March 31 Operating Revenues $ 90,741 $518,221 $151,030 $197,064 $ 81,052 Operating Income 15,360 78,956 12,031 25,810 6,922 Income Before Extraordinary Items 8,209 60,821 2,423 12,095 932 Net Income 8,209 60,821 2,423 12,095 932 June 30 Operating Revenues $ 86,231 $498,587 $178,699 $242,888 $107,782 Operating Income 10,233 73,328 23,172 35,269 16,361 Income Before Extraordinary Items 2,995 51,865 13,955 21,411 10,116 Net Income 2,995 51,865 13,955 21,411 10,116 September 30 Operating Revenues $ 94,939 $544,451 $258,656 $312,035 $164,104 Operating Income 14,244 72,858 57,720 61,541 27,030 Income Before Extraordinary Items 7,197 56,233 50,257 44,908 21,413 Net Income 7,197 56,233 50,257 41,897 15,952 December 31 Operating Revenues $102,071 $478,004 $161,005 $219,540 $ 92,771 Operating Income 14,838 63,687 5,790 24,442 3,486 Income (Loss) Before Extraordinary Items 7,029 43,238 (5,127) 7,791 (594) Net Income (Loss) 7,029 43,238 (5,127) 7,791 (594)
21. Trust Preferred Securities: The following Trust Preferred Securities issued by the wholly-owned statutory business trusts of CPL, PSO and SWEPCo were outstanding at December 31, 2000 and December 31, 1999. They are classified on the balance sheets as certain subsidiaries Obligated, Mandatorily Redeemable Preferred Securities of Subsidiary Trusts Holding Solely Junior Subordinated Debentures of such subsidiaries. The Junior Subordinated Debentures mature on April 30, 2037. CPL reacquired 60,000 trust preferred units during 2000. Units issued/ 2000 1999 Description of outstanding Amount Amount Underlying Business Trust Security at 12/31/00 (millions) (millions) Debentures of Registrant - --------------------------------------------------------------------------------------------- CPL Capital I 8.00%, Series A 5,940,000 $149 $150 CPL, $153 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, ---------- ---- ---- 13,340,000 $334 $335 7.875%, Series A ========== ==== ==== Each of the business trusts is treated as a subsidiary of its parent company. The only assets of the business trusts are the subordinated debentures issued by their parent company as specified above. In addition to the obligations under their subordinated debentures, each of the parent companies has also agreed to a security obligation which represents a full and unconditional guarantee of its capital trust obligation.
22. Jointly Owned Electric Utility Plant: CPL, CSP, PSO, SWEPCo and WTU have generating units that are jointly owned with unaffiliated companies. Each of the participating companies is obligated to pay its share of the costs of any such jointly owned facilities in the same proportion as its ownership interest. Each AEP registrant subsidiary's proportionate share of the operating costs associated with such facilities is included in its statements of income and the investments are reflected in its balance sheets under utility plant as follows: Company's Share December 31, 2000 1999 -------------------------- --------------------------- Percent Utility Construction Utility Construction of Plant Work Plant Work Ownership in Service in Progress in Service in Progress --------- ------------ ------------- ------------ ------------ (in thousands) (in thousands) CPL: Oklaunion Generating Station (Unit No. 1) 7.8 $ 37,236 $ 395 $ 37,236 $ - South Texas Project Generating Station (Units No. 1 and 2) 25.2 2,373,575 19,292 2,351,795 56,021 ---------- ------- ---------- ------- $2,410,811 $19,687 $2,389,031 $56,021 ========== ======= ========== ======== CSP: W.C. Beckjord Generating Station (Unit No. 6) 12.5 $ 14,108 $ 178 $ 13,919 $ 390 Conesville Generating Station (Unit No. 4) 43.5 80,103 261 80,433 80 J.M. Stuart Generating Station 26.0 191,875 10,086 184,168 3,620 Wm. H. Zimmer Generating Station 25.4 706,549 5,265 701,054 6,030 Transmission (a) 61,820 451 60,333 1,210 ---------- ------- ---------- ------- $1,054,455 $16,241 $1,039,907 $11,330 ========== ======= ========== ======= PSO: Oklaunion Generating Station (Unit No. 1) 15.6 $ 81,185 $ 817 $ 81,185 $ - ========== ======= ========== ======== SWEPCo: Dolet Hills Generating Station (Unit No. 1) 40.2 $ 231,442 $ 1,984 $ 230,971 $ 1,771 Flint Creek Generating Station (Unit No. 1) 50.0 82,899 852 81,895 286 Pirkey Generating Station (Unit No. 1) 85.9 437,069 435 434,960 1,777 ---------- ------- ---------- ------- $ 751,410 $ 3,271 $ 747,826 $ 3,834 ========== ======= ========== ======== WTU: Oklaunion Generating Station (Unit No. 1) 54.7 $ 277,624 $ 3,295 $ 281,777 $ - ========== ======= ========== ======== (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, 2000 1999 ---- ---- (in thousands) CPL $834,722 $758,460 CSPCo 389,558 361,113 PSO 33,669 36,374 SWEPCo 367,558 354,360 WTU 98,045 93,807
23. Related Party Transactions AEP System Power Pool APCo, CSPCo, I&M, KEPCo and OPCo are parties to the Interconnection Agreement, dated July 6, 1951, as amended (the Interconnection Agreement), defining how they share the costs and benefits associated with their generating plants. This sharing is based upon each company's "member-load-ratio," which is calculated monthly on the basis of each company's maximum peak demand in relation to the sum of the maximum peak demands of all five companies during the preceding 12 months. In addition, since 1995, APCo, CSPCo, I&M, KEPCo and OPCo have been parties to the AEP System Interim Allowance Agreement which provides, among other things, for the transfer of SO2 Allowances associated with transactions under the Interconnection Agreement. Power marketing and trading transactions (trading activities) are conducted by the AEP Power Pool and shared among the parties under the Interconnection Agreement. In addition, the AEP Power Pool enters into transactions for the purchase and sale of electricity options, futures and swaps, and for the forward purchase and sale of electricity outside of the AEP System's traditional marketing area. CPL, PSO, SWEPCo, WTU and AEP Service Corporation are parties to a Restated and Amended Operating Agreement originally dated as of January 1, 1997 (CSW Operating Agreement). The CSW Operating Agreement requires the operating companies of the west zone to maintain specified annual planning reserve margins and requires the subsidiaries that have capacity in excess of the required margins to make such capacity available for sale to other AEP subsidiaries as capacity commitments. The CSW Operating Agreement also delegates to AEP Service Corporation the authority to coordinate the acquisition, disposition, planning, design and construction of generating units and to supervise the operation and maintenance of a central control center. The CSW Operating Agreement has been accepted for filing and allowed to become effective by FERC. AEP's System Integration Agreement provides for the integration and coordination of AEP's east and west zone operating subsidiaries, joint dispatch of generation within the AEP System, and the distribution, between the two operating zones, of costs and benefits associated with the System's generating plants. It is designed to function as an umbrella agreement in addition to the AEP Interconnection Agreement and the CSW Operating Agreement, each of which will continue to control the distribution of costs and benefits within each zone. The following table shows the revenues derived from sales to the Pools and direct sales to affiliates for years ended December 31, 2000, 1999 and 1998:
APCo CSPCo I&M KPCo OPCo AEGCo Related Party Revenues (in thousands) 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 - -------- ------- -------- ------- -------- --------- Total Revenues $151,908 $43,241 $207,598 $39,355 $578,404 $227,983 ======== ======= ======== ======= ======== ======== 1999 Sales to East System Pool $41,869 $15,136 $50,624 $43,157 $337,699 $ - Direct Sales To East Affiliates 57,201 - - - 50,968 152,559 ------- ------- ------- ------- -------- -------- Total Revenues $99,070 $15,136 $50,624 $43,157 $388,667 $152,559 ======= ======= ======= ======= ======== ======== 1998 Sales to East System Pool $36,930 $20,128 $37,561 $43,543 $363,343 $ - Direct Sales To East Affiliates 56,753 - - - 55,167 153,537 ------- ------- ------- ------- -------- -------- Total Revenues $93,683 $20,128 $37,561 $43,543 $418,510 $153,537 ======= ======= ======= ======= ======== ========
CPL PSO SWEPCo WTU Related Party Revenues (in thousands) 2000 Sales to East System Pool $ - $ - $ - $ - Sales to West System Pool 23,421 7,323 5,546 194 Direct Sales To East Affiliates (3,348) (1,990) (3,008) (1,116) Direct Sales To West Affiliates 12,516 21,995 62,178 7,645 ------- ------- ------- ------- Total Revenues $32,589 $27,328 $64,716 $ 6,723 ======= ======= ======= ======= 1999 Sales to West System Pool $ 6,124 $ 3,097 $ 4,527 $ 401 Direct Sales To West Affiliates 7,470 7,968 49,542 2,576 ------- ------- ------- ------ Total Revenues $13,594 $11,065 $54,069 $2,977 ======= ======= ======= ====== 1998 Sales to West System Pool $ 7,853 $ 3,223 $ 5,660 $ 270 Direct Sales To West Affiliates 9,798 10,196 29,811 2,190 ------- ------- ------- ------ Total Revenues $17,651 $13,419 $35,471 $2,460 ======= ======= ======= ======
The following table shows the purchased power expense incurred from purchases from the Pools and affiliates for the years ended December 31, 2000, 1999, and 1998: APCo CSPCo I&M KPCo OPCo Related Party Purchases (in thousands) 2000 Purchases from East System Pool $355,305 $287,482 $106,644 $ 58,150 $50,339 Purchases from West System Pool 455 260 285 108 390 Direct Purchases from East Affiliates - - 158,537 69,446 - Direct Purchases from West Affiliates 14 8 9 3 12 -------- -------- -------- -------- ------- Total Purchases $355,774 $287,750 $265,475 $127,707 $50,741 ======== ======== ======== ======== ======= 1999 Purchases from East System Pool $130,991 $199,574 $112,350 $19,502 $ 20,864 Direct Purchases from East Affiliates - - 88,022 64,498 - -------- -------- -------- ------- --------- Total Purchases $130,991 $199,574 $200,372 $84,000 $ 20,864 ======== ======== ======== ======= ======== 1998 Purchases from East System Pool $180,762 $167,619 $125,240 $ 9,673 $ 18,211 Direct Purchases from East Affiliates - - 86,246 67,291 - -------- -------- -------- ------- --------- Total Purchases $180,762 $167,619 $211,486 $76,964 $ 18,211 ======== ======== ======== ======= ======== CPL PSO SWEPCo WTU Related Party Purchases (in thousands) 2000 Purchases from East System Pool $ - $20,100 $ - $ - Purchases from West System Pool 1,696 5,386 4,379 18,444 Direct Purchases from East Affiliates 251 2,117 - 71 Direct Purchases from West Affiliates 30,644 33,185 8,264 39,258 ------- ------- ------- ------- Total Purchases $32,591 $60,788 $12,643 $57,773 ======= ======= ======= ======= 1999 Purchases from West System Pool $ 895 $ 6,992 $1,295 $ 7,266 Direct Purchases from West Affiliates 15,778 27,627 6,256 19,325 ------- ------- ------ ------- Total Purchases $16,673 $34,619 $7,551 $26,591 ======= ======= ====== ======= 1998 Purchases from West System Pool $1,091 $ 5,022 $ 2,579 $ 8,314 Direct Purchases from West Affiliates 8,636 15,970 7,576 20,935 ------ ------- ------- ------- Total Purchases $9,727 $20,992 $10,155 $29,249 ====== ======= ======= =======
AEP System Transmission Pool APCo, CSPCo, I&M, KEPCo and OPCo are parties to the Transmission Agreement, dated April 1, 1984, as amended (the Transmission Agreement), defining how they share the costs associated with their relative ownership of the extra-high-voltage transmission system (facilities rated 345 kw and above) and certain facilities operated at lower voltages (138 kv and above). Like the Interconnection Agreement, this sharing is based upon each company's "member-load-ratio." The following table shows the net (credits) or charges allocated among the parties to the Transmission Agreement during the years ended December 31, 1998, 1999 and 2000: 1998 1999 2000 ---- ---- ---- (in thousands) APCo $ (2,400) $ (8,300) $ (3,400) CSPCo 35,600 39,000 38,300 I&M (44,100) (43,900) (43,800) KEPCo (6,000) (4,300) (6,000) OPCo 16,900 17,500 14,900 CPL, PSO, SWEPCo, WTU and AEP Service Corporation are parties to a Transmission Coordination Agreement originally dated as of January 1, 1997 (TCA). The TCA established a coordinating committee, which is charged with the responsibility of overseeing the coordinated planning of the transmission facilities of the west zone operating subsidiaries, including the performance of transmission planning studies, the interaction of such subsidiaries with independent system operators (ISO) and other regional bodies interested in transmission planning and compliance with the terms of the Open Access Transmission Tariff (OATT) filed with the FERC and the rules of the FERC relating to such tariff. Under the TCA, the west zone operating subsidiaries have delegated to AEP Service Corporation the responsibility of monitoring the reliability of their transmission systems and administering the OATT on their behalf. The TCA also provides for the allocation among the west zone operating subsidiaries of revenues collected for transmission and ancillary services provided under the OATT. In December 1999, the FERC approved the TCA filing based on the revised revenue allocation ratios effective as of January 1, 1997. In January 2000, the west zone operating companies settled among themselves, including interest, under the revised TCA. The following table shows the net (credits) or charges, excluding interest, allocated among the west zone operating companies during the years ended December 31, 1998, 1999 and 2000: 1998 1999 2000 ---- ---- ---- (in thousands) CPL $ - $ - $(15,498) WTU 1,139 (28) (23,443) SWEPCo 3,572 1,058 22,115 PSO (4,711) (1,030) 16,826 AEP's System Transmission Integration Agreement provides for the integration and coordination of the planning, operation and maintenance of the transmission facilities of AEP's east and west zone operating subsidiaries. Like the System Integration Agreement, the System Transmission Integration Agreement functions as an umbrella agreement in addition to the AEP Transmission Agreement and the Transmission Coordination Agreement. The System Transmission Integration Agreement contains two service schedules that govern: o The allocation of transmission costs and revenues. o The allocation of third-party transmission costs and revenues and System dispatch costs. The Transmission Integration Agreement anticipates that additional service schedules may be added as circumstances warrant. Unit Power Agreements and Other A unit power agreement between AEGCo and I&M (the I&M Power Agreement) provides for the sale by AEGCo to I&M of all the power (and the energy associated therewith) available to AEGCo at the Rockport Plant. I&M is obligated, whether or not power is available from AEGCo, to pay as a demand charge for the right to receive such power (and as an energy charge for any associated energy taken by I&M) such amounts, as when added to amounts received by AEGCo from any other sources, will be at least sufficient to enable AEGCo to pay all its operating and other expenses, including a rate of return on the common equity of AEGCo as approved by FERC, currently 12.16%. The I&M Power Agreement will continue in effect until the expiration of the lease term of Unit 2 of the Rockport Plant unless extended in specified circumstances. Pursuant to an assignment between I&M and KEPCo, and a unit power agreement between KEPCo and AEGCo, AEGCo sells KEPCo 30% of the power (and the energy associated therewith) available to AEGCo from both units of the Rockport Plant. KEPCo has agreed to pay to AEGCo in consideration for the right to receive such power the same amounts which I&M would have paid AEGCo under the terms of the I&M Power Agreement for such entitlement. The KEPCo unit power agreement expires on December 31, 2004. 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, 2000 1999 1998 ---- ---- ---- Company (in millions) I&M - revenues $23.5 $28.1 $24.8 AEGCo - expense 8.8 8.5 8.8 APCo - expense 7.8 10.5 8.5 OPCo - expense 6.9 9.1 7.5 American Electric Power Service Corporation (AEPSC) provides certain managerial and professional services to AEP System companies. The costs of the services are billed to its affiliated companies by AEPSC on a direct-charge basis, whenever possible, and on reasonable bases of proration for shared services. The billings for services are made at cost and include no compensation for the use of equity capital, which is furnished to AEPSC by AEP Co., Inc. Billings from AEPSC are capitalized or expensed depending on the nature of the services rendered. AEPSC and its billings are subject to the regulation of the SEC under the 1935 Act. M-26 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION, CONTINGENCIES AND OTHER MATTERS - ---------------------------------------------------------------------------- The following is a combined presentation of management's discussion and analysis of financial condition, contingencies and other matters for AEP and certain of its registrant subsidiaries. Management's discussion and analysis of results of operations for AEP and each of its subsidiary registrants is presented with their financial statements earlier in this document. The following is a list of sections of management's discussion and analysis of financial condition, contingencies and other matters and the registrant to which they apply: Financial Condition AEP, APCo, CPL, I&M, OPCo, SWEPCo Market Risks AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU Industry Restructuring AEP, APCo, CPL, CSPCo, I&M, OPCo, PSO, SWEPCo, WTU Litigation AEP, APCo, CPL, CSPCo, I&M, KPCo, OPCo, SWEPCo, WTU Environmental Concerns and Issues AEP, APCo, CPL, CSPCo, I&M, OPCo, SWEPCo Foreign Energy Delivery, AEP Worldwide Energy Investments and Other Business Operations Other Matters AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU Financial Condition - Affecting AEP, APCo, CPL, I&M, OPCo and SWEPCo The Cook Plant extended outage and related restart expenditures negatively affected AEP's 2000 earnings and cash flows and the write-off related to COLI and non-regulated subsidiaries further depressed earnings. Although the 2000 dividend payout ratio was 289%, it is expected that the ratio will improve significantly as a result of earnings growth in 2001. It has been a management objective to reduce the payout ratio by increasing earnings. Management expects to grow future earnings by growing the wholesale business and by controlling operations and maintenance costs. AEP's common equity to total capitalization, including long-term debt due within one year and short-term debt, decreased from 37% in 1999 to 34% in 2000. Preferred stock at 1% remained unchanged. Long-term debt decreased from 50% to 47%, while short-term debt increased from 12% to 18%. AEP's intention is to maintain flexibility during corporate separation by issuing floating rate debt. In 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. Sales of common stock and/or equity linked securities may be necessary in the future to support AEP's plan to grow the business. Expenditures by the AEP System for domestic electric utility construction are estimated to be $6 billion for the next three years. Approximately 70% of those construction expenditures are expected to be financed by internally generated funds. Construction expenditures for the registrant subsidiaries for the next three years excluding AFUDC are: Construction Projected Expenditures Construction Financed with Expenditures Internal Funds (in millions) APCo $1,122.8 79% I&M 427.2 ALL OPCo 1,044.5 ALL CPL 745.1 NONE SWEPCo 405.6 70% The year-end ratings of the subsidiaries' first mortgage bonds are listed in the following table: Company Moody's S&P Fitch APCo A3 A A- CSPCo A3 A- A I&M Baa1 A- BBB+ KPCo Baa1 A- BBB+ OPCo A3 A- A- CPL A3 A- A PSO A1 A A+ SWEPCo A1 A A+ WTU A2 A- A The ratings at the end of the year for senior unsecured debt issued by the subsidiaries are listed in the following table: Company Moody's S&P Fitch AEP Resources* Baa2 BBB+ BBB+ APCo Baa1 BBB+ BBB+ CSPCo Baa1 BBB+ A- I&M Baa2 BBB+ BBB KPCo Baa2 BBB+ BBB OPCo Baa1 BBB+ BBB+ CPL Baa1 BBB+ A- PSO A2 BBB+ A SWEPCo A2 BBB+ A WTU A3 BBB+ - o The rating is for a series of senior notes issued with a Support Agreement from AEP. Financing Activity Debt was issued in 2000 for the funding of debt maturities, for construction programs and for the growth of the wholesale business. AEP and its subsidiaries issued $1.1 billion principal amount of long-term obligations in 2000 at variable interest rates with due dates ranging from 2001 to 2007. The principal amount of long-term debt retirements, including maturities, totaled $1.6 billion with interest rates ranging from 5.25% to 9.6%. The principal amount of long-term obligations issued and retired in 2000 by the registrant subsidiaries was: Issuance Retirements (in thousands) APCo $ 75,000 $136,000 I&M 200,000 148,000 OPCo 75,000 32,102 CPL 150,000 150,000 SWEPCo 150,000 45,595 The domestic electric utility subsidiaries generally issue short-term debt to provide for interim financing of capital expenditures that exceed internally generated funds. They periodically reduce their outstanding short-term debt through issuances of long-term debt and additional capital contributions by the parent company. The sources of funds available to the parent company, AEP, are dividends from its subsidiaries, short-term and long-term borrowings and proceeds from the issuance of common stock. The subsidiaries formed to pursue worldwide electric and gas opportunities use short-term debt and capital contributions from the parent company for interim financing of working capital and acquisitions. Short-term debt is replaced with long-term debt when financial market conditions are favorable. Some acquisitions of existing business entities include the assumption of their outstanding debt. The AEP System uses short-term debt, primarily commercial paper, to meet fluctuations in working capital requirements and other interim capital needs. AEP has established a system money pool to meet the short-term borrowings for certain of its subsidiaries, including AEGCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU. In January 2001 APCo became a participant in AEP's money pool and retired all outstanding short-term debt. 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, 2000, AEP had back up credit facilities totaling $3.5 billion to support its commercial paper program. At December 31, 2000, AEP had $2.7 billion outstanding in short-term borrowings. The maximum amount of short-term borrowings outstanding during the year, which had a weighted average interest rate for the year of 7.5%, was $2.7 billion during December 2000. AEP Credit purchases, without recourse, the accounts receivable of most of the domestic utility operating companies and certain non-affiliated electric utility companies. The sale of accounts receivable provides the domestic electric utility operating companies with cash immediately, thereby reducing working capital needs and revenue requirements. In addition, AEP Credit's capital structure contains greater leverage than that of the domestic electric utility operating companies, so cost of capital is lowered. AEP Credit issues commercial paper to meet its financing needs. At December 31, 2000, AEP Credit had a $2.0 billion unsecured back up credit facility to support its commercial paper program, which had $1.2 billion outstanding. The maximum amount of such commercial paper outstanding during the year, which had a weighted average interest rate of 6.6%, was $1.5 billion during September 2000. Market Risks - Affecting AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU AEP as a major power producer and a trader of wholesale electricity and natural gas has certain market risks inherent in its business activities. The trading of electricity and natural gas and related financial derivative instruments exposes AEP to market risk. Market risk represents the risk of loss that may impact due to changes in commodity market prices and rates. Policies and procedures have been established to identify, assess, and manage market risk exposures including the use of a risk measurement model which calculates Value at Risk (VaR). 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. Throughout the year ending December 31, 2000 the average, high, and low VaRs in the wholesale electricity and gas trading portfolio were $10 million, $32 million, and $1 million, respectively. The average, high, and low VaRs for the year ending December 31, 1999 were $4 million, $8 million, and $1 million, respectively. Based on this VaR analysis, at December 31, 2000 a near term typical change in commodity prices is not expected to have a material effect on AEP's results of operations, cash flows or financial condition. The following table shows the high and average U.S. electricity market risk as measured by VaR allocated to the AEP registrant subsidiaries based upon the AEP System's trading activities in the U.S. Low VaR is excluded because all companies are under $1 million. VaR for Registrant Subsidiaries: December 31, 2000 1999 ---- ---- High Average High Average (in millions) APCo $2 $6 $1 $2 CPL 1 4 - - CSPCo 1 3 1 1 I&M 1 4 1 2 KPCo - 1 - 1 OPCo 2 5 1 2 PSO 1 3 - - SWEPCo 1 4 - - WTU - 1 - - Investments in foreign ventures expose AEP to risk of foreign currency fluctuations. AEP's exposure to changes in foreign currency exchange rates related to these foreign ventures and investments is not expected to be significant for the foreseeable future. AEP is exposed to changes in interest rates primarily due to short-and long-term borrowings to fund its business operations. AEP measures interest rate market risk exposure utilizing a VaR model. 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 $998 million at December 31, 2000 and $966 million at December 31, 1999. 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, 2000 1999 ---- ---- (in millions) Company AEGCo $ 4 $ 4 APCo 149 144 CPL 135 131 CSPCo 84 81 I&M 129 125 KPCo 31 30 OPCo 112 109 PSO 44 42 SWEPCo 60 58 WTU 24 23 AEP and its registrant subsidiaries would not expect to liquidate its entire debt portfolio in a one year holding period. Therefore, a near term change in interest rates should not materially affect results of operations or the consolidated financial position of AEP and its registrant subsidiaries. AEP is currently utilizing interest rate swaps as a hedge to manage its exposure to interest rate fluctuations in the U.K. and Australia. AEP has investments in debt and equity securities which are held in nuclear trust funds. The trust investments and their fair value are discussed in Note 15 of the Notes to Consolidated Financial Statements. Instruments in the 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 are reflected in a corresponding decommissioning liability. Any differences between the trust fund assets and the ultimate liability should be recoverable from ratepayers. AEGCo is not exposed to risk from changes in interest rates on short-term and long-term borrowings used to finance oper-ations since financing costs are recovered through the unit power agreements. Inflation affects the AEP's System's cost of replacing utility plant and the cost of operating and maintaining its plant. The rate-making process limits recovery to the historical cost of assets, resulting in economic losses when the effects of inflation are not recovered from customers on a timely basis. However, economic gains that result from the repayment of long-term debt with inflated dollars partly offset such losses. Industry Restructuring In 2000 California's deregulated energy market suffered problems including high energy prices, short energy supply, and financial difficulties for retail energy suppliers whose prices to customers are controlled. This energy crisis has highlighted the importance of risk management and has contributed to certain state regulatory and legislative actions which could delay the start of customer choice and the transition to competitive, market based pricing for retail electricity supply in some of the states in which the AEP System companies operate. Seven of the eleven state retail jurisdictions in which the domestic electric utility companies operate have enacted restructuring legislation. In general, the legislation provides for a transition from cost-based regulation of bundled electric service to customer choice and market pricing for the supply of electricity. As legislative and regulatory proceedings evolve, six of the electric operating companies (APCo, CPL, CSPCo, OPCo, SWEPCo and WTU) doing business in five of the seven states that have passed restructuring legislation have discontinued the application of SFAS 71 regulatory accounting for generation. The seven states in various stages of restructuring to transition generation to market based pricing are Arkansas, Michigan, Ohio, Oklahoma, Texas, Virginia, and West Virginia. PSO and I&M have not discontinued regulatory accounting for their generation business in Oklahoma and Michigan, respectively, pending the implementation of the legislation. The following is a summary of 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 the AEP System's seven state regulatory jurisdictions affected by restructuring legislation. Ohio Restructuring - Affecting AEP, CSPCo and OPCo Effective January 1, 2001, customer choice of electricity supplier began under the Ohio Act. In February 2001, one supplier announced its plan to offer service to CSPCo's residential customers. Currently for residential customers of OPCo, no alternative suppliers have registered with the PUCO as required by the Ohio Act. Two alternative suppliers have been approved to compete for CSPCo's and OPCo's commercial and industrial customers. Presently, customers continue to be served by CSPCo and OPCo with a legislatively required residential rate reduction of 5% for the generation portion of rates and a freezing of generation rates including fuel rates starting on January 1, 2001. The Ohio Act provides for a five-year transition period to move from cost based rates to market pricing for generation services. It granted the PUCO broad oversight responsibility for promulgation of rules for competitive retail electric generation service, approval of a transition plan for each electric utility company and addressing certain major transition issues including unbundling of rates and the recovery of stranded costs including regulatory assets and transition costs. The Ohio Act also provides for a reduction in property tax assessments, the imposition of replacement franchise and income taxes, and the replacement of a gross receipts tax with a KWH based excise tax. The property tax assessment percentage on generation property was lowered from 100% to 25% of value effective January 1, 2001 and Ohio electric utilities will become subject to the Ohio Corporate Franchise Tax and municipal income taxes on January 1, 2002. The last year for which Ohio electric utilities will pay the excise tax based on gross receipts is the tax year ending April 30, 2002. As of May 1, 2001 electric distribution companies will be subject to an excise tax based on KWH sold to Ohio customers. The gross receipts tax is paid at the beginning of the tax year (May 1), deferred by CSPCo and OPCo as a prepaid expense and amortized to expense during the tax year pursuant to the tax law whereby the payment of the tax results in the privilege to conduct business in the year following the payment of the tax. As a result a duplicate tax will be expensed from May 1, 2001 through April 30, 2002 adding approximately $90 million to AEP consolidated tax expense ($40 million for CSPCo and $50 million for OPCo) during that period. Unless the companies can recover the duplicate amount from ratepayers it will negatively impact results of operations. On September 28, 2000, the PUCO approved, with minor modifications, a stipulation agreement between CSPCo, OPCo, the PUCO staff, the Ohio Consumers' Counsel and other concerned parties regarding transition plans filed by CSPCo and OPCo. The key provisions of this stipulation agreement are: o Recovery of generation-related regulatory assets at December 31, 2000 over seven years for OPCo ($518 million) and over eight years for CSPCo ($248 million) through frozen transition rates for the first five years of the recovery period and a wires charge for the remaining years. o A shopping incentive (a price credit) of 2.5 mills per KWH for the first 25% of CSPCo residential customers that switch suppliers. There is no shopping incentive for OPCo customers. o The absorption of $40 million by CSPCo and OPCo ($20 million per company) of consumer education, implementation and transition plan filing costs with deferral of the remaining costs, plus a carrying charge, as a regulatory asset for recovery in future distribution rates. o CSPCo and OPCo will make available a fund of up to $10 million to reimburse customers who choose to purchase their power from another company for certain transmission charges imposed by PJM and/or a Midwest ISO on generation originating in the Midwest ISO or PJM areas. o The statutory 5% reduction in the generation component of residential tariffs will remain in effect for the entire five year transition period. o The companies' request for a $90 million ($40 million for CSPCo and $50 million for OPCo) gross receipts tax rider to recover the duplicate gross receipts KWH based excise tax would be considered separately by the PUCO. The approved stipulation agreement also accepted the following provisions contained in CSPCo's and OPCo's filed transition plans: o a corporate separation plan to segregate generation, transmission and distribution assets into separate legal entities, and o a plan for independent operation of transmission facilities. The gross receipts tax issue was considered by the PUCO in hearings held in June 2000. In the September 28, 2000 order approving the stipulation agreement, the PUCO determined that there was no duplicate tax overlap period and denied the request for a $90 million ($40 million for CSPCo and $50 million for OPCo) gross receipts tax rider. CSPCo's and OPCo's request for rehearing of the gross receipts tax issue was denied. An appeal of this issue to the Ohio Supreme Court has been filed. Unless this issue is resolved in the companies' favor, it will have an adverse effect on future results of operations and financial position. One of the intervenors at the hearings for approval of the settlement agreement (whose request for rehearing was denied by the PUCO) has filed with the Ohio Supreme Court for review of the settlement agreement including recovery of regulatory assets. Management is unable to predict the outcome of litigation but the resolution of this matter could negatively impact results of operations. Beginning January 1, 2001, CSPCo's and OPCo's fuel costs will not be subject to PUCO fuel recovery proceedings. Deferred fuel costs at December 31, 2000 which represent under or over recoveries were one of the items included in the PUCO's final determination of net regulatory assets to be collected (recovered) during the transition period. The elimination of fuel clause recoveries in 2001 in Ohio will subject AEP, CSPCo and OPCo to the risk of fuel market price increases and could adversely affect their future results of operations and cash flows. CSPCo and OPCo Discontinue Application of SFAS 71 Regulatory Accounting for the Ohio Jurisdiction In September 2000 CSPCo and OPCo discontinued the application of SFAS 71 for their Ohio retail jurisdictional generation business since generation is no longer cost-based regulated in the Ohio jurisdiction and management was able to determine their transition rates and wires charges. The discontinuance in the Ohio jurisdiction was possible as a result of the PUCO's September 28, 2000 approval of the stipulation agreement which established rates, wires charges and net regulatory asset recovery procedures during the transition to market rates. CSPCo's and OPCo's discontinuance of SFAS 71 for generation resulted in after tax extraordinary losses in the third quarter of 2000 of $25 million and $19 million, respectively, due to certain unrecoverable generation-related regulatory assets and transition expenses. Management believes that substantially all of the remaining net regulatory assets related to the Ohio generation business will be recovered under the PUCO's September 28, 2000 order. Therefore, under the provisions of EITF 97-4, CSPCo's and OPCo's generation-related recoverable net regulatory assets were transferred to the transmission and distribution portion of the business and will be amortized as they are recovered through transition rates to customers. CSPCo and OPCo performed an accounting impairment analysis on their generating assets under SFAS 121 as required when discontinuing the application of SFAS 71 and concluded there was no impairment of generation assets. Virginia Restructuring - Affecting AEP and APCo In Virginia, a restructuring law provides for a transition to choice of electricity supplier for retail customers beginning on January 1, 2002. In February 2001, restructuring revision legislation was approved by the Virginia Legislature which could modify the terms of restructuring. Presently, the transition period is to be completed, subject to a finding by the Virginia SCC that an effective competitive market exists by January 1, 2004 but no later than January 1, 2005. The restructuring law also 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. The restructuring law provides for the establishment of capped rates prior to January 1, 2001 based either on a request by APCo for a change in rates prior to January 1, 2001 or on the rates in effect at July 1, 1999 if no rate change request is made and the establishment of a wires charge by the fourth quarter of 2001. APCo did not request new rates; therefore, its current rates are the capped rates. In the third quarter of 2000, the Virginia SCC directed APCo to file a cost of service study using 1999 as a test year to review the reasonableness of APCo's capped rates. The cost of service study was filed on January 3, 2001. In the opinion of APCo's Virginia counsel, Virginia's restructuring law does not permit the Virginia SCC to change rates for the transition period except for changes in the fuel factor, changes in state gross receipts taxes, or to address the utility's financial distress. However, if the Virginia SCC were to reduce APCo's capped rates or deny recovery of regulatory assets, it would adversely affect results of operations if such action is ultimately determined to be legal. The Virginia restructuring law also requires filings to be made that outline the functional separation of generation from transmission and distribution and a rate unbundling plan. On January 3, 2001, APCo filed its corporate separation plan and rate unbundling plan with the Virginia SCC which is based on the most recent rate case test year (1996). See Note 7 of the Notes to Consolidated Financial Statements for a discussion of AEP's corporate separation plan filed with the SEC. West Virginia Restructuring - Affecting AEP and APCo On January 28, 2000, the WVPSC issued an order approving an electricity restructuring plan for WV. On March 11, 2000, the WV Legislature approved the restructuring plan by joint resolution. The joint resolution provides that the WVPSC cannot implement the plan until the legislature makes necessary tax law changes to preserve the revenues of the state and local governments. The Joint Committee on Government and Finance of the WV Legislature hired a consultant to study and issue a report on the tax changes required to implement electric restructuring. Moreover, the committee also hired a consultant to study and issue a report on the electric restructuring plan in light of events occurring in California. The WV Legislature is not expected to consider these reports until the 2002 Legislative Session since the 2001 Legislative Session ends in April 2001. Since the WV Legislature has not yet passed the required tax law changes, the restructuring plan has not become effective. AEP subsidiaries, APCo and WPCo, provide electric service in WV. The provisions of the restructuring plan provide for customer choice to begin after all necessary rules are in place (the "starting date"); deregulation of generation assets on the starting date; functional separation of the generation, transmission and distribution businesses on the starting date and their legal corporate separation no later than January 1, 2005; a transition period of up to 13 years, during which the incumbent utility must provide default service for customers who do not change suppliers unless an alternative default supplier is selected through a WVPSC-sponsored bidding process; capped and fixed rates for the 13 year transition period as discussed below; deregulation of metering and billing; a 0.5 mills per KWH wires charge applicable to all retail customers for a 10-year period commencing with the starting date intended to provide for recovery of any stranded cost including net regulatory assets; establishment of a rate stabilization deferred liability balance of $81 million ($76 million by APCo and $5 million by WPCo) by the end of year ten of the transition period to be used as determined by the WVPSC to offset market prices paid in the eleventh, twelfth, and thirteenth year of the transition period by residential and small commercial customers that do not choose an alternative supplier. Default rates for residential and small commercial customers are capped for four years after the starting date and then increase as specified in the plan for the next six years. In years eleven, twelve and thirteen of the transition period, the power supply rate shall equal the market price of comparable power. Default rates for industrial and large commercial customers are discounted by 1% for four and a half years, beginning July 1, 2000, and then increased at pre-defined levels for the next three years. After seven years the power supply rate for industrial and large commercial customers will be market based. APCo's Joint Stipulation agreement, discussed in Note 5 of the Notes to Consolidated Financial Statements, which was approved by the WVPSC on June 2, 2000 in connection with a base rate filing, also provides additional mechanisms to recover regulatory assets. APCo Discontinues Application of SFAS 71 Regulatory Accounting In June 2000 APCo discontinued the application of SFAS 71 for its Virginia and WV retail jurisdictional portions of its generation business since generation is no longer considered to be cost-based regulated in those jurisdictions and management was able to determine APCo's transition rates and wires charges. The discontinuance in the WV jurisdiction was made possible by the June 2, 2000 approval of the Joint Stipulation which established rates, wires charges and regulatory asset recovery procedures for the transition period to market rates which was determined to be probable. APCo was also able to discontinue application of SFAS 71 for the generation portion of its Virginia retail jurisdiction after management decided that APCo would not request capped rates different from its current rates. The existence of effective restructuring legislation in Virginia and the probability that the WV legislation would become effective with the expected probable passage of required enabling tax legislation in 2001 supported management's decision in 2000 to discontinue SFAS 71 regulatory accounting for APCo's electricity generation and supply business. APCo's discontinuance of SFAS 71 for generation resulted in an after tax extraordinary gain, in the second quarter of 2000, of $9 million. Management believes that it is probable that substantially all net regulatory assets related to the Virginia and WV generation business will be recovered. Therefore, under the provisions of EITF 97-4, APCo's generation-related net regulatory assets were transferred to the distribution portion of the business and are being amortized as they are recovered through charges to regulated distribution customers. As required by SFAS 101 when discontinuing SFAS 71 regulatory accounting, APCo performed an accounting impairment analysis on its generating assets under SFAS 121 and concluded that there was no accounting impairment of generation assets. The recent energy crisis in California, discussed above, may be having a chilling effect on efforts to enact the required tax change legislation in West Virginia. The WV Legislature could decide not to enact the required tax changes, thereby, effectively continuing cost based rate regulation in West Virginia or it could modify the restructuring plan. Modifications in the restructuring plan could adversely affect future results of operations if they were to occur. Management is carefully monitoring the situation in West Virginia and continues to work with all concerned parties to get approval to successfully transition our generation business in West Virginia. Failure to pass the required enabling tax changes could ultimately require APCo to re-instate regulatory accounting principles under SFAS 71 for its generation operations in West Virginia. Arkansas Restructuring - Affecting AEP and SWEPCo In 1999 legislation was enacted in Arkansas that will ultimately restructure the electric utility industry. Its major provisions are: o retail competition begins January 1, 2002 but can be delayed until as late as June 30, 2003 by the Arkansas Commission; o transmission facilities must be operated by an ISO if owned by a company which also owns generation assets; o rates will be frozen for one to three years; o market power issues will be addressed by the Arkansas Commission; and o an annual progress report to the Arkansas General Assembly on the development of competition in electric markets and its impact on retail customers is required. In November 2000 the Arkansas Commission filed its annual progress report with the Arkansas General Assembly recommending a delay in the start date of retail competition to a date between October 1, 2003 and October 1, 2005. The report also asks the Arkansas General Assembly to delegate authority to the Arkansas Commission to determine the appropriate retail competition start date within the approved time frame. In February 2001 the Arkansas General Assembly passed legislation that was signed into law by the Governor that changes the date of electric retail competition to October 1, 2003, and provides the Arkansas Commission with the authority to delay that date for up to two years. Texas Restructuring - Affecting AEP, CPL, SWEPCo and WTU In June 1999 Texas restructuring legislation was signed into law which, among other things: o gives Texas customers of investor-owned utilities the opportunity to choose their electricity provider beginning January 1, 2002; o provides for the recovery of regulatory assets and of other stranded costs through securitization and non-bypassable wires charges; o requires reductions in NOx and sulfur dioxide emissions; o provides for a rate freeze until January 1, 2002 followed by a 6% rate reduction for residential and small commercial customers and a number of customer protections; o provides for an earnings test for each of the three years of the rate freeze period (1999 through 2001) which will reduce stranded cost recoveries or if there is no stranded cost provides for a refund or their use to fund certain capital expenditures in the amount of the excess earnings; o requires each utility to structurally unbundle into a retail electric provider, a power generation company and a transmission and distribution utility; o provides for certain limits for ownership and control of generating capacity by companies; o provides for elimination of the fuel clause reconciliation process beginning January 1, 2002; and o provides for a 2004 true-up proceeding to determine recovery of stranded costs including final fuel recovery balances, net regulatory assets, certain environmental costs, accumulated excess earnings and other issues. Under the Texas Legislation, delivery of electricity will continue to be the responsibility of the local electric transmission and distribution utility company at regulated prices. Each electric utility was required to submit a plan to structurally unbundle its business activities into a retail electric provider, a power generation company, and a transmission and distribution utility. In May 2000 CPL, SWEPCo and WTU filed a revised business separation plan that the PUCT approved on July 7, 2000 in an interim order. The revised business separation plans provided for CPL and WTU, which operate in Texas only, to establish separate companies and divide their integrated utility operations and assets into a power generation company, a transmission and distribution utility and a retail electric provider. SWEPCo will separate its Texas jurisdictional transmission and distribution assets and operations into a new Texas regulated transmission and distribution subsidiary. In addition, a retail electric provider will be formed by SWEPCo to provide retail electric service to SWEPCo's Texas jurisdictional customers. Under the Texas Legislation, electric utilities are allowed, with the approval of the PUCT, to recover stranded generation costs including generation-related regulatory assets that may not be recoverable in a future competitive market. The approved stranded costs can be refinanced through securitization, which is a financing structure designed to provide lower financing costs than are available through conventional financings. Lower financing costs are achieved through the issuance of securitization bonds at a lower interest rate to finance 100% of the costs pursuant to a state pledge to ensure recovery of the bond principal and financing costs through a non-bypassable rate surcharge by the regulated transmission and distribution utility over the life of the securitization bonds. In 1999 CPL 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 permitting CPL to securitize approximately $764 million of net regulatory assets. The PUCT's order authorized issuance of up to $797 million of securitization bonds including the $764 million for recovery of net generation-related regulatory assets and $33 million for other qualified refinancing costs. The $764 million for recovery of net generation-related regulatory assets reflects the recovery of $949 million of generation-related regulatory assets offset by $185 million of customer benefits associated with accumulated deferred income taxes. CPL had previously proposed in its filing to flow these benefits back to customers over the 14-year term of the securitization bonds. On April 11, 2000, four parties appealed the PUCT's securitization order to the Travis County District Court. In July 2000 the Travis County District Court upheld the PUCT's securitization order. The securitization order is being appealed to the Supreme Court of Texas. One of these appeals challenges CPL's ability to recover securitization charges under the Texas Constitution. CPL will not be able to issue the securitization bonds until these appeals are resolved. The remaining regulatory assets of $206 million originally included by CPL in its 1999 securitization request were included in a March 2000 filing with the PUCT, requesting recovery of an additional $1.1 billion of stranded costs. The March 2000 filing of $1.1 billion included recovery of approximately $800 million of STP costs included in property, plant and equipment-electric on AEP's Consolidated Balance Sheets and in electric utility plant-production on CPL's Consolidated Balance Sheets. These STP costs had previously been identified as excess cost over market (ECOM) by the PUCT for regulatory purposes and were earning a lower return and were being amortized on an accelerated basis for rate-making purposes in Texas. The March 2000 filing will determine the initial amount of stranded costs in addition to the securitized regulatory assets to be recovered beginning January 1, 2002. CPL submitted a revised estimate of stranded costs on October 2, 2000 using assumptions developed in generic proceedings by the PUCT and an administrative model developed by the PUCT staff that reduced the amount of the initial stranded cost estimate to $361 million from the $1.1 billion requested by CPL. CPL subsequently agreed to accept adjustments proposed by intervenors that reduced ECOM to approximately $230 million. Hearings on CPL's requested ECOM were held in October 2000. In February 2001 the PUCT issued an interim decision determining an initial amount of CPL ECOM or stranded costs of negative $580 million. The decision indicated that CPL's costs were below market after securitization of regulatory assets. Management does not agree with the critical inputs to this model. Management believes CPL has a positive stranded cost exclusive of securitized regulatory assets. The final amount of CPL's stranded costs including regulatory assets and ECOM will be established by the PUCT in the legislatively required 2004 true-up proceeding. If CPL's total stranded costs determined in the 2004 true-up are less than the amount of securitized regulatory assets, the PUCT can implement an offsetting credit to transmission and distribution rates. The PUCT ruled that prior to the 2004 true-up proceeding, no adjustments would be made to the amount of regulatory costs authorized by the PUCT to be securitized. However, the PUCT also ruled that excess earnings for the period 1999-2001 should be refunded through transmission and distribution rates to the extent of any over-mitigation of stranded costs represented by negative ECOM. In the event that CPL will be required to refund excess earnings in the future instead of applying them to reduce ECOM or regulatory assets, it will adversely affect future cash flow but not results of operations since excess earnings for 1999 and 2000 were accrued and expensed in 1999 and 2000. The Texas Legislation allows for several alternative methods to be used to value stranded costs in the final 2004 true-up proceeding including the sale or exchange of generation assets, the issuance of power generation company stock to the public or the use of PUCT staff's ECOM model. To the extent that the final 2004 true-up proceeding determines that CPL should recover additional stranded costs, the total amount recoverable can be securitized. The Texas Legislation provides that each year during the 1999 through 2001 rate freeze period, electric utilities are subject to an earnings test. For electric utilities with stranded costs, such as CPL, any earnings in excess of the most recently approved cost of capital in its last rate case must be applied to reduce stranded costs. Utilities without stranded costs, such as SWEPCo and WTU, must either flow such excess earnings amounts back to customers or make capital expenditures to improve transmission or distribution facilities or to improve air quality. The Texas Legislation requires PUCT approval of the annual earnings test calculation. The 1999 earnings test reports filed by CPL, SWEPCo and WTU showed excess earnings of $21 million, $1 million and zero, respectively. The PUCT staff issued its report on the excess earnings calculations filed by CPL, SWEPCo and WTU and calculated the excess earnings amounts to be $41 million, $3 million and $11 million for CPL, SWEPCo and WTU, respectively. The Office of Public Utility Counsel also filed exceptions to the companies' earnings reports. Several issues were resolved via settlement and the remaining open issues were submitted to the PUCT. A final order was issued by the PUCT in February 2001 and adjustments to the accrued 1999 and 2000 excess earnings were recorded in results of operations in the fourth quarter of 2000. After adjustments the accruals for 1999 excess earnings for CPL and WTU were $24 million and $1 million, respectively. CPL and WTU also recorded an estimated provision for excess 2000 earnings of $16 million and $14 million, respectively. A Texas settlement agreement in connection with the AEP and CSW merger permits CPL to apply for regulatory purposes up to $20 million of STP ECOM plant assets a year in 2000 and 2001 to reduce excess earnings, if any. For book and financial reporting purposes, STP ECOM plant assets will be depreciated in accordance with GAAP, on a systematic and rational basis unless impaired. CPL will establish a regulatory liability or reduce regulatory assets by a charge to earnings to the extent excess earnings exceed $20 million in 2000 and 2001. Beginning January 1, 2002, fuel costs will not be subject to PUCT fuel reconciliation proceedings. Consequently, CPL, SWEPCo and WTU will file a final fuel reconciliation with the PUCT to reconcile their fuel costs through the period ending December 31, 2001. Fuel costs have been reconciled by CPL, SWEPCo and WTU through June 30, 1998, December 31, 1999 and June 30, 1997, respectively. WTU is currently reconciling its fuel through June 2000. See discussion in Note 5 of the Notes to Consolidated Financial Statements. At December 31, 2000, CPL's, SWEPCo's and WTU's Texas jurisdictional unrecovered deferred fuel balances were $127 million, $20 million and $59 million, respectively. Final unrecovered deferred fuel balances at December 31, 2001 will be included in each company's 2004 true-up proceeding. If the final fuel balances or any amount incurred but not yet reconciled were not recovered, they could have a negative impact on results of operations. The elimination of the fuel clause recoveries in 2002 in Texas will subject AEP, CPL, SWEPCo and WTU to greater risks of fuel market price increases and could adversely affect future results of operations beginning in 2002. The affiliated retail electric provider of CPL, SWEPCo and WTU will be required to offer residential and small commercial customers (with a peak usage of less than 1000 KW) a rate 6% below rates in effect on January 1, 1999 adjusted for any changes in fuel cost recovery factors since January 1, 1999 (price to beat). The price to beat must be offered to residential and small commercial customers until January 1, 2007. Customers with a peak usage of more than 1000 KW are subject to market rates. The Texas restructuring legislation provides for the price to beat to be adjusted up to two times annually to reflect significant changes in fuel and purchased energy costs. CPL, SWEPCo and WTU Discontinue Application of SFAS 71 Regulatory Accounting in Arkansas and Texas The financial statements of CPL, SWEPCo and WTU have historically reflected the economic effects of regulation by applying the requirements of SFAS 71. As a result of the scheduled deregulation of generation in Arkansas and Texas, the application of SFAS 71 for the generation portion of the business in those states was discontinued in the third quarter of 1999. Under the provisions of EITF 97-4, CPL's generation-related net regulatory assets were transferred to the distribution portion of the business and will be amortized as they are recovered through wires charges to customers. Management believes that substantially all of CPL's generation-related regulatory assets will be recovered under the Texas Legislation. CPL's recovery of generation-related regulatory assets and stranded costs are subject to a final determination by the PUCT in 2004. If future events were to make the recovery through securitization of CPL's generation-related regulatory assets no longer probable, CPL would write-off the portion of such regulatory assets deemed unrecoverable as a non-cash extraordinary charge to earnings. The Texas Legislation provides that all finally determined stranded costs will be recovered. Since SWEPCo and WTU are not expected to have net stranded costs, all Arkansas and Texas jurisdictional generation-related net regulatory assets were written off as non-recoverable in 1999 when they discontinued application of SFAS 71 regulatory accounting. As required by SFAS 101 when SFAS 71 is discontinued, an accounting impairment analysis for generation assets under SFAS 121 was completed for CPL, SWEPCo and WTU. The analysis showed that there was no accounting impairment of generation assets when the application of SFAS 71 was discontinued. CPL, SWEPCo and WTU will test their generation assets for impairment under SFAS 121 if circumstances change. Management believes that on a discounted basis CPL's generation business net cash flows will likely be less than its generating assets' net book value and together with its generation-related regulatory assets should create a recoverable stranded cost for regulatory purposes under the Texas Legislation. Therefore, management continues to carry on the balance sheet at December 31, 2000, $953 million of generation-related regulatory assets already approved for securitization and $195 million of net generation-related regulatory assets pending approval for securitization in Texas. A final determination of whether they will be securitized and recovered will be made as part of the 2004 true-up proceeding. CPL, SWEPCo, and WTU continue to analyze the impact of electric utility industry restructuring legislation on their Arkansas and Texas electric operations. Although management believes that the Texas Legislation provides for full recovery of stranded costs and that the companies do not have a recordable accounting impairment, a final determination of whether CPL will experience an accounting loss or whether SWEPCo and WTU will experience any additional accounting loss from an inability to recover generation-related regulatory assets and other restructuring related costs in Texas and Arkansas cannot be made until such time as the regulatory process is complete following the 2004 true-up proceeding in Texas and a determination by the Arkansas Commission. In the event CPL, SWEPCo, and WTU are unable after the 2004 true-up proceeding and after the Arkansas Commission proceedings to recover all or a portion of their generation-related regulatory assets, stranded costs and other restructuring related costs, it could have a material adverse effect on results of operations, cash flows and possibly financial condition. Although Arkansas' delay of retail competition may be having a negative effect on the progress of efforts to transition SWEPCo's generation in Arkansas to market based pricing of electricity, it appears that Texas is moving forward as planned. Management is carefully monitoring the situation in Arkansas and is working with all concerned parties to prudently quicken the pace of the transition. However, changes could occur due to concerns stemming from the California energy crisis and other events which could adversely affect future results of operations in Arkansas and possibly Texas. Michigan Restructuring - Affecting AEP and I&M On June 5, 2000, the Michigan Legislation became law. Its major provisions, which were effective immediately, applied only to electric utilities with one million or more retail customers. I&M, AEP's electric operating subsidiary doing business in Michigan, has less than one million customers in Michigan. Consequently, I&M was not immediately required to comply with the Michigan Legislation. The Michigan Legislation gives the MPSC broad power to issue orders to implement retail customer choice of electric supplier no later than January 1, 2002 including recovery of regulatory assets and stranded costs. On October 2, 2000, I&M filed a restructuring implementation plan as required by a MPSC order. The plan identifies I&M's proposal to file with the MPSC on June 5, 2001 its unbundled rates, open access tariffs, terms of service and supporting schedules. Described in the plan are I&M's intentions and preparation for competition related to supplier transactions, customer transactions, rate unbundling, education programs, and regional transmission organization. The plan contains a proposed methodology to determine stranded costs and implementation costs and requests the continuation of a wires charge for recovery of nuclear decommissioning costs. Approval of the restructuring implementation plan is pending before the MPSC. Management has concluded that as of December 31, 2000 the requirements to apply SFAS 71 continue to be met since I&M's rates for generation in Michigan will continue to be cost-based regulated until the MPSC approves rates and wires charges in 2001. The establishment of rates and wires charges under a MPSC approved transition plan will enable management to determine the ability to recover stranded costs including regulatory assets and other implementation costs, a requirement of EITF 97-4 to discontinue the application of SFAS 71. Upon the discontinuance of SFAS 71, I&M will, if necessary, have to write off its Michigan jurisdictional generation-related regulatory assets and record its unrecorded Michigan jurisdictional liability for decommissioning the Cook Plant to the extent that they cannot be recovered under the transition rates and wires charges. As required by SFAS 101 when discontinuing SFAS 71 regulatory accounting, I&M will have to perform an accounting impairment analysis under SFAS 121 to determine if the Michigan jurisdictional portion of its generating assets are impaired for accounting purposes. The amount of regulatory assets recorded on the books at December 31, 2000 applicable to I&M's Michigan retail jurisdictional generation business is approximately $45 million before related tax effects. The estimated unrecorded liability for the Michigan jurisdiction to decommission the Cook Plant ranges from $114 million to $215 million in 2000 non-discounted dollars based upon studies completed during 2000. For the Michigan jurisdiction, I&M has accumulated approximately $100 million in trust funds to decommission the Cook Plant. Based on the current information available, management does not anticipate that I&M will experience any material tangible asset accounting impairment or regulatory asset write-offs. Ultimately, however, whether I&M will experience material regulatory asset write-offs will depend on whether the MPSC approves their recovery in future restructuring proceedings. A determination of whether I&M will experience any asset impairment loss regarding its Michigan retail jurisdictional generating assets and any loss from a possible inability to recover Michigan generation-related regulatory assets, decommissioning obligations and transition costs cannot be made until such time as the rates and the wires charges are determined through the regulatory process. In the event I&M is unable to recover all or a portion of its generation-related regulatory assets, unrecorded decommissioning obligation, stranded costs and other implementation costs, it could have a material adverse effect on results of operations, cash flows and possibly financial condition. Oklahoma Restructuring - Affecting AEP and PSO In 1997, the Oklahoma Legislature passed restructuring legislation providing for retail open access by July 1, 2002. That legislation called for a number of studies to be completed on a variety of restructuring issues, including an independent system operator, technical, financial, transition and consumer issues. During 1998 and 1999 several of the studies were completed. The information from the studies was expected to be used in the development of additional industry restructuring legislation during the 2000 legislative session. Several additional electric industry restructuring bills were filed in the 2000 Oklahoma legislative session. The proposed bills generally supple-mented the industry restructuring legislation previously enacted in Oklahoma which lacked specific procedures for a transition to market based competitive prices. The industry restructuring legislation previously passed did not delegate the establishment of transition procedures to the Oklahoma Corporation Commission. The 2000 Oklahoma legislative session adjourned in May without passing further restructuring legislation. The 2001 Oklahoma legislative session convened in early February. No further electric restructuring legislation has passed and proposals have been made to delay the implementation of the transition to customer choice and market based pricing under the restructuring legislation. These proposals are a reaction to California's recent energy crisis. Management is working with all concerned parties to reassure them that what happened in California will not occur in Oklahoma. If the necessary legislation is not passed, PSO's generation and retail electric supply business will remain regulated in Oklahoma. If implementation legislation were to modify the original restructuring legislation in Oklahoma it could have a adverse effect on results of operations. Management has concluded that as of December 31, 2000 the requirements to apply SFAS 71 continue to be met since PSO's rates for generation in Oklahoma will continue to be cost-based regulated until the Oklahoma Legislature approves further restructuring legislation and transition rates and wires charges are established under an approved transition plan. Until management is able to determine the ability to recover stranded costs which includes regulatory assets and other implementation costs, PSO cannot discontinue application of SFAS 71 accounting under GAAP. When PSO discontinues application of SFAS 71, it will be necessary to write off Oklahoma jurisdictional generation-related regulatory assets to the extent that they cannot be recovered under the transition rates and wires charges, when determined, and record any asset accounting impairments in accordance with SFAS 121. A determination of whether PSO will experience any asset impairment loss regarding its Oklahoma retail jurisdictional generating assets and any loss from a possible inability to recover Oklahoma generation-related regulatory assets and other transition costs cannot be made until such time as the rates and the wires charges are determined through the legislative and/or regulatory process. In the event PSO is unable to recover all or a portion of its generation-related regulatory assets and implementation costs, Oklahoma restructuring could have a material adverse effect on results of operations and cash flows. Restructuring In Other Jurisdictions The remaining four states (Indiana, Kentucky, Louisiana and Tennessee) making up AEP's service territory have initiatives to implement or review customer choice, although the timing of any implementation is uncertain and may be further delayed due to the California situation. AEP supports customer choice and deregulation of generation and is proactively involved in discussions regarding the best competitive market structure and transition method to arrive at a fair, competitive marketplace. As the pricing of generation in these markets evolves from regulated cost-of-service rates to market-based pricing, the recovery of stranded costs including net regulatory assets and other transition costs must be addressed. The amount of stranded costs the AEP subsidiaries could experience when and if restructuring occurs in their state jurisdictions depends on the timing and extent to which competition is introduced to their business and the future market prices of electricity. The recovery of stranded cost is dependent on the terms of future legislation and, if required, related regulatory proceedings. Customer choice and the transition to market based competition if restructuring is implemented in Indiana, Kentucky, Louisiana and Tennessee could also ultimately result in adverse impacts on results of operations and cash flows depending on the future market prices of electricity and the ability of the subsidiaries to recover their stranded costs including net regulatory assets during a transition or subsequent period through a wires charge or other recovery mechanism. Management believes that state restructuring legislation and the regulatory process should provide for full recovery of generation-related net regulatory assets and other reasonable stranded costs if these states decide to deregulate generation. However, if in the future any portion of the generation business in these other jurisdictions were to no longer be cost-based regulated and if it were not possible to demonstrate probability of recovery of resultant stranded costs including regulatory assets, results of operations, cash flows and financial condition would be adversely affected. Amortization of Transition Regulatory Assets and Other Deferred Costs - Affecting AEP, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU Future earnings will be negatively impacted by amortization of certain deferred costs and regulatory assets related to I&M's Cook Plant extended outage, transition plans to discontinue SFAS 71 regulatory accounting for generation with the beginning of customer choice in certain states and the merger of AEP and CSW. During 1999, the IURC and MPSC approved settlement agreements which provided for the deferral in 1999 and amortization of restart costs and fuel-related revenues from the extended Cook Plant outage. The amortization period is for five years ending in December 2003. Annual amortization is $78 million for I&M. See Note 4 of the Notes to Consolidated Financial Statements. Beginning in 2001 under the Ohio Act, CSPCo and OPCo began amortizing their transition regulatory assets over eight and seven years, respectively. The annual amortization in 2001 for CSPCo and OPCo is estimated to be $20 million and $74 million, respectively. The amount of amortization is based upon KWH sold. APCo began amortization of its West Virginia jurisdictional regulatory assets over an eleven year period in July 2000. In the Virginia jurisdiction, APCo started straight line amortization of regulatory assets over a seven year period in July 2000. The annual amortization for 2001 is $9 million for APCo's West Virginia jurisdiction and $9 million for APCo's Virginia jurisdiction. In June 2000 AEP merged with CSW. In connection with securing approval for the merger, AEP and certain of its subsidiaries signed agreements, approved by regulatory authorities, which included rate reductions to share estimated merger savings with customers. The agreements provide for rate reductions for periods up to eight years beginning in the third quarter of 2000. Certain merger related costs recover-able from ratepayers were deferred pursuant to the settlement agreements and will be amortized over five to eight years depending upon the terms of the respective agreements. The annual amortization of the deferred merger costs for the AEP System is estimated to total $8 million in 2001. The merger amortization will be recorded as follows: $2.6 million by CPL, $1.7 million by I&M, $600,000 by KPCo, $1.2 million by PSO, $1.1 million by SWEPCo and $800,000 by WTU. If actual merger savings are significantly less than the merger savings rate reductions required by the merger settlement agreements and the amortization of deferred merger-related costs, future results of operations, cash flows and possibly financial condition could be adversely affected. See Note 3 of the Notes to Consolidated Financial Statements for further discussion of the merger. Amortization of the above described deferred costs and regulatory assets could negatively affect future earnings to the extent that they exceed cost savings or revenues growth. Litigation COLI - Affecting AEP, APCo, CSPCo, I&M, KPCo and OPCo On February 20, 2001, the U.S. District Court for the Southern District of Ohio ruled against AEP in its suit against the United States over deductibility of interest claimed by AEP in its consolidated federal income tax return related to its COLI program. AEP had filed suit to resolve the IRS' assertion that interest deductions for AEP's COLI program should not be allowed. In 1998 and 1999 AEP and the impacted subsidiaries paid the disputed taxes and interest attributable to COLI interest deductions for taxable years 1991-98 for APCo, CSPCo, I&M and OPCo and 1992-98 for KPCo to avoid the potential assessment by the IRS of additional interest on the contested tax. The payments were included in other assets on AEP Consolidated Balance Sheet and Other Property and Investments on the subsidiaries' balance sheets 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 for the AEP System in 2000. Management plans to appeal the decision. The earnings reductions for affected registrant subsidiaries are as follows: (in millions) APCo $ 82 CSPCo 41 I&M 66 KPCo 8 OPCo 118 Shareholders' Litigation - Affecting AEP On June 23, 2000, a complaint was filed in the U.S. District Court for the Eastern District of New York seeking unspecified compensatory damages against AEP and four former or present officers. The individual plaintiff also seeks certification as the representative of a class consisting of all persons and entities who purchased or otherwise acquired AEP common stock between July 25, 1997, and June 25, 1999. The complaint alleges that the defendants knowingly violated federal securities laws by disseminating materially false and misleading statements concerning, among other things, the undisclosed materially impaired condition of the Cook Plant, AEP's inability to properly monitor, manage, repair, supervise and report on operations at the Cook Plant and the materially adverse conditions these problems were having, and would continue to have, on AEP's deteriorating financial condition, and ultimately on AEP's operations, liquidity and stock price. Four other similar class action complaints have been filed and the court has consolidated the five cases. The plaintiffs filed a consolidated complaint pursuant to this court order. This case has been transferred to the U.S. District Court for the Southern District of Ohio. Although, management believes these shareholder actions are without merit and intends to oppose them vigorously, management cannot predict the outcome of this litigation or its impact on results of operations, cash flows or financial condition. Municipal Franchise Fee Litigation - Affecting AEP and CPL CPL has been involved in litigation regarding municipal franchise fees in Texas as a result of a class action suit filed by the City of San Juan, Texas in 1996. The City of San Juan claims CPL underpaid municipal franchise fees and seeks damages of up to $300 million plus attorney's fees. CPL filed a counterclaim for overpayment of franchise fees. During 1997, 1998 and 1999 the litigation moved procedurally through the Texas Court System and was sent to mediation without resolution. In 1999 a class notice was mailed to each of the cities served by CPL. Over 90 of the 128 cities declined to participate in the lawsuit. However, CPL has pledged that if any final, non-appealable court decision awards a judgement against CPL for a franchise underpayment, CPL will extend the principles of that decision, with regard to any franchise underpayment, to the cities that declined to participate in the litigation. In December 1999, the court ruled that the class of plaintiffs would consist of approximately 30 cities. A trial date for June 2001 has been set. Although management believes that it has substantial defenses to the cities' claims and intends to defend itself against the cities' claims and pursue its counterclaim vigorously, management cannot predict the outcome of this litigation or its impact on results of operations, cash flows or financial condition. Texas Base Rate Litigation - Affecting AEP and CPL In November 1995 CPL filed with the PUCT a request to increase its retail base rates by $71 million. In October 1997 the PUCT issued a final order which lowered CPL's annual retail base rates by $19 million from the rate level which existed prior to May 1996. The PUCT also included a "glide path" rate methodology in the final order pursuant to which annual rates were reduced by $13 million beginning May 1, 1998 with an additional annual reduction of $13 million commencing on May 1, 1999. CPL appealed the final order to the Travis District Court. The primary issues being appealed include: the classification of $800 million of invested capital in STP as ECOM and assigning it a lower return on equity than other generation property; the use of the "glide path" rate reduction methodology; and an $18 million disallowance of service billings from an affiliate, CSW Services. As part of the appeal, CPL sought a temporary injunction to prohibit the PUCT from implementing the "glide path" rate reduction methodology. The temporary injunction was denied and the "glide path" rate reduction was implemented. In February 1999 the Travis District Court affirmed the PUCT order in regard to the three major items discussed above. CPL appealed the Travis District Court's findings to the Texas Appeals Court which in July 2000, issued its opinion upholding the Travis District Court except for the disallowance of affiliated service company billings. Under Texas law, specific findings regarding affiliate transactions must be made by PUCT. In regards to the affiliate service billing issue, the findings were not complete in the opinion of the Texas Appeals Court who remanded the issue back to PUCT. CPL has sought a rehearing of the Texas Appeals Court's opinion. The Texas Appeals Court has requested briefs related to CPL's rehearing request from interested parties. Management is unable to predict the final resolution of its appeal. If the appeal is unsuccessful the PUCT's 1997 order will continue to adversely affect results of operations and cash flows. As part of the AEP/CSW merger approval process in Texas, a stipulation agreement was approved which resulted in the withdrawal of the appeal related to the "glide path" rate methodology. CPL will continue its appeal of the ECOM classification for STP property and the related loss of return on equity and the disallowed affiliated service billings. Lignite Mining Agreement Litigation - Affecting AEP and SWEPCo SWEPCo and CLECO are each a 50% owner of Dolet Hills Power Station Unit 1 and jointly own lignite reserves in the Dolet Hills area of northwestern Louisiana. In 1982, SWEPCo and CLECO entered into a lignite mining agreement with DHMV, a partnership for the mining and delivery of lignite from a portion of these reserves. In April 1997, SWEPCo and CLECO sued DHMV and its partners in U.S. District Court for the Western District of Louisiana seeking to enforce various obligations of DHMV under the lignite mining agreement, including provisions relating to the quality of delivered lignite, pricing, and mine reclamation practices. In June 1997, DHMV filed an answer denying the allegations in the suit and filed a counterclaim asserting various contract-related claims against SWEPCo and CLECO. SWEPCo and CLECO have denied the allegations contained in the counterclaims. In January 1999, SWEPCo and CLECO amended the claims against DHMV to include a request that the lignite mining agreement be terminated. In April 2000, the parties agreed to settle the litigation. As part of the settlement, DHMV's interest in the mining operations and related debt and other obligations will be purchased by SWEPCo and CLECO. The closing date for the settlement has been extended from December 31, 2000 to March 31, 2001. The litigation has been stayed until April 2001 to give the parties time to consummate the settlement agreement. Management believes that the resolution of this matter will not have a material effect on results of operations, cash flows or financial condition. AEP and its registrant subsidiaries are involved in a number of other legal proceedings and claims. While management is unable to predict the outcome of such litigation, it is not expected that the ultimate resolution of these matters will have a material adverse effect on the results of operations, cash flows or financial condition. Environmental Concerns and Issues As 2001 begins, the U.S. continues to debate an array of environmental issues affecting the electric utility industry. Most of the policies are aimed at reducing air emissions citing alleged impacts of such emissions on public health, sensitive ecosystems or the global climate. AEP and its subsidiaries' policy on the environment continues to be the development and application of long-term economically feasible measures to improve air and water quality, limit emissions and protect the health of employees, customers, neighbors and others impacted by their operations. In support of this policy, AEP and its subsidiaries continue to invest in research through groups like the Electric Power Research Institute and directly through demonstration projects for new technology for the capture and storage of carbon dioxide, mercury, NOx and other emissions. The AEP System intends to continue in a leadership role to protect and preserve the environment while providing vital energy commodities and services to customers at fair prices. AEP and its subsidiaries have a proven record of efficiently producing and delivering electricity and gas while minimizing the impact on the environment. AEP and its subsidiaries have spent billions of dollars to equip their facilities with the latest cost effective clean air and water technologies and to research new technologies. Award winning efforts to reclaim our mining properties is a proud accomplishment. The introduction of multi-pollutant control legislation is being discussed by members of Congress and the Bush Administration. The legislation being considered may regulate carbon dioxide, NOx, sulfur dioxide, mercury and other emissions from electric generating plants. Management will continue to support solutions which are based on sound science, economics and demonstrated control technologies. Management is unable to predict the timing or magnitude of additional pollution control laws or regulations. If additional control technology is required on facilities owned by the electric utility companies and their costs were not recoverable from ratepayers or through market based prices or volumes of product sold, they could adversely affect future results of operations and cash flows. The following discussions explains existing control efforts, litigation and other pending matters related to environmental issues for AEP System companies. Federal EPA Complaint and Notice of Violation - Affecting AEP, APCo, CSPCo, I&M and OPCo 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. AEP, APCo, CSPCo, I&M and OPCo have been involved in litigation regarding generating plant emissions under the Clean Air Act. In 1999 Notices of Violation were issued and complaints were filed by Federal EPA in various U.S. District Courts alleging APCo, CSPCo, I&M and OPCo and a number of unaffiliated utilities made modifications to generating units at certain of their coal-fired generating plants over the course of the past 25 years that extended unit operating lives or increased unit generating capacity without a preconstruction permit in violation of the Clean Air Act. The complaint was amended in March 2000 to add allegations for certain generating units previously named in the complaint and to include additional generating units previously named only in the Notices of Violation in the complaint. A number of northeastern and eastern states were granted leave to intervene in the Federal EPA's action against the AEP System under the Clean Air Act. A lawsuit against power plants owned by certain AEP System operating companies alleging similar violations to those in the Federal EPA complaint and Notices of Violation was filed by a number of special interest groups and has been consolidated with the Federal EPA action. 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). Civil penalties, if ultimately imposed by the court, and the cost of any required new pollution control equipment, if the court accepts Federal EPA's contentions, could be substantial. On May 10, 2000, the AEP System companies filed motions to dismiss all or portions of the complaints. Briefing on these motions was completed on August 2, 2000. On February 23, 2001, the government filed a motion for partial summary judgement seeking a determination that four projects undertaken on units at Sporn, Cardinal and Clinch River plants do not constitute "routine maintenance, repair and replacement" as used in the Clear Air Act. Management believes its maintenance, repair and replacement activities were in conformity with the Clean Air Act and intends to vigorously pursue its defense. In the event the AEP System companies do not prevail, any capital and operating costs of additional pollution control equipment that may be required as well as any penalties imposed would adversely affect future results of operations, cash flows and possibly financial condition unless such costs can be recovered through regulated rates, and where states are deregulating generation, unbundled transition period generation rates, stranded cost wires charges and future market prices for electricity. In December 2000 Cinergy Corp., an unaffiliated utility, which operates certain plants jointly owned by AEP's subsidiary, CSPCo, reached a tentative agreement with Federal EPA and other parties to settle litigation regarding generating plant emissions under the Clean Air Act. Negotiations are continuing between the parties in an attempt to reach final settlement terms. Cinergy's settlement could impact the operation of Zimmer Plant and W.C. Beckjord Generating Station Unit 6 which are owned 25.4% and 12.5%, respectively, by CSPCo. Until a final settlement is reached, CSPCo will be unable to determine the settlement's impact on its jointly owned facilities and its future earnings and cash flows. NOx Reduction - Affecting AEP, APCo, CPL, I&M, OPCo and SWEPCo Federal EPA issued a NOx rule that required substantial reductions in NOx emissions in a number of eastern states, including certain states in which the AEP System's generating plants are located. A number of utilities, including several AEP System companies, filed petitions seeking a review of the final rule in the D.C. Circuit Court. In March 2000, the D.C. Circuit Court issued a decision generally upholding the NOx rule. The D.C. Circuit Court issued an order in August 2000 which extends the final compliance date to May 31, 2004. In September 2000 following denial by the D.C. Circuit Court of a request for rehearing, the industry petitioners, including the AEP System companies, petitioned the U.S. Supreme Court for review, which was denied. In December 2000 Federal EPA ruled that eleven states, including certain states in which the AEP System's generating units are located, failed to submit plans to comply with the mandates of the NOx rule. This deter-mination means that those states could face stringent sanctions within the next 24 months including limits on construction of new sources of air emissions, loss of federal high-way funding and possible Federal EPA take-over of state air quality management programs. In January 2000 Federal EPA adopted a revised rule granting petitions filed by certain northeastern states under Section 126 of the Clean Air Act seeking significant reductions in nitrogen oxide emissions from utility and industrial sources. The rule im-poses emissions reduction requirements com-parable to the NOx rule beginning May 1, 2003, for most of AEP's coal-fired generating units. Certain AEP companies and other utili-ties filed petitions for review in the D.C. Circuit Court. Briefing has been completed and oral argument was held in December 2000. In a related matter, on April 19, 2000, the Texas Natural Resource Conservation Commission adopted rules requiring significant reductions in NOx emissions from utility sources, including CPL and SWEPCo. The rule's compliance date is May 2003 for CPL and May 2005 for SWEPCo. In June 2000 OPCo announced that it was beginning a $175 million installation of selective catalytic reduction technology (expected to be operational in 2001) to reduce NOx emissions on its two-unit 2,600 MW Gavin Plant. Construction of selective catalytic reduction technology on Amos Plant Unit 3, which is jointly owned by OPCo and APCo, and APCo's Mountaineer Plant is scheduled to begin in 2001. The Amos and Mountaineer projects (expected to be completed in 2002) are estimated to cost a total of $230 million ($145 million for APCo and $85 million for OPCo). Preliminary estimates indicate that compliance with the NOx rule upheld by the D.C. Circuit Court as well as compliance with the Texas Natural Resource Conservation Commission rule and the Section 126 petitions could result in required capital expenditures of approximately $1.6 billion including the amounts discussed in the previous paragraph for the AEP System. The following table shows the estimated compliance cost for certain of AEP's registrant subsidiaries. Company Amount - ------- ------ (in millions) APCo $365 CPL 57 I&M 202 OPCo 606 SWEPCo 28 Since compliance costs cannot be estimated with certainty, the actual cost to comply could be significantly different than the preliminary estimates depending upon the compliance alternatives selected to achieve reductions in NOx emissions. Unless any capital and operating costs of additional pollution control equipment are recovered from customers through regulated rates and/or future market prices for electricity where generation is deregulated, they will have an adverse effect on future results of operations, cash flows and possibly financial condition. Superfund - Affecting AEP, APCo, CPL, CSPCo, I&M, OPCo and SWEPCo By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically disposed of or treated in captive disposal facilities or are beneficially utilized. In addition, the AEP System's generating plants and transmission and distribution facilities have used asbestos, PCBs and other hazardous and non-hazardous materials. The AEP System companies 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 2000, subsidiaries of AEP have been named by the Federal EPA as a PRP for five sites. APCo, CSPCo, and OPCo each have one PRP site and I&M has two PRP sites. There are five additional sites for which AEP, APCo, CSPCo, I&M, OPCo and SWEPCo have received information requests which could lead to PRP designation. CPL, OPCo and SWEPCo have also been named a PRP at three sites under state law. Liability has been resolved for a number of sites with no significant effect on the AEP subsidiaries' results of operations. In those instances where AEP or its subsidiaries have been named a PRP or defendant, their disposal or recycling activities were in accordance with the then-applicable laws and regulations. Unfortunately, Superfund does not recognize compliance as a defense, but imposes strict liability on parties who fall within its broad statutory categories. While the potential liability for each Superfund site must be evaluated separately, several general statements can be made regarding AEP's and its subsidiaries' potential future liability. Disposal of materials at a particular site is often unsubstantiated and the quantity of materials deposited at a site was small and often nonhazardous. Although liability is joint and several, typically many parties are named as PRPs for each site and several of the parties are financially sound enterprises. Therefore, management's present estimates do not anticipate material cleanup costs for identified sites for which AEP System companies 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 At the Third Conference of the Parties to the United Nations Framework Convention on Climate Change held in Kyoto, Japan in December 1997 more than 160 countries, including the U.S., negotiated a treaty requiring legally-binding reductions in emissions of greenhouse gases, chiefly carbon dioxide, which many scientists believe are contributing to global climate change. The treaty, which requires the advice and consent of the U.S. Senate for ratification, would require the U.S. to reduce greenhouse gas emissions seven percent below 1990 levels in the years 2008-2012. Although the U.S. has agreed to the treaty and signed it on November 12, 1998, the treaty has not been submitted to the Senate for consideration as it does not contain requirements for "meaningful participation by key developing countries" and the rules, procedures, methodologies and guidelines of the treaty's emissions trading and joint implementation programs and compliance enforcement provisions have not been negotiated. At the Fourth Conference of the Parties in November 1998, the parties agreed to a work plan to complete negotiations on outstanding issues with a view toward approving them at the Sixth Conference of the Parties to be held in November 2000. During the Sixth Conference of the Parties agreement was not reached on any of the outstanding issues requiring resolution in order to faciliate ratification of the Kyoto Protocol. There are several contentious issues and literally hundreds of pages of detailed, complex rules that remain to be negotiated. Discussions are expected to resume in July 2001. While a candidate for the presidency, George Bush had stated his opposition to U.S. ratification of the Kyoto Protocol. The Seventh Conference of the Parties is scheduled for October 2001 in Morocco. AEP does not support the Kyoto Treaty as presently drafted. Management will continue to work with the Administration and Congress to develop responsible public policy on this issue. If the Kyoto treaty is approved by Congress as presently drafted, the costs for the AEP System to comply with the required emission reductions required by the treaty are expected to be substantial and would have a material adverse impact on results of operations, cash flows and possibly financial condition if not recovered from customers. It is management's belief that the Kyoto Protocol is unlikely to be ratified and implemented in the U.S. in its current form. Costs for Spent Nuclear Fuel and Decommissioning - Affecting AEP, CPL and I&M I&M, as the owner of the Cook Plant, and CPL, as a partial owner of STP, have a significant future financial commitment to safely dispose of SNF and decommission and decontaminate the plants. The Nuclear Waste Policy Act of 1982 established federal responsibility for the permanent off-site disposal of SNF and high-level radioactive waste. By law CPL and I&M participate in the DOE's SNF disposal program which is described in Note 8 of the Notes to Consolidated Financial Statements. Since 1983 I&M has collected $275 million from customers for the disposal of nuclear fuel consumed at the Cook Plant. $116 million of these funds have been deposited in external trust funds to provide for the future disposal of SNF and $159 million has been remitted to the DOE. CPL has collected and remitted to the DOE, $44 million for the future disposal of SNF since STP began operation in the late 1980s. Under the provisions of the Nuclear Waste Policy Act, collections from customers are to provide the DOE with money to build a permanent repository for spent fuel. However, in 1996, the DOE notified the companies that it would be unable to begin accepting SNF by the January 1998 deadline required by law. To date DOE has failed to comply with the requirements of the Nuclear Waste Policy Act. As a result of DOE's failure to make sufficient progress toward a permanent repository or otherwise assume responsibility for SNF, AEP on behalf of I&M and STPNOC on behalf of CPL and the other STP owners, along with a number of unaffiliated utilities and states, filed suit in the D.C. Circuit Court requesting, among other things, that the D.C. Circuit Court order DOE to meet its obligations under the law. The D.C. Circuit Court ordered the parties to proceed with contractual remedies but declined to order DOE to begin accepting SNF for disposal. DOE estimates its planned site for the nuclear waste will not be ready until at least 2010. In 1998, AEP and I&M filed a complaint in the U.S. Court of Federal Claims seeking damages in excess of $150 million due to the DOE's partial material breach of its unconditional contractual deadline to begin disposing of SNF generated by the Cook Plant. Similar lawsuits were filed by other utilities. In August 2000, in an appeal of related cases involving other unaffiliated utilities, the U.S. Court of Appeals for the Federal Circuit held that the delays clause of the standard contract between utilities and the DOE did not apply to DOE's complete failure to perform its contract obligations, and that the utilities' suits against DOE may continue in court. AEP's and I&M suit has been stayed pending further action by the U.S. Court of Federal Claims. As long as the delay in the availability of a government approved storage repository for SNF continues, the cost of both temporary and permanent storage and the cost of decommissioning will continue to increase. In January 2001, I&M and STPNOC, on behalf of STP's joint owners, joined a lawsuit against DOE, filed in November 2000 by unaffiliated utilities, related to DOE's nuclear waste fund cost recovery settlement with PECO Energy Corporation. The settlement allows PECO to skip two payments to the DOE for disposal of SNF due to the lack of progress towards development of a permanent repository for SNF. The companies believe the settlement is unlawful as the settlement would force other utilities to make up any shortfall in DOE's SNF disposal funds. The cost to decommission nuclear plants is affected by both NRC regulations and the delayed SNF disposal program. Studies completed in 2000 estimate the cost to decommission the Cook Plant ranges from $783 million to $1,481 million in 2000 non-discounted dollars. External trust funds have been established with amounts collected from customers to decommission the plant. At December 31, 2000, the total decommissioning trust fund balance for Cook Plant was $558 million which includes earnings on the trust investments. Studies completed in 1999 for STP estimate CPL's share of decommissioning cost to be $289 million in 1999 non-discounted dollars. Amounts collected from customers to decommission STP have been placed in an external trust. At December 31, 2000, the total decommissioning trust fund for CPL's share of STP was $94 million which includes earnings on the trust investments. Estimates from the decommissioning studies could continue to escalate due to the uncertainty in the SNF disposal program and the length of time that SNF may need to be stored at the plant site. We will work with regulators and customers to recover the remaining estimated costs of decommissioning Cook Plant and STP through regulated rates and, where generation has been deregulated, through wires charges. However, AEP's, CPL's and I&M's future results of operations, cash flows and possibly their financial conditions would be adversely affected if the cost of SNF disposal and decommissioning continues to increase and cannot be recovered. Foreign Energy Delivery, Worldwide Energy Investments and Other Business Operations Worldwide electric and gas operations on AEP's Consolidated Statements of Income include the foreign energy delivery, worldwide energy investments, and other segments of AEP's business. See Note 14 of the Notes to Consolidated Financial Statements for a discussion of segments. AEP's investment in certain types of activities is limited by PUHCA. SEC authorization under PUHCA limits AEP to issuing and selling securities in an amount up to 100% of its average quarterly consolidated retained earnings balance for investment in EWGs and FUCOs. At December 31, 2000, AEP's investment in EWGs and FUCOs was $1.8 billion compared to AEP's limit of $3.4 billion by law. SEC rules under PUHCA permit AEP to invest up to 15% of consolidated capitalization (such amount was $3.5 billion at December 31, 2000) in energy-related companies that engage in marketing and/or trading of electricity, gas and other energy commodities. AEP's gas trading business and its interests in domestic cogeneration projects are reported as investments under this rule and at December 31, 2000, AEP's investment was less than one million dollars. Management continues to evaluate the U.S. and international energy markets for investment opportunities that complement AEP's wholesale operations. Management expects to continue to pursue new and existing energy supply projects and to provide energy related services worldwide. AEP's future consolidated earnings will be impacted by the performance of existing and any future investments. The major business activities and subsidiaries of AEP's worldwide electric and gas operations are SEEBOARD, CitiPower, Yorkshire, European energy trading operations, U.S. power trading more than two transmission systems removed from the AEP transmission system and gas trading operations in the U.S., domestic and foreign generating facilities in China, Mexico and the U.S., electric distribution in South America and power plant construction. SEEBOARD's principal business is the distribution and supply of electricity in southeast England. CitiPower provides electricity and electric distribution service in the city of Melbourne, Australia. AEP owns 100% of SEEBOARD and CitiPower. The revenues and operating expenses for SEEBOARD and CitiPower are included in worldwide revenues and expenses on AEP's Consolidated Statements of Income. Interest, taxes and other nonoperating items for SEEBOARD and CitiPower are included in the appropriate income statement lines. In 1998 SEEBOARD's 80% owned subsidiary, SEEBOARD Powerlink, signed a 30-year contract for $1.6 billion to operate, maintain, finance and renew the high-voltage power distribution network of the London Underground transportation system. SEEBOARD Powerlink will be responsible for distributing high voltage electricity to supply 270 London Underground stations and 250 miles of the rail system's track. SEEBOARD's partners in Powerlink are an international electrical engineering group and an international cable and construction group. AEP has a 50% investment in Yorkshire, another U.K. regional electricity distribution and supply company. The investment is accounted for using the equity method of accounting with equity earnings included in other income (net) on the AEP Consolidated Statements of Income. In December 2000 AEP entered into negotiations to sell its investment in Yorkshire. On February 26, 2001, an agreement to sell AEP's 50% interest in Yorkshire was signed. The sale is expected to close by March 31, 2001. See Note 10 of the Notes to Consolidated Financial Statements. In the U.K. all residential and commercial customers have been allowed to choose their electricity supplier since May 1999. Margins on retail electric sales have been generally declining due to competition. In April 2000 final proposals from the regulatory commission reduced distribution rates and electricity supply price caps. The distribution rate reductions and reduced price caps are expected to reduce AEP's earnings from SEEBOARD and its Yorkshire investment. In response to these final proposals and increasing competition, SEEBOARD and Yorkshire adopted an aggressive program of reducing controllable costs. Significant features of this program include staff reductions, outsourcing of certain functions and consolidation of facilities. Management intends to aggressively pursue this cost reduction program and continues to evaluate additional cost reduction measures to further mitigate the effects of the final proposals and increasing competition in the U.K. electricity supply business. Management expects that, despite the cost control measures, the rate reductions will negatively impact AEP's earnings. The Utilities Act which became law in the U.K. in July 2000 includes a requirement for separate licensing of electricity supply and distribution and the introduction of a prohibition of electricity supply and distribution licenses being held by the same legal entity. This requirement effectively means that the electricity supply and distribution businesses of SEEBOARD and Yorkshire must be held by separate companies. However, AEP will not be required to divest its interest in either the supply entity or the distribution entity. The separation of the supply and distribution business into two entities each for SEEBOARD and Yorkshire is not expected to have a material impact on future results of operations or cash flows. Beginning January 1, 2001 price reductions on the supply and distribution of electricity are being implemented in Victoria, Australia. The effect of these price reductions is expected to reduce CitiPower's results of operations to the extent that they cannot be offset by reduced expenses, improved efficiencies or increased sales. A new, higher tariff rate for the electricity from two 250 MW coal-fired generating units located in Henan Province, China was approved by the Central Chinese government in January 2000. AEP owns 70% of these units, with the remaining 30% owned by two Chinese partners. As a result of the new tariff the units contributed positively to AEP's results of operations for 2000 after incurring a loss in 1999. Other foreign generating facilities include a 37.5% interest in 675 MW of capacity in the U.K. and a 50% interest in 118 MW of capacity in Mexico. AEP also has a 50% ownership interest in two generating plants under construction; a 600 MW facility in Mexico and a 400 MW facility in the U.K. All of these facilities sell their capacity under long-term contracts. The investment in these facilities is accounted for using the equity method. AEP, through its CSW Energy subsidiary, has an ownership interest in seven operational domestic generation facilities in Colorado, Florida and Texas with one 440 MW facility under construction. These plants are EWGs or qualifying facilities (QF) as defined by law and not subject to cost-based rate regulation or the application of SFAS 71 regulatory accounting. The combined installed capacity of the operational facilities is 1,508 MW at December 31, 2000. The power from these QF facilities is sold under long-term power purchase agreements with the local host facility. Any merchant power is sold in the wholesale market generally under short-term contract. As a result, increases in the market price of natural gas used to generate electricity at these facilities may adversely impact results of operations. In 1999 a 50% equity interest in one of the above facilities was sold to an unaffiliated company. The after-tax gain from the sale was approximately $33 million. An additional unit is under construction at this facility. Pursuant to the terms of the sale agreement, the unaffiliated company will make additional payments to CSW Energy upon completion of the additional unit. Under terms of the FERC and Texas settlement agreements that approved the merger, the divestiture of certain generating units is required. The Frontera power plant, one of CSW Energy's facilities, is specifically identified as one of the plants where the entire ownership interest must be sold. On February 8, 2001, AEP announced that it had reached agreement with an unaffiliated company to sell the 500 MW Frontera power plant for $265 million in cash. In 2000 an electricity and gas trading operation in Europe was added. This business requires minimal capital investment and offers an opportunity to employ our expertise in energy marketing and trading to a new market. The domestic gas trading operation grew substantially in 2000 and is expected to benefit from the planned acquisition of the Houston Pipe Line Company which was announced in January 2001. The acquisition of Houston Pipe Line Company, which has more than 4,400 miles of natural gas transmission pipeline and operates one of the largest storage facilities, is expected to complement our intra-state gas transmission and storage facilities in Louisiana and extends AEP's strategy of linking physical energy asset operations with trading and marketing operations. AEP's Louisiana gas operation is LIG, a midstream natural gas operation, that was purchased in December 1998 for approximately $340 million including working capital funds. LIG includes a fully integrated natural gas gathering, processing, storage and transportation operation in Louisiana and a gas trading and marketing operation. Assets include an intrastate pipeline system, natural gas liquids processing plants and natural gas storage facilities. AEP's subsidiaries are engaged in the engineering and construction for third parties of three power plants in the U.S. with a capacity of 1,910 MW. These plants will be natural gas-fired facilities that are scheduled to be completed from 2001 to 2003. AEP intends to use its engineering, trading and marketing expertise on these projects some of which also include power purchase and power sale agreements to enhance its results of operations. Other Matters - Affecting AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU New Accounting Standards - SFAS 133, "Accounting for Derivative Instruments and Hedging Activities", as amended by SFAS 137 and SFAS 138, is effective for the AEP System beginning January 1, 2001. SFAS 133 requires that entities recognize all derivatives as either assets or liabilities and measure them at fair value. Changes in the fair value of derivative assets and liabilities must be recognized currently in net income. Changes in the derivatives that are effective cash flow hedges are recorded in other comprehensive income. Pending the resolution of certain industry issues presently before the FASB's Derivatives Implementation Group (DIG), the effect of adoption of SFAS 133 will result in transition adjustment amounts which will have an immaterial effect on both net income and other comprehensive income. The FASB's DIG, has issued tentative guidance, which has not yet been approved by the FASB, that option contracts cannot qualify as normal purchases and sales. In addition there are two industry issues pending resolution by the DIG related to whether electric capacity contracts that may have some characteristics of purchased and written options can qualify as normal sales, and whether contracts which do not result in physical delivery of power because of transmission constraints are derivatives. While the Company believes the majority of the its fuel supply agreements should qualify as normal purchases and that the majority of its power sales agreements qualify as normal sales, the ultimate resolution of the above issues may result in accounting for certain power sales and fuel supply agreements as derivatives which may have a material effect on reported net income under SFAS 133. Whether the impact will be favorable or adverse will depend on the market prices compared to the contractual prices at the time of valuation. INVESTOR INQUIRIES Investors should direct inquiries to Investor Relations using the toll free number, 1-800-237-2667 or by writing to: Bette Jo Rozsa Managing Director of Investor Relations American Electric Power Service Corporation 28th Floor 1 Riverside Plaza Columbus, OH 43215-2373 FORM 10-K ANNUAL REPORT The Annual Report (Form 10-K) to the Securities and Exchange Commission will be available in April 2001 at no cost to shareholders. Please address requests for copies to: Geoffrey C. Dean Director of Financial Reporting American Electric Power Service Corporation 26th Floor 1 Riverside Plaza Columbus, OH 43215-2373 TRANSFER AGENT AND REGISTRAR OF CUMULATIVE PREFERRED STOCK Equiserve, First Chicago Division P.O. Box 2500 Jersey City, NJ 07303-2500 Phone number: 1-800-328-6955 EX-21 12 0012.txt SUBSIDIARIES EXHIBIT 21 Subsidiaries of American Electric Power Company, Inc. As of December 31, 2000 The voting stock of each company shown indented is owned by the company immediately above which is not indented to the same degree. Subsidiaries not indented are directly owned by American Electric Power Company, Inc.
Percentage of Voting Securities Location of Owned By Name of Company Incorporation Immediate Parent --------------- ------------- ---------------- American Electric Power Service Corporation New York 100.0 AEP Communications, Inc. Ohio 100.0 AEP Communications, LLC Virginia 100.0 AEP Fiber Venture, LLC Virginia 100.0 America's Fiber Network, LLC Delaware 48.0 (x) American Fiber Touch, LLC Delaware 50.0 (v) Datapult LLC Delaware 100.0 Datapult Limited Partnership Delaware .5 (u) Datapult Limited Partnership Delaware 49.75(w) AEP Energy Services, Inc. Ohio 100.0 AEP Generating Company Ohio 100.0 AEP Investments, Inc. Ohio 100.0 AEP Power Marketing, Inc. Ohio 100.0 AEP Pro Serv, Inc. Ohio 100.0 AEP Resources, Inc. Ohio 100.0 AEP Energy Management, L.L.C. Delaware 100.0 AEP Holdings I CV Netherlands 99.0 (a) AEP Resources Australia Holdings Pty Ltd Australia 100.0 AEP Resources CitiPower I Pty Ltd Australia 100.0 Australia's Energy Partnership Australia 99.0 (b) Marregon II Pty Ltd Australia 100.0 CitiPower Pty Australia 100.0 CitiPower Trust Australia 100.0 Marregon Pty Ltd Australia 100.0 AEP Resources CitiPower II Pty Ltd Australia 100.0 Australia's Energy Partnership Australia 1.0 (b) Marregon II Pty Ltd Australia 100.0 CitiPower Pty Australia 100.0 CitiPower Trust Australia 100.0 Marregon Pty Ltd Australia 100.0 AEP Resources Australia Pty., Ltd. Australia 100.0 Pacific Hydro Limited Australia 20.0 (c) AEP Delaware Investment Company Delaware 100.0 AEP Holdings I CV Netherlands 1.0 (a) AEP Funding Limited Cayman Islands 100.0 AEP Holdings II CV Netherlands 85.0 (d) AEP Energy Services Limited Great Britain 100.0 AEPR Global Investments B.V. Netherlands 100.0 AEPR Global Holland Holding B.V. Netherlands 100.0 AEPR Global Ventures B.V. Netherlands 100.0 Australian Energy International Pty Ltd Australia 16.0 (e) AEI (Loy Yang) Pty Ltd Australia 100.0 Intergen Denmark, Aps Denmark 50.0 (f) AEP Delaware Investment Company II Delaware 100.0 AEP Holdings II CV Netherlands 15.0 (d) AEP Energy Services Limited Great Britain 100.0 AEP Energy Services (Germany)GmbH Germany 100.0 AEP Energy Services (Switzerland) GmbH Switzerland 100.0 AEP Energy Services (Austria) GmbH Austria 100.0 AEPR Global Investments B.V. Netherlands 100.0 AEPR Global Holland Holding B.V. Netherlands 100.0 Energia de Mexicali, S de R.L.de C.V. Mexico .03 (t) AEPR Global Ventures B.V. Netherlands 100.0 Energia de Mexicali, S de R.L. de C.V. Mexico 97.97 (t) Australian Energy International Pty Ltd Australia 16.0 (e) AEI (Loy Yang) Pty Ltd Australia 100.0 Intergen Denmark, Aps Denmark 50.0 (f) AEP Resources Do Brasil LTDA. Brazil 0.1 (g) AEP Resources Do Brasil LTDA. Brazil 99.9 (g) AEP Energy Services Gas Holding Company Delaware 100.0 AEP Energy Services Investments, Inc. Delaware 100.0 LIG Pipeline Company Nevada 100.0 LIG, Inc. Nevada 100.0 Louisiana Intrastate Gas Company, L.L.C.Louisiana 10.0 (h) LIG Chemical Company Louisiana 100.0 LIG Liquids Company,L.L.C. Louisiana 10.0 (i) LIG Liquids Company,L.L.C. Louisiana 90.0 (i) Tuscaloosa Pipeline Company Louisiana 100.0 Louisiana Intrastate Gas Company,L.L.C. Louisiana 90.0 (h) LIG Chemical Company Louisiana 100.0 LIG Liquids Company,L.L.C. Louisiana 10.0 (i) LIG Liquids Company,L.L.C. Louisiana 90.0 (i) Tuscaloosa Pipeline Company Louisiana 100.0 AEP Energy Services Ventures, Inc. Delaware 100.0 AEP Acquisition, L.L.C. Delaware 50.0 (j) Jefferson Island Storage & Hub L.L.C. Delaware 100.0 Ventures Lease Co., LLC Delaware 100.0 AEP Energy Services Ventures II, Inc. Delaware 100.0 AEP Acquisition, L.L.C. Delaware 50.0 (j) Jefferson Island Storage & Hub L.L.C. Delaware 100.0 AEP Energy Services Ventures III, Inc. Delaware 100.0 AEP Resources International, Limited Cayman Islands 100.0 AEP Pushan Power, LDC Cayman Islands 99.0 (k) Nanyang General Light Electric Co., Ltd. People's Republic of China 70.0 (l) AEP Resources Mauritius Company Mauritius 99.0 (k) AEP Resources Mauritius Investment Company Mauritius 100.0 AEP Resources Project Management Company, Ltd.Cayman Islands 100.0 AEP Pushan Power, LDC Cayman Islands 1.0 (k) Nanyang General Light Electric Co., Ltd. People's Republic of China 70.0 (l) AEP Resources Mauritius Company Mauritius 1.0 (k) AEP Resources Limited Great Britain 100.0 AEP Resources Services LLC Delaware 100.0 Yorkshire Power Group Limited Great Britain 50.0 (m) Yorkshire Cayman Holding Limited Cayman Islands 100.0 Yorkshire Holdings plc Great Britain 100.0 Yorkshire Electricity Group plc Great Britain 100.0 Yorkshire Power Finance Limited Cayman Islands 2.0 (n) Yorkshire Power Finance Limited Cayman Islands 98.0 (n) AEP Retail Energy, LLC Delaware 100.0 Appalachian Power Company Virginia 98.7 (o) Cedar Coal Co. West Virginia 100.0 Central Appalachian Coal Company West Virginia 100.0 Central Coal Company West Virginia 50.0 (p) Central Operating Company West Virginia 50.0 (p) Southern Appalachian Coal Company West Virginia 100.0 West Virginia Power Company West Virginia 100.0 Central and South West Corporation Delaware 100.0 C3 Communications, Inc. Delaware 100.0 Datapult Limited Patnership Delaware 49.75(v) Central and South West Services, Inc. Texas 100.0 Central Power and Light Company Texas 100.0 AEP Credit, Inc. Delaware 100.0 CSW Energy Services, Inc. Delaware 100.0 CSW Energy, Inc. Texas 100.0 CSW Power Marketing, Inc. Delaware 100.0 CSW International, Inc. Delaware 100.0 SEEBOARD plc Great Britain 100.0 CSW Leasing, Inc. Delaware 80.0 (t) EnerShop Inc Delaware 100.0 Public Service Company of Oklahoma Oklahoma 100.0 Southwestern Electric Power Company Delaware 100.0 West Texas Utilities Company Texas 100.0 Columbus Southern Power Company Ohio 100.0 Colomet, Inc. Ohio 100.0 Conesville Coal Preparation Company Ohio 100.0 Simco Inc. Ohio 100.0 Franklin Real Estate Company Pennsylvania 100.0 Indiana Franklin Realty, Inc. Indiana 100.0 Indiana Michigan Power Company Indiana 100.0 Blackhawk Coal Company Utah 100.0 Price River Coal Company, Inc. Indiana 100.0 Kentucky Power Company Kentucky 100.0 Kingsport Power Company Virginia 100.0 Ohio Power Company Ohio 99.2 (q) Cardinal Operating Company Ohio 50.0 (r) Central Coal Company West Virginia 50.0 (p) Central Ohio Coal Company Ohio 100.0 Central Operating Company West Virginia 50.0 (p) Southern Ohio Coal Company West Virginia 100.0 Windsor Coal Company West Virginia 100.0 Ohio Valley Electric Corporation Ohio 44.2 (s) Indiana-Kentucky Electric Corporation Indiana 100.0 Wheeling Power Company West Virginia 100.0 (a) Owned 99% by AEP Resources, Inc. and 1% by AEP Delaware Investment Company. (b) Owned 99% by AEP Resources CitiPower I Pty Ltd and 1% by AEP Resources CitiPower II Pty Ltd. (c) Owned 20% by AEP Resources Australia Pty Ltd and 80% by an unaffiliated company. (d) Owned 85% by AEP Holdings I CV and 15% by AEP Delaware Investment Company II. (e) AEPR Global Ventures B.V. owns 16% and the remaining 84% is owned by an unaffiliated company. (f) Owned 50% by AEP Holdings II CV and 50% by an unaffiliated company. (g) Owned 99.9% by AEP Resources, Inc. and 0.1% by AEP Delaware Investment Company II. (h) Owned 90% by LIG Pipeline Company and 10% by LIG, Inc. (i) Owned 90% by Louisiana Intrastate Gas Company, L.L.C. and 10% by Lig Chemical Company (j) Owned 50% by AEP Resources Ventures, Inc and 50% by AEP Resources Ventures II. (k) Owned 99% by AEP Resources International, Ltd. and 1% by AEP Resources Project Management Company, Ltd. (l) AEP Pushan Power LDC owns 70% and the remaining 30% is owned by two unaffiliated companies. (m) Owned 50% by AEP Resources, Inc. and 50% by an unaffiliated company. (n) Yorkshire Power Group Limited owns 980 shares and Yorkshire Holdings plc owns 20 shares. (o) 13,499,500 shares of Common Stock, all owned by parent, have one vote each and 177,905 shares of Preferred Stock, all owned by the public, have one vote each. (p) Owned 50% by Appalachian Power Company and 50% by Ohio Power Company. (q) 27,952,473 shares of Common Stock, all owned by parent, have one vote each and 238,977 shares of Preferred Stock, all owned by the public, have one vote each. (r) Ohio Power Company owns 50% of the stock; the other 50% is owned by a corporation not affiliated with American Electric Power Company, Inc. (s) American Electric Power Company, Inc. and Columbus Southern Power Company own 39.9% and 4.3% of the stock, respectively, and the remaining 55.8% is owned by unaffiliated companies. (t) AEPR Global Investments B.V. owns .03% of the company and AEPR Global Ventures B.V. owns 99.97% of the company. (u) C3 Communications and AEP Communications, LLC each own 49.75% of the company and Datapult LLC owns .5% of the company. (v) AEP Comunications LLC owns 50% of the company and the remaining 50% is owned by an unaffiliated company. (x) AEP Communications LLC owns approximately 48% of the company and the remaining 52% is owned by unaffiliated companies.
EX-23.(A) 13 0013.txt CONSENT OF DELOITTE & TOUCHE INDEPENDENT AUDITORS' CONSENT We consent to the incorporation by reference in Registration Statement Nos. 333-46360 and 333-39402 of American Electric Power Company, Inc. on Form S-8, Post-Effective Amendment No. 1 to Registration Statement No. 333-50109 of American Electric Power Company, Inc. on Form S-8, Post-Effective Amendment No. 3 to Registration Statement No. 33-01052 of American Electric Power Company, Inc. on Form S-8 and Post Effective Amendment No. 3 to Registration Statement No. 33-01734 of American Electric Power Company, Inc. on Form S-3 of our reports dated February 26, 2001, appearing in and incorporated by reference in this Annual Report on Form 10-K of American Electric Power Company, Inc. for the year ended December 31, 2000. Deloitte & Touche LLP Columbus, Ohio March 28, 2001 EX-23.(B) 14 0014.txt CONSENT OF ARTHUR ANDERSEN Exhibit 23 (b) Consent of Independent Public Accountants As independent public accountants, we hereby consent to the incorporation of our report dated February 25, 2000 on Central and South West Corporation, included and incorporated by reference in this Form 10-K, into the American Electric Power Company, Inc. registration statements on Form S-8 (File Nos. 333-46360, 333-39402 and 333-50109) and on Form S-3 (File No. 33-01734). /s/ Arthur Andersen LLP Dallas, Texas March 27, 2001 EX-23.(C) 15 0015.txt CONSENT OF KPMG AUDIT The Board of Directors CSW UK Holdings We consent to the incorporation of our report dated 18 January 1999, with respect to the consolidated balance sheet of CSW UK Finance Company as of 31 December 1998 (not separately presented herein), and our report dated 17 January 2000 with respect to the consolidated balance sheet of CSW UK Holdings as of 31 December 1999 and the related consolidated statements of earnings and cash flows for the years then ended (not separately presented herein), which reports appear in the 2000 Annual Report of American Electric Power Company, Inc. and are incorporated by reference in Form 10-K of American Electric Power Company, Inc. for the year ended 31 December 2000. KPMG Audit Plc London, England Chartered Accountants 15th March 2001 Registered Auditor EX-24 16 0016.txt POWER OF ATTORNEY Exhibit 24 POWER OF ATTORNEY AMERICAN ELECTRIC POWER COMPANY, INC. Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2000 The undersigned directors of AMERICAN ELECTRIC POWER COMPANY, INC., a New York corporation (the "Company"), do hereby constitute and appoint E. LINN DRAPER, JR., ARMANDO A. PENA and HENRY W. FAYNE, 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, 2000, and any and all amendments thereto, and to file the same, with all exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in- fact and agents, and each of them, full power and authority to do and perform every act and thing required or necessary to be done, as fully to all intents and purposes as the undersigned might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, may lawfully do or cause to be done by virtue hereof. IN WITNESS WHEREOF, the undersigned have signed these presents this 28th day of February, 2001. /s/ E. R. Brooks /s/ James L. Powell - ---------------------------------- ------------------------------------- E. R. Brooks James L. Powell /s/ Donald M. Carlton /s/ Richard L. Sandor - ---------------------------------- ------------------------------------- Donald M. Carlton Richard L. Sandor /s/ John P. DesBarres /s/ Thomas V. Shockley, III - ---------------------------------- ------------------------------------- John P. DesBarres Thomas V. Shockley, III /s/ E. Linn Draper, Jr. /s/ Donald G. Smith - ---------------------------------- ------------------------------------- E. Linn Draper, Jr. Donald G. Smith /s/ Robert W. Fri Linda Gillespie Stuntz - ---------------------------------- ------------------------------------- Robert W. Fri Linda Gillespie Stuntz /s/ William R. Howell /s/ Kathryn D. Sullivan - ---------------------------------- ------------------------------------- William R. Howell Kathryn D. Sullivan /s/ Lester A. Hudson, Jr. /s/ Morris Tanenbaum - ---------------------------------- ------------------------------------- Lester A. Hudson, Jr. Morris Tanenbaum /s/ Leonard J. Kujawa - ---------------------------------- Leonard J. Kujawa -----END PRIVACY-ENHANCED MESSAGE-----